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Securities registered pursuant to Section 12(b) of the Act:
Calpine Corporation Common Stock,
$0.001 Par Value
Name of each exchange on which registered:
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes [X] No [ ]
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes [ ] No [X]
Indicate by check mark whether the
registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer, “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large
accelerated filer [X]
Accelerated filer [ ]
Non-accelerated filer [ ]
Smaller reporting company [ ]
(Do not check if a 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, 2014, the last business day of the registrant’s most recently completed second fiscal quarter: approximately $9,891 million.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: Calpine Corporation: 376,193,256 shares of common stock, par value $0.001, were outstanding as of February 11, 2015.
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 2015 Annual Meeting of Shareholders are incorporated by reference into Part III to the extent described therein.
As used in this annual report for the year ended December 31, 2014, the following abbreviations and terms have the meanings as listed below. Additionally, the terms “Calpine,”“we,”“us” and “our” refer to Calpine Corporation and its consolidated subsidiaries,
unless the context clearly indicates otherwise. The term “Calpine Corporation” refers only to Calpine Corporation and not to any of its subsidiaries. Unless and as otherwise stated, any references in this Report to any agreement means such agreement and all schedules, exhibits and attachments in each case as amended, restated, supplemented or otherwise modified to the date of filing this Report.
ABBREVIATION
DEFINITION
2017
First Lien Notes
The $1.2 billion aggregate principal amount of 7.25% senior secured notes due 2017, issued October 21, 2009
2018 First Lien Term Loans
Collectively, the $1.3 billion first lien senior secured term loan dated March 9, 2011 and the $360 million first lien senior secured term loan dated June
17, 2011
2019 First Lien Notes
The $400 million aggregate principal amount of 8.0% senior secured notes due 2019, issued May 25, 2010
2019 First Lien Term Loan
The
$835 million first lien senior secured term loan, dated October 9, 2012, among Calpine Corporation, as borrower, and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
2020 First Lien Notes
The $1.1 billion aggregate principal amount of 7.875% senior secured notes due 2020, issued July 23, 2010
2020
First Lien Term Loan
The $390 million first lien senior secured term loan, dated October 23, 2013, among Calpine Corporation, as borrower, and the lenders party hereto, and Citibank, N.A., as administrative agent and Goldman Sachs Credit Partners L.P., as collateral agent
2021 First Lien Notes
The $2.0 billion aggregate principal amount of 7.5% senior secured notes due 2021, issued October 22,
2010
2022 First Lien Notes
The $750 million aggregate principal amount of 6.0% senior secured notes due 2022, issued October 31, 2013
2023 First Lien Notes
The
$1.2 billion aggregate principal amount of 7.875% senior secured notes due 2023, issued January 14, 2011
2023 Senior Unsecured Notes
The $1.25 billion aggregate principal amount of 5.375% senior unsecured notes due 2023, issued July 22, 2014
2024
First Lien Notes
The $490 million aggregate principal amount of 5.875% senior secured notes due 2024, issued October 31, 2013
2024 Senior Unsecured Notes
The $650 million aggregate principal amount of 5.5% senior unsecured notes due 2024, issued February 3, 2015
2025
Senior Unsecured Notes
The $1.55 billion aggregate principal amount of 5.75% senior unsecured notes due 2025, issued July 22, 2014
AB 32
California Assembly Bill 32
Adjusted
EBITDA
EBITDA as adjusted for the effects of (a) impairment charges, (b) major maintenance expense, (c) operating lease expense, (d) gains or losses on commodity derivative mark-to-market activity, (e) adjustments to reflect only the Adjusted EBITDA from our unconsolidated investments, (f) adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, (g) stock-based compensation expense, (h) gains or losses on sales, dispositions or retirements of assets, (i) non-cash gains and losses from foreign currency translations, (j) gains or losses on the repurchase or extinguishment of debt, (k) non-cash GAAP-related adjustments to levelize revenues from tolling agreements and (l) other extraordinary, unusual or non-recurring items
ii
ABBREVIATION
DEFINITION
AOCI
Accumulated Other Comprehensive Income
Average
availability
Represents the total hours during the period that our plants were in-service or available for service as a percentage of the total hours in the period
Average capacity factor, excluding peakers
A measure of total actual power generation as a percent of total potential power generation. It is calculated by dividing (a) total MWh generated by our power plants, excluding peakers, by (b) the product of multiplying (i) the average total
MW in operation, excluding peakers, during the period by (ii) the total hours in the period
Bcf
Billion cubic feet
Broad River
Broad River Energy LLC, formerly an indirect,
wholly-owned subsidiary of Calpine that leased the Broad River Energy Center, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina
Btu
British thermal unit(s), a measure of heat content
CAA
Federal
Clean Air Act, U.S. Code Title 42, Chapter 85
CAIR
Clean Air Interstate Rule
CAISO
California Independent System Operator
Calpine
Equity Incentive Plans
Collectively, the Director Plan and the Equity Plan, which provide for grants of equity awards to Calpine non-union employees and non-employee members of Calpine’s Board of Directors
Cap-and-Trade
A government imposed emissions reduction program that would place a cap on the amount of emissions that can be emitted from certain sources, such as power plants. In its simplest form, the cap amount is set as a reduction from the
total emissions during a base year and for each year over a period of years the cap amount would be reduced to achieve the targeted overall reduction by the end of the period. Allowances or credits for emissions in an amount equal to the cap would be issued or auctioned to companies with facilities, permitting them to emit up to a certain amount of emissions during each applicable period. After allowances have been distributed or auctioned, they can be transferred or traded
CARB
California Air Resources Board
CCFC
Calpine
Construction Finance Company, L.P., an indirect, wholly-owned subsidiary of Calpine
CCFC Notes
The $1.0 billion aggregate principal amount of 8.0% senior secured notes due 2016 issued May 19, 2009, by CCFC and CCFC Finance Corp.
CCFC Term Loans
Collectively,
the $900 million first lien senior secured term loan and the $300 million first lien senior secured term loan entered into on May 3, 2013, and the $425 million first lien senior secured term loan entered into on February 26, 2014, between CCFC, as borrower, and Goldman Sachs Lending Partners, LLC, as administrative agent and as collateral agent, and the lenders party thereto
CDHI
Calpine Development Holdings, Inc., an indirect, wholly-owned subsidiary of Calpine
CFTC
U.S.
Commodities Futures Trading Commission
Chapter 11
Chapter 11 of the U.S. Bankruptcy Code
CO2
Carbon dioxide
COD
Commercial
operations date
iii
ABBREVIATION
DEFINITION
Cogeneration
Using
a portion or all of the steam generated in the power generating process to supply a customer with steam for use in the customer's operations
Commodity expense
The sum of our expenses from fuel and purchased energy expense, fuel transportation expense, transmission expense, environmental compliance expense and realized settlements from our marketing, hedging and optimization activities including natural gas transactions hedging future power sales, but excludes our mark-to-market activity
Commodity
Margin
Non-GAAP financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities including natural gas transactions hedging future power sales, but excludes our mark-to-market activity and other revenues
Commodity revenue
The
sum of our revenues from power and steam sales, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and realized settlements from our marketing, hedging, optimization and trading activities, but excludes our mark-to-market activity
Company
Calpine Corporation, a Delaware corporation, and its subsidiaries
Corporate
Revolving Facility
The $1.5 billion aggregate amount revolving credit facility credit agreement, dated as of December 10, 2010, as amended on June 27, 2013 and July 30, 2014, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and the other parties thereto
CPUC
California
Public Utilities Commission
CSAPR
Cross-State Air Pollution Rule
D.C. Circuit
U.S. Court of Appeals for the District of Columbia Circuit
Director
Plan
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan
Dodd-Frank Act
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
EBITDA
Net
income (loss) attributable to Calpine before net (income) loss attributable to the noncontrolling interest, interest, taxes, depreciation and amortization
EIA
Energy Information Administration of the U.S. Department of Energy
EPA
U.S.
Environmental Protection Agency
Equity Plan
The Amended and Restated Calpine Corporation 2008 Equity Incentive Plan
ERCOT
Electric Reliability Council of Texas
EWG(s)
Exempt
wholesale generator(s)
Exchange Act
U.S. Securities Exchange Act of 1934, as amended
FASB
Financial Accounting Standards Board
FDIC
U.S.
Federal Deposit Insurance Corporation
FERC
U.S. Federal Energy Regulatory Commission
iv
ABBREVIATION
DEFINITION
First
Lien Credit Facility
Credit Agreement, dated as of January 31, 2008, as amended by the First Amendment to Credit Agreement and Second Amendment to Collateral Agency and Intercreditor Agreement, dated as of August 20, 2009, among Calpine Corporation, as borrower, certain subsidiaries of the Company named therein, as guarantors, the lenders party thereto, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, and the other agents named therein
First
Lien Notes
Collectively, the 2019 First Lien Notes, the 2020 First Lien Notes, the 2021 First Lien Notes, the 2022 First Lien Notes, the 2023 First Lien Notes and the 2024 First Lien Notes
First Lien Term Loans
Collectively, the 2018 First Lien Term Loans, the 2019 First Lien Term Loan and the 2020 First Lien Term Loan
FRCC
Florida
Reliability Coordinating Council
GE
General Electric International, Inc.
Geysers Assets
Our geothermal power plant assets, including our steam extraction and gathering assets,
located in northern California consisting of 15 operating power plants and one plant not in operation
GHG(s)
Greenhouse gas(es), primarily carbon dioxide (CO2), and including methane (CH4), nitrous oxide (N2O), sulfur hexafluoride (SF6), hydrofluorocarbons (HFCs) and perfluorocarbons (PFCs)
Greenfield
LP
Greenfield Energy Centre LP, a 50% partnership interest between certain of our subsidiaries and a third party which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant in Ontario, Canada
Heat Rate(s)
A measure of the amount of fuel required to produce a unit of power
Hg
Mercury
IRC
Internal
Revenue Code
IRS
U.S. Internal Revenue Service
ISO(s)
Independent System Operator(s)
ISO-NE
ISO
New England
KIAC
KIAC Partners, an indirect, wholly-owned subsidiary of Calpine that leases our Kennedy International Airport Power Plant, a 121 MW natural gas-fired, combined-cycle power plant located at John F. Kennedy International Airport in New York
KWh
Kilowatt
hour(s), a measure of power produced, purchased or sold
LIBOR
London Inter-Bank Offered Rate
LTSA(s)
Long-Term Service Agreement(s)
Market
Heat Rate(s)
The regional power price divided by the corresponding regional natural gas price
MATS
Mercury and Air Toxics Standard
MISO
Midwest
ISO
MMBtu
Million Btu
MRO
Midwest Reliability Organization
v
ABBREVIATION
DEFINITION
MW
Megawatt(s), a measure of plant capacity
MWh
Megawatt
hour(s), a measure of power produced, purchased or sold
NAAQS
National Ambient Air Quality Standards
NERC
North American Electric Reliability Council
NOL(s)
Net
operating loss(es)
NOx
Nitrogen oxides
NPCC
Northeast Power Coordinating Council
NYISO
New
York ISO
NYMEX
New York Mercantile Exchange
NYSE
New York Stock Exchange
OCI
Other
Comprehensive Income
OMEC
Otay Mesa Energy Center, LLC, an indirect, wholly-owned subsidiary of Calpine that owns the Otay Mesa Energy Center, a 608 MW natural gas-fired, combined-cycle power plant located in San Diego county, California
OTC
Over-the-Counter
PG&E
Pacific
Gas & Electric Company
PJM
PJM Interconnection is a RTO that coordinates the movement of wholesale electricity in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia
PPA(s)
Any
term power purchase agreement or other contract for a physically settled sale (as distinguished from a financially settled future, option or other derivative or hedge transaction) of any power product, including power, capacity and/or ancillary services, in the form of a bilateral agreement or a written or oral confirmation of a transaction between two parties to a master agreement, including sales related to a tolling transaction in which the purchaser provides the fuel required by us to generate such power and we receive a variable payment to convert the fuel into power and steam
PSD
Prevention
of Significant Deterioration
PUCT
Public Utility Commission of Texas
PUHCA 2005
U.S. Public Utility Holding Company Act of 2005
PURPA
U.S.
Public Utility Regulatory Policies Act of 1978
QF(s)
Qualifying facility(ies), which are cogeneration facilities and certain small power production facilities eligible to be “qualifying facilities” under PURPA, provided that they meet certain power and thermal energy production requirements and efficiency standards. QF status provides an exemption from the books and records requirement of PUHCA 2005 and grants certain other benefits to the QF
The measure of how much the total generating capacity installed in a region exceeds the peak demand for power in that region
RFC
Reliability First Corporation
RGGI
Regional
Greenhouse Gas Initiative
Risk Management Policy
Calpine's policy applicable to all employees, contractors, representatives and agents which defines the risk management framework and corporate governance structure for commodity risk, interest rate risk, currency risk and other risks
Collectively, the 2023 Senior Unsecured Notes, the 2024 Senior Unsecured Notes and the 2025 Senior Unsecured Notes
SERC
Southeastern Electric Reliability Council
SO2
Sulfur
dioxide
Spark Spread(s)
The difference between the sales price of power per MWh and the cost of natural gas to produce it
Steam Adjusted Heat Rate
The adjusted Heat Rate for our
natural gas-fired power plants, excluding peakers, calculated by dividing (a) the fuel consumed in Btu reduced by the net equivalent Btu in steam exported to a third party by (b) the KWh generated. Steam Adjusted Heat Rate is a measure of fuel efficiency, so the lower our Steam Adjusted Heat Rate, the lower our cost of generation
TCEQ
Texas Commission on Environmental Quality
TRE
Texas
Reliability Entity, Inc.
TSR
Total shareholder return
U.S. GAAP
Generally accepted accounting principles in the U.S.
VAR
Value-at-risk
VIE(s)
Variable
interest entity(ies)
WECC
Western Electricity Coordinating Council
Whitby
Whitby Cogeneration Limited Partnership, a 50% partnership interest between certain of our subsidiaries
and a third party which operates Whitby, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada
WP&L
Wisconsin Power & Light Company
vii
Forward-Looking Statements
In
addition to historical information, this Report contains “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act, and Section 21E of the Exchange Act. Forward-looking statements may appear throughout this Report, including without limitation, the “Management’s Discussion and Analysis” section. We use words such as “believe,”“intend,”“expect,”“anticipate,”“plan,”“may,”“will,”“should,”“estimate,”“potential,”“project” and similar expressions to identify forward-looking statements. Such statements include, among others, those concerning our expected financial performance and strategic and operational plans, as well as all assumptions, expectations, predictions, intentions or beliefs about future events. You are cautioned that any such forward-looking statements are not guarantees of future
performance and that a number of risks and uncertainties could cause actual results to differ materially from those anticipated in the forward-looking statements. Such risks and uncertainties include, but are not limited to:
•
Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks;
•
Laws,
regulations and market rules in the markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;
•
Our ability to manage our liquidity needs, access the capital markets when necessary and to comply with covenants under our First Lien Notes, Senior Unsecured Notes, Corporate Revolving Facility, First Lien Term Loans, CCFC Term Loans and other existing financing obligations;
•
Risks
associated with the operation, construction and development of power plants including unscheduled outages or delays and plant efficiencies;
•
Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;
•
Competition,
including risks associated with marketing and selling power in the evolving energy markets;
•
Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);
•
The expiration or early termination of our PPAs and the related results on revenues;
•
Future
capacity revenues may not occur at expected levels;
•
Natural disasters, such as hurricanes, earthquakes and floods, acts of terrorism or cyber attacks that may impact our power plants or the markets our power plants serve and our corporate headquarters;
•
Disruptions in or limitations on the transportation of natural gas, fuel oil and transmission of power;
•
Our
ability to manage our customer and counterparty exposure and credit risk, including our commodity positions;
•
Our ability to attract, motivate and retain key employees;
•
Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and
•
Other
risks identified in this Report.
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.
1
Where You Can Find Other Information
Our website
is www.calpine.com. Information contained on our website is not part of this Report. Information that we furnish or file with the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to, or exhibits included in, these reports are available for download, free of charge, on our website soon after such reports are filed with or furnished to the SEC. Our SEC filings, including exhibits filed therewith, are also available at the SEC’s website
at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC’s public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC’s public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.
2
PART I
Item
1.
Business
BUSINESS AND STRATEGY
Business
We are a premier wholesale power producer with 88 power plants, including one under construction, located in competitive wholesale power markets primarily in the U.S. We measure our success by delivering long-term shareholder value. We accomplish this through our focus on operational excellence at our power plants and in our commercial activity and on a disciplined approach to capital allocation that includes investing in growth, returning money to shareholders through share repurchases, while prudently managing our balance sheet.
Our capital allocation philosophy seeks to maximize levered cash returns to equity on a per share basis. We currently consider the repurchases
of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders.
We are one of the largest power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast region(included in our East segment) of the U.S. Since our inception in 1984, we have been a leader in environmental stewardship. We have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible
portfolio of power plants. Our portfolio is primarily comprised of two types of power generation technologies: natural gas-fired combustion turbines, which are primarily efficient combined-cycle plants, and renewable geothermal conventional steam turbines. We are among the world’s largest owners and operators of industrial gas turbines as well as cogeneration power plants. Our Geysers Assets located in northern California represent the largest geothermal power generation portfolio in the U.S. and produced approximately 15% of all renewable energy in the state of California during 2013.
We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We purchase primarily natural gas and some fuel oil as fuel for
our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power and other physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
Our portfolio, including partnership interests, consists of 88 power plants, including one under construction, located throughout 18 states in the U.S. and in Canada, with an aggregate generation capacity of 26,548 MW and 309 MW under construction. Our fleet, including projects under construction, consists of 71 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 15 geothermal steam turbine-based plants and one photovoltaic solar
plant. In 2014, our fleet of power plants produced approximately 103 billion KWh of electric power for our customers. In addition, we are one of the largest consumers of natural gas in North America. In 2014, we consumed 793 Bcf or approximately 10% of the total estimated natural gas consumed for power generation in the U.S.
We believe our unique fleet compares favorably with those of our major competition on a cost basis, an environmental basis, and a scale and geographical diversity basis. The discovery and exploitation of natural gas from shale combined with our modern and efficient combined-cycle plants has created short-term and long-term advantages. In the short-term, we are often the lowest cost resource to dispatch compared to other fuel types as demonstrated in 2012 and in 2013 when we realized meaningfully higher capacity factors than we have historically given our ability to displace other fuel types and older technologies.
In the long-term, when compared on a full life-cycle cost, we believe our power plants will be even more competitive when considering the greater non-fuel operating costs and potential environmental liabilities associated with other technologies.
The environmental profile of our power plants reflects our commitment to environmental leadership and stewardship. We have invested the capital necessary to develop a power generation portfolio that has substantially lower air emissions compared to our major competitors’ power plants that use other fossil fuels, such as coal. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, our combined-cycle power plants use cooling towers with a closed water cooling system or air cooled condensers and do not employ “once-through” water cooling, which uses large quantities of water from adjacent waterways, negatively impacting aquatic life.
Since our plants are modern and efficient and utilize cleaner 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
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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 existing and potential legislation or regulation addressing GHG or other emissions, water use or waste disposal, compared to our competitors who use other fossil fuels or older, less efficient technologies.
Our scale provides the opportunity to have meaningful regulatory input, to leverage our procurement efforts for better pricing, terms and conditions on our
goods and services, and to develop and offer a wide array of products and services to our customers. Finally, geographic diversity helps us manage and mitigate the impact of weather, regulatory and regional economic differences across our markets to provide more consistent financial performance.
Our principal offices are located in Houston, Texas with regional offices in Dublin, California and Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena, Texas and government affairs offices in Washington D.C., Sacramento, California and Austin, Texas. We operate our business through a variety of divisions, subsidiaries and affiliates.
Strategy
Our goal
is to be recognized as the premier power generation company in the U.S. as measured by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located. We seek to achieve sustainable growth through financially disciplined power plant development, construction, acquisition, operation and ownership. Our strategy to achieve this is reflected in the following five major initiatives listed below and subsequently described in further detail:
•Focus on remaining a premier operating company;
•Focus on managing and growing our portfolio;
•Focus on our customer-oriented origination business;
•Focus on advocacy and corporate responsibility; all of which culminate
in
•Focus on enhancing shareholder value.
1.
Focus on Remaining a Premier Operating Company — Our objective is to be the “best-in-class” in regards to certain operational performance metrics, such as safety, availability, reliability, efficiency and cost management.
•
During 2014, our employees achieved a lost time incident rate of 0.08 lost time injuries per 100 employees which places us in the first quartile performance for power generation
companies with 1,000 or more employees.
•
Our entire fleet achieved a forced outage factor of 1.9% and a starting reliability of 98.6% during the year ended December 31, 2014.
•
During 2014, our outage services subsidiary completed 14 major inspections and nine hot gas path inspections.
•
For
the past 14 consecutive years, our Geysers Assets have reliably generated approximately six million MWh of renewable power per year.
2.
Focus on Managing and Growing our Portfolio — Our goal is to continue to grow our presence in core markets with an emphasis on acquisitions, expansions or modernizations of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts
and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively. In addition, we believe that modernizations and expansions of our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. During 2014, we strategically repositioned our portfolio by divesting positions in non-core markets and adding capacity in our core regions through the following transactions:
•
On February 26, 2014, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with a nameplate capacity of 1,050
MW located in Guadalupe County, Texas for approximately $625 million, excluding working capital adjustments, which increased capacity in our Texas segment. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker plant. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission).
4
•
In June 2014, we completed construction
to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency at a meaningful discount to the market cost of building new capacity.
•
On July 3, 2014, we completed the sale of six of our power plants in our East segment for a purchase price of approximately $1.57 billion in cash, excluding working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.
•
On
November 7, 2014, we completed the purchase of Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant located in North Weymouth, Massachusetts, increased capacity in our East segment, specifically in the constrained New England market.
•
During the third quarter of 2014, we executed a PPA with Duke Energy Florida, Inc. related to our Osprey Energy Center with a term of 27 months which commenced in October 2014. Subsequently, we
executed an asset sale agreement during the fourth quarter of 2014 for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. upon the conclusion of the PPA for approximately $166 million, excluding working capital and other adjustments. The asset sale agreement is subject to federal and state regulatory approval and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.
In addition, our significant ongoing projects under construction, growth initiatives and modernizations are discussed below:
•
Garrison Energy Center — Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site
secured by a long-term lease with the City of Dover. Once complete, the power plant will feature one combustion turbine, one heat recovery steam generator and one steam turbine. Construction commenced in April 2013, and we expect COD during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility, system impact and facilities studies for this phase. The facilities study results are being internally evaluated.
•
York 2 Energy Center — York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy
Center in Peach Bottom Township, Pennsylvania. Once complete, the power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 base residual auction and we expect COD during the second quarter of 2017. We executed a preliminary notice to proceed for the engineering, procurement and construction agreement during the fourth quarter of 2014 and are currently pursuing key permits and approvals for the project. PJM is completing a feasibility study for increasing York 2 Energy Center’s capacity by 120 MW.
•
Mankato Power Plant Expansion — By order dated February 5, 2015, the Minnesota
Public Utilities Commission concluded a competitive resource acquisition proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. Commercial operation of the expanded capacity may commence as early as June 2018, subject to applicable regulatory approvals and other contract conditions.
•
PJM Development Opportunities — We are currently evaluating opportunities to develop additional projects in the PJM market area that feature cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing
to advance entitlements (such as permits, zoning and transmission) for their potential future development.
•
Turbine Modernization — We continue to move forward with our turbine modernization program. Through December 31, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at certain of our power plants in our East segment.
3.
Focus
on our Customer-Oriented Origination Business — We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant contracts entered into in 2014 is as follows:
West
•
We entered into a new ten-year PPA, subject to approval by the CPUC, with Southern California Edison (“SCE”) to provide 225 MW of capacity and renewable energy from our Geysers Assets commencing in June 2017.
5
•
We
entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 15 MW of renewable power from our Geysers Assets commencing in January 2017. The capacity under contract will vary by year, increasing up to a maximum of 50 MW for years 2024 through 2026.
•
We entered into a new three-year resource adequacy contract with SCE for our Pastoria Energy Facility commencing in January 2016. The capacity under contract will initially be 238 MW, and will increase to 476
MW during the final year of the contract.
•
We entered into a new two-year resource adequacy contract with SCE for our Delta Energy Center for 500 MW of capacity commencing in January 2017.
Texas
•
We entered into a new six-year PPA with the City of San Marcos to provide power from our Texas power
plant fleet commencing in July 2015.
•
We entered into a new two-year PPA with Pedernales Electric Cooperative to provide approximately 70 MW of power from our Texas power plant fleet commencing in August 2016.
•
We entered into a new one-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power from our Texas power plant fleet commencing in June 2016.
East
•
We
entered into a new five-year PPA with Dairyland Power Cooperative to provide capacity and energy from our RockGen Energy Center commencing in June 2018. The capacity under contract will initially be 135 MW, and then will increase to 235 MW for the final four years of the contract.
•
We entered into a new PPA with a term of 27 months with Duke Energy Florida, Inc. to provide 515 MW of power and capacity from our Osprey Energy Center, which commenced in October 2014. The capacity under contract
increased to 580 MW beginning in January 2015.
4.
Focus on Advocacy and Corporate Responsibility — We recognize that our business is heavily influenced by laws, regulations and rules at federal, state and local levels as well as by ISOs and RTOs that oversee the competitive markets in which we operate. We believe that being active participants in the legislative, regulatory and rulemaking processes may yield better outcomes for all stakeholders, including Calpine. Our two basic areas of focus are environmental stewardship in power generation and competitive wholesale power markets. Below are some recent examples of our advocacy efforts:
Ensuring Competitive
Market Structure/Rules
•
Provided leadership in stakeholder processes at PJM on a new “Capacity Performance” product and at ISO-NE on its Pay-For-Performance initiatives, resulting in pending FERC approval of the PJM Capacity Performance product and implementation of the FERC approved ISO-NE Pay-For-Performance capacity structure.
•
Our employees participated as invited panelists at FERC technical conferences regarding price formation and “out-of-market payments” in organized markets.
Stopping
Non-Competitive/Subsidized Generation
•
Successfully advocated for a competitive generation supply bidding process in Florida, resulting in a contract for the acquisition of our Osprey Energy Center rather than a utility self-build as the most cost effective alternative for Florida ratepayers.
•
Successfully advocated for a competitive generation supply bidding process in Minnesota, resulting in an order requiring the local utility to enter into
a long-term PPA for new additional capacity at our Mankato Power Plant rather than a utility self-build as the most cost effective alternative for Minnesota ratepayers.
•
Provided leadership in the successful legal challenges against New Jersey and Maryland for discriminatory behavior affecting FERC jurisdictional capacity auctions, resulting in decisions by the U.S. Circuit Court of Appeals for the Third and Fourth Circuits striking those state actions as violative of U.S. law.
•
Successfully advocated against proposed
legislation in California requiring investor owned utilities to contract for 500 MW of new geothermal resources that would have discriminated against our existing geothermal fleet.
Environmental
•
Filed a brief with the D.C. Circuit supporting the EPA’s MATS rules which were upheld by the Court.
•
Filed a brief with the U.S. Supreme Court supporting the EPA’s CSAPR rules which were upheld
by the Court citing our brief in its opinion.
6
•
Filed a brief with the U.S. Supreme Court supporting the EPA’s GHG air permit rules which were upheld in part by the Court citing our brief in its opinion.
5.
Focus on Enhancing Shareholder Value — We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder
value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet for future growth and success. Given our strong cash flow from operations, we are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2014 was marked by the following accomplishments:
•
We delivered annual TSR of 13.4%, in line with the S&P 500 Index.
•
We continued to return capital
to our shareholders in the form of share repurchases, having cumulatively repurchased approximately $2.4 billion or 25% of our previously outstanding shares as of the filing of this Report.
•
Specifically during 2014, we repurchased a total of 49.7 million shares of our outstanding common stock for approximately $1.1 billion at an average price of $22.14 per share.
•
In 2015, through
the filing of this Report, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share.
We further optimized our capital structure by refinancing or redeeming several of our debt instruments during the year ended December 31, 2014, including the following transactions:
•
During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January
2, 2018.
•
On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. We used the proceeds to repurchase secured debt with a higher fixed interest rate.
•
On
July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
•
In December 2014, we used cash on hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest.
THE MARKET FOR POWER
Our Power Markets and Market Fundamentals
The power industry represents one of the largest industries in the U.S. and impacts nearly every aspect of our economy, with an estimated
end-user market of approximately $388 billion in power sales in 2014 according to the EIA. Historically, vertically integrated power utilities with monopolies over franchised territories dominated the power generation industry in the U.S. Over the last 25 years, industry trends and legislative and regulatory initiatives, culminating with the deregulation trend of the late 1990’s and early 2000’s, provided opportunities for wholesale power producers to compete to provide power. Although different regions of the country have very different models and rules for competition, the markets in which we operate have some form of wholesale market competition. California (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment), which are the markets in which we have our largest presence, have emerged as among the most competitive wholesale power markets in the U.S. We also operate, to a lesser extent, in the competitive
wholesale power markets in the Southeast and the Midwest. In addition to our sales of electrical power and steam, we produce several ancillary products for sale to our customers.
•
First, we are a wholesale provider of power to utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities and power marketers. Our power sales occur in several different product categories including baseload (around the clock generation), intermediate (generation typically more expensive than baseload and utilized during higher demand periods to meet shifting demand needs), and peaking energy (most expensive variable cost and utilized during the highest demand periods), for which the latter is provided by some of our
stand-alone peaking power plants/units and from our combined-cycle power plants by using technologies such as steam injection or duct firing additional burners in the heat recovery steam generators. Many of our units have operated more frequently as baseload units at times when low natural gas prices have driven their production costs below those of some competing coal-fired units.
•
Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers (or independent electric system operators on their behalf) are required to demonstrate adequate resources to meet their power sales commitments. To meet this obligation, they procure a
7
market product known as capacity from power plant owners or resellers. Most electricity market administrators have acknowledged that an energy only market does not provide sufficient revenues to enable existing merchant generators to recover all of their costs or to encourage the construction of new power plants. Capacity auctions have been implemented in the Northeast and certain Midwest regional markets to address this issue. California has a bilateral capacity program. Texas does not presently have a capacity market or a requirement for retailers to ensure adequate resources.
•
Third, we sell RECs from our Geysers Assets in northern
California, as well as from our small solar power plant in New Jersey. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state or in neighboring areas. Because geothermal is a renewable source of energy, we receive a REC for each MWh we produce and are able to sell our RECs to load serving entities. New Jersey has a solar specific RPS which enables us to sell RECs from a 4 MW photovoltaic solar generation facility located in Vineland, New Jersey.
•
Fourth, our cogeneration power plants produce steam, in addition to electricity, for sale to industrial customers for use in their manufacturing processes or
heating, ventilation and air conditioning operations.
•
Fifth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid. For example, we are sometimes paid to reserve a portion of capacity at some of our power plants that could be deployed quickly should there be an unexpected increase in load or to assure reliability due to fluctuations in the supply of power from variable renewable resources such as wind and solar generation. These ramping characteristics are becoming increasingly necessary in markets where intermittent renewables have large penetrations.
In
addition to the five products above, we are buyers and sellers of emission allowances and credits, including those under California’s AB 32 GHG reduction program, RGGI, the federal Acid Rain and CSAPR programs and emission reduction credits under the federal Nonattainment New Source Review program.
Although all of the products mentioned above contribute to our financial performance and are the primary components of our Commodity Margin, the most important are our sales of wholesale power and capacity. We utilize long-term customer contracts for our power and steam sales where possible. For power and capacity that are not sold under customer contracts or longer-dated capacity auctions, we use our hedging program and sell power into shorter term wholesale
markets throughout the regions in which we participate.
When selling 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 rational economic behavior by market participants, generating units generally are dispatched in order of their variable costs, with lower cost units being dispatched first and units with higher costs dispatched as demand, or “load,” grows beyond the capacity of the lower cost units. For this reason, in a competitive market, the price of power typically is related to the variable operating costs of the marginal generator, which is the last unit to be dispatched in order to meet demand. The factors that most significantly impact our operations are reserve margins in each of our markets, the price and supply of natural gas and competing fuels such as coal and oil, weather patterns and natural
events, our operating Heat Rate, availability factors, and regulatory and environmental pressures as further discussed below.
Reserve Margins
Reserve margin, a measure of excess generation capacity in a market, is a key indicator of the competitive conditions in the markets in which we operate. For example, a reserve margin of 15% indicates that supply is 115% of expected peak power demand under normal weather and power plant operating conditions. Holding other factors constant, lower reserve margins typically lead to higher power prices because the less efficient capacity in the region is needed more often to satisfy power demand or voluntary or involuntary load shedding measures are taken. Markets with tight demand and supply conditions often display price spikes, higher capacity prices and improved bilateral contracting opportunities. Typically, the market price impact of reserve
margins, as well as other supply/demand factors, is reflected in the Market Heat Rate, calculated as the local market power price divided by the local natural gas price.
During the last decade, the supply and demand fundamentals in some regional markets have been negatively impacted by the combination of new generation coming on line and a general decline in weather normalized load growth rates due to the economic recession, energy efficiency measures and the installation of small generating facilities (such as rooftop solar) at some customer sites. Although uncertainty exists and there are key regional differences, at a macro level, continued economic recovery and thus, corresponding net load recovery, with the lack of broad new power plant investments and the retirement of older, uneconomic units in our key markets should lead to lower reserve margins and higher Market Heat Rates. Reserve margins by NERC regional assessment
area for each of our segments are listed below:
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2014(1)
West:
WECC
29.9
%
Texas:
TRE
15.0
%
East:
NPCC
23.6
%
MISO
15.0
%
PJM
25.3
%
SERC
29.3
%
FRCC
29.0
%
___________
(1)
Data
source is NERC weather-normalized estimates for 2014 published in May 2014.
In recent years and in some regional markets such as PJM, the ability of customers to curtail load or temporarily utilize onsite backup generation instead of grid-provided electricity, known as “demand response,” has become a meaningful portion of “supply” and thus contributes to reserve margin estimates. While demand response reduces demand for centralized generation during peak times, it typically does so at a very high variable cost. To the extent demand response resources are treated like other sources of supply (e.g., their variable cost-based bids are allowed to affect the market clearing price for power), high resulting prices benefit lower-cost units like Calpine’s. Further, in many cases demand response has acted to discourage new investment in competing centralized generation plants (for example, by winning
capacity auctions instead of new units). This may contribute to higher energy price volatility during peak energy demand periods.
The Price and Supply of Natural Gas
Approximately 95% of our generating capability’s fuel requirements are met with natural gas. We have approximately 725 MW of baseload capacity from our Geysers Assets and our expectation is that the steam reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future as our steam flow decline rates have become very small over the past several years. We also have approximately 562 MW of capacity from power plants where we purchase fuel oil to meet generation requirements, but generally do not expect fuel oil requirements to be material to our portfolio of power plants. In our East segment, where the supply of natural gas can be constrained under some weather circumstances,
we have approximately 6,200 MW of dual-fueled capable power plants. Additionally, we have 4 MW of capacity from solar power generation technology with no fuel requirement.
We procure natural gas from multiple suppliers and transportation and storage sources. Although availability is generally not an issue, localized shortages (especially in extreme weather conditions in and around population centers), transportation availability and supplier financial stability issues can and do occur. When natural gas supply interruptions do occur, some of our power plants benefit from the ability to operate on fuel oil instead of natural gas.
Lower natural gas prices over the past five years have had a significant impact on power markets. Beginning in 2009, there was a significant decrease in NYMEX Henry Hub natural gas prices from a range of $6/MMBtu — $13/MMBtu during 2008 to an average natural
gas price of $2.83/MMBtu, $3.73/MMBtu, and $4.26/MMBtu during 2012, 2013 and 2014, respectively. Natural gas prices in some parts of the country for parts of 2012 and 2013 were low enough that modern, combined-cycle, natural gas-fired generation became less expensive on a marginal basis than coal-fired generation. The result was that natural gas displaced coal as a less expensive generation resource resulting in what the industry describes as coal-to-gas switching, the effects of which can be seen in our increased generation volumes, particularly in 2012. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant). Recent forward market natural gas prices suggest that coal-to-gas-switching
could increase again during 2015 (although future market conditions are uncertain and settled prices remain to be seen).
The availability of non-conventional natural gas supplies, in particular shale natural gas, has been the primary driver of reduced natural gas prices in the last few years. Access to significant deposits of shale natural gas has altered the natural gas supply landscape in the U.S. and could have a longer-term and profound impact on both the outright price of natural gas and the historical regional natural gas price relationships (basis differentials). The U.S. Department of Energy estimates that shale natural gas production has the potential of 3 trillion to 4 trillion cubic feet per year and may be sustainable for decades with enough natural gas to supply the U.S. for the next 90 years. Despite moderate increases in natural gas prices and some significant, weather induced
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regional price spikes last winter, there is an emerging view that lower priced natural gas will be available for the medium to long-term future. Further, high levels of natural gas production relative to available pipeline export capacity in some locations such as the Marcellus shale production region have put additional, seasonal downward pressure on local natural gas prices. Overall, low natural gas prices and corresponding low power prices have challenged the economics of nuclear and coal-fired plants, leading to numerous announced and potential unit retirements.
The price of natural gas, economic growth and environmental regulations affect our Commodity Margin and liquidity. The impact of changes in natural gas prices differs according to the time horizon and regional market conditions and depends
on our hedge levels and other factors discussed below.
Much of our generating capacity is located in California (included in our West segment), Texas (included in our Texas segment) and the Northeast (included in our East segment) where natural gas-fired units set power prices during many hours. When natural gas is the price-setting fuel (i.e. natural gas prices are above coal prices in our Texas or East segments), increases in natural gas prices may increase our unhedged Commodity Margin because our combined-cycle power plants in those markets are more fuel-efficient than conventional natural gas-fired technologies and peaking power plants. Conversely, decreases in natural gas prices may decrease our unhedged Commodity Margin. In these instances, our cost of production advantage relative to less efficient natural gas-fired generation is diminished on an absolute basis. Additionally, in the Northeast region, we have generating
units capable of burning either natural gas or fuel oil. For these units, on the rare occasions when the cost of consuming natural gas is excessively high relative to fuel oil, our unhedged Commodity Margin may increase as a result of our ability to use the lower cost fuel.
Where we operate under long-term contracts, changes in natural gas prices can have a neutral impact on us in the short-term. This tends to be the case where we have entered into tolling agreements under which the customer provides the natural gas and we convert it to power for a fee, or where we enter into indexed-based agreements with a contractual Heat Rate at or near our actual Heat Rate for a monthly payment.
Changes in natural gas prices or power prices may also affect our liquidity. During periods of high or volatile
natural gas prices, we could be required to post additional cash collateral or letters of credit.
Despite these short-term dynamics, over the long-term, we expect lower natural gas prices to enhance the competitiveness of our modern, natural gas-fired fleet by making investment in other technologies such as coal, nuclear or renewables less economic and, in fact, making it more challenging for existing generation resources that utilize such technology to continue operating economically.
During the second half of 2014, global oil prices declined significantly. Brent crude oil (a commonly cited global oil index) spot prices fell from a 2014 high of $115 per barrel on June 19th to a price of $55 per barrel by the end of the year (per the EIA). Since U.S. power and natural gas prices are generally not linked to oil prices, the oil market shift has not been material to our financial performance.
The impact going forward will also likely not be material to our financial performance. While lower oil prices may lead to lower oil extraction and lower power demand in some parts of the U.S., such as North Dakota and Texas, lower oil prices are generally considered a boon to economic growth more broadly, which typically contributes to higher electricity demand.
Weather Patterns and Natural Events
Weather generally has a significant short-term impact on supply and demand for power and natural gas. Historically, demand for and the price of power is higher in the summer and winter seasons when temperatures are more extreme, and therefore, our unhedged revenues and Commodity Margin could be negatively impacted by relatively cool summers or mild winters. However, our geographically diverse portfolio mitigates the impact on our Commodity Margin of weather in specific regions of the U.S.
Additionally, a disproportionate amount of our total revenue is usually realized during the summer months of our third fiscal quarter. We expect this trend to continue in the future as U.S. demand for power generally peaks during this time.
Operating Heat Rate and Availability
Our fleet is modern and more efficient than the average generation fleet; accordingly, we run more and earn incremental margin in markets where less efficient natural gas units frequently set the power price. In such cases, our unhedged Commodity Margin is positively correlated with how much more efficient our fleet is than our competitors’ fleets and with higher natural gas prices. Efficient operation of our fleet creates the opportunity to capture Commodity Margin. However, unplanned outages during periods when Commodity Margin is positive can result in a loss of that opportunity. We measure our fleet performance
based on our operating Heat Rate and availability factors. The higher our availability factor, the better positioned we are to capture Commodity Margin. The lower our operating Heat Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin.
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Regulatory and Environmental Trends
We believe that, on balance, we will be favorably impacted by current regulatory and environmental trends, including those described below, given the characteristics of our power plant portfolio:
•
Economic pressures continue
to increase for coal-fired power generation as state and federal agencies enact environmental regulations to reduce air emissions of certain pollutants such as SO2, NOX, GHG, Hg and acid gases, restrict the use of once-through cooling, and provide for stricter standards for managing coal combustion residuals. We anticipate that older, less efficient fossil-fuel power plants that emit much higher amounts of GHG, SO2, NOX, Hg and acid gases, which operate nationwide, but more prominently in the eastern U.S., will be negatively impacted by current and future air emissions, water and waste regulations and legislation both at the state and federal levels which will require many coal-fired power plants to install expensive air pollution controls or reduce or discontinue operations. As a result,
any retirements or curtailments could enhance our growth opportunities through greater utilization of our existing power plants and development of new power plants. The estimated capacity for fossil-fueled plants older than 50 years and the total estimated capacity for fossil-fueled plants by NERC region are as follows:
Generating Capacity Older Than 50 years
Total
Generating Capacity
West:
WECC
9,164
MW
132,408
MW
Texas:
TRE
3,045
MW
85,277
MW
East:
NPCC
7,582
MW
56,770
MW
MRO
5,041
MW
46,226
MW
RFC
25,082
MW
192,534
MW
SERC
26,714
MW
232,364
MW
FRCC
288
MW
60,032
MW
Total
76,916
MW
805,611
MW
•
An
increase in power generated from renewable sources could lead to an increased need for flexible power that many of our power plants provide to protect the reliability of the grid and premium compensation for that flexibility; however, risks also exist that renewables have the ability to lower overall wholesale prices which could negatively impact us. Significant economic and reliability concerns for renewable generation have been raised, but we expect that renewable market penetration will continue, assisted by state-level renewable portfolio standards and federal tax incentives. Should wind and solar generation continue to expand, our energy margin may decrease. To the extent market structures evolve to appropriately compensate units for providing flexible capacity to ensure reliability, our capacity revenues are likely to increase, providing an offset to reduced energy margin.
•
One
small but growing source of competing renewable generation in some of our regional markets (primarily California) is customer-sited (primarily rooftop) solar generation. Levelized costs for solar installation have fallen significantly over the past several years, aided by federal tax subsidies and other local incentives, and are now in some regions lower than customer retail electric rates. To the extent on-site solar generation is compensated at the full retail rate (an increasingly controversial policy known as “net energy metering”), rooftop solar installations may continue to grow. Should net energy metered solar installations remain capped at relatively low levels of penetration or net energy metering policies be weakened (by rate structure reforms that charge customers fixed amounts regardless of the level of electricity consumed, thus lowering the variable portion of the rates), rooftop solar growth might diminish. Absent incentives and supportive policies,
rooftop solar is currently generally not competitive with wholesale power.
•
The regulators in our core markets remain committed to the competitive wholesale power model, particularly in Texas and PJM where they continue to focus on market design and rules to assure the long-term viability of competition and the benefits to customers that justify competition.
•
Utilities are increasingly focused on demand side management – managing the level and timing of power usage through load curtailment, dispatching generators located
at commercial or industrial sites, and “smart grid” technologies that may improve the efficiencies, dispatch usage and reliability of electric grids. Scrutiny of demand side resources has increased recently as system operators evaluate their reliability (especially at high levels of
11
penetration) and environmental authorities deal with the implications of relying on smaller, less environmentally efficient generation sources during periods of peak demand when air quality is already challenged. Further, the way in which demand side resources might participate in the electricity markets going forward has become less clear due to the recent FERC Order No. 745 reversal (see further discussion in “— Governmental and Regulatory Matters.”)
•
Environmental
permitting requirements for new power plants, transmission lines and pipelines continue to increase in stringency and complexity, resulting in prolonged, expensive development cycles and high capital investments.
We believe these trends are overall positive for our existing fleet. For a discussion of federal, state and regional legislative and regulatory initiatives and how they might affect us, see “— Governmental and Regulatory Matters.”
It is very difficult to predict the continued evolution of our markets due to the uncertainty of the following:
•
number of market participants, both in terms of physical presence as well as contribution toward financial
market liquidity;
•
amount of generation capacity 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, which could be impacted by the efficiency of generation technology and fluctuations in fuel supply or interruptions in natural gas transportation;
•
relative ease or difficulty of developing, permitting and constructing new power plants;
•
availability and cost of power transmission;
•
potential
growth of demand side management, customer-sited solar generation and electricity storage devices;
•
creditworthiness and other risks associated with counterparties;
•
bidding behavior of market participants;
•
regulatory and ISO guidelines and rules;
•
structure
of commercial products; and
•
ability to optimize the market’s mix of alternative sources of power such as renewable and hydroelectric power.
Competition
Wholesale power generation is a capital-intensive, commodity-driven business with numerous industry participants. We compete against other independent power producers, power marketers and trading companies, including those owned by financial institutions, retail load aggregators, municipalities, retail power providers, cooperatives and regulated utilities to supply power and power-related products to our customers in major markets in the U.S. and Canada. In addition, in some markets, we
compete against some of our customers.
In markets with centralized ISOs, such as California, Texas and the Northeast, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2014, 27% of the power generated in the U.S. was fueled by natural gas, 39% by coal, 19% by nuclear facilities and the remaining 15% of power generated by hydroelectric, fuel oil, geothermal and other energy sources. We are subject to complex and stringent energy, environmental and other governmental laws and regulations at the federal, state and local levels in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change. The federal government is continuing to take further action on many air pollutant emissions such as NOX, SO2,
Hg and acid gases as well as on once-through cooling and coal ash disposal. Although we cannot predict the ultimate effect any future environmental legislation or regulations will have on our business, as a clean energy provider, we believe that we are well positioned for almost any increase in environmental rule stringency. We are actively participating in these debates at the federal, regional and state levels. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters.”
With new environmental regulations, the proportion of power generated by natural gas and other low emissions resources is expected to increase because older coal-fired power plants will be required to install costly emissions control devices, limit their operations or retire. 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, could increase in the future, but likely at a lower rate than had been previously expected. The nuclear incident in March 2011 at the Fukushima Daiichi nuclear power plant introduced substantial uncertainties around new nuclear power plant development in the U.S. The nuclear projects that are currently under construction in the U.S. are experiencing cost overruns and delays. Low power prices are even challenging the economics of existing nuclear facilities, resulting in the retirement or potential retirement of certain existing nuclear generating
units.
Federal and state financial incentives and RPS requirements continue to foster renewables development. However, the production tax credit for wind expired at the end of 2014 (although power plants that were “under construction” by the end of 2014 and reach commercial operations by the end of 2016 can still secure the credits), and for solar, the investment tax credit declines significantly at the end of 2016. Unless the tax credits are extended, renewables development costs decline, and/or natural gas prices increase substantially from today’s levels, competition from new renewables will likely diminish. Beyond economic issues, there are concerns over the reliability and adequacy of transmission infrastructure to transmit certain renewable generation from its source to where it is needed. Consequently, long-term, natural gas units are likely still needed as baseload and “back-up” generation.
We
believe our ability to compete will be driven by the extent to which we are able to accomplish the following:
•
provide affordable, reliable services to our customers;
•
maintain excellence in operations;
•
achieve and maintain a lower cost of production, primarily by maintaining unit availability, efficiency and
production cost management;
•
accurately assess and effectively manage our risks; and
•
accomplish all of the above with an environmental impact lower than the competition, and further decreasing over time.
MARKETING, HEDGING AND OPTIMIZATION ACTIVITIES
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity
Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. Additionally, we seek strong bilateral relationships with load serving entities that can benefit us and our customers.
The majority of our risk exposures arise from our ownership and operation of power plants. Our primary risk exposures are Spark Spread, power prices, natural gas prices, capacity prices, locational price differences in power and in natural gas, natural gas transportation, electric transmission, REC prices, carbon allowance prices in California and other emissions credit prices. In addition to the direct risk exposure to commodity prices, we also have general market risks such as risk related to performance of our counterparties and customers and plant operating performance risk. We also have a small exposure to Canadian exchange rates due to our partial ownership of Greenfield LP and Whitby located in Canada, which
are under long term contracts, and minimal fuel oil exposure which are not currently material to our operations. As such, we have currently elected not to hedge our Canadian exchange rate and have only hedged our fuel oil exposure through anticipatory purchases of fuel oil inventory.
We produced approximately 103 billion KWh of electricity in 2014 across North America (primarily in the U.S.). We are one of the largest consumers of natural gas in North America having consumed approximately 793 Bcf during 2014. The three primary power markets in which we conduct our operations are California (included in our West segment), Texas (included in our Texas segment) and the Northeast (included in our East segment) which have centralized markets for which power demand and prices are determined on a spot basis (day ahead and real time). Most of
the power generated by our power plants is sold to entities such as independent electric system operators, utilities, municipalities and cooperatives, as well as to retail power providers, commercial and industrial end users, financial institutions, power trading and marketing companies and other third parties.
We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, load sales, steam sales, buying and selling standard physical products, buying and selling exchange traded instruments, gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for
our Commodity Margin.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2015
13
and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread
at pre-determined generation and price levels.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits and controls structure. Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group,
Chief Risk Officer, senior management and Board of Directors. For control purposes, we have VAR limits that govern the overall risk of our portfolio of power plants, energy contracts, financial hedging transactions and other contracts. Our VAR limits, transaction approval limits and other risk related controls are dictated by our Risk Management Policy which is approved by our Board of Directors and by a committee comprised of members of our senior management and administered by our Chief Risk Officer’s organization. The Chief Risk Officer’s organization is segregated from the commercial operations unit and reports directly to our Audit Committee and Chief Financial Officer. Our Risk Management Policy is primarily designed to provide us with a degree of protection from significant downside
commodity price risk exposure to our cash flows.
We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. The reclassification of mark-to-market losses from AOCI into earnings and the changes in fair value and settlements subsequent to the reclassification date of the interest rate swaps formerly hedging our First Lien Credit Facility is presented separately from interest expense as loss on interest rate derivatives on our Consolidated Statements of Operations. See Note 8 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
Seasonality
and weather can have a significant impact on our results of operations and are also considered in our hedging and optimization activities. Most of our power plants are located in regional power markets where the greatest demand for power occurs during the summer months, which coincides with our third fiscal quarter. Depending on existing contract obligations and forecasted weather and power demands, we may maintain either a larger or smaller open position on fuel supply and committed generation during the summer months in order to protect and enhance our Commodity Margin accordingly.
SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION
See Note 16 of the Notes to Consolidated Financial Statements for a discussion of financial information
by reportable segment and sales in excess of 10% of our annual consolidated revenues to two of our customers.
We own 88 power plants, including one under construction, with an aggregate generation capacity of 26,548 MW and 309 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 2,431 MW of simple-cycle combustion turbines and 22,663 MW of combined-cycle combustion turbines and a small portion from conventional natural gas/oil-fired boilers with steam turbines. Simple-cycle combustion turbines burn natural gas or oil to spin an electric generator to produce power. A
combined-cycle unit combusts fuel like a simple-cycle combustion turbine and the exhaust heat is captured by a heat recovery boiler to create steam which can then spin a steam turbine. Simple-cycle turbines are easier to maintain, but combined-cycle turbines operate with much higher efficiency. Each of our power plants currently in operation is capable of producing power for sale to a utility, another third-party end user or an intermediary such as a marketing company. At 17 of our power plants we also produce thermal energy (primarily steam and chilled water), which can be sold to industrial and governmental users. These plants are called combined heat and power facilities.
Our Steam Adjusted Heat Rate for 2014 for the power plants we operate was 7,384 Btu/KWh which results in a power conversion efficiency of approximately 46%. The power conversion efficiency is a measure of how efficiently a fossil fuel power plant converts
thermal energy to electrical energy. Our Steam Adjusted Heat Rate includes all fuel required to dispatch our power plants including “start-up” and “shut-down” fuel, as well as all non-steady state operations. Once our power plants achieve steady state operations, our combined-cycle power plants achieve an average power conversion efficiency of approximately 50%. Additionally, we also sell steam from our combined heat and power plants, which improves our power conversion efficiency in steady state operations from these power plants to an average of approximately 53%. Due to our modern combustion turbine fleet, our power conversion efficiency is significantly better than that of older technology natural gas-fired power plants and coal-fired power plants, which typically have power conversion efficiencies that range from 28% to 36%.
Our natural gas fleet is relatively young with a weighted average age, based upon
MW capacities in operation, of approximately 15 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 per MWh produced than most typical utility fleets. The age, scale, efficiency and cleanliness of our power plants is a unique profile in the wholesale power sector.
The majority of the combustion turbines in our fleet are one of four technologies: GE 7FA, GE LM6000, Siemens 501FD or Siemens V84.2 turbines. We maintain our fleet through a regular and rigorous maintenance program. As units reach certain operating targets, which are typically based upon service hours or number of starts, we perform the maintenance that is required for that unit at that stage in its life cycle. Our large fleet of similar technologies has enabled us to build significant technical and engineering experience with these units and minimize the number of
replacement parts in inventory. We leverage this experience by performing much of our major maintenance ourselves with our outage services subsidiary.
Geothermal Fleet
Our Geysers Assets are a 725 MW fleet of 15 operating power plants in northern California. Geothermal power is considered 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 generate power. For the past 14 consecutive years, our Geysers Assets have continued to generate approximately six million MWh of renewable power per year. Unlike other renewable resources such as wind or sunlight, which depend on intermittent
sources to generate power, making them less reliable, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability record of approximately 94% in 2014.
We inject water back into the steam reservoir, which extends the useful life of the resource and helps to maintain the output of our Geysers Assets. The water we inject comes from the condensate associated with the steam extracted to generate power, wells and creeks, as well as water purchase agreements for reclaimed water. We receive and inject an average of approximately 13 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 11 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive,
on average, approximately two million gallons a day from The Lake County Recharge Project from Lake County. As a result of these recharge projects, MWh production has been relatively constant. We expect that, as a result of the water injection program, the reservoir at our Geysers Assets will be able to supply economic quantities of steam for the foreseeable future.
16
We periodically review our geothermal studies to help us assess the economic life of our geothermal reserves. Our most recent geothermal reserve study was conducted in 2011. Our evaluation of our geothermal reserves, including our review of any applicable independent studies conducted, indicated that our Geysers Assets should continue to supply sufficient
steam to generate positive cash flows at least through 2068. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2011, assumes that defined “proved reserves” are those quantities of geothermal energy which, by analysis of geological and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under current economic conditions, operating methods and government regulations.
We lease the geothermal steam fields from which we extract steam for our Geysers Assets. We have leasehold mineral interests in 107 leases comprising approximately 29,000 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 2014 is:
•
28% related to leases with the federal government via the Office of Natural Resources Revenue (formerly, the Minerals Management Service),
•
27% related to leases with the California State Lands Commission, and
•
45%
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 relative to the total steam generated by our Geysers Assets as a whole.
Our geothermal leases are generally for initial terms varying from five to 20 years and for so long as geothermal resources are produced and sold. A few of our geothermal leases were signed in excess of 30 years ago. Our federal leases are, in general, for an initial 10-year period with renewal clauses for an additional 40 years for a maximum of 50 years. The 50-year term expires in 2024 for the majority of our federal leases. However, our federal leases allow for a preferential right to renewal for a second 40-year term on such terms and conditions as the lessor deems appropriate if, at the end of the initial 40-year term, geothermal steam is being produced or utilized in commercial quantities. The majority of our other leases
run through the economic life of our Geysers Assets and provide for renewals so long as geothermal resources are being produced or utilized, or are capable of being produced or utilized, in commercial quantities from the leased land or from land unitized with the leased land. Although we believe that we will be able to renew our leases through the economic life of our Geysers Assets on terms that are acceptable to us, it is possible that certain of our leases may not be renewed, or may be renewable only on less favorable terms.
In addition, we hold 40 geothermal leases comprising approximately 43,840 acres of federal geothermal resource lands in the Glass Mountain area in northern California, which is separate from The Geysers region. Four test production wells were drilled prior to our acquisition of these leases and we have drilled one test well since their acquisition, which produced commercial quantities of steam during
flow tests. However, the properties subject to these leases have not been developed and there can be no assurance that these leases will ultimately be developed.
Other Power Generation Technologies
Across the fleet, we also have a variety of older, less efficient technologies including approximately 725 MW of capacity from a power plant which has conventional steam turbine technology. We also have approximately 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.
17
Table of Operating Power Plants and Projects Under Construction and Advanced Development
Set
forth below is certain information regarding our operating power plants and projects under construction and advanced development at December 31, 2014.
SEGMENT / Power Plant
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)
2014
Total MWh
Generated(4)
WEST
Geothermal
McCabe
#5 & #6
WECC
CA
Renewable
100
%
78
78
510,172
Ridge
Line #7 & #8
WECC
CA
Renewable
100
%
69
69
657,705
Calistoga
WECC
CA
Renewable
100
%
66
66
490,052
Eagle
Rock
WECC
CA
Renewable
100
%
66
66
576,597
Quicksilver
WECC
CA
Renewable
100
%
53
53
337,155
Cobb
Creek
WECC
CA
Renewable
100
%
52
52
447,020
Lake
View
WECC
CA
Renewable
100
%
52
52
518,660
Sulphur
Springs
WECC
CA
Renewable
100
%
51
51
451,161
Socrates
WECC
CA
Renewable
100
%
50
50
392,465
Big
Geysers
WECC
CA
Renewable
100
%
48
48
405,556
Grant
WECC
CA
Renewable
100
%
43
43
295,217
Sonoma
WECC
CA
Renewable
100
%
42
42
318,273
West
Ford Flat
WECC
CA
Renewable
100
%
24
24
207,226
Aidlin
WECC
CA
Renewable
100
%
17
17
139,692
Bear
Canyon (5)
WECC
CA
Renewable
100
%
14
14
89,366
Natural
Gas-Fired
Delta
Energy Center
WECC
CA
Combined Cycle
100
%
835
857
5,186,552
Pastoria
Energy Center
WECC
CA
Combined Cycle
100
%
770
749
5,096,711
Hermiston
Power Project
WECC
OR
Combined Cycle
100
%
566
635
3,100,556
Otay Mesa Energy
Center
WECC
CA
Combined Cycle
100
%
513
608
3,664,180
Metcalf
Energy Center
WECC
CA
Combined Cycle
100
%
564
605
2,511,944
Sutter
Energy Center
WECC
CA
Combined Cycle
100
%
542
578
1,226,069
Los
Medanos Energy Center
WECC
CA
Cogen
100
%
518
572
3,538,271
South
Point Energy Center
WECC
AZ
Combined Cycle
100
%
520
530
1,103,622
Russell City Energy Center
WECC
CA
Combined
Cycle
75
%
429
464
1,668,096
Los Esteros Critical Energy Facility
WECC
CA
Combined
Cycle
100
%
243
309
252,220
Gilroy Energy Center
WECC
CA
Simple
Cycle
100
%
—
141
29,497
Gilroy Cogeneration Plant
WECC
CA
Cogen
100
%
109
130
61,370
King
City Cogeneration Plant
WECC
CA
Cogen
100
%
120
120
514,957
Greenleaf
1 Power Plant (6)
WECC
CA
Combined Cycle
100
%
50
50
17,303
Greenleaf
2 Power Plant (6)
WECC
CA
Cogen
100
%
49
49
246,357
Wolfskill
Energy Center
WECC
CA
Simple Cycle
100
%
—
48
18,102
Yuba
City Energy Center
WECC
CA
Simple Cycle
100
%
—
47
26,100
Feather
River Energy Center
WECC
CA
Simple Cycle
100
%
—
47
23,857
Creed
Energy Center
WECC
CA
Simple Cycle
100
%
—
47
10,810
Lambie
Energy Center
WECC
CA
Simple Cycle
100
%
—
47
10,827
Goose
Haven Energy Center
WECC
CA
Simple Cycle
100
%
—
47
11,225
Riverview
Energy Center
WECC
CA
Simple Cycle
100
%
—
47
18,939
King
City Peaking Energy Center
WECC
CA
Simple Cycle
100
%
—
44
4,914
Agnews
Power Plant
WECC
CA
Combined Cycle
100
%
28
28
15,794
Subtotal
6,581
7,524
34,194,590
18
SEGMENT / Power Plant
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)
2014
Total MWh
Generated(4)
TEXAS
Deer
Park Energy Center
TRE
TX
Cogen
100
%
1,103
1,204
6,160,473
Guadalupe
Energy Center
TRE
TX
Combined Cycle
100
%
1,009
1,000
4,145,500
Baytown
Energy Center
TRE
TX
Cogen
100
%
782
842
3,286,980
Channel
Energy Center
TRE
TX
Cogen
100
%
723
808
3,319,798
Pasadena
Power Plant(7)
TRE
TX
Cogen/Combined Cycle
100
%
763
781
4,069,518
Bosque
Energy Center
TRE
TX
Combined Cycle
100
%
740
762
3,732,612
Freestone
Energy Center
TRE
TX
Combined Cycle
75
%
779
746
3,065,393
Magic
Valley Generating Station
TRE
TX
Combined Cycle
100
%
682
712
3,737,596
Brazos
Valley Power Plant
TRE
TX
Combined Cycle
100
%
523
609
2,417,800
Corpus
Christi Energy Center
TRE
TX
Cogen
100
%
426
500
2,056,507
Texas
City Power Plant
TRE
TX
Cogen
100
%
400
453
1,039,057
Clear
Lake Power Plant
TRE
TX
Cogen
100
%
344
400
411,473
Hidalgo
Energy Center
TRE
TX
Combined Cycle
78.5
%
392
374
1,235,508
Freeport
Energy Center(8)
TRE
TX
Cogen
100
%
210
236
1,736,482
Subtotal
8,876
9,427
40,414,697
EAST
Bethlehem
Energy Center
RFC
PA
Combined Cycle
100
%
1,037
1,130
4,703,870
Hay
Road Energy Center
RFC
DE
Combined Cycle
100
%
1,036
1,130
4,583,913
Morgan
Energy Center
SERC
AL
Cogen
100
%
720
807
3,869,576
Fore
River Energy Center
NPCC
MA
Combined Cycle
100
%
750
731
554,549
Edge
Moor Energy Center
RFC
DE
Steam Cycle
100
%
—
725
854,248
Osprey
Energy Center
FRCC
FL
Combined Cycle
100
%
537
599
1,389,851
York
Energy Center
RFC
PA
Combined Cycle
100
%
519
565
2,537,059
Westbrook
Energy Center
NPCC
ME
Combined Cycle
100
%
552
552
1,838,910
Greenfield
Energy Centre(9)
NPCC
ON
Combined Cycle
50
%
422
519
759,689
RockGen
Energy Center
MRO
WI
Simple Cycle
100
%
—
503
65,620
Zion
Energy Center
RFC
IL
Simple Cycle
100
%
—
503
63,658
Mankato
Power Plant
MRO
MN
Combined Cycle
100
%
280
375
355,759
Pine
Bluff Energy Center
SERC
AR
Cogen
100
%
184
215
1,051,672
Cumberland
Energy Center
RFC
NJ
Simple Cycle
100
%
—
191
116,354
Kennedy
International Airport Power Plant
NPCC
NY
Cogen
100
%
110
121
734,258
Auburndale
Peaking Energy Center
FRCC
FL
Simple Cycle
100
%
—
117
12,363
Sherman
Avenue Energy Center
RFC
NJ
Simple Cycle
100
%
—
92
28,716
Bethpage
Energy Center 3
NPCC
NY
Combined Cycle
100
%
60
80
140,717
Middle
Energy Center(10)
RFC
NJ
Simple Cycle
100
%
—
77
2,365
Carll's
Corner Energy Center
RFC
NJ
Simple Cycle
100
%
—
73
26,325
Mickleton
Energy Center
RFC
NJ
Simple Cycle
100
%
—
67
13,737
Missouri
Avenue Energy Center(10)
RFC
NJ
Simple Cycle
100
%
—
60
2,099
Bethpage
Power Plant
NPCC
NY
Combined Cycle
100
%
55
56
295,157
Christiana
Energy Center
RFC
DE
Simple Cycle
100
%
—
53
1,326
Bethpage
Peaker
NPCC
NY
Simple Cycle
100
%
—
48
123,639
Stony
Brook Power Plant
NPCC
NY
Cogen
100
%
45
47
283,328
Cedar
Energy Center (10)
RFC
NJ
Simple Cycle
100
%
—
34
2,553
Tasley
Energy Center
RFC
VA
Simple Cycle
100
%
—
33
2,707
Whitby
Cogeneration(11)
NPCC
ON
Cogen
50
%
25
25
193,329
Delaware
City Energy Center
RFC
DE
Simple Cycle
100
%
—
23
993
West
Energy Center
RFC
DE
Simple Cycle
100
%
—
20
133
19
SEGMENT / Power Plant
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)
2014
Total MWh
Generated(4)
Bayview Energy Center
RFC
VA
Simple Cycle
100
%
—
12
3,712
Crisfield
Energy Center
RFC
MD
Simple Cycle
100
%
—
10
2,242
Vineland
Solar Energy Center
RFC
NJ
Renewable
100
%
—
4
5,513
Subtotal
6,332
9,597
24,619,940
Total
operating power plants
87
21,789
26,548
99,229,227
Power
plants sold or retired during 2014
Carville Energy Center
SERC
LA
Cogen
100%
n/a
n/a
1,117,532
Columbia
Energy Center
SERC
SC
Cogen
100%
n/a
n/a
224,367
Decatur
Energy Center
SERC
AL
Combined Cycle
100%
n/a
n/a
653,780
Deepwater
Energy Center
RFC
NJ
Steam Cycle
100%
n/a
n/a
662
Hog
Bayou Energy Center
SERC
AL
Combined Cycle
100%
n/a
n/a
300,466
Oneta
Energy Center
SPP
OK
Combined Cycle
100%
n/a
n/a
1,524,648
Santa
Rosa Energy Center
SERC
FL
Combined Cycle
100%
n/a
n/a
256,046
Subtotal
4,077,501
Total
operating, sold and retired power plants
103,306,728
Projects
Under Construction and Advanced Development
Projects Under Construction
Garrison
Energy Center
RFC
DE
Combined Cycle
100
%
273
309
n/a
Projects
Under Advanced Development
York
2 Energy Center
RFC
PA
Combined Cycle
100
%
668
760
n/a
Total
operating power plants and projects
22,730
27,617
___________
(1)
Natural
gas-fired fleet capacities are generally derived on as-built as-designed outputs, including upgrades, based on site specific annual average temperatures and average process steam flows for cogeneration power plants, as applicable. Geothermal capacities are derived from historical generation output and steam reservoir modeling under average ambient conditions (temperatures and rainfall).
(2)
Natural gas-fired fleet peaking capacities are primarily derived on as-built as-designed peaking outputs based on site specific average summer temperatures and include power enhancement features such as heat recovery steam generator duct-firing, gas turbine power augmentation, and/or other power augmentation features. For certain power plants with definitive
contracts, capacities at contract conditions have been included. Oil-fired capacities reflect capacity test results.
(3)
These outputs do not factor in the typical MW loss and recovery profiles over time, which natural gas-fired turbine power plants display associated with their planned major maintenance schedules.
(4)
MWh generation is shown
here as our net operating interest.
(5)
Bear Canyon will be retired in February 2015; however, the steam used to run its turbine will be redirected to a different Geysers power plant resulting in no diminution of overall generating capacity at our Geysers fleet.
(6)
The operating lease related to these power plants will expire in July 2015.
(7)
Pasadena
is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
(8)
Freeport Energy Center is owned by Calpine; however, it is contracted and operated by The Dow Chemical Company.
(9)
Calpine holds a 50% partnership interest in Greenfield LP through its subsidiaries; however, it is operated by a third party.
(10)
We
have provided notice to PJM that we plan to retire these units before commencement of the PJM Reliability Pricing Model 2015/2016 delivery year.
(11)
Calpine holds a 50% partnership interest in Whitby Cogeneration through its subsidiaries; however, it is operated by Atlantic Packaging Products Ltd.
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We provide operations and maintenance services for all but three of the power plants
in which we have an interest. Such services include the operation of power plants, geothermal steam fields, wells and well pumps and natural gas pipelines. We also supervise maintenance, materials purchasing and inventory control, manage cash flow, train staff and prepare operations and maintenance manuals for each power plant that we operate. As a power plant develops an operating history, we analyze its operation and may modify or upgrade equipment, or adjust operating procedures or maintenance measures to enhance the power plant’s reliability or profitability. Although we do not operate the Freeport Energy Center, our outage services subsidiary performs all major maintenance services for this plant under a contract with The Dow Chemical Company through April 2032.
Certain power plants in which we have an interest have been financed
primarily with project financing that is structured to be serviced out of the cash flows derived from the sale of power (and, if applicable, thermal energy and capacity) produced by such power plants and generally provide that the obligations to pay interest and principal on the loans are secured solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders under these project financings generally have no recourse for repayment against us or any of our assets or the assets of any other entity other than foreclosure on pledges of stock or partnership interests and the assets attributable to the entities that own the power plants. However, defaults under some project financings may result in cross-defaults to certain of our other debt and debt instruments, including our First
Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Acceleration of the maturity of a project financing following a default may also result in a cross-acceleration of such other debt.
Substantially all of the power plants in which we have an interest are located on sites which we own or lease on a long-term basis.
EMISSIONS AND OUR ENVIRONMENTAL PROFILE
Our environmental record has been widely recognized. We were an EPA Climate Leaders Partner with a stated goal to reduce GHG emissions, and we became the first power producer to earn the distinction of Climate Action LeaderTM. In 2013, our emissions of GHG amounted to approximately 45 million tons.
Natural
Gas-Fired Generation
Our natural gas-fired, primarily combined-cycle fleet consumes significantly less fuel to generate power than conventional boiler/steam turbine power plants and emits fewer air pollutants per MWh of power produced as compared to coal-fired or oil-fired power plants. All of our power plants have air emissions controls and most have selective catalytic reduction to further reduce emissions of nitrogen oxides, a precursor of atmospheric ozone and acid rain. In addition, we have implemented a program of proprietary operating procedures to reduce natural gas consumption and further lower air pollutant emissions per MWh of power generated. The table below summarizes approximate air pollutant emission rates from our natural gas-fired, combined-cycle power plants compared to the average emission rates from U.S. coal-, oil- and natural gas-fired power plants as a group, based on the most recent statistics available
to us.
Air Pollutant Emission Rates —
Pounds of Pollutant Emitted
Per MWh of Power Generated
Air Pollutants
Average U.S. Coal-, Oil-,
and Natural
Gas-Fired
Power Plant(1)
Calpine
Natural Gas-Fired,
Combined-Cycle
Power Plant(2)
Advantage Compared to
Average U.S. Coal-, Oil-,
and Natural Gas-Fired
Power Plant
Nitrogen Oxides, NOx
4.16
0.12
97.1%
Acid
rain, smog and fine particulate formation
Sulfur Dioxide, SO2
8.71
0.0043
99.9%
Acid
rain and fine particulate formation
Mercury Compounds(3)
0.00002
—
100%
Neurotoxin
Carbon
Dioxide, CO2
1,941
852
56.1%
Principal GHG—contributor to climate change
___________
(1)
The
average U.S. coal-, oil- and natural gas-fired power plants’ emission rates were obtained from the U.S. Department of Energy’s Electric Power Annual Report for 2012. Emission rates are based on 2012 emissions and net generation. The U.S. Department of Energy has not yet released 2013 information.
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(2)
Our natural gas-fired, combined-cycle power plant estimated emission rates are based on our 2012 emissions and power generation data from our natural gas-fired, combined-cycle power plants (excluding combined heat power plants) as measured under the EPA reporting requirements.
(3)
The
U.S. coal-, oil- and natural gas-fired power plant air emissions of mercury compounds were obtained from the EPA Toxics Release Inventory for 2012. Emission rates are based on 2012 emissions and net generation from U.S. Department of Energy’s Electric Power Annual Report for 2012.
Geothermal Generation
Our 725 MW fleet of geothermal turbine-based power plants utilizes a natural, renewable energy source, steam from the Earth’s interior, to generate power. Since these power plants do not burn fossil fuel, they are able to produce power with negligible CO2 (the principal GHG), NOX and SO2 emissions. Compared to the average U.S. coal-, oil- and natural gas-fired power plant, our Geysers Assets emit 99.9% less NOX,
100% less SO2 and 96.9% less CO2. There are 18 active geothermal power plants located in The Geysers region of northern California. We own and operate 15 of them. We recognize the importance of our Geysers Assets and we are committed to extending this renewable geothermal resource through the addition of new steam wells and wastewater recharge projects where clean, reclaimed water from local municipalities is recycled into the geothermal resource where it is converted by the Earth’s heat into steam for power production.
Water Conservation and Reclamation
We have also invested substantially in technologies and systems that reduce the impact of our operations on water as a natural resource:
•
We
receive and inject an average of approximately 13 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 11 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately two million gallons a day from The Lake County Recharge Project from Lake County.
•
In our combined-cycle power plants, we use mechanical draft cooling towers, which use up to 90% less water than conventional once-through cooling systems.
•
Three
of our power plants (Sutter Energy Center, Otay Mesa Energy Center and Fore River Energy Center) employ air cooled condensers for cooling, consuming virtually no water for cooling.
•
In 12 of our operating natural gas-fired power plants equipped with cooling towers, we reuse treated water from municipal treatment systems for cooling. By reusing water in these cooling towers, we avoid the usage of as much as 36 million gallons per day of valuable surface and/or groundwater for cooling.
GOVERNMENTAL AND REGULATORY MATTERS
We are subject to complex and stringent energy, environmental
and other laws and regulations at the federal, state and local levels as well as within the RTO and ISO markets in which we participate in connection with the development, ownership and operation of our power plants. Federal and state legislative and regulatory actions continue to change how our business is regulated.
Some of the more significant governmental and regulatory matters that affect our business are discussed below.
Environmental Matters
Federal Regulation of Air Emissions
The CAA provides for the regulation of air quality and air emissions, largely through state implementation of federal requirements. We believe that all of our operating power plants comply with existing federal and state performance standards mandated under the CAA. We continue to monitor and actively participate
in EPA initiatives where we anticipate an impact on our business.
The CAA requires the EPA to regulate emissions of pollutants considered harmful to public health and the environment. The EPA has set NAAQS for six “criteria” pollutants: carbon monoxide, lead, NO2, particulate matter, ozone and SO2. In addition, the CAA regulates a large number of air pollutants that are known to cause or may reasonably be anticipated to cause adverse effects to human health or adverse environmental effects, known as hazardous air pollutants (“HAPs”). The EPA is required to issue technology-based national emissions standards for hazardous air pollutants (“NESHAPs”) to limit the release of specified
22
HAPs
from specific industrial sectors. The Clean Air Act also requires the EPA to regulate emissions of certain pollutants that affect visibility in national parks and wilderness areas (“Regional Haze”).
Ozone NAAQS
On November 25, 2014, the EPA proposed to revise the ozone NAAQS downward, to a range of 0.065-0.070 ppm. The EPA is under court order to finalize this standard by no later than October 1, 2015. Ozone is formed in the atmosphere by the reaction of NOx with volatile organic compounds (“VOC”) in the presence of sunlight, with the implication that a reduction in the ozone NAAQS generally leads to requirements to reduce emissions of NOx and VOC. Depending on the final level of the standard, additional reductions in NOx emissions from the power industry may be required
in areas in which this standard is not attained or more generally in the Eastern U.S. However, given the timelines noted above, we cannot yet estimate what the impact will be on our business.
Mercury and Air Toxics Standards
On February 16, 2012, the EPA promulgated the NESHAP from Coal- and Oil-fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units, otherwise known as MATS. MATS will reduce emissions of all hazardous air pollutants emitted by coal- and oil-fired electric generating units, including mercury (Hg), arsenic (As), chromium (Cr), nickel (Ni) and acid gases.
The EPA estimates that there are approximately 1,400 units
affected by MATS, consisting of approximately 1,100 existing coal-fired units and 300 oil-fired units at approximately 600 power plants. The CAA provides existing units three years from the effective date of MATS to achieve compliance. As a result, existing coal-fired units without emissions controls will need to retire or install controls on acid gases, mercury and particulate matter emissions by April 16, 2015. State enforcement authorities also have discretion under the CAA to provide an additional year for technology installation to comply with MATS. Further, the EPA issued a policy memorandum which indicates that the EPA may provide, in limited circumstances due to delays in the installation of controls, an additional year extension for MATS compliance where necessary to maintain electric system reliability. Accordingly, although the EPA’s analysis indicates that it should take no longer than three years for most
existing units to comply, they may have up to five years, or until April 16, 2017, to install controls and comply with MATS.
On April 15, 2014, the D.C. Circuit rejected all legal challenges to the EPA’s MATS regulation in the White Stallion Energy Center, LLC, et al v. EPA. case, which included challenges by over 20 states, industry groups and companies. On July 14, 2014, three petitions for a writ of certiorari were filed with the U.S. Supreme Court in conjunction with the D.C. Circuit’s action. On November 25, 2014, the U.S. Supreme Court granted the petitions on the limited issue of the consideration of costs in the determination of
the regulation of HAPs. Oral arguments will be heard in the spring of 2015.
Multi-Pollutant Programs — CAIR and CSAPR
Pursuant to authority granted under the CAA, the EPA promulgated CAIR regulations in March 2005, applicable to 28 eastern states and the District of Columbia, to facilitate attainment of its ozone and fine particulates NAAQS issued in 1997. CAIR’s goal was to reduce SO2 emissions in these states by over 70%, and NOX emissions by over 60% from 2003 levels by 2015. CAIR established annual Cap-and-Trade programs for SO2 and NOX as well as a seasonal program for NOX. On July 11, 2008, the D.C.
Circuit invalidated CAIR, but ultimately allowed CAIR to take effect and continue to apply while the EPA designed a replacement rule. CAIR was in effect from January 1, 2009 through December 31, 2014.
On July 6, 2011, the EPA finalized CSAPR as the replacement program for CAIR. CSAPR requires a total of 28 primarily eastern states, to reduce annual SO2 emissions, annual NOx emissions and/or ozone seasonal NOx emissions to assist in attaining three NAAQS: the 1997 annual PM2.5 NAAQS, the 1997 8-hour ozone NAAQS, and the 2006 24-hour PM2.5 NAAQS. The reduction requirements in CSAPR are similar in magnitude to those in CAIR. CSAPR has been in litigation since before its original implementation, with the rule being declared invalid by
the D.C. Circuit and stayed while appeals to the U.S. Supreme Court were heard.
On April 29, 2014, the U.S. Supreme Court in EME Homer City Generation v. EPA ruled in favor of the EPA by reversing and remanding the decision of the D.C. Circuit invalidating CSAPR. On October 23, 2014, the D.C. Circuit lifted the stay so that CSAPR can be fully implemented. On December 3, 2014, the EPA issued ministerial rules and a Notice of Data Availability that clearly defined how CSAPR is to be implemented. As a result of the U.S. Supreme Court ruling and the EPA’s subsequent rulemaking, CSAPR took effect on January 1, 2015. All of the original provisions of CSAPR were included, with a three year
delay of the original rule timelines. Remaining legal issues are scheduled for oral argument before the D.C. Circuit on February 25, 2015.
23
CSAPR and MATS primarily impact coal-fired power plants, and therefore judicial decisions related to these rules do not directly affect our business. However, we believe that well-founded regulations protecting health and the environment could benefit our competitive position by better recognizing the value of our investments in clean power generation technology.
Regional Haze
The EPA first issued the Regional Haze Rule in 1999, with a focus on emissions of SO2,
NOx, and particulate matter, particularly PM2.5. Such emissions can affect visibility regionally, with the result that in the eastern U.S., regional NOx and SO2 programs like CSAPR and CAIR are considered to achieve much of the required emission reductions that would be required to reduce regional haze. However, individual facilities may still be required to install Best Available Retrofit Technology (“BART”) if they are found to have a significant individual effect on visibility in areas of interest. On November 24, 2014, the EPA proposed to partially approve and partially disapprove Texas’ Regional Haze program. This proposal includes a federal implementation plan that would impose SO2 emission controls on 15 units at eight coal-fired power plants in Texas as part of a long-term strategy for making reasonable progress
at three Class I areas in Texas and Oklahoma, set new reasonable progress goals for the Big Bend, the Guadalupe Mountains, and Wichita Mountains Class I areas, and substitute CSAPR for CAIR to satisfy BART requirements. The federal implementation plan would be effective until Texas replaces it with an approvable state implementation plan. While this will not directly affect our fleet, it does have the potential to affect the power market in Texas because the affected facilities will either have to further reduce emissions or retire.
GHG Emissions
In response to the 2007 decision of the U.S. Supreme Court in Massachusetts v. EPA and the Tailpipe Rule, which set GHG emission standards for cars and light trucks, the EPA issued two rules phasing in GHG regulation of stationary sources under the PSD and Title V programs of the CAA. First,
pursuant to the Timing Rule, the EPA delayed when major stationary sources of GHGs would otherwise be subject to PSD and Title V, limiting their application to the effective date of the Tailpipe Rule. Second, pursuant to the Tailoring Rule, the EPA limited the initial applicability of the GHG regulations to sources exceeding a specified carbon threshold.
These rules were the subject of more than sixty petitions for review by industry and the states, and after consolidation at the D.C. Circuit, were upheld. The U.S. Supreme Court heard the case on appeal, and on June 23, 2014, rejected the Tailoring Rule, but upheld the EPA’s authority to impose GHG limits on large new or modified sources if such sources were required to obtain permits for other pollutants. We are still assessing the overall impact of this ruling, but we do not expect a significant negative impact on our business
as a result of this narrowing of the EPA’s authority.
In January 2014, the EPA proposed New Source Performance Standards (“NSPS”) for GHG emissions from new power plants, which are to be finalized within a reasonable period. In June 2014, the EPA proposed the Clean Power Plan which requires a reduction in GHG emissions from existing power plants of 30% from 2005 levels by 2030. According to the EPA, the Clean Power Plan is to be finalized by June 2015 with state plans to implement these guidelines to be finalized by June 2016 with a possible extension to 2017. The Clean Power Plan provides states flexibility in meeting the requirements including increasing energy efficiency measures, adding renewable generation and increasing dispatch of natural gas-fired generation. In June 2014, the EPA also proposed GHG NSPS provisions for modified and reconstructed sources (the “Modification/Reconstruction Rule”). In January
2015, the EPA announced that the GHG NSPS, the Modification/Reconstruction Rule and the Clean Power Plan would be finalized by summer 2015. We believe that our competitive position is enhanced by regulations that ensure all power plants take the necessary steps to reduce their pollutant emissions.
Demand Response Resources under NESHAPs
FERC’s Order No. 745 regarding compensation of demand response in the energy market was appealed to the D.C. Circuit. In May 2014, the D.C. Circuit issued an order vacating and remanding Order No. 745 on the basis that the FERC does not have jurisdiction to regulate demand response in the energy market. On January 15, 2015, the FERC and several other entities filed petitions for certiorari with the U.S. Supreme Court, asking for review of the D.C. Circuit’s decision. Also, on October
20, 2014, the D.C. Circuit granted the FERC’s request for a stay of the decision. The stay will remain in place until final disposition by the U.S. Supreme Court.
On January 30, 2013, the EPA finalized amendments to the NESHAP for Reciprocating Internal Combustion Engines (“RICE”). The final rule creates an exemption from otherwise applicable air emission requirements for uncontrolled “emergency” diesel-fired backup generators to operate for up to 100 hours per year for “emergency demand response” and up to 50 hours per year in certain non-emergency situations as part of a financial arrangement with another entity.
On March 29, 2013, Calpine and PSEG Power LLC filed a petition for reconsideration with the EPA objecting to the final rule because it allows the
increased use of uncontrolled, behind-the-meter diesel engines for the generation of electricity
24
during periods of peak demand and, thereby, will cause an increase in ozone during the peak ozone season. Additionally, on April 1, 2013, Calpine, First Energy Solutions Corporation and PSEG Power LLC filed a petition for review of the final rule with the D.C. Circuit.
On June 28, 2013, the EPA granted partial reconsideration of the NESHAP for RICE, including the final rule’s provisions allowing uncontrolled diesel engines to operate for up to 50 hours per year in non-emergency situations as part of a financial arrangement. Administrative
and judicial challenges continue and we cannot predict the outcome of this litigation.
Fees on Permissible Emissions
Section 185 of the CAA requires major stationary sources of NOX and VOC, such as power plants and refineries, in areas that fail to attain the NAAQS for ozone by the attainment date to pay a fee to the state or, if the state fails to collect the fee, the EPA. The fee is set in the CAA at $5,000 per ton of NOX or VOC (adjusted for inflation or approximately $9,000 per ton in 2011) and is payable on emissions that exceed 80% of each individual power plant’s baseline emissions, which are established in the year before the attainment date; however, the EPA has provided guidance for the calculation of alternative baselines. The fee will remain in effect until the designated area
achieves attainment.
We operate seven power plants in Texas and one in California that are located within designated nonattainment area subject to Section 185. The relevant agencies in both states issued regulations in 2012 and 2013 to address Section 185 fee collection. The EPA approval of the TCEQ regulation is pending. Our analysis of the final regulations indicates that we will have no fee obligation in either state.
Regional and State Air Emissions Activities
Several states and regional organizations have developed state-specific or regional initiatives to reduce GHG emissions through mandatory programs. The most advanced programs include the RGGI in the Northeast and California’s suite of GHG policies promulgated pursuant to AB 32, including its Cap-and-Trade program. The evolution of these programs could have a material impact on
our business.
In both of these programs, a cap is established defining the maximum allowable emissions of GHGs emitted by sources subject to the program. Affected sources are required to hold one allowance for each ton of CO2 emitted (and, in the case of California’s program, other GHGs) during the applicable compliance period. Both programs also contain provisions for the use of qualified offsets in lieu of allowances. Allowances are distributed through auctions or through allocations to affected companies. In addition, there are functional secondary markets for allowances. We obtain allowances in a variety of ways, including participation in auctions, as part of power purchase agreements, and through bilateral or exchange transactions.
California: GHG — Cap-and-Trade Regulation
California’s
AB 32 requires the state to reduce statewide GHG emissions to 1990 levels by 2020. To meet this benchmark, the CARB has promulgated a number of regulations, including the Cap-and-Trade Regulation and Mandatory Reporting Rule, which took effect on January 1, 2012. These regulations have been amended by the CARB several times since then.
Under the Cap-and-Trade Regulation, the first compliance period for covered entities like Calpine began on January 1, 2013 and ended on December 31, 2014. The second and third compliance periods, wherein the program applies to a broader scope of entities, including transportation fuels and natural gas distribution, run through the end of 2017 and 2020, respectively.
On January
1, 2014, the California Cap-and-Trade market was officially linked to the GHG Cap-and-Trade market in Quebec. The first joint GHG allowance auction occurred on November 25, 2014. Joint auctions of allowances issued by both jurisdictions will be held quarterly.
On May 22, 2014, the CARB approved its “First Update to the Climate Change Scoping Plan: Building on the Framework” pursuant to AB 32. The updated scoping plan states that California is on track to meet its 2020 emissions target and makes recommendations for how to achieve the goal of reducing statewide GHG emissions to 80% below 1990 levels by 2050, including recommending the establishment of a mid-term emissions target for 2030. Legislation has been introduced for consideration in 2015 concerning the development of such goals. The CARB has also begun considering
how the Cap-and-Trade Regulation might be relied upon as a component of any state plan that would be required pursuant to the EPA-proposed Clean Power Plan.
Overall, we support AB 32 and expect the net impact of the Cap-and-Trade Regulation to be beneficial to Calpine. We also believe we are well positioned to comply with the Cap-and-Trade Regulation.
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Northeast: CO2 – RGGI
On January 1, 2009, ten states in the Northeast implemented a Cap-and-Trade program, RGGI, which affects our power plants in Maine, Massachusetts, New York and Delaware (together emitting about 3.9 million tons of CO2
annually). In 2011, New Jersey announced its withdrawal from the RGGI program effective as of the 2012 compliance year.
We receive annual allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPAs at both the Kennedy International Airport Power Plant and Stony Brook Power Plant. We do not anticipate any significant business or financial impact from RGGI, given the efficiency of our power plants in RGGI states.
Consistent with the original memorandum of understanding under which the states created RGGI, the overall success of the RGGI program was reviewed in 2012. This program review led to a number of changes, most significant of which was a reduction of the aggregate RGGI cap downward
from 165 million tons to 91 million tons, slightly less than RGGI-wide emissions in 2012. We do not expect any material impact to our business from this change in regulations.
Texas: NOX
Pursuant to authority granted under the CAA, regulations adopted by the TCEQ to attain the one-hour and eight-hour NAAQS for ozone included the establishment of a Cap-and-Trade program for NOX emitted by power plants in the Houston-Galveston-Brazoria ozone nonattainment area. We own and operate seven power plants that participate in this program, all of which received free NOX allowances based on historical operating profiles. At this time, our Houston-area power plants have sufficient NOX allowances to meet forecasted obligations under
the program. Depending on the final level of the revised ozone NAAQS, allowable NOx emissions under this program could be reduced at some point in the future, which could cause us to incur additional compliance costs. However, we cannot estimate such costs until such time as the standard is finalized, nonattainment levels are determined and compliance programs are put in place.
New Jersey: NOX
New Jersey’s High Electric Demand Day (“HEDD”) Rule limits NOx emissions from turbines and boilers. Beginning in 2015, Phase 2 of the HEDD Rule will require investments in emissions controls on some of our peaking power plants. We retired our 158 MW Deepwater Energy Center in 2014. We provided notice to PJM that we plan to retire our 34 MW Cedar Energy Center, 60 MW Missouri Avenue Energy Center and 77 MW Middle Energy Center before the commencement of the PJM
2015/2016 delivery year. Due to current generator capacity concerns in the PJM service area for the winter of 2015/2016, PJM may require one or more of the plants to continue to operate for a period of time, but we would be entitled to full cost recovery. In addition, PJM has proposed a new Capacity Performance Program intended to improve electric reliability within PJM during extreme weather conditions, and this program could potentially affect the retirement date of a number of sources within PJM, including ours, subject to regulatory approvals.
We are installing emissions controls equipment at our 73 MW Carll’s Corner Energy Center and 67 MW Mickleton Energy Center to comply with the emission limits in the HEDD Rule, as these power plants cleared PJM’s 2015/2016 base residual auction. We expect that the implementation of the HEDD rule, and our method of compliance, whether retirement of, or installation of emissions controls
at these facilities will not have a material impact on our financial condition, results of operations or cash flows.
Renewable Portfolio Standards
Policymakers have been considering variations of an RPS at the federal and state level. Generally, an RPS requires each retail seller of electricity to include in its resource portfolio (the resources procured by the retail seller to supply its retail customers) a certain amount of power generated from renewable or clean energy resources by a certain date.
Federal RPS
Although there is currently no national RPS, President Obama has stated his goal is to have 80% of the nation’s electricity provided from clean energy resources, which includes natural gas resources, by 2035, and some U.S. Congressional members have expressed interest in national renewable
or clean energy standard legislation. It is too early to determine whether or not the enactment of a national RPS will have a positive or negative impact on us. Depending on the RPS structure, an RPS could enhance the value of our existing Geysers Assets. However, an RPS would likely initially drive up the number of wind and solar resources, which could negatively impact the dispatch of our natural gas-fired power plants, primarily in Texas and California. Conversely, our natural gas power plants could benefit by providing complementary/back-up service for these intermittent renewable resources or by being included in a clean energy standard.
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California RPS
On April 12, 2011, California’s
Governor signed into law legislation establishing a new and higher RPS. The new law requires implementation of a 33% RPS by 2020, with intermediate targets between 2010 and 2020. The previous RPS legislation required certain retail power providers to generate or procure 20% of the power they sell to retail customers from renewable resources beginning in 2010. The new standard applies to all load-serving entities, including entities such as large municipal utilities that are not subject to CPUC jurisdiction. Under the new law, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy at least a fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour. Similarly, the legislation places limits on the use of certain transactions and unbundled RECs - claims to the renewable aspect of the power produced by a renewable
resource that can be traded separately from the underlying power. In general, the ability to use “firmed and shaped” transactions and unbundled RECs becomes more limited over the course of the implementation period. In our role as an energy service provider, we are subject to the RPS requirements and continue to meet our compliance obligations. The increase in solar and wind generation on the state’s electrical grid has increased the need for flexible thermal generation which may be beneficial to Calpine but may also have adverse effects on wholesale electricity prices. In his recent inaugural address, the Governor articulated the goal of producing half of California’s electricity from renewables by 2030. It is unclear whether the primary vehicle to achieve this goal will be a higher RPS.
Other
A number of additional states have an RPS in place. Existing state-specific RPS
requirements may change due to regulatory and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future.
Other Environmental Regulations
In addition to controls on air emissions, our power plants and the equipment necessary to support them are subject to other extensive federal, state and local laws and regulations adopted for the protection of the environment and to regulate land use. The laws and regulations applicable to us primarily involve the discharge of wastewater and the use of water, but can also include wetlands protection and preservation, protection of endangered species, hazardous materials handling and disposal, waste disposal and noise regulations. Noncompliance with environmental laws and regulations can result in the imposition of civil or criminal fines or penalties. In some instances, environmental laws may also impose
clean-up or other remedial obligations in the event of a release of pollutants or contaminants into the environment. The following federal laws are among the more significant environmental laws that apply to us. In most cases, analogous state laws also exist that may impose similar and, in some cases, more stringent requirements on us than those discussed below. In general, our relatively clean portfolio as compared to our competitors affords us some advantage in complying with these laws.
Clean Water Act and Cooling Water Intake Structure Rule
The federal Clean Water Act establishes requirements relating to the discharge of pollutants into waters of the U.S. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, for some of our power plants. In addition, we are required to maintain spill prevention control and countermeasure
plans for some of our power plants. We believe that we are in compliance with applicable discharge requirements of the Clean Water Act.
On August 15, 2014, the EPA published the final Cooling Water Intake Structure Rule, which regulates the design and operation of such structures at power plants and other sources in order to minimize adverse environmental impacts. We are only subject to the provisions of this rule at one of our power plants, and we do not expect the rule to have a material direct impact on our operations.
In California, the EPA delegates the implementation of Section 316(b) to the California State Water Resources Control Board (“SWRCB”). The SWRCB has promulgated its own once-through cooling policy that establishes a schedule for once-through cooling units to install closed-cycle wet cooling (i.e., cooling towers)
or reduce entrainment and impingement to comparable levels as would be achieved with a cooling tower, or be retired. The compliance dates for approximately 12,000 MW of once-through cooling capacity in California occur between 2012 and 2020. We do not anticipate that the SWRCB’s policy will have a negative impact on our operations, as none of our power plants in California utilize once-through cooling systems.
Safe Drinking Water Act
Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface, are exempt under the Energy Policy Act of 2005 (“EPAct 2005”), we use geothermal re-injection wells to inject reclaimed wastewater
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back
into the steam reservoir, which are subject to the underground injection control program. We believe that we are in compliance with Part C of the Safe Drinking Water Act.
Resource Conservation and Recovery Act
The Resource Conservation and Recovery Act (“RCRA”), regulates the management of solid and hazardous waste. With respect to our solid waste disposal practices at our power plants and steam fields located in The Geysers region of northern California, we are also subject to certain solid waste requirements under applicable California laws. We believe that our operations are in compliance with RCRA and related state laws.
On June 21, 2010, the EPA proposed a rule to regulate coal combustion residuals (“CCRs”) under RCRA. The EPA announced the finalization of this rule on
December 19, 2014 which determined that storage and disposal of CCRs will be regulated as nonhazardous waste under Subtitle D of RCRA. The rule establishes technical requirements for CCR landfills and surface impoundments (ponds) intended to ensure impoundment integrity and protection of surface, groundwater and air quality. We do not use coal, so the final CCR rule, will have no direct impact on our financial condition, results of operations or cash flows.
Comprehensive Environmental Response, Compensation and Liability Act
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also referred to as the Superfund, requires cleanup of sites from which there has been a release or threatened release of hazardous substances, and authorizes the EPA to take any necessary response action at Superfund sites,
including ordering potentially responsible parties liable for the release to pay for such actions. Potentially responsible parties are broadly defined under CERCLA to include past and present owners and operators of, as well as generators of, wastes sent to a site. As of the filing of this Report, we are not subject to any material liability for any Superfund matters. However, we generate certain wastes, including hazardous wastes, and send certain of our wastes to third party waste disposal sites. As a result, there can be no assurance that we will not incur a liability under CERCLA in the future.
Federal Litigation Regarding Liability for GHG Emissions
Litigation relating to common law tort liability for GHG emissions is working its way through the federal courts. While the U.S. Supreme Court has established that, in light of the EPA regulation of GHGs under the CAA, companies
cannot be sued under federal common law theories of nuisance and negligence for their contribution to climate change, questions remain as to the viability of related state-law claims. In general, these state law-related claims have been unsuccessful in assigning tort liability for GHG emissions to power generators. We cannot predict the outcomes of these cases or what impact such cases, if successful, could have on our business.
Power and Natural Gas Matters
Federal Regulation of Power
FERC Jurisdiction
Electric utilities have been highly regulated by the federal government since the 1930s, principally under the Federal Power Act (“FPA”) and the U.S. Public Utility Holding Company Act of 1935. These statutes have been amended and supplemented by subsequent legislation, including PURPA,
EPAct 2005, and PUHCA 2005. These particular statutes and regulations are discussed in more detail below.
The FPA grants the federal government broad authority over electric utilities and independent power producers, and vests its authority in the 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. The FERC governs, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the transmission or wholesale sale of power in interstate commerce, the interlocking directorates, and the uniform system of accounts and reporting requirements for public utilities.
The majority of our power plants are subject to FERC’s jurisdiction; however, certain power
plants qualify for available exemptions. FERC’s jurisdiction over EWGs under the FPA applies to the majority of our power plants because they are EWGs or are owned by EWGs, except our EWGs located in ERCOT. Power plants located in ERCOT are exempt from many FERC regulations under the FPA. Many of our power plants that are not EWGs are operated as QFs under PURPA. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities, and have also been granted certain waivers of FERC reporting and accounting regulations available to non-traditional public utilities; however, we cannot assure that such authorities or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.
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FERC
has the right to review books and records of “holding companies,” as defined in PUHCA 2005, that are determined by FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are considered a holding company, as defined in PUHCA 2005, by virtue of our control of the outstanding voting securities of our subsidiaries that own or operate power plants used for the generation of power for sale, or that are themselves holding companies. However, we are exempt from FERC’s books and records inspection rights pursuant to one of the limited exemptions under PUHCA 2005 as we are a holding company due solely to our owning one or more QFs, EWGs and Foreign Utility Companies (“FUCOs”). If any of our entities were not a QF, EWG or FUCO, then we and our holding company subsidiaries
would be subject to the books and records access requirement.
FERC 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.
Pursuant to EPAct 2005, NERC has been certified by the FERC as the Electric Reliability Organization to develop and oversee the enforcement of electric system reliability standards applicable throughout the U.S., which are subject to FERC review and
approval. FERC-approved reliability standards may be enforced by FERC independently, or, alternatively, by NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to FERC oversight. Monetary penalties of up to $1 million per day per violation may be assessed for violations of the reliability standards.
FERC’s policies and rules will continue to evolve, and the FERC may amend or revise them, or may introduce new policies or rules in the future. The impact of such policies and rules on our business is uncertain and cannot be predicted at this time.
Power Regions
The following is a brief overview of the most significant regulatory issues affecting our business in our core power regions — CAISO, ERCOT, PJM and ISO-NE. The
CAISO market is in our West segment. The ERCOT market is in our Texas segment. The PJM and ISO-NE markets are in our East segment.
CAISO
The majority of our power plants in our West segment are located in California, in the CAISO region. We also own one power plant in Arizona and one in Oregon.
CAISO is responsible for ensuring the safe and reliable operation of the transmission grid within the bulk of California and providing open, nondiscriminatory transmission services. CAISO maintains various markets for wholesale sales of power, differentiated by time and type of electrical service, into which our subsidiaries may sell power from time to time. These markets are subject to various controls, such as price caps and mitigation of bids when transmission
constraints arise. The controls and the markets themselves are subject to regulatory change at any time.
The CPUC and CAISO continue to evaluate capacity procurement policies and products for the California power market. With the expectation of significant increases in renewables, both entities are evaluating the need for operational flexibility, including the ability to start and ramp quickly as well as the ability to operate efficiently at low output levels or cycle off. We are an active participant in these discussions and support products and policies that would provide appropriate compensation for the required attributes. As these proceedings are ongoing, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows, though we believe our fleet offers many features that can and do provide operational flexibility to the power markets.
ERCOT
ERCOT
is the ISO that manages approximately 85% of Texas’ load and an electric grid covering about 75% of the state, overseeing transactions associated with Texas’ competitive wholesale and retail power markets. FERC does not regulate wholesale sales of power in ERCOT. The PUCT exercises regulatory jurisdiction over the rates and services of any electric utility conducting business within Texas. Our subsidiaries that own power plants in Texas have power generation company status at the PUCT, and are either EWGs or QFs and are exempt from PUCT rate regulation. ERCOT ensures resource adequacy through an energy-only model. In ERCOT, there is a market offer price cap for energy and capacity services purchased by ERCOT. Under certain market conditions, the offer cap could be lower. Our subsidiaries
are subject to the offer cap rules, but only for sales of power and capacity services to ERCOT.
The PUCT is considering changes regarding its approach to resource adequacy, including price formation. ERCOT successfully launched the Operating Reserve Demand Curve (“ORDC”) functionality on June 1, 2014. This application produces
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a price “adder” to the clearing price of energy that increases as reserve capacity declines. As follow up to the ORDC, stakeholders have approved a rule change that will create a reliability deployment adder and will reflect the value of ISO out of merit actions and correct real time price reversals which is scheduled to be implemented prior to the
2015 peak summer season. The PUCT continues to consider the appropriate reliability standard that should be used to set ERCOT’s planning reserve margin. As these proceedings are ongoing and the timing of these changes is uncertain, we cannot predict the ultimate impact on our financial condition, results of operations or cash flows.
PJM
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. The rules and regulations affecting PJM power markets and transmission are subject to change at any time.
PJM experienced several unusual cold weather events during January 2014. PJM maintained system reliability, but the system was challenged. In order to address some of these challenges, PJM has filed proposed capacity
market rule changes that, if approved by the FERC, would significantly change PJM’s Reliability Pricing Model. PJM’s proposed changes include stronger performance incentives and more significant penalties for failure to perform during peak power system conditions. We support PJM’s proposed changes and believe that, overall, they enhance the competitiveness of the PJM power market; however, we cannot predict whether the FERC will approve all of PJM’s changes, what their ultimate impact may be, nor the impact on our financial condition, results of operations or cash flows.
ISO-NE
We have two power plants in our East segment located in Massachusetts and Maine for which ISO-NE is the RTO. 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 an ancillary services
markets.
ISO-NE continues to express concern related to the adequacy of natural gas transmission infrastructure and, for the past two years, has taken various out-of-market actions to ensure winter reliability over the near term. Over the longer term, the FERC has approved significant changes to the operation of the region’s capacity market beginning with the 2015 Forward Capacity Auction (“FCA”). The ISO’s new “Pay for Performance” construct will result in significantly higher penalties for assets that fail to perform during shortage events beginning with the 2018-2019 commitment period. The FERC also approved a two-year extension of the “lock-in” period for new generation, allowing new generating assets that clear an FCA to lock in their cleared price for a total of seven years.
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.
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.
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, one of our natural gas transportation pipelines in Texas is subject to dual jurisdiction by the FERC and the Texas Railroad Commission. This pipeline is an intrastate pipeline within the meaning of Section 2(16) of the Natural Gas Policy Act (“NGPA”). FERC regulates the rates charged by this pipeline for transportation services performed under Section 311 of the NGPA, and the Texas Railroad Commission regulates the rates and services provided by this pipeline as a gas utility in Texas. We also own a pipeline in Texas that is subject to the Texas Railroad Commission regulation as a Texas gas utility.
We also operate a proprietary pipeline
system in California, which is regulated by the U.S. Department of Transportation and the Pipeline and Hazardous Materials Safety Administration with regard to safety matters. Additionally, some of our power plants own and operate short pipeline laterals that connect the natural gas-fired power plants to the North American natural gas grid. Some of these laterals are subject to state and/or federal safety regulations.
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The FERC has civil penalty authority for violations of the Natural Gas Act (“NGA”) and NGPA, as well as any rule or order issued thereunder. The FERC’s regulations specifically prohibit the manipulation of the natural gas markets by making it unlawful for any entity in connection with the purchase or sale of natural gas, or the purchase or sale of transportation
service under the FERC’s jurisdiction, to engage in fraudulent or deceptive practices. Similar to its penalty authority under the FPA described above, the FERC is authorized to assess a maximum civil penalty of $1 million per violation for each day that the violation continues. The NGA and NGPA also provide for the assessment of criminal fines and imprisonment time for violations.
Federal Regulation of Futures and Other Derivatives
CFTC Regulation of Futures Transactions
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also give
the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for the purpose of influencing futures prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations).
The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
CFTC Regulation of Derivatives Transactions
The Dodd-Frank Act, which was signed into law on July 21, 2010, contains a variety of provisions designed to regulate financial markets, including credit and derivatives transactions.
Title VII of the Dodd-Frank Act addresses regulatory reform of the OTC derivatives market in the U.S. and significantly changes the regulatory framework of this market. Certain Title VII regulations have been finalized and are effective though some regulations remain subject to a delayed compliance schedule. Other key regulations have not been finalized as of this time or remain in draft form. Until all of these regulations have been finalized, the extent to which the provisions of Title VII might affect our derivatives activities cannot be completely known.
While we are closely monitoring this rulemaking process from the CFTC (including related no-action relief, interpretations and orders), we have reviewed and assessed the impact of the CFTC’s Title VII regulations on our business and related processes, and we have adjusted our internal procedures where necessary to comply with the applicable statutory law and related Title
VII regulations which are effective at this time. We will continue to monitor all relevant developments and rulemaking initiatives, and we expect to successfully implement any new applicable requirements.
EMPLOYEES
At December 31, 2014, we employed 2,052 full-time employees, of whom 162 were represented by collective bargaining agreements. Four collective bargaining agreements, representing a total of 100 employees, will expire within one year. We have never experienced a work stoppage or strike.
Item 1A.
Risk
Factors
Commercial Operations
Our financial performance is impacted by price fluctuations in the wholesale power and natural gas markets and other market factors that are beyond our control.
Market prices for power, generation capacity, ancillary services, natural gas and fuel oil are unpredictable and fluctuate substantially. Unlike most other commodities, power can only be stored on a very limited basis and generally must be produced concurrently with its use. As a result, power prices are subject to significant volatility due to supply and demand imbalances, especially in the day-ahead and spot markets. Long- and short-term power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:
•
increases
and decreases in generation capacity in our markets, including the addition of new supplies of power as a result of the development of new power plants, expansion of existing power plants or additional transmission capacity;
•
changes in power transmission or fuel transportation capacity constraints or inefficiencies;
•
power supply disruptions, including power plant outages and transmission disruptions;
•
weather
conditions, particularly unusually mild summers or warm winters in our market areas;
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•
quarterly and seasonal fluctuations;
•
an economic downturn which could negatively impact demand for power;
•
changes
in commodity prices and the supply of commodities, including but not limited to coal, natural gas and fuel oil;
•
changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools and practices;
•
development of new fuels or new technologies for the production or storage of power;
•
federal
and state regulations and actions of the ISOs;
•
federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply;
•
changes in prices related to RECs; and
•
changes
in capacity prices and capacity markets.
These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the future.
Our revenues and results of operations depend on market rules, regulation and other forces beyond our control.
Our revenues and results of operations are influenced by factors that are beyond our control, including:
•
rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;
•
regulations
promulgated by the FERC and the CFTC;
•
sufficient liquidity in the forward commodity markets to conduct our hedging activities;
•
some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may impact our ability to sell our power at economical rates;
•
structure
and operating characteristics of our capacity markets such as our PJM capacity auctions and our NYISO markets; and
•
regulations and market rules related to our RECs.
Accounting for our hedging activities may increase the volatility in our quarterly and annual financial results.
We engage in commodity-related marketing and price-risk management activities in order to economically hedge our exposure to market risk with respect to power sales from our power plants, fuel utilized by those assets and emission allowances. We generally attempt to balance our fixed-price physical and financial purchases, and sales commitments in terms of contract
volumes and the timing of performance and delivery obligations through the use of financial and physical derivative contracts. These derivatives are accounted for under U.S. GAAP, which requires us to record all derivatives on the balance sheet at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. As a result, we are unable to accurately predict the impact that our risk management decisions may have on our quarterly and annual financial results.
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 risks related to commodity price movements, deviations in weather and 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.
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In addition, we have various internal policies and procedures designed to monitor hedging activities and positions. These policies and procedures are designed, in part, to prevent unauthorized purchases or sales of products by our employees. We cannot assure, however, that these steps will detect and prevent all violations of our Risk Management Policy, particularly if deception or other intentional misconduct is involved. A significant policy violation that is not detected could result in a material financial loss for us.
Our
ability to enter into hedging agreements and manage our counterparty credit risk could adversely affect us.
Our customer and supplier counterparties may experience deteriorating credit. These conditions could cause counterparties in the natural gas and power markets, particularly in the energy commodity derivative markets that we rely on for our hedging activities, to withdraw from participation in those markets. If multiple parties withdraw from those markets, market liquidity may be threatened, which in turn could adversely impact our business and create more volatility in our earnings. Additionally, these conditions may cause our counterparties to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code. Our credit risk may be exacerbated to the extent collateral held by us cannot be realized or is liquidated at prices not sufficient to recover the full amount of the exposure
due to us. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not materially and adversely affect our financial condition, results of operations and cash flows.
Competition in the power generation industry 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. This competition has put pressure on power utilities to lower their costs, including the cost of purchased power, and increasing competition in the supply of power in the future could increase this pressure. In addition, construction during the last decade has created excess power supply and higher reserve margins in the power trading markets, putting downward pressure on
prices.
Other companies we compete with may have greater liquidity, greater access to credit and other financial resources, lower cost structures, greater ability to incur losses, longer-standing relationships with customers, greater potential for profitability from ancillary services or greater flexibility in the timing of their sale of generation capacity and ancillary services than we do.
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;
•
failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;
•
failure of a power plant to achieve certain output
or efficiency minimums;
•
our failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of or increase any required collateral;
•
failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;
•
a material
breach of a representation or warranty or our failure to observe, comply with or perform any other material obligation under the contract; or
•
events of liquidation, dissolution, insolvency or bankruptcy.
Revenue may be reduced significantly upon expiration or termination of our PPAs.
Some of the capacity from our existing portfolio is sold under long-term PPAs that expire at various times. We seek to sell any capacity not sold under long-term PPAs, on a short-term basis as market opportunities arise. Our non-contracted capacity is generally sold
on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for the generation of power under subsequent arrangements or in short-term markets may be significantly less than the price that had been paid to us under the PPA. Power plants without long-term PPAs involve risk and uncertainty in forecasting future demand load for merchant sales because they are exposed to market fluctuations for some or all of their generating capacity and output. A significant under- or over-estimation of load requirements may increase our operating costs. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power plants at commercially attractive rates and these power plants may not be able to operate profitably. Certain of our PPAs have
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values
in excess of current market prices. We are at risk of loss of margins to the extent that these contracts expire or are terminated and we are unable to replace them on comparable terms. Additionally, our PPAs contain termination provisions standard to contracts in our industry such as negligence, performance default or prolonged events of force majeure.
The introduction or expansion of competing technologies for power generation and demand-side management tools could adversely affect our performance.
The power generation business has seen a substantial change in the technologies used to produce power. With federal and state incentives for the development and production of renewable
sources of power, we have seen market penetration of competing technologies, such as wind, solar, and commercial-sized power storage. Additionally, the development of demand-side management tools and practices can impact peak demand requirements for some of our markets at certain times during the year. The continued development of subsidized, competing power generation technologies and significant development of demand-side management tools and practices could alter the market and price structure for power and negatively impact our financial condition, results of operations and cash flows.
Power Operations
Our power generating operations performance involves significant risks and hazards and may be below expected levels of output or efficiency.
The operation of power plants involves risks, including the breakdown or failure of power generation
equipment, transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency and risks related to the creditworthiness of our contract counterparties and the creditworthiness of our counterparties’ customers or other parties, such as steam hosts, with whom our counterparties have contracted. From time to time our power plants have experienced unplanned outages, including extensions of scheduled outages due to equipment breakdowns, failures or other problems and are an inherent risk of our business. Unplanned outages typically can result in lost revenues, increase our maintenance expenses and may reduce our profitability, which could have a material adverse effect on our financial condition, results of operations and cash flows.
In addition, an unplanned outage may prevent the affected
power plant from performing under any applicable PPAs, commodity contracts or other contractual arrangements. Such failure may allow a counterparty to terminate an agreement and/or seek liquidated damages, and we could incur costs to cover our hedges. Although insurance is maintained to partially protect against operating risks, the proceeds of insurance may not be adequate to cover lost revenues or increased expenses. As a result, we could be unable to service principal and interest payments under, or may otherwise breach, our financing obligations, particularly with respect to the affected power plant, which could result in losing our interest in the affected power plant or, possibly, one or more other power plants.
We may be subject to future claims, litigation and enforcement.
Our power
generating operations are inherently hazardous and may lead to catastrophic events, including loss of life, personal injury and destruction of property, and subject us to litigation. Natural gas is highly explosive and power generation involves hazardous activities, including acquiring, transporting and delivering fuel, operating large pieces of rotating equipment and delivering power to transmission and distribution systems. These and other hazards can cause severe damage to and destruction of property, plant and equipment and suspension of operations. In the worst circumstances, catastrophic events can cause significant personal injury or loss of life. Further, the occurrence of any one of these events may result in us being named as a defendant in lawsuits asserting claims for substantial damages. We maintain an amount of insurance protection that we consider adequate; however, we cannot provide any assurance that the insurance will be sufficient or effective under
all circumstances and against all hazards or liabilities to which we are subject.
Additionally, we are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. We review our litigation activities and determine if an unfavorable outcome to us is considered “remote,”“reasonably possible” or “probable” as defined by U.S. GAAP. Where we have determined an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. A successful claim against us that is not fully insured could be material. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss.
The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows. See also Note 15 of the Notes to Consolidated Financial Statements for a description of our more significant litigation matters.
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We rely on power transmission and fuel distribution facilities owned and operated by other companies.
We depend on facilities and assets that we do not own or control for the transmission to our customers of the power produced
by our power plants and the distribution of natural gas fuel or fuel oil to our power plants. If these transmission and distribution systems are disrupted or capacity on those systems is inadequate, our ability to sell and deliver power products or obtain fuel may be hindered. ISOs that oversee transmission systems in regional power markets have imposed price limitations and other mechanisms to address volatility in their power markets. Existing congestion, as well as expansion of transmission systems, could affect our performance, which in turn could adversely impact our business.
Our power project development and construction activities involve risk and may not be successful.
The development and construction of power plants is subject to substantial risks. In connection with the development of a power plant, we must generally obtain:
•
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
To the extent that our development and construction activities continue or expand, we may be unsuccessful on a timely and profitable basis. Although we may attempt to minimize the financial risks of these activities by securing a favorable
PPA and arranging adequate financing prior to the commencement of construction, the development of a power project may require us to expend significant cash sums for preliminary engineering, permitting, legal and other expenses before we can determine whether a project is feasible, economically attractive or financeable. The process for obtaining governmental permits and approvals is complicated and lengthy, often taking more than one year, and is subject to significant uncertainties. We may be unable to obtain all necessary licenses, permits, approvals and certificates for proposed projects, and completed power plants may not comply with all applicable permit conditions, statutes or regulations. In addition, regulatory compliance for the construction and operation of our power plants can be a costly and time-consuming process. Intricate and changing environmental and other regulatory requirements may necessitate substantial expenditures to obtain and maintain permits.
If a project is unable to function as planned due to changing requirements, loss of required permits or regulatory status or local opposition, it may create expensive delays, extended periods of non-operation or significant loss of value in a project resulting in potential impairments.
We may be unable to obtain an adequate supply of fuel in the future.
We obtain substantially all of our physical natural gas and fuel oil supply from third parties pursuant to arrangements that vary in term, pricing structure, firmness and delivery flexibility. Our physical natural gas and fuel oil supply arrangements must be coordinated with transportation agreements, balancing agreements, storage services, financial hedging transactions and other contracts so that the natural gas and fuel oil is delivered to
our power plants at the times, in the quantities and otherwise in a manner that meets the needs of our generation portfolio and our customers. We must also comply with laws and regulations governing natural gas transportation.
While adequate supplies of natural gas and fuel oil are currently available to us at prices we believe are reasonable for each of our power plants, we are exposed to increases in the price of natural gas and fuel oil, and it is possible that sufficient supplies to operate our portfolio profitably may not continue to be available to us. In addition, we face risks with regard to the delivery to and the use of natural gas and fuel oil by our power plants including the following:
•
transportation may
be unavailable if pipeline infrastructure is damaged or disabled;
•
pipeline tariff changes may adversely affect our ability to, or cost to, deliver natural gas and fuel oil supply;
•
third-party suppliers may default on natural gas supply obligations, and we may be unable to replace supplies currently under contract;
•
market
liquidity for physical natural gas and fuel oil or availability of natural gas and fuel oil services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
35
•
natural gas and fuel oil quality variation may adversely affect our power plant operations;
•
our natural gas and fuel oil operations capability may be compromised due to various
events such as natural disaster, loss of key personnel or loss of critical infrastructure;
•
fuel supplies diverted to residential heating for humanitarian reasons; and
•
any other reasons.
Our power plants and construction projects are subject to impairments.
If we were to experience a significant reduction in our expected revenues and operating cash flows for an extended period of time from a prolonged economic
downturn or from advances or changes in technologies, we could experience future impairments of our power plant assets as a result. There can be no assurance that any such losses or impairments to the carrying value of our financial assets would not have a material adverse impact on our financial condition, results of operations and cash flows.
Our geothermal power reserves may be inadequate for our operations.
In connection with each geothermal power plant, we estimate the productivity of the geothermal resource and the expected decline in productivity. The productivity of a geothermal resource may decline more than anticipated, resulting in insufficient reserves being available for sustained generation of the power capacity desired. In addition, we may not be able to successfully manage the development and operation of our geothermal reservoirs or accurately estimate the quantity
or productivity of our steam reserves. An incorrect estimate or inability to manage our geothermal reserves or a decline in productivity could adversely affect our results of operations or financial condition. In addition, the development and operation of geothermal power resources are subject to substantial risks and uncertainties. The successful exploitation of a geothermal power resource ultimately depends upon many factors including the following:
•
the heat content of the extractable steam or fluids;
•
the geology of the reservoir;
•
the
total amount of recoverable reserves;
•
operating expenses relating to the extraction of steam or fluids;
•
price levels relating to the extraction of steam, fluids or power generated; and
•
capital expenditure requirements relating primarily to the drilling of new wells.
Significant
events beyond our control, such as natural disasters or acts of terrorism, could damage our power plants or our corporate offices and may impact us in unpredictable ways.
Certain of our geothermal and natural gas-fired power plants, particularly in the West, are subject to frequent low-level seismic disturbances. More significant seismic disturbances are possible. In addition, other areas in which we operate, particularly in Texas and the Southeast, experience tornados and hurricanes. Similarly, operations at our corporate offices in Houston, Texas could be substantially affected by a hurricane. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our generation business is dependent. Our existing power plants are built to withstand relatively significant levels of seismic and other disturbances, and we believe we maintain adequate insurance protection. However,
earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of serious damages or disturbances to our power plants or our operations due to natural disasters.
In addition to physical damage to our power plants, the risk of future terrorist activity could result in adverse changes in the insurance markets and disruptions in the power and fuel markets. These events could also adversely affect the U.S. economy, create instability in the financial markets and, as a result, have an adverse effect on our ability to access capital on terms and conditions acceptable to us.
Our business, financial condition and results of operations could be adversely impacted by strikes or work stoppages by unionized employees or by our inability to replace key employees.
Approximately 8%
of our employees are subject to collective bargaining agreements. In the event that our union employees participate in a strike, work stoppage or engage in other forms of labor disruption, we would be responsible for procuring replacement labor and could experience reduced power generation or outages.
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In addition, 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.
We depend on computer and telecommunications systems we do not own or control
and failures in our systems or cyber security attacks could significantly disrupt our business operations.
We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with the operation of our power plants. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We also rely on software systems owned and operated by third parties such as ISOs and RTOs to be functioning in order to be able to transmit the electricity produced by our power plants to our customers. It is possible we or a third party that we rely on could incur interruptions from a loss of communications, hardware or software failures, cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related vendors and maintain
adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties, to our computing and communications infrastructure, or our information systems or any of those operated by a third party that we rely on functioning could significantly disrupt our business operations.
Capital Resources; Liquidity
We have substantial liquidity needs and could face liquidity pressure.
As of December 31, 2014, our consolidated debt outstanding was $11.3 billion, of which approximately $7.7 billion was outstanding under our First Lien Notes, Senior Unsecured Notes and First Lien Term Loans. In addition, we had $644 million
issued in letters of credit and our pro rata share of unconsolidated subsidiary debt was approximately $171 million. Although we significantly extended our maturities during the last five years, we could face liquidity challenges as we continue to have substantial debt and substantial liquidity needs in the operation of our business. Our ability to make payments on our indebtedness, to meet margin requirements and to fund planned capital expenditures and development efforts will depend on our ability to generate cash in the future from our operations and our ability to access the capital markets. This, to a certain extent, is dependent upon industry conditions, as well as general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control, as discussed further in “— Commercial Operations” above. Although we are permitted to enter into new project financing credit facilities
to fund our development and construction activities, there can be no assurance that we will not face liquidity pressure in the future.
We also have exposure to many different financial institutions and counterparties including those under our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans, Corporate Revolving Facility and other credit and financing arrangements as we routinely execute transactions in connection with our hedging and optimization activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. 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 indebtedness could adversely impact our financial health and limit our operations.
Our indebtedness has important consequences, including:
•
limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth or other purposes;
•
limiting our ability to use operating cash flows in other areas of our business because
we must dedicate a substantial portion of these funds to service our debt;
•
increasing our vulnerability to general adverse economic and industry conditions;
•
limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in governmental regulation;
•
limiting
our ability or increasing the costs to refinance indebtedness or to repurchase equity issued by certain of our subsidiaries to third parties; and
•
limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of counterparties with whom we can transact as well as the volume and type of those transactions.
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We may be unable to obtain additional financing or access the credit and capital markets in the future
at prices that are beneficial to us or at all.
If our available cash, including future cash flows generated from operations, is not sufficient in the near term to finance our operations, post collateral or satisfy our obligations as they become due, we may need to access the capital and credit markets. Our ability to arrange financing (including any extension or refinancing) and the cost of the financing is dependent upon numerous factors, including general economic and capital market conditions. Market disruptions such as those experienced in the U.S. and abroad in recent years, may increase our cost of borrowing or adversely affect our ability to access capital. In addition, we believe these conditions have and may continue to have an adverse effect on the price of our common stock, which in turn may also reduce our ability to access capital or credit markets. Other factors include:
•
low
credit ratings may prevent us from obtaining any material amount of additional debt financing;
•
conditions in energy commodity markets;
•
regulatory developments;
•
credit availability from banks or other lenders for us and our industry peers;
•
investor
confidence in the industry and in us;
•
the continued reliable operation of our current power plants; and
•
provisions of tax, regulatory and securities laws that are conducive to raising capital.
While we have utilized non-recourse or lease financing when appropriate, market conditions and other factors may prevent us from completing similar financings in the future. It is possible that we may be unable to obtain the financing required to develop, construct,
acquire or expand power plants on terms satisfactory to us. We have financed our existing power plants using a variety of leveraged financing structures, including senior secured and unsecured indebtedness, construction financing, project financing, term loans and lease obligations. In the event of a default under a financing agreement which we do not cure, the lenders or lessors would generally have rights to the power plant and any related assets. In the event of foreclosure after a default, we may not be able to retain any interest in the power plant or other collateral supporting such financing. In addition, any such default or foreclosure may trigger cross default provisions in our other financing agreements.
Our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and our other debt instruments impose restrictions on us and any failure to comply with these restrictions
could have a material adverse effect on our liquidity and our operations.
The restrictions under our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and other debt instruments could adversely affect us by limiting our ability to plan for or react to market conditions or to meet our capital needs and, if we were unable to comply with these restrictions, could result in an event of default under these debt instruments. These restrictions require us to meet certain financial performance tests on a quarterly basis and limit or prohibit our ability, subject to certain exceptions to, among other things:
•
incur or guarantee additional first lien indebtedness up
to certain consolidated net tangible asset ratios;
•
enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
•
enter into sale and leaseback transactions;
•
make certain investments;
•
create
or incur liens;
•
consolidate or merge with or transfer all or substantially all of our assets to another entity, or allow substantially all of our subsidiaries to do so;
•
lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
•
engage
in certain business activities; and
•
enter into certain transactions with our affiliates.
Our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans 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
38
continuing
under such debt, the lenders or the holders or trustee of the First Lien Notes, as applicable, could give notice and declare outstanding borrowings and other obligations under such debt immediately due and payable.
Our ability to comply with these covenants may be affected by events beyond our control, and any material deviations from our forecasts could require us to seek waivers or amendments of covenants or alternative sources of financing or to reduce expenditures. We may not be able to obtain such waivers, amendments or alternative financing, or if obtainable, it could be on terms that are not acceptable to us. If we are unable to comply with the terms of our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans, Corporate Revolving Facility, CCFC Term Loans and our other debt instruments, or if we fail to generate sufficient cash flows from operations, or if it becomes necessary to obtain such waivers, amendments
or alternative financing, it could adversely impact our financial condition, results of operations and cash flows.
Our credit status is below investment grade, which may restrict our operations, increase our liquidity requirements and restrict financing opportunities.
There are a number of factors that rating agencies evaluate to arrive at credit ratings for us and our subsidiaries, including regulatory framework, ability to recover costs and earn returns, diversification, financial strength and liquidity. If one or more rating agencies downgrade us, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit collateral demands may be triggered by the terms of a number of commodity contracts,
leases and other agreements.
Our corporate and debt credit ratings are below investment grade. There is no assurance that our credit ratings will improve in the future, which may restrict the financing opportunities available to us or may increase the cost of any available financing. Our current credit rating has resulted in the requirement that we provide additional collateral in the form of letters of credit or cash for credit support obligations and may adversely impact our subsidiaries’ and our financial position and results of operations.
Certain of our obligations are required to be secured by letters of credit or cash, which increase our costs; if we are unable to provide such security it may restrict our ability to conduct our business.
Companies
using derivatives, which include many commodity contracts, are subject to the inherent risks of such transactions. Consequently, many such companies, including us, may be required to post cash collateral for certain commodity transactions; and, the level of collateral will increase as a company increases its hedging activities. We use margin deposits, prepayments and letters of credit as credit support for commodity procurement and risk management activities. Future cash collateral requirements may increase based on the extent of our involvement in standard contracts and movements in commodity prices, and also based on our credit ratings and general perception of creditworthiness in this market. Certain of our financing arrangements for our power plants have required us to post letters of
credit which are at risk of being drawn down in the event we, or the applicable subsidiary, default on our obligations.
Many of our collateral agreements require that letters of credit posted as collateral must be issued by a financial institution with a minimum credit rating of “A”. Currently the financial institutions that issue letters of credit under our Corporate Revolving Facility and other letter of credit facilities meet or exceed the minimum credit rating criteria. However, if one or more of these financial institutions is no longer able to meet the minimum credit rating criteria, then we could be required to post collateral funding from our cash and cash equivalents which could negatively impact our liquidity.
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, 2014, we had $644 million issued in letters of credit under our Corporate Revolving Facility and other facilities, with $1.3 billion remaining available for borrowing or for letter of credit support under our Corporate Revolving Facility. In addition, we have ratably secured our obligations under certain of our power and natural gas agreements that qualify as eligible commodity hedge agreements with the assets subject to liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility.
Additionally, changes in market regulations can increase the use of credit support and collateral.
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We may not have sufficient liquidity to hedge market risks effectively.
We are exposed to market risks through our sale of power, capacity and related products and the purchase and sale of fuel, transmission services and emission allowances. These market risks include, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel, converting fuel into power and delivering the power to a buyer.
We undertake these activities through agreements with various counterparties, many of which require us to provide guarantees, offset or netting arrangements, letters of credit, a second lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency.
The amount of such credit support that must be provided typically is based on the difference between the price of the commodity in a given contract and the market price of the commodity. Significant movements in market prices can result in our being required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral in support of performance guarantees or as a cash margin, we may not be able to manage price volatility effectively or to implement our strategy. An increase in the amount of letters
of credit or cash collateral required to be provided to our counterparties may negatively affect our liquidity and financial condition.
Further, if any of our power plants experience unplanned outages, we may be required to procure replacement power at spot market prices in order to fulfill contractual commitments. Without adequate liquidity to meet margin and collateral requirements, we may be exposed to significant losses, may miss significant opportunities and may have increased exposure to the volatility of spot markets.
Our ability to receive future cash flows generated from the operation of our subsidiaries may be limited.
Almost all of our operations are conducted through our subsidiaries
and other affiliates. As a result, we depend almost entirely upon their earnings and cash flows to service our indebtedness, post collateral and finance our ongoing operations. Certain of our project debt and other agreements restrict our ability to receive dividends and other distributions from our subsidiaries. Some of these limitations are subject to a number of significant exceptions (including exceptions permitting such restrictions in connection with certain subsidiary financings). Accordingly, the financing agreements of certain of our subsidiaries and other affiliates generally restrict their ability to pay dividends, make distributions or otherwise transfer funds to us prior to the payment of their other obligations, including their outstanding debt, operating expenses, lease payments
and reserves or during the existence of a default.
We may utilize project financing, preferred equity and other types of subsidiary financing transactions when appropriate in the future, which could increase our debt and may be structurally senior to other debt such as our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility.
Our ability and the ability of our subsidiaries to incur additional indebtedness are limited in some cases by existing indentures, debt instruments or other agreements. Our subsidiaries may incur additional construction/project financing indebtedness, issue preferred equity
to finance the acquisition and development of new power plants and engage in certain types of non-recourse financings to the extent permitted by existing agreements, and may continue to do so in order to fund our ongoing operations. Any such newly incurred subsidiary preferred equity would be added to our current consolidated debt levels and would likely be structurally senior to our debt, which could also intensify the risks associated with our already existing leverage.
Our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility are effectively subordinated to certain project indebtedness.
Certain of our subsidiaries and other affiliates are separate and distinct legal entities and, except in limited circumstances, have no obligation to pay any amounts due with respect to
our indebtedness or indebtedness of other subsidiaries or affiliates, and do not guarantee the payment of interest on or principal of such indebtedness. In the event of our bankruptcy, liquidation or reorganization (or the bankruptcy, liquidation or reorganization of a subsidiary or affiliate), such subsidiaries’ or other affiliates’ creditors, including trade creditors and holders of debt issued by such subsidiaries or affiliates, will generally be entitled to payment of their claims from the assets of those subsidiaries or affiliates before any assets are made available for distribution to us or the holders
of our indebtedness. As a result, holders of our indebtedness will be effectively subordinated to all present and future debts and other liabilities (including trade payables) of certain of our subsidiaries. As of December 31, 2014, our subsidiaries had approximately $1.6 billion in debt from our CCFC subsidiary and approximately $1.8 billion in secured project financing from other subsidiaries, which are effectively senior to our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. We may incur additional project financing indebtedness in
the future, which will be effectively senior to our other secured and unsecured debt.
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Governmental Regulation
Existing and proposed federal and state RPS and energy efficiency, as well as economic support for renewable sources of power under federal or state legislation could adversely impact our operations.
Federal policymakers have been considering imposing a national RPS on retail power providers. California already has an RPS in effect and in 2011 signed into law legislation requiring implementation of a 33% RPS by 2020. A number of additional states, including Maine, Minnesota, New York, Texas and Wisconsin, have an array of different RPS in place. Existing state-specific RPS requirements
may change due to regulatory and/or legislative initiatives, and other states may consider implementing enforceable RPS in the future. A national RPS or more robust RPS in states in which we are active, coupled with economic incentives provided under the federal stimulus package, would likely initially drive up the number of wind and solar resources, increasing power supply to various markets which could negatively impact the dispatch of our natural gas-fired power plants, primarily in Texas and California.
Similarly, federal legislators are considering national energy efficiency initiatives. Several states already have energy efficiency initiatives in place while others are considering imposing them. Improved energy efficiency when mandated by law or promoted by government sponsored incentives can decrease demand for power which could negatively impact the dispatch of our natural gas-fired power plants, primarily in Texas
and California.
Increased oversight and investigation by the CFTC relating to derivative transactions, as well as certain financial institutions, could have an adverse impact on our ability to hedge risks associated with our business.
The CFTC has regulatory oversight of the futures markets, including trading on NYMEX for energy, and licensed futures professionals such as brokers, clearing members and large traders. In connection with its oversight of the futures markets and NYMEX, the CFTC regularly investigates market irregularities and potential manipulation of those markets. Recent laws also give the CFTC certain powers with respect to broker-type markets referred to as “exempt commercial markets” or ECMs, including the Intercontinental Exchange. The CFTC monitors activities in the OTC, ECM and physical markets that may be undertaken for the purpose of influencing futures
prices. With respect to ECMs, the CFTC exercises only light-handed regulation primarily related to trade reporting, price dissemination and record retention (including retention of fraudulent claims and allegations).
Changes in the regulation of the power markets in which we operate could negatively impact us.
We have a significant presence in the major competitive power markets for California, Texas and the Northeast region of the U.S. While these markets are largely deregulated, they continue to evolve. Existing regulations within the markets in which we operate may be revised or reinterpreted and new laws or regulations may be issued. We cannot predict the future development of regulation or legislation nor the ultimate effect such changes in these markets could have on our business; however, we could be negatively impacted.
Existing
and future anticipated GHG/Carbon and other environmental regulations could cause us to incur significant costs and adversely affect our operations generally or in a particular quarter when such costs are incurred.
Environmental laws and regulations have generally become more stringent over time, and this trend is likely to continue. In particular, there is growing likelihood that carbon tax or limits on carbon, CO2 and other GHG emissions will be implemented at the federal or expanded at the state or regional levels.
In 2009, ten states in the Northeast began the compliance period of a Cap-and-Trade program, RGGI, to regulate CO2 emissions from power plants. California has implemented AB 32 which places a statewide cap on GHG emissions and requires the state to return to 1990 emission levels
by 2020. In December 2010, CARB adopted a regulation establishing a GHG Cap-and- trade program which is in effect for electric utilities and other “major industrial sources,” and in 2015 for certain other GHG sources.
In 2011, the EPA finalized regulations governing GHG emissions from major sources as well as emissions of criteria and hazardous air pollutants from the electric generation sector. We continue to monitor and actively participate in the EPA initiatives where we anticipate a material impact on our business.
Further, air regulations enacted in New Jersey that further limit NOX emissions from turbines and boilers beginning in 2015 will impact six of our power plants that will either need to retire or install additional NOX controls to continue operating beyond 2015. We plan
to install emissions controls equipment at two of these power plants, have retired one power plant in 2014 and expect to retire the remaining three power plants in 2015. We do not expect the retirement of these power plants or installation of emissions controls to have a material impact on our financial condition, results of operations or cash flows.
41
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. We could also be required to install expensive pollution control measures or limit or cease activities, including the retirement of certain generating plants, based on these regulations. 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. We could be determined to have market power if these existing significant shareholders acquire additional significant ownership or equity interest in other entities with power generating assets in the same markets where we generate and sell power.
If FERC makes the determination that we have market power, FERC could, among other things, revoke market-based rate authority for the affected market-based companies or order them to mitigate that market power. If market-based rate authority was revoked
for any of our market-based rate companies, those companies would be required to make wholesale sales of power based on cost-of-service rates, which could negatively impact their revenues. If we are required to mitigate market power, we could be required to sell certain power plants in regions where we are determined to have market power. A loss of our market-based rate authority or required sales of power plants, particularly if it affected several of our power plants or was in a significant market, could have a material negative impact on our financial condition, results of operations and cash flows.
Item 1B.
Unresolved Staff Comments
None.
Item
2.
Properties
Our principal executive offices are located in Houston, Texas. This facility is leased until 2020. We also have regional offices in Dublin, California and Wilmington, Delaware, an engineering, construction and maintenance services office in Pasadena, Texas and government affairs offices in Washington D.C., Sacramento, California and Austin, Texas.
We either lease or own the land upon which our power plants are built. We believe that our properties are adequate for our current operations. A description of our power plants is included under Item 1. “Business —Description of Our Power Plants.”
Item
3.
Legal Proceedings
See Note 15 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.
Item 4.
Mine Safety Disclosures
Not applicable.
42
PART II
Item
5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information and Stockholder Matters
Calpine Corporation common stock is traded on the NYSE under the symbol “CPN”. The following table sets forth the high and low bid prices for our common stock for each quarter of the years 2014 and 2013, as reported on the NYSE.
High
Low
2014
First
Quarter
$
21.06
$
18.46
Second Quarter
24.24
20.48
Third
Quarter
24.04
21.27
Fourth Quarter
24.37
19.60
2013
First
Quarter
$
20.62
$
17.95
Second Quarter
22.16
19.33
Third
Quarter
21.97
18.59
Fourth Quarter
21.03
18.74
As of December 31, 2014, there were
129 stockholders of record of our common stock.
We have never paid cash dividends on our common stock. Future cash dividends, if any, will be at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Repurchase of Equity Securities
Period
(a)
Total Number of
Shares Purchased(1)
(b)
Average Price
Paid Per Share
(c)
Total Number
of
Shares Purchased
as Part of
Publicly Announced
Plans or Programs(2)
(d)
Maximum Dollar Value of Shares That May
Yet Be Purchased
Under the Plans or
Programs (in millions)
October
7,204,830
$
21.31
7,204,263
$
285
November
2,250,705
$
23.22
2,249,735
$
233
December
5,956,850
$
21.55
5,894,561
$
106
Total
15,412,385
$
21.68
15,348,559
$
106
___________
(1)
Upon
vesting of restricted stock awarded by us to employees, we withhold shares to cover employees’ tax withholding obligations, other than for employees who have chosen to satisfy their tax withholding obligations in cash. During the fourth quarter of 2014, we withheld a total of 63,826 shares that are included in total number of shares purchased. In addition, our Board of Directors approved the repurchase of 13,213,372 shares of our common stock from a shareholder for approximately $311 million in a private transaction that was completed in July 2014.
(2)
In November 2013, our Board of Directors authorized a $1 billion
multi-year share repurchase program. During 2014, we repurchased a total of 36.5 million shares of our common stock, excluding shares repurchased in (1) above, for approximately $789 million at an average price of $21.62 per share under this program.
In 2015, through the filing of this Report, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share.
43
Stock
Performance Graph
The performance graph below compares cumulative return on our common stock for the period December 31, 2009 through December 31, 2014, with the cumulative return of Standard & Poor’s 500 Index (S&P 500) and the S&P 500 Utilities Index.
The graph below compares each period assuming that $100 was invested on December 31, 2009 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.
Income
(loss) before discontinued operations attributable to Calpine
$
946
$
14
$
199
$
(190
)
$
(162
)
Discontinued
operations, net of tax expense, attributable to Calpine
—
—
—
—
193
Net
income (loss) attributable to Calpine
$
946
$
14
$
199
$
(190
)
$
31
Basic
earnings (loss) per common share:
Income (loss) before discontinued operations attributable to Calpine
$
2.34
$
0.03
$
0.43
$
(0.39
)
$
(0.33
)
Discontinued
operations, net of tax expense, attributable to Calpine
—
—
—
—
0.39
Net
income (loss) per common share attributable to Calpine
$
2.34
$
0.03
$
0.43
$
(0.39
)
$
0.06
Diluted
earnings (loss) per common share:
Income (loss) before discontinued operations attributable to Calpine
$
2.31
$
0.03
$
0.42
$
(0.39
)
$
(0.33
)
Discontinued
operations, net of tax expense, attributable to Calpine
—
—
—
—
0.39
Net
income (loss) per common share attributable to Calpine
$
2.31
$
0.03
$
0.42
$
(0.39
)
$
0.06
Balance
Sheet data:
Total assets
$
18,378
$
16,559
$
16,549
$
17,371
$
17,256
Short-term
debt and capital lease obligations
$
199
$
204
$
115
$
104
$
152
Long-term
debt and capital lease obligations
$
11,083
$
10,908
$
10,635
$
10,321
$
10,104
45
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Forward-Looking Information
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Financial Statements and related Notes. See the cautionary statement regarding forward-looking statements on page 1 of this Report for a description
of important factors that could cause actual results to differ from expected results. See also Item 1A. “Risk Factors.”
INTRODUCTION AND OVERVIEW
Our Business
We are one of the largest wholesale power generators in the U.S. measured by power produced. We own and operate primarily natural gas-fired and geothermal power plants in North America and have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment) of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators, industrial and agricultural companies,
retail power providers, municipalities, power marketers and others. As a result of our investment in cleaner power generation, we have become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of flexible and reliable power plants.
In order to manage our various physical assets and contractual obligations, we execute commodity and commodity transportation agreements within the guidelines of our Risk Management Policy. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. We also enter into natural gas, power and other physical and financial contracts to hedge certain business risks and optimize our portfolio
of power plants. Seasonality and weather can have a significant impact on our results of operations and are also considered in our hedging and optimization activities.
Our goal is to be recognized as the premier power generation company in the U.S. as measured by our employees, shareholders, customers and policy-makers as well as the communities in which our facilities are located.
We 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 and East (including Canada).
Our portfolio, including partnership interests, consists of 88 power plants, including one under construction located throughout 18
states in the U.S. and in Canada, with an aggregate current generation capacity of 26,548 MW and 309 MW under construction. Our fleet, including projects under construction, consists of 71 natural gas-fired combustion turbine-based plants, one fuel oil-fired steam-based plant, 15 geothermal steam turbine-based plants and one photovoltaic solar plant. Our segments have an aggregate generation capacity of 7,524 MW in the West, 9,427 MW in Texas and 9,597 MW with an additional 309 MW under construction in the East.
In addition to the unique profile of our fleet, we believe our business is also advantaged by our capital allocation philosophy, which seeks to maximize levered cash returns to equity on a per share basis. We currently consider the repurchases of our own shares of common stock as an attractive investment opportunity, and we utilize the expected returns from this investment as the benchmark against which we evaluate
all other capital allocation decisions. We believe this philosophy closely aligns our objectives with those of our shareholders.
Premier Operating Company
Our objective is to be the “best-in-class” in regards to certain operational performance metrics, such as safety, availability, reliability, efficiency and cost management.
•
During 2014, our employees achieved a lost time incident rate of 0.08 lost time injuries per 100 employees which places us in the first quartile performance for power generation companies with 1,000 or more employees.
•
Our
entire fleet achieved a forced outage factor of 1.9% and a starting reliability of 98.6% during the year ended December 31, 2014.
•
During 2014, our outage services subsidiary completed 14 major inspections and nine hot gas path inspections.
46
•
For the past 14 consecutive years, our Geysers Assets have reliably generated approximately
six million MWh of renewable power per year.
Managing and Growing our Portfolio
Our goal is to continue to grow our presence in core markets with an emphasis on acquisitions, expansions or modernizations of existing power plants. We intend to take advantage of favorable opportunities to continue to design, develop, acquire, construct and operate the next generation of highly efficient, operationally flexible and environmentally responsible power plants where such investment meets our rigorous financial hurdles, particularly if power contracts and financing are available and attractive returns are expected. Likewise, we actively seek to divest non-core assets where we can find opportunities to do so accretively.
In addition, we believe that modernizations and expansions to our current assets offer proven and financially disciplined opportunities to improve our operations, capacity and efficiencies. During 2014, we strategically repositioned our portfolio by divesting positions in non-core markets and adding capacity in our core regions through the following transactions:
•
On February 26, 2014, we completed the purchase of a modern, natural gas-fired, combined-cycle power plant with a nameplate capacity of 1,050 MW located in Guadalupe County, Texas for approximately $625 million, excluding working capital
adjustments, which increased capacity in our Texas segment. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker plant. Development efforts are ongoing and we are continuing to advance entitlements (such as permits, zoning and transmission).
•
In June 2014, we completed construction to expand the baseload capacity of our Deer Park and Channel Energy Centers by approximately 260 MW each. Each power plant featured an oversized steam turbine that, along with existing plant infrastructure, allowed us to add capacity and improve the power plant’s overall efficiency
at a meaningful discount to the market cost of building new capacity.
•
On July 3, 2014, we completed the sale of six of our power plants in our East segment for a purchase price of approximately $1.57 billion in cash, excluding working capital and other adjustments. The divestiture of these power plants has better aligned our asset base with our strategic focus on competitive wholesale markets.
•
On November 7, 2014,
we completed the purchase of Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant located in North Weymouth, Massachusetts, increased capacity in our East segment, specifically in the constrained New England market.
•
During the third quarter of 2014, we executed a PPA with Duke Energy Florida, Inc. related to our Osprey Energy Center with a term of 27 months which commenced in October 2014. Subsequently, we executed an asset sale agreement during the fourth quarter of 2014
for the sale of our Osprey Energy Center to Duke Energy Florida, Inc. upon the conclusion of the PPA for approximately $166 million, excluding working capital and other adjustments. The asset sale agreement is subject to federal and state regulatory approval and represents a strategic disposition of a power plant in a wholesale power market dominated by regulated utilities.
In addition, our significant ongoing projects under construction, growth initiatives and modernizations are discussed below:
•
Garrison Energy Center — Garrison Energy Center is a 309 MW combined-cycle project located in Delaware on a site secured by a long-term lease with the City of Dover. Once complete,
the power plant will feature one combustion turbine, one heat recovery steam generator and one steam turbine. Construction commenced in April 2013, and we expect COD during the second quarter of 2015. The project’s capacity has cleared each of PJM’s three most recent base residual auctions. We are in the early stages of development of a second phase (309 MW) of this project. PJM has completed the feasibility, system impact and facilities studies for this phase. The facilities study results are being internally evaluated.
•
York 2 Energy Center — York 2 Energy Center is a 760 MW dual fuel combined-cycle project that will be co-located with our York Energy Center in Peach Bottom Township, Pennsylvania. Once complete, the
power plant will feature two combustion turbines, two heat recovery steam generators and one steam turbine. The project’s capacity cleared PJM’s 2017/2018 base residual auction and we expect COD during the second quarter of 2017. We executed a preliminary notice to proceed for the engineering, procurement and construction agreement during the fourth quarter of 2014 and are currently pursuing key permits and approvals for the project. PJM is completing a feasibility study for increasing York 2 Energy Center’s capacity by 120 MW.
•
Mankato Power Plant Expansion — By order dated February 5, 2015, the Minnesota Public Utilities Commission concluded a competitive resource acquisition
proceeding and selected a 345 MW expansion of our Mankato Power Plant, authorizing execution of a 20-year PPA between Calpine and Xcel Energy. Commercial operation of the
47
expanded capacity may commence as early as June 2018, subject to applicable regulatory approvals and other contract conditions.
•
PJM Development Opportunities — We are currently evaluating opportunities to develop additional projects in the PJM market area that feature
cost advantages such as existing infrastructure and favorable transmission queue positions. These projects are continuing to advance entitlements (such as permits, zoning and transmission) for their potential future development.
•
Turbine Modernization — We continue to move forward with our turbine modernization program. Through December 31, 2014, we have completed the upgrade of thirteen Siemens and eight GE turbines totaling approximately 210 MW and have committed to upgrade three additional turbines. In addition, we have begun a program to update our dual-fueled turbines at
certain of our power plants in our East segment.
Customer-Oriented Origination Business
We continue to focus on providing products and services that are beneficial to our customers. A summary of certain significant contracts entered into in 2014 is as follows:
West
•
We entered into a new ten-year PPA, subject to approval by the CPUC, with Southern California Edison (“SCE”) to provide 225 MW of capacity and renewable energy from our Geysers Assets commencing
in June 2017.
•
We entered into a new ten-year PPA with the Sonoma Clean Power Authority to provide 15 MW of renewable power from our Geysers Assets commencing in January 2017. The capacity under contract will vary by year, increasing up to a maximum of 50 MW for years 2024 through 2026.
•
We entered into a new three-year resource adequacy contract
with SCE for our Pastoria Energy Facility commencing in January 2016. The capacity under contract will initially be 238 MW, and will increase to 476 MW during the final year of the contract.
•
We entered into a new two-year resource adequacy contract with SCE for our Delta Energy Center for 500 MW of capacity commencing in January 2017.
Texas
•
We
entered into a new six-year PPA with the City of San Marcos to provide power from our Texas power plant fleet commencing in July 2015.
•
We entered into a new two-year PPA with Pedernales Electric Cooperative to provide approximately 70 MW of power from our Texas power plant fleet commencing in August 2016.
•
We entered into a new one-year PPA with Guadalupe Valley Electric Cooperative to provide approximately 270 MW of power from our Texas power plant fleet commencing in June 2016.
East
•
We
entered into a new five-year PPA with Dairyland Power Cooperative to provide capacity and energy from our RockGen Energy Center commencing in June 2018. The capacity under contract will initially be 135 MW, and then will increase to 235 MW for the final four years of the contract.
•
We entered into a new PPA with a term of 27 months with Duke Energy Florida, Inc. to provide 515 MW of power and capacity from our Osprey Energy Center, which commenced in October 2014. The capacity under contract
increased to 580 MW beginning in January 2015.
Advocacy and Corporate Responsibility
We recognize that our business is heavily influenced by laws, regulations and rules at federal, state and local levels as well as by ISOs and RTOs that oversee the competitive markets in which we operate. We believe that being active participants in the legislative, regulatory and rulemaking processes may yield better outcomes for all stakeholders, including Calpine. Our two basic areas of focus are environmental stewardship in power generation and competitive wholesale power markets. Below are some recent examples of our advocacy efforts:
Ensuring Competitive Market Structure/Rules
•
Provided
leadership in stakeholder processes at PJM on a new “Capacity Performance” product and at ISO-NE on its Pay-For-Performance initiatives, resulting in pending FERC approval of the PJM Capacity Performance product and implementation of the FERC approved ISO-NE Pay-For-Performance capacity structure.
48
•
Our employees participated as invited panelists at FERC technical conferences regarding price formation and “out-of-market payments” in organized markets.
Stopping Non-Competitive/Subsidized Generation
•
Successfully
advocated for a competitive generation supply bidding process in Florida, resulting in a contract for the acquisition of our Osprey Energy Center rather than a utility self-build as the most cost effective alternative for Florida ratepayers.
•
Successfully advocated for a competitive generation supply bidding process in Minnesota, resulting in an order requiring the local utility to enter into a long-term PPA for new additional capacity at our Mankato Power Plant rather than a utility self-build as the most cost effective alternative for Minnesota ratepayers.
•
Provided
leadership in the successful legal challenges against New Jersey and Maryland for discriminatory behavior affecting FERC jurisdictional capacity auctions, resulting in decisions by the U.S. Circuit Court of Appeals for the Third and Fourth Circuits striking those state actions as violative of U.S. law.
•
Successfully advocated against proposed legislation in California requiring investor owned utilities to contract for 500 MW of new geothermal resources that would have discriminated against our existing geothermal fleet.
Environmental
•
Filed
a brief with the D.C. Circuit supporting the EPA’s MATS rules which were upheld by the Court.
•
Filed a brief with the U.S. Supreme Court supporting the EPA’s CSAPR rules which were upheld by the Court citing our brief in its opinion.
•
Filed a brief with the U.S. Supreme Court supporting the EPA’s GHG air permit rules which were upheld in part by the Court citing our brief in its opinion.
Federal and state legislative and regulatory actions continue to change
how our business is regulated. The EPA is moving forward on climate change regulation, and has already promulgated regulations related to other air pollutant emissions, and some states and regions in the U.S. have implemented or are considering implementing regulations to reduce GHG emissions. We are actively participating in these debates at the federal, regional and state levels as noted by the actions above. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Item 1. of this Report. Although we cannot predict the ultimate effect future climate change regulations or legislation could have on our business, we believe that we will be less adversely impacted by potential Cap-and-Trade limits, carbon taxes or required environmental upgrades as a result of existing and potential legislation or regulation addressing GHG or other emissions, water use or waste disposal, compared
to our competitors who use other fossil fuels or older, less efficient technologies.
Since our inception in 1984, we have been a leader in environmental stewardship and have invested in clean power generation to become a recognized leader in developing, constructing, owning and operating an environmentally responsible portfolio of power plants. The combination of our Geysers Assets and our high efficiency portfolio of natural gas-fired power plants results in substantially lower emissions of these gases compared to our competitors’ power plants using other fossil fuels, such as coal. Consequently, our power generation portfolio's GHG footprint per MWh is lower than most major wholesale power producers in the U.S. In addition, we strive to preserve our nation’s valuable water and land resources. To condense steam, we primarily use cooling towers with a closed water cooling system or air cooled condensers. Since our power plants
are modern and efficient and utilize clean burning natural gas, we do not require large areas of land for our power plants nor do we require large specialized landfills for the disposal of coal ash or nuclear plant waste.
Although different regions of the country have very different models and rules for competition, the markets in which we operate have some form of wholesale market competition. California (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment), which are the markets in which we have our largest presence, have emerged as among the most competitive wholesale power markets in the U.S. We also operate, to a lesser extent, in the competitive wholesale power markets in the Southeast and the Midwest. We believe that properly designed competitive wholesale markets offer the best signals for investment decisions, broader choices for customers and
the least cost solutions for reliable electric system operations.
Enhancing Shareholder Value
We continue to make significant progress to deliver financially disciplined growth, to enhance shareholder value through disciplined capital allocation including the return of capital to shareholders and to manage the balance sheet for future growth and success. Given our strong cash flow from operations, we are committed to remaining financially disciplined in our capital allocation decisions. The year ended December 31, 2014 was marked by the following accomplishments:
•
We
delivered annual TSR of 13.4%, in line with the S&P 500 Index.
49
•
We continued to return capital to our shareholders in the form of share repurchases, having cumulatively repurchased approximately $2.4 billion or 25% of our previously outstanding shares as of the filing of this Report.
•
Specifically during 2014, we repurchased a total of 49.7
million shares of our outstanding common stock for approximately $1.1 billion at an average price of $22.14 per share.
•
In 2015, through the filing of this Report, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share.
We further optimized our capital structure by refinancing or redeeming several of our debt instruments during the year
ended December 31, 2014, including the following transactions:
•
During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.
•
On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured
notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. We used the proceeds to repurchase secured debt with a higher fixed interest rate.
•
On July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
•
In December 2014, we used cash on
hand to redeem 10% of the original aggregate principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest.
Our Market and Our Key Financial Performance Drivers
The market Spark Spread, sales of RECs, revenues from our PPAs and steam sales and the results from our marketing, hedging and optimization activities are the primary drivers of our Commodity Margin and contribute significantly to our financial results. The market Spark Spread is primarily impacted by fuel prices, weather and reserve margins, which impact market supply and demand fundamentals. Those factors plus the relationship between our operating Heat Rate compared to the Market Heat Rate, our power plant operating performance and availability are key to our financial performance.
Fluctuations
in natural gas price levels affect our Commodity Margin (depending on our hedge levels and holding other factors constant). When less efficient, higher cost natural gas-fired units set power prices in our regional markets, higher natural gas prices tend to increase our Commodity Margin. In these instances, while our production costs increase when natural gas prices are higher, our competitors’ costs (and power prices) increase at a greater rate, leading to higher Commodity Margin. Similarly, when natural gas prices decline, our Commodity Margin tends to decline.
In 2012 and to a much lesser degree in 2013, given very low natural gas prices, natural gas-fired, combined-cycle units in many markets were frequently cheaper to dispatch than coal-fired power plants. When coal-fired electricity production costs exceed natural gas-fired production costs, coal-fired units tend to set power prices. In these hours, lower natural gas prices
tend to increase our Commodity Margin, since our production costs fall while power prices remain constant (depending on our hedge levels and holding other factors constant). Recent forward market natural gas prices suggest that coal-to-gas-switching could increase again during 2015 (although future market conditions are uncertain and settled prices remain to be seen).
Efficient operation of our fleet creates the opportunity to capture Commodity Margin in a cost effective manner. However, unplanned outages during periods when Commodity Margin is positive could result in a loss of that opportunity. We generally measure our fleet performance based on our availability factors, Heat Rate and plant operating expense. The higher our availability factor, the better positioned we are to capture Commodity Margin. The less natural gas we must consume for each MWh of power generated, the lower our Heat Rate. The lower our operating Heat
Rate compared to the Market Heat Rate, the more favorable the impact on our Commodity Margin. Holding all other factors constant, our Commodity Margin increases when we are able to lower our operating Heat Rate compared to the Market Heat Rate and conversely decreases when our operating Heat Rate increases compared to the Market Heat Rate. See also “— The Market for Power — Our Power Markets and Market Fundamentals” in Item 1. of this Report for additional information on how these factors impact our Commodity Margin.
Below
are our results of operations for the year ended December 31, 2014, as compared to the same period in 2013 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
2014
2013
Change
% Change
Operating
revenues:
Commodity revenue
$
7,595
$
6,374
$
1,221
19
Mark-to-market
gain (loss)
419
(86
)
505
#
Other revenue
16
13
3
23
Operating
revenues
8,030
6,301
1,729
27
Operating expenses:
Fuel
and purchased energy expense:
Commodity expense
4,815
3,808
(1,007
)
(26
)
Mark-to-market
(gain) loss
77
(72
)
(149
)
#
Fuel and purchased energy expense
4,892
3,736
(1,156
)
(31
)
Plant
operating expense
969
895
(74
)
(8
)
Depreciation and amortization expense
603
593
(10
)
(2
)
Sales,
general and other administrative expense
144
136
(8
)
(6
)
Other operating expenses
88
81
(7
)
(9
)
Total
operating expenses
6,696
5,441
(1,255
)
(23
)
Impairment losses
123
16
(107
)
#
(Gain)
on sale of assets, net
(753
)
—
753
#
(Income) from unconsolidated investments in power plants
(25
)
(30
)
(5
)
(17
)
Income
from operations
1,989
874
1,115
#
Interest expense
645
696
51
7
Interest
(income)
(6
)
(6
)
—
—
Debt extinguishment costs
346
144
(202
)
#
Other
(income) expense, net
21
20
(1
)
(5
)
Income before income taxes
983
20
963
#
Income
tax expense
22
2
(20
)
#
Net income
961
18
943
#
Net
income attributable to the noncontrolling interest
(15
)
(4
)
(11
)
#
Net income attributable to Calpine
$
946
$
14
$
932
#
2014
2013
Change
% Change
Operating
Performance Metrics:
MWh generated (in thousands)(1)
100,617
101,610
(993
)
(1
)
Average
availability
90.7
%
91.7
%
(1.0
)%
(1
)
Average total MW in operation(1)
26,652
26,854
(202
)
(1
)
Average
capacity factor, excluding peakers
48.4
%
48.7
%
(0.3
)%
(1
)
Steam Adjusted Heat Rate
7,384
7,386
2
—
__________
#
Variance
of 100% or greater
(1)
Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our total equity generation and capacities.
51
We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally
determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, increased $214 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, primarily due to:
•
generation
additions from our Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013, the acquisition of Guadalupe Energy Center in February 2014 and the completion of the expansions of our Deer Park and Channel Energy Centers in June 2014;
•
running some of our dual-fueled power plants in the East on fuel oil during the first quarter of 2014 rather than natural gas when the relative cost of consuming fuel oil was lower than natural gas; and
•
stronger market conditions resulting
in higher on-peak Spark Spreads in the West during 2014 compared to 2013; partially offset by
•
the sale of six power plants with a total capacity of 3,498 MW in our East segment on July 3, 2014;
•
the expiration of a tolling contract associated with our Delta Energy Center in December 2013 and a PPA associated with our Osprey Energy Center in May 2014 partially offset by a new
PPA associated with our Osprey Energy Center effective in October 2014; and
•
lower regulatory capacity revenue in PJM during the second half of 2014.
Mark-to-market gain/loss from hedging our future generation and fuel needs had a favorable variance of $356 million primarily driven by a decrease in forward power prices resulting from lower natural gas prices, which favorably impacted our power hedges during the year ended December 31, 2014 as compared to 2013.
Our plant operating expense increased
by $62 million during the year ended December 31, 2014, compared to the year ended December 31, 2013, after excluding an increase of $12 million attributable to power plant portfolio changes detailed above. Outside of portfolio changes, major maintenance and cost from scrap parts related to outages, our plant operating expense increased $52 million during the year ended December 31, 2014 compared to 2013 of which $14 million related to an increase in normal, recurring plant operating expense. The remaining increase primarily resulted from a $13 million increase in equipment failure costs related to outages, an $11 million reversal of Section 185 fees for which we determined we have no current or retroactive fee obligations during 2013 and a $14 million increase resulting from the 2014 reclassification of shared expenses
associated with our Freeport Energy Center and an increase in the accrual for performance-based compensation. We also experienced a $10 million increase in major maintenance expense resulting from our plant outage schedule, net of costs from scrap parts, related to outages during the year ended December 31, 2014 compared to 2013.
In line with our strategy to sell or contract power plants located in wholesale power markets dominated by regulated utilities and focus on competitive wholesale markets, we completed the sale of six of our power plants in our East segment on July 3, 2014, resulting in a gain on sale of assets, net of $753 million during the year ended December
31, 2014. In addition, we executed a term sheet with a third party related to our Osprey Energy Center in August 2014 for a new PPA with a term of 27 months, after which the third party would purchase our Osprey Energy Center. Although the asset sale agreement was executed in the fourth quarter of 2014 and remains subject to federal and state regulatory approval, the offer implied by the term sheet resulted in an impairment loss of approximately $123 million which was recorded during the third quarter of 2014. See Notes 2 and 3 of the Notes to Consolidated Financial Statements for further information regarding the impairment and the sale of six power plants, respectively.
Interest expense decreased by $51 million for the year ended December 31, 2014, compared to the year ended December
31, 2013, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, to 5.9% for the year ended December 31, 2014, from 6.7% for the year ended December 31, 2013. The issuance of our Senior Unsecured Notes in 2014 and CCFC Term Loans, 2022 First Lien Notes, 2024 First Lien Notes and 2020 First Lien Term Loan in 2013 allowed us to reduce our overall cost of debt by replacing our CCFC Notes and a portion of our First Lien Notes with debt carrying lower interest rates. The decrease in interest expense was partially offset by a decrease in capitalized interest of $19 million during the year ended December 31, 2014 compared to 2013 due primarily to our Russell City and Los Esteros power
plants commencing commercial operations during the third quarter of 2013.
52
Debt extinguishment costs for the year ended December 31, 2014, consisted primarily of $340 million related to the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes, which is comprised of $306 million of prepayment penalties and $34 million associated with the write-off of unamortized debt discount and deferred financing costs. Debt extinguishment costs for the year ended December 31, 2013, consisted primarily of $139 million relating to the repayment of the
CCFC Notes and the 2017 First Lien Notes and redeeming a portion of our First Lien Notes during 2013, which is comprised of $96 million of prepayment penalties and $43 million associated with the write-off of unamortized debt discount and deferred financing costs.
During the year ended December 31, 2014, we recorded income tax expense of $22 million compared to income tax expense of $2 million for the year ended December 31, 2013. The unfavorable year-over-year change primarily resulted from an increase in state income tax expense of $19 million which is related to an increase in income including the sale and disposition of assets, changes in state apportionment, and state law changes for the year ended December 31, 2014, compared
to the year ended December 31, 2013.
Net income attributable to the noncontrolling interest increased $11 million during the year ended December 31, 2014, compared to the year ended December 31, 2013 as our Russell City Energy Center commenced operations in August 2013.
Below
are our results of operations for the year ended December 31, 2013, as compared to the same period in 2012 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
2013
2012
Change
% Change
Operating
revenues:
Commodity revenue
$
6,374
$
5,417
$
957
18
Mark-to-market
gain (loss)
(86
)
48
(134
)
#
Other revenue
13
13
—
—
Operating
revenues
6,301
5,478
823
15
Operating expenses:
Fuel
and purchased energy expense:
Commodity expense
3,808
2,894
(914
)
(32
)
Mark-to-market
(gain) loss
(72
)
130
202
#
Fuel and purchased energy expense
3,736
3,024
(712
)
(24
)
Plant
operating expense
895
922
27
3
Depreciation and amortization expense
593
562
(31
)
(6
)
Sales,
general and other administrative expense
136
140
4
3
Other operating expenses
81
78
(3
)
(4
)
Total
operating expenses
5,441
4,726
(715
)
(15
)
Impairment losses
16
—
(16
)
#
(Gain)
on sale of assets, net
—
(222
)
(222
)
#
(Income) from unconsolidated investments in power plants
(30
)
(28
)
2
7
Income
from operations
874
1,002
(128
)
(13
)
Interest expense
696
736
40
5
Loss
on interest rate derivatives
—
14
14
#
Interest (income)
(6
)
(11
)
(5
)
(45
)
Debt
extinguishment costs
144
30
(114
)
#
Other (income) expense, net
20
15
(5
)
(33
)
Income
before income taxes
20
218
(198
)
(91
)
Income tax expense
2
19
17
89
Net
income
18
199
(181
)
(91
)
Net income attributable to the noncontrolling interest
(4
)
—
(4
)
#
Net
income attributable to Calpine
$
14
$
199
$
(185
)
(93
)
2013
2012
Change
% Change
Operating
Performance Metrics:
MWh generated (in thousands)(1)
101,610
112,216
(10,606
)
(9
)
Average
availability
91.7
%
91.3
%
0.4
%
—
Average total MW in operation(1)
26,854
27,318
(464
)
(2
)
Average
capacity factor, excluding peakers
48.7
%
53.7
%
(5.0
)%
(9
)
Steam Adjusted Heat Rate
7,386
7,361
(25
)
—
__________
54
#
Variance of 100% or greater
(1)
Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Projects Under Construction and Advanced Development” for our total equity generation and capacities.
We evaluate our Commodity
revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin and Adjusted EBITDA.”
Commodity revenue, net of Commodity expense, increased $43 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to:
•
our
Russell City and Los Esteros power plants commencing commercial operations during the third quarter of 2013 and the acquisition of Bosque Energy Center in November 2012 partially offset by the sale of Broad River and Riverside Energy Center in December 2012;
•
higher regulatory capacity revenue in the East; and
•
higher revenue from contracts in our West and East segments which became effective in January 2013; partially offset
by
•
weaker market conditions in 2013 compared to 2012 in our Texas and East segments partially offset by higher contribution from hedges related to these segments and stronger market conditions in our West segment partially offset by lower contribution from hedges in the West.
Generation decreased 9% primarily due to weaker market conditions and the sale of Broad River and Riverside Energy Center in December 2012 which were partially offset by the acquisition of Bosque Energy Center in November 2012 and our Russell City and Los Esteros power plants which commenced commercial operations during the third quarter of 2013. Our average total
MW in operation decreased by 464 MW, or 2%, primarily due to the aforementioned changes in our power plant portfolio.
Mark-to-market gain/loss from hedging our future generation and fuel needs, for the year ended December 31, 2013, compared to the year ended December 31, 2012, had a favorable variance of $68 million primarily driven by overall increase in forward natural gas prices favorably affecting our natural gas hedges during the year ended December 31, 2013, as compared to the year ended December 31, 2012.
Plant operating expense decreased by $27 million for the year ended December
31, 2013, compared to the year ended December 31, 2012. Our normal, recurring plant operating expense decreased $59 million during 2013 compared to 2012 after excluding the net impact of a $12 million increase from power plant portfolio changes, a net $16 million increase in major maintenance expense resulting from our plant outage schedule net of costs from scrap parts related to outages and a $4 million increase related to higher stock-based compensation expense. The decrease in normal, recurring plant operating expense resulted primarily from a $30 million decrease in mainly production-related costs and salaries and benefits, a $12 million positive period-over-period change resulting from the TCEQ issuance of final regulations on Section 185 fees for which we determined we have no current or retroactive fee obligations, a $10 million period-over-period decrease in equipment failure cost related to outages and a
$7 million decrease related to the restructuring of a ground lease in 2012.
Depreciation and amortization expense increased by $31 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily resulting from a $18 million increase due to our acquisition of the Bosque Energy Center in November 2012 and a $12 million increase related to our Russell City and Los Esteros power plants commencing commercial operations in August 2013.
Gain on sale of assets, net consists of a $215 million gain related to the sale of 100% of our ownership interests in Broad River, and a $7 million gain related to the sale of our Riverside Energy Center, both of which closed in December 2012. See Note 3 of the Notes to
Consolidated Financial Statements for further information.
Interest expense decreased by $40 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, primarily due to a decrease in our annual effective interest rate on our consolidated debt, excluding the impacts of capitalized interest and mark-to-market gains (losses) on interest rate swaps, to 6.7% for the year ended December 31, 2013, from 7.3% for the year ended December 31, 2012. The issuance of our CCFC Term Loans in June 2013 and 2019 First Lien Term Loan in October 2012 allowed us to reduce our overall cost of debt by replacing our CCFC Notes and a portion of our First Lien Notes
55
and variable rate project debt with term loans carrying lower variable interest rates. Also, in February 2013, we repriced our First Lien Term Loans by lowering our interest rate, which decreased our interest expense during the year ended December 31, 2013. See Note 6 of the Notes to the Consolidated Financial Statements for further information regarding our debt.
Loss on interest rate derivatives had a favorable change of $14 million for the year ended December 31, 2013, compared to the year ended December
31, 2012, resulting from the termination in March 2012 of our legacy interest rate swaps formerly hedging our First Lien Credit Facility. During the year ended December 31, 2012, we recorded the settlement amount of approximately $156 million reflecting the fair value of the terminated swaps, of which approximately $142 million reflected the realization of losses in prior periods and $14 million was recorded as a component of loss on interest rate derivatives.
Debt extinguishment costs for the year ended December 31, 2013, consisted primarily of $139 million relating to the repayment of the CCFC Notes and the 2017 First Lien Notes and redeeming a portion of our First Lien Notes during 2013, which is comprised of $96 million of prepayment penalties and $43 million associated
with the write-off of unamortized debt discount and deferred financing costs. Debt extinguishment costs for the year ended December 31, 2012, consisted of $18 million associated with the redemption premium, the write-off of unamortized deferred financing costs and debt premium and discount related to repayment of a portion of our First Lien Notes and variable rate project debt during the fourth quarter of 2012, and $12 million associated with the purchase of two of the three third party interests in GEC Holdings, LLC in March 2012 that were previously recorded as preferred interests and classified as debt under U.S. GAAP.
During the year ended December 31, 2013, we recorded income tax expense of $2 million compared to income tax expense of $19 million for the year ended December 31,
2012. The favorable year-over-year change primarily resulted from a decrease in income tax expense of $21 million related to the expiration of applicable statutes of limitation related to uncertain tax positions and a decrease of $8 million related to the application of intraperiod tax allocation for the year ended December 31, 2013, compared to the year ended December 31, 2012. The overall favorable year-over-year change in income tax expense was partially offset by a refund of approximately $10 million received in October 2012 related to the IRS approval of our 2004 amended federal income tax return.
56
COMMODITY MARGIN AND ADJUSTED EBITDA
Management’s Discussion and Analysis of Financial Condition and Results of Operations includes financial information prepared in accordance with U.S. GAAP, as well as the non-GAAP financial measures, Commodity Margin and Adjusted EBITDA, discussed below, which we use as measures of our performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with U.S. GAAP.
We use Commodity Margin, a non-GAAP financial measure, to assess our performance
by our reportable segments. Commodity Margin includes our power and steam revenues, sales of purchased power and physical natural gas, capacity revenue, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expense, and realized settlements from our marketing, hedging, optimization and trading activities including natural gas transactions hedging future power sales, but excludes mark-to-market activity and other revenues. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure reviewed by our chief operating decision maker. Commodity Margin is not a measure calculated in accordance with U.S. GAAP and should be viewed as a supplement to and not a substitute for our results of operations presented in accordance with U.S. GAAP. Commodity Margin does not intend to represent
income from operations, the most comparable U.S. GAAP measure, as an indicator of operating performance and is not necessarily comparable to similarly titled measures reported by other companies. See Note 16 of the Notes to Consolidated Financial Statements for a reconciliation of Commodity Margin to income from operations by segment.
The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2014 and 2013
(exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidate and operate.
West:
2014
2013
Change
% Change
Commodity
Margin (in millions)
$
1,050
$
1,020
$
30
3
Commodity
Margin per MWh generated
$
30.71
$
28.25
$
2.46
9
MWh
generated (in thousands)
34,195
36,110
(1,915
)
(5
)
Average availability
92.9
%
92.2
%
0.7
%
1
Average
total MW in operation
7,524
7,058
466
7
Average capacity factor, excluding peakers
55.4
%
62.6
%
(7.2
)%
(12
)
Steam
Adjusted Heat Rate
7,314
7,308
(6
)
—
West — Commodity Margin in our West segment increased by $30 million, or 3%, for the year ended
December 31, 2014 compared to the year ended December 31, 2013, primarily due to our contracted 464 MW Russell City and 309 MW Los Esteros power plants, which commenced commercial operations in August 2013 and were also the drivers of a 466 MW, or 7%, increase in our average total MW in operation. The positive impact of these power plants was partially offset by the expiration of a tolling contract associated with our Delta Energy Center in December 2013. Commodity Margin was also positively impacted by higher on-peak Spark Spreads resulting from stronger market conditions due to warmer weather and lower hydroelectric generation during the year ended December 31, 2014 compared to 2013. The impact on Commodity Margin of these positive
factors was partially offset by lower contribution from hedges during the year ended December 31, 2014 compared to the year ended December 31, 2013.
57
Texas:
2014
2013
Change
% Change
Commodity
Margin (in millions)
$
760
$
632
$
128
20
Commodity
Margin per MWh generated
$
19.65
$
18.95
$
0.70
4
MWh
generated (in thousands)
38,678
33,343
5,335
16
Average availability
90.5
%
89.8
%
0.7
%
1
Average
total MW in operation
8,856
7,784
1,072
14
Average capacity factor, excluding peakers
49.9
%
48.9
%
1.0
%
2
Steam
Adjusted Heat Rate
7,203
7,198
(5
)
—
Texas — Commodity Margin in our Texas segment increased by $128 million, or 20%, for the year
ended December 31, 2014 compared to the year ended December 31, 2013, due primarily to the acquisition of our 1,000 MW Guadalupe Energy Center on February 26, 2014 and the expansions of our Deer Park and Channel Energy Centers which were completed in June 2014, all of which were also the primary drivers of the 1,072 MW, or 14%, increase in our average total MW in operation and 16% increase in generation. Commodity Margin also increased due to stronger market conditions resulting from higher on-peak Spark Spreads during the first quarter of 2014 compared to the same period in 2013 and higher contribution from hedges during the year ended December 31, 2014 compared to 2013.
East:
2014
2013
Change
% Change
Commodity
Margin (in millions)
$
949
$
916
$
33
4
Commodity
Margin per MWh generated
$
34.21
$
28.49
$
5.72
20
MWh
generated (in thousands)
27,744
32,157
(4,413
)
(14
)
Average availability
89.2
%
93.0
%
(3.8
)%
(4
)
Average
total MW in operation
10,272
12,012
(1,740
)
(14
)
Average capacity factor, excluding peakers
40.0
%
38.7
%
1.3
%
3
Steam
Adjusted Heat Rate
7,721
7,663
(58
)
(1
)
East — Commodity Margin in our East segment increased by $104 million for the year ended December
31, 2014 compared to the year ended December 31, 2013, after excluding a decrease of $71 million resulting from the sale of six power plants with a total capacity of 3,498 MW on July 3, 2014 which was also the primary driver of the 1,740 MW, or 14%, decrease in average total MW in operation. The increase in Commodity Margin was primarily due to colder than normal weather during the first quarter of 2014 resulting in higher margins. Given the flexible, dual-fuel capability of some of our power plants in the East, we were able to realize higher Commodity Margin by running some of our power plants on fuel oil during the first quarter of 2014 rather than natural gas when the relative cost of consuming fuel oil was lower than natural gas. Also contributing to the period-over-period increase was higher market Spark Spreads realized by our Mid-Atlantic power plants. During
the second half of 2014, our Mid-Atlantic combined-cycle power plants benefited from low natural gas prices due to the locational advantage that allows these power plants access to discounted Marcellus natural gas. The increase in Commodity Margin was partially offset by lower contribution from hedges, lower regulatory capacity revenues in PJM during the second half of 2014 compared to the same period in 2013 and the expiration of a PPA associated with our Osprey Energy Center in May 2014 partially offset by a new PPA associated with our Osprey Energy Center effective in October 2014. Generation decreased 14% due to the sale of six power plants, the expiration of a PPA and outages at several of our power plants during the year ended December 31, 2014 compared to 2013 partially offset by the acquisition of our 731 MW Fore River Energy Center.
The following tables show our Commodity Margin and related operating performance metrics by segment for the years ended December 31, 2013 and 2012 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by segment below represent generation from power plants that we both consolidated and operate.
58
West:
2013
2012
Change
% Change
Commodity
Margin (in millions)
$
1,020
$
994
$
26
3
Commodity
Margin per MWh generated
$
28.25
$
29.77
$
(1.52
)
(5
)
MWh
generated (in thousands)
36,110
33,390
2,720
8
Average availability
92.2
%
91.9
%
0.3
%
—
Average
total MW in operation
7,058
6,742
316
5
Average capacity factor, excluding peakers
62.6
%
60.6
%
2.0
%
3
Steam
Adjusted Heat Rate
7,308
7,278
(30
)
—
West — Commodity Margin in our West segment increased by $26 million, or 3%, for the year ended
December 31, 2013 compared to the year ended December 31, 2012. During 2013, Commodity Margin was positively impacted by our contracted 464 MW Russell City and 309 MW Los Esteros power plants which commenced commercial operations during the third quarter of 2013 and were also the primary drivers of a 316 MW, or 5%, increase in our average total MW in operation. The increase in Commodity Margin was also due to higher revenue from a tolling contract which became effective in January 2013 and stronger market conditions resulting from lower hydroelectric generation, warmer weather and the impact of the January 1, 2013 implementation of the AB 32 carbon market. The impact of these positive factors was partially offset by lower contribution
from hedges during the year ended December 31, 2013 compared to 2012. Generation increased 8% period-over-period due primarily to our Russell City and Los Esteros power plants and the stronger market conditions in 2013 compared to 2012.
Texas:
2013
2012
Change
% Change
Commodity
Margin (in millions)
$
632
$
570
$
62
11
Commodity
Margin per MWh generated
$
18.95
$
15.86
$
3.09
19
MWh
generated (in thousands)
33,343
35,946
(2,603
)
(7
)
Average availability
89.8
%
91.1
%
(1.3
)%
(1
)
Average
total MW in operation
7,784
7,127
657
9
Average capacity factor, excluding peakers
48.9
%
57.4
%
(8.5
)%
(15
)
Steam
Adjusted Heat Rate
7,198
7,147
(51
)
(1
)
Texas — Commodity Margin in our Texas segment increased by $62 million, or 11%, for the year ended
December 31, 2013 compared to the year ended December 31, 2012, due to higher contribution from hedges and the acquisition of our 762 MW Bosque Energy Center in November 2012 which was also the primary driver of the 657 MW, or 9%, increase in our average total MW in operation. The overall period-over-period increase in Commodity Margin was partially offset by lower realized market Spark Spreads resulting from weaker market conditions during the first nine months of 2013 partially offset by stronger market conditions during the fourth quarter of 2013. Generation decreased 7% resulting from weaker market conditions in the first nine months of 2013 partially offset by the acquisition of Bosque Energy Center. Our average capacity factor decreased 15% resulting from lower generation at our legacy power plants during 2013 compared to 2012.
East:
2013
2012
Change
% Change
Commodity
Margin (in millions)
$
916
$
974
$
(58
)
(6
)
Commodity
Margin per MWh generated
$
28.49
$
22.71
$
5.78
25
MWh
generated (in thousands)
32,157
42,880
(10,723
)
(25
)
Average availability
93.0
%
91.2
%
1.8
%
2
Average
total MW in operation
12,012
13,449
(1,437
)
(11
)
Average capacity factor, excluding peakers
38.7
%
46.6
%
(7.9
)%
(17
)
Steam
Adjusted Heat Rate
7,663
7,611
(52
)
(1
)
East — Commodity Margin in our East segment increased by $67 million for the year ended December
31, 2013 compared to the year ended December 31, 2012, after excluding a decrease of $125 million resulting from the sale of Riverside Energy Center and Broad River in December 2012 which was also the primary driver of a 1,437 MW, or 11%, decrease in our average total MW in operation. The increase in Commodity Margin was primarily due to higher regulatory capacity revenues, higher revenue from a new contract which became effective in January 2013 and higher contribution from hedges during 2013 compared to 2012. The impact of these positive factors was partially offset by weaker market conditions resulting from milder weather and
59
higher
natural gas prices which drove a reversal of coal-to-gas switching during the year ended December 31, 2013 compared to 2012. Generation decreased 25% due to weaker market conditions during 2013 and the sale of Riverside Energy Center and Broad River.
Adjusted EBITDA
We define Adjusted EBITDA, a non-GAAP financial measure, as EBITDA adjusted for certain items described below and presented in the accompanying reconciliation. Adjusted EBITDA is not a measure calculated in accordance with U.S. GAAP, and should be viewed as a supplement to, and not a substitute for, our results of operations presented in accordance with U.S. GAAP. Adjusted EBITDA is not intended to represent cash flows from operations or net income (loss) as
defined by U.S. GAAP as an indicator of operating performance. Furthermore, Adjusted EBITDA is not necessarily comparable to similarly-titled measures reported by other companies.
We believe Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. We believe that EBITDA is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired.
Additionally, we believe that investors commonly adjust EBITDA information to eliminate the effect of
restructuring and other expenses, which vary widely from company to company and impair comparability. As we define it, Adjusted EBITDA represents EBITDA adjusted for the effects of impairment losses, gains or losses on sales, dispositions or retirements of assets, any mark-to-market gains or losses from accounting for derivatives, adjustments to exclude the Adjusted EBITDA related to the noncontrolling interest, stock-based compensation expense, operating lease expense, non-cash gains and losses from foreign currency translations, major maintenance expense, gains or losses on the repurchase or extinguishment of debt, non-cash GAAP-related adjustments to levelize revenues from tolling agreements and any extraordinary, unusual or non-recurring items plus adjustments to reflect the Adjusted EBITDA from our unconsolidated investments. We adjust for these items in our Adjusted EBITDA as our management believes that these items would distort their ability to efficiently view
and assess our core operating trends.
In summary, our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 from what was formerly
our Southeast segment. Thus, beginning in the third quarter of 2014, our reportable segments are West (including geothermal), Texas and East (including Canada). The tables below have been revised to present our segments on this revised basis for all periods.
The tables below provide a reconciliation of Adjusted EBITDA to our income from operations on a segment basis and to net income attributable to Calpine on a consolidated basis for years ended December 31, 2014, 2013 and 2012 (in millions).
60
2014
West
Texas
East(1)
Consolidation
and
Elimination
Total
Net
income attributable to Calpine
$
946
Net income attributable to the noncontrolling interest
15
Income
tax expense
22
Debt extinguishment costs and other (income) expense, net
367
Interest
expense, net of interest income
639
Income from operations
$
549
$
329
$
1,111
$
—
$
1,989
Add:
Adjustments
to reconcile income from operations to Adjusted EBITDA:
Depreciation and amortization expense, excluding deferred financing costs(2)
240
191
167
—
598
Major
maintenance expense
64
91
79
—
234
Operating
lease expense
8
—
26
—
34
Mark-to-market
gain on commodity derivative activity
(172
)
(114
)
(56
)
—
(342
)
Impairment
losses
—
—
123
—
123
(Gain)
on sale of assets, net
—
—
(753
)
—
(753
)
Adjustments
to reflect Adjusted EBITDA from unconsolidated investments and exclude the noncontrolling interest(3)
Our
East segment includes Adjusted EBITDA of $43 million, $88 million and $56 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to the six power plants in our East segment that were sold in July 2014.
(2)
Depreciation and amortization expense in the income from operations calculation on our Consolidated Statements of Operations excludes amortization of other assets.
(3)
Adjustments
to reflect Adjusted EBITDA from unconsolidated investments include (gain) loss on mark-to-market activity of nil for each of the years ended December 31, 2014, 2013 and 2012, respectively.
63
LIQUIDITY AND CAPITAL RESOURCES
We maintain a strong focus on liquidity. We manage our liquidity to help provide access to sufficient funding to meet our business needs and financial obligations throughout business cycles.
Our business
is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.
Liquidity
The following table provides a summary of our liquidity position at December 31, 2014 and 2013 (in millions):
2014
2013
Cash
and cash equivalents, corporate(1)(2)
$
460
$
649
Cash and cash equivalents, non-corporate
257
292
Total
cash and cash equivalents
717
941
Restricted cash
244
272
Corporate Revolving Facility availability(3)
1,277
758
CDHI
letter of credit facility availability
86
7
Total current liquidity availability
$
2,324
$
1,978
____________
(1)
Includes
$47 million and $5 million of margin deposits posted with us by our counterparties at December 31, 2014 and 2013, respectively.
(2)
On February 3, 2015, we issued our $650 million 2024 Senior Unsecured Notes and used the proceeds to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014 and to repurchase approximately $150 million of our 2023 First Lien Notes.
(3)
On
July 30, 2014, we amended our Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash and cash equivalents.
Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, and capital expenditures for construction,
project development and other growth initiatives. In addition, we may use capital resources to opportunistically repurchase our shares of common stock. The ultimate decision to allocate capital to share repurchases will be based upon the expected returns compared to alternative uses of capital.
Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.
We have never paid cash dividends on our common stock. Future cash dividends,
if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can have an impact on our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. Utilizing our portfolio of transactions subject to collateral exposure, we estimate that as of January 15, 2015, an increase of $1/MMBtu in natural gas prices would result in an increase of collateral required by approximately $309
million. If natural gas prices decreased by $1/MMBtu, we estimate that our collateral requirements would
64
decrease by approximately $303 million. Changes in Market Heat Rates also affect our liquidity. For example, as demand increases, less efficient generation is dispatched, which increases the Market Heat Rate and results in increased collateral requirements. Historical relationships of natural gas and Market Heat Rate movements for our portfolio of assets have been volatile over time and are influenced by the absolute price of natural gas and the regional characteristics of each power market. We estimate that at January 15, 2015, an increase of 500 Btu/KWh in the
Market Heat Rate would result in an increase in collateral required by approximately $22 million. If Market Heat Rates were to fall at a similar rate, we estimate that our collateral required would decrease by $22 million. These amounts are not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible
to significant price movements for 2015 and beyond. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:
•
the level of Market Heat Rates;
•
our continued ability to successfully hedge our Commodity Margin;
•
changes in U.S. macroeconomic conditions;
•
maintaining
acceptable availability levels for our fleet;
•
the impact of current and pending environmental regulations in the markets in which we participate;
•
improving the efficiency and profitability of our operations;
•
increasing future contractual cash flows; and
•
our
significant counterparties performing under their contracts with us.
Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience another economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities
The
Corporate Revolving Facility represents our primary revolving facility. The table below represents amounts issued under our letter of credit facilities at December 31, 2014 and 2013 (in millions):
2014
2013
Corporate
Revolving Facility
$
223
$
242
CDHI
214
218
Various
project financing facilities
207
170
Total
$
644
$
630
Major
Maintenance and Capital Spending
Our major maintenance and capital spending remains an important part of our business. Our expected expenditures for 2015 are as follows (in millions):
2015
Major maintenance expense
$
235
Capital
expenditures, operations, net
160
Growth related capital expenditures
355
Total major maintenance expense and capital spending
$
750
65
NOLs
We
have significant NOLs that will provide future tax deductions when we generate sufficient taxable income during the applicable carryover periods. At December 31, 2014, our consolidated federal NOLs totaled approximately $6.9 billion. See Note 10 of the Notes to Consolidated Financial Statements for further discussion of our NOLs.
Cash Flow Activities
The following table summarizes our cash flow activities for the years ended December 31, 2014, 2013 and 2012 (in millions):
2014
2013
2012
Beginning
cash and cash equivalents
$
941
$
1,284
$
1,252
Net cash provided by (used in):
Operating
activities
854
549
653
Investing activities
(84
)
(593
)
(470
)
Financing
activities
(994
)
(299
)
(151
)
Net increase (decrease) in cash and cash equivalents
(224
)
(343
)
32
Ending
cash and cash equivalents
$
717
$
941
$
1,284
2014 — 2013
Net Cash Provided By Operating Activities
Cash
provided by operating activities for the year ended December 31, 2014, was $854 million compared to $549 million for the year ended December 31, 2013. The increase was primarily due to:
•
Income from operations — Income from operations, adjusted for non-cash items, increased by $130 million for the year ended December 31, 2014, compared to the year ended December 31, 2013. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants,
impairment losses, gain on sale of assets, net and mark-to-market activity. The increase in income from operations was primarily driven by a $214 million increase in Commodity revenue, net of Commodity expense partially offset by a $74 million increase in plant operating expense for the year ended December 31, 2014, compared to the year ended December 31, 2013. See “Results of Operations for the Year Ended December 31, 2014 and 2013” above for further discussion of these changes.
•
Working capital employed — Working
capital employed decreased by approximately $328 million for the year ended December 31, 2014, compared to the year ended December 31, 2013, after adjusting for change in debt, restricted cash and mark-to-market related balances which did not impact cash provided by operating activities. The decrease was primarily due to a reduction in net margin requirements and accounts receivable/accounts payable balances for the year ended December 31, 2014 compared to the year ended December 31, 2013.
•
Interest paid — Cash paid for interest
decreased by $62 million to $610 million for the year ended December 31, 2014, from $672 million for the year ended December 31, 2013. The decrease was primarily due to the lower effective interest rates year over year due to our refinancing activity and the timing of interest payments.
•
Debt extinguishment payments — For the year ended December 31, 2014, we made cash payments of $310 million related to the repayment of our 2019 First Lien Notes, 2020 First Lien Notes, and 2021 First Lien Notes, as compared to $101 million for the year ended December
31, 2013, which were associated with the redemption of the CCFC Notes and a portion of our First Lien Notes.
Net Cash Used In Investing Activities
Cash used in investing activities for the year ended December 31, 2014 was $84 million compared to $593 million for the year ended December 31, 2013. The decrease was primarily due to:
•
Higher proceeds from the sale of power plants, interests and other — During the year ended December 31, 2014, we received proceeds of approximately $1.57
billion related to the completion of the sale of six power plants in our East segment, compared to $1 million during the year ended December 31, 2013 that was related to the sale of equipment.
66
•
Capital expenditures — Capital expenditures for the year ended December 31, 2014 were $492 million, a decrease of $83 million, compared to expenditures of $575 million for the year ended December 31, 2013. The decrease was primarily
due to lower expenditures on construction projects in 2014 as compared to 2013.
•
Purchase of Fore River and Guadalupe Energy Centers — In 2014, we purchased two natural gas-fired, combined-cycle power plants located in North Weymouth, Massachusetts and Guadalupe County, Texas for $541 million and $656 million, respectively. There were no acquisitions during the year ended December 31, 2013.
•
Restricted cash — Restricted
cash decreased $28 million for the year ended December 31, 2014, compared to an increase of $18 million for the year ended December 31, 2013. The decrease was primarily due to a decrease in insurance reserve resulting from property damage claim settlements, and a decrease in debt service primarily related to the timing of funding and debt payments.
Net Cash Used In Financing Activities
Cash used in financing activities increased by $695 million to $994 million for the year ended December 31, 2014, compared to cash used in financing activities of $299 million for the year ended December 31, 2013. The increase was primarily due to:
•
CCFC
Term Loans and CCFC Notes — During the year ended December 31, 2014, we received proceeds of approximately $420 million under the CCFC Term Loans, which were used to fund a portion of the purchase price paid in connection with the acquisition of the Guadalupe Energy Center compared to proceeds of approximately $1,197 million under the CCFC Term Loans which were used to repay the $1.0 billion of outstanding CCFC Notes for the year ended December 31, 2013, resulting in a net increase of approximately $223 million. In addition, during the year ended December 31, 2014, we made principal payments of approximately $16 million, compared to principal payments of $6 million during the year ended December 31, 2013.
•
First
Lien Term Loans — During the year ended December 31, 2013, we received proceeds of approximately $390 million from the issuance of the 2020 First Lien Term Loan which was used together with the proceeds from the 2022 First Lien Notes to repay the 2017 First Lien Notes. There was no similar activity during the year ended December 31, 2014. In addition, during the year ended December 31, 2014, we made principal payments of $29 million, compared to principal payments of $25 million during the year ended December 31, 2013.
•
First
Lien Notes and Senior Unsecured Notes — During the year ended December 31, 2014, we received proceeds of $2.8 billion from the issuance of Senior Unsecured Notes, which were used to repay our 2019 First Lien Notes, 2020 First Lien Notes, and 2021 First Lien Notes resulting in a net use of $120 million in cash. During the year ended December 31, 2013, we received proceeds of approximately $1.2 billion under the 2022 First Lien Notes and 2024 First Lien Notes, which were used to redeem the 2017 First Lien Notes along with 10% redemption of the remaining First Lien Notes for a net use of $316 million in cash.
•
Proceeds
from project debt — During the year ended December 31, 2014, we received proceeds of approximately $79 million from project debt, compared to $182 million during the year ended December 31, 2013. The decrease was related to lower draws on our Russell City and Los Esteros project debt as the power plants commenced operations during the third quarter of 2013.
•
Repayments of project debt, notes payable and other — During the year ended December 31, 2014, we made repayments of $178 million compared to $66
million for the year ended December 31, 2013. The increase in repayments was related to the conversion of Russell City and Los Esteros project debt to term loans in December 2013 and September 2014, respectively.
•
Distribution to noncontrolling interest holder — During the year ended December 31, 2014, we made a distribution to a noncontrolling interest holder in Russell City Energy Company, LLC of approximately $15 million, with no similar activity during the year ended December 31, 2013.
•
Stock
repurchases — During the year ended December 31, 2014, we made payments of approximately $1.1 billion to repurchase our common stock compared to $623 million during the year ended December 31, 2013. The increase is primarily due to the repurchase of $311 million of common stock from a shareholder in a private transaction.
2013 — 2012
Net Cash Provided By Operating Activities
Cash provided by operating activities for the year ended December 31, 2013, was $549 million compared to $653 million for the year ended December 31, 2012.
The decrease was primarily due to:
67
•
Working capital employed — Working capital employed increased by approximately $129 million for the year ended December 31, 2013, compared to the year ended December 31, 2012, after adjusting for debt related balances and non-hedging interest rate swaps which did not impact cash provided by operating activities. The increase was primarily due to a $125 million increase in net accounts receivable/accounts payable balances resulting from higher than normal
revenue in December 2013.
•
Debt extinguishment payments — For the year ended December 31, 2013, we made cash payments of $101 million associated with the redemption of the CCFC Notes and a portion of our First Lien Notes compared to cash payments of $29 million in prepayment premiums for the year ended December 31, 2012 associated with the repayment of a portion of our First Lien Notes and variable rate project debt.
•
AB32
compliance requirements — Operating cash flows decreased by approximately $31 million due to an increase in net assets required for AB32 compliance. We had no such compliance requirements for the year ended December 31, 2012.
•
Cash paid for income taxes (net) — Cash paid for income taxes, net of refunds received, was $19 million for year ended December 31, 2013, as compared to $1 million for the year ended December 31, 2012.
•
Income
from operations — Income from operations, adjusted for non-cash items, increased by $73 million for the year ended December 31, 2013, compared to the year ended December 31, 2012. Non-cash items consist primarily of depreciation and amortization, income from unconsolidated investments in power plants, impairment losses and mark-to-market activity.
•
Interest paid — Cash paid for interest decreased by $47 million to $672 million for the year ended December 31, 2013, compared to $719 million for the year
ended December 31, 2012. The decrease was primarily due to the replacement of 10% of our fixed interest rate First Lien Notes with a corporate level term loan at a variable interest rate, the re-pricing of our First Lien Term Loans and the repayment of project debt.
•
Ground lease modification — For the year ended December 31, 2012, we paid $28 million related to a renegotiated ground lease at one of our operating plants. We made no similar payments for the year ended December 31, 2013.
Net Cash Used In Investing
Activities
Cash used in investing activities for the year ended December 31, 2013 was $593 million compared to $470 million for the year ended December 31, 2012. The increase was primarily due to:
•
Proceeds from the sale of power plants, interests and other — For the year ended December 31, 2013, we had $1 million in proceeds received as compared to $825 million for the year ended December 31, 2012, which was due to the sale of Broad River and Riverside Energy Center.
•
Purchase
of Bosque Energy Center — In 2012, we purchased a natural gas-fired, combined-cycle power plant located in Bosque County, Texas for $432 million. There were no acquisitions in 2013.
•
Settlement of non-hedging interest rate swaps — During the year ended December 31, 2012, we terminated our legacy interest rate swaps formerly hedging our First Lien Credit Facility resulting in payments of approximately $156 million. We made no similar payments during the year ended December 31, 2013.
•
Capital
expenditures — Capital expenditures for the year ended December 31, 2013 were $575 million, a decrease of $62 million, compared to expenditures of $637 million for the year ended December 31, 2012. The decrease was primarily due to timing on our construction projects and turbine modernization program.
•
Restricted cash — Restricted cash increased $18 million for the year ended December 31, 2013, compared to an increase of $59 million for the year ended December 31, 2012. The decrease was primarily due
to the release of cash collateral previously posted under our CDHI letter of credit facility.
Net Cash Used In Financing Activities
Cash used in financing activities increased by $148 million to $299 million for the year ended December 31, 2013, compared to cash used in financing activities of $151 million for the year ended December 31, 2012. The increase was primarily due to:
•
Stock repurchases — During the year ended December 31, 2013, we made payments of approximately $623 million
to repurchase our common stock as compared to $463 million during the year ended December 31, 2012.
•
Lower proceeds from First Lien Term Loans — During the year ended December 31, 2013, we received proceeds of approximately $390 million from the issuance of the 2020 First Lien Term Loan, a decrease of $445 million when
68
compared to $835 million received during the year ended December
31, 2012, from the issuance of the 2019 First Lien Term Loan.
•
Repayments of First Lien Notes — During the year ended December 31, 2013, we redeemed the 2017 First Lien Notes along with 10% of the original aggregate principal amounts of the First Lien Notes for $1.6 billion as compared to $590 million for the year ended December 31, 2012 related to 10% redemption of the aggregate principal amount of each series of our then existing First Lien Notes. The redemption in 2013 was funded from the $390 million in proceeds from the issuance of the 2020 First Lien Term Loan together with $1.2 billion in proceeds from the issuance of the 2022
First Lien Notes and 2024 First Lien Notes.
•
Lower proceeds from project debt — During the year ended December 31, 2013, we received proceeds of approximately $182 million from project debt, compared to $389 million during the year ended December 31, 2012. The decrease was related to lower draws on our Russell City and Los Esteros project debt.
•
Increased finance costs —
During the year ended December 31, 2013, we incurred finance costs of approximately $53 million, compared to approximately $20 million during the year ended December 31, 2012. The increase was primarily due to the CCFC Term Loans, the re-pricing of our First Lien Term Loans and the issuances of the 2020 First Lien Term Loan, 2022 First Lien Notes and 2024 First Lien Notes.
•
CCFC refinancing — During the year ended December 31, 2013, we received proceeds of approximately $1.2 billion under the CCFC Term Loans and used approximately $1.0 billion to repay the CCFC Notes, for
net proceeds of $197 million.
•
Proceeds from First Lien Notes — During the year ended December 31, 2013, we received proceeds of approximately $1.2 billion under the 2022 First Lien Notes and 2024 First Lien Notes, which were used to redeemed the 2017 First Lien Notes along with 10% of the original aggregate principal amounts of the First Lien Notes.
•
Repayments of project debt, notes payable and other — During the year
ended December 31, 2013, we made repayments of $66 million primarily due to the repayment of the Pasadena and Steamboat project debt. During the year ended December 31, 2012, we made repayments of $289 million primarily due to the retirement of the Calpine BRSP project debt.
Counterparties and Customers
Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets: financial institutions and trading companies; regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and oil, natural gas, chemical and other energy-related industrial companies. We have exposure to trends within the energy industry, including declines
in the creditworthiness of our counterparties. We have concentrations of credit risk with a few of our customers relating to our sales of power, steam and hedging and optimization activities. Currently, certain of our counterparties within the energy industry have below investment grade credit ratings. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing according to their respective agreements.
Credit Considerations
Our credit rating has, among other things, generally required us to post significant collateral with our hedging counterparties. Our collateral is generally in the form of cash deposits, letters of credit or first liens on our assets. See also Note 9 of the Notes to Consolidated Financial Statements
for our use of collateral. Our credit rating reduces the number of hedging counterparties willing to extend credit to us and reduces our ability to negotiate more favorable terms with them. However, we believe that we will continue to be able to work with our hedging counterparties to execute beneficial hedging transactions and provide adequate collateral. At December 31, 2014, our First Lien Notes, First Lien Term Loans, Corporate Revolving Facility, Senior Unsecured Notes and our corporate rating had the following ratings and commentary from Standard and Poor’s and Moody’s Investors Service:
Standard and Poor’s
Moody’s Investors
Service
First
Lien Notes, First Lien Term Loans and Corporate Revolving Facility rating
BB
Ba3
Senior Unsecured Notes
B
B3
Corporate rating
B+
B1
Commentary
Stable
Positive
69
Off Balance Sheet Arrangements
Our power plant operating leases are not reflected on our Consolidated Balance Sheets and contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project finance debt instruments. See Note 15 of the Notes to Consolidated Financial Statements for the future minimum lease payments under our power plant operating leases.
Some of our unconsolidated equity method investments have debt that is not reflected on our Consolidated Balance Sheets. As of December 31, 2014, our equity method investees (Greenfield LP and Whitby) had aggregate debt outstanding of $342 million.
Based on our pro rata share of each of the investments, our share of such debt would be approximately $171 million. All such debt is non-recourse to us. See Note 5 of the Notes to Consolidated Financial Statements for additional information on our investments.
Guarantee Commitments — As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety
bonds for power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes. Our primary commercial obligations as of December 31, 2014, are as follows (in millions):
Amounts
of Commitment Expiration per Period
Guarantee Commitments
2015
2016
2017
2018
2019
Thereafter
Total
Amounts
Committed
Guarantee
of subsidiary debt(1)
$
37
$
36
$
26
$
31
$
30
$
148
$
308
Standby
letters of credit(2)(3)(5)
572
14
20
—
—
38
644
Surety
bonds(4)(5)(6)
—
—
—
—
—
4
4
Guarantee
of subsidiary operating lease payments(5)
4
—
—
—
—
—
4
Total
$
613
$
50
$
46
$
31
$
30
$
190
$
960
___________
(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 6 of the Notes to Consolidated Financial Statements.
(3)
Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter
of credit will likely follow the term of the associated commercial obligation.
(4)
The majority of surety bonds do not have expiration or cancellation dates.
(5)
These are contingent off balance sheet obligations.
(6)
As of December 31, 2014, $2
million of cash collateral is outstanding related to these bonds.
70
Contractual Obligations — Our contractual obligations as of December 31, 2014, are as follows (in millions):
Total
Less than 1
Year
1-3 Years
3-5 Years
More than 5
Years
Operating
lease obligations(1)
$
455
$
53
$
94
$
99
$
209
Purchase
obligations:
Turbine commitments
$
61
$
53
$
8
$
—
$
—
Commodity
purchase obligations(2)
1,763
390
490
261
622
LTSA
189
18
39
40
92
Cost
to complete construction projects
125
109
16
—
—
Parts
supply agreements(3)
716
125
172
154
265
Other
purchase obligations(4)
596
50
96
75
375
Total
purchase obligations(5)
$
3,450
$
745
$
821
$
530
$
1,354
Debt
$
11,306
$
199
$
767
$
2,947
$
7,393
Other
contractual obligations:
Interest payments on debt(6)
$
4,143
$
575
$
1,167
$
996
$
1,405
Liability
for uncertain tax positions
25
—
—
—
25
Interest
rate swap agreement(6)
116
44
49
18
5
Total
other contractual obligations
$
4,284
$
619
$
1,216
$
1,014
$
1,435
___________
(1)
Included
in the total are future minimum payments for power plant, office, land and other operating leases. See Note 15 of the Notes to Consolidated Financial Statements for more information.
(2)
The amounts presented here include contracts for the purchase, transportation, or storage of commodities accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet.
(3)
Our
parts supply agreements are generally cancelable upon payment of an insubstantial termination fee.
(4)
The amounts presented here include water agreements, maintenance agreements and other purchase obligations.
(5)
The amounts included above for purchase obligations represent the minimum requirements under contract.
(6)
Amounts
are projected based upon interest rates at December 31, 2014.
Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities. As of the date of filing of this Report, these entities included: Calpine King City Cogen, LLC, Calpine Securities Company, L.P. (a parent company of Calpine King City Cogen, LLC), Calpine King City, LLC (an indirect parent company of Calpine Securities
Company, L.P.), Russell City Energy Company, LLC and OMEC.
71
RISK MANAGEMENT AND COMMODITY ACCOUNTING
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, load sales, steam sales, buying and selling standard physical products, buying and selling exchange traded instruments, gas transportation
and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products.
We conduct our hedging and optimization activities within a structured risk management framework based on controls, policies and procedures. We monitor these activities through active and ongoing management and oversight, defined roles and responsibilities, and daily risk estimates and reporting. Additionally, we seek to manage the associated risks through diversification, by controlling position sizes, by using portfolio position limits, and by entering into offsetting positions that lock in a margin. We also are exposed to commodity price movements (both profits and losses) in connection with these transactions. These positions are included in and subject to our consolidated risk management portfolio position limits
and controls structure. Changes in fair value of commodity positions that do not qualify for or we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product contracts, swaps and options). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.
At any point in time, the relative quantity
of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio mostly through power and natural gas forward physical and financial transactions; however, we currently remain susceptible to significant price movements for 2015 and beyond. When we elect to enter into these transactions, we are able to economically hedge a portion of our Spark Spread at pre-determined generation and price levels.
We have historically used interest rate swaps to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate swaps have been designated as cash flow hedges, and changes in
fair value are recorded in OCI to the extent they are effective with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings. See Note 8 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative
transactions. Our derivative assets have increased to approximately $2.5 billion at December 31, 2014, when compared to approximately $0.6 billion at December 31, 2013, and our derivative liabilities have increased to approximately $2.2 billion at December 31, 2014, compared to approximately $0.7 billion at December 31, 2013. The period-over-period increase in our derivative assets and derivative liabilities was driven primarily by a decrease in forward power prices resulting from lower natural gas prices, which increased the fair value of our power hedges at December 31, 2014. The fair
value of our level 3 derivative assets and liabilities at December 31, 2014 represent only a small portion of our total assets and liabilities measured at fair value (approximately 5% and 3%, respectively). See Note 7 of the Notes to Consolidated Financial Statements for further information related to our level 3 derivative assets and liabilities.
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The change in fair value of our outstanding commodity and interest rate derivative instruments from January 1, 2014, through December 31, 2014,
is summarized in the table below (in millions):
Commodity
contract settlements consist of the realization of previously recognized gains on contracts not designated as hedging instruments of $61 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Statements of Operations) and $20 million related to current period changes in derivative assets and liabilities not reflected in OCI or earnings.
(2)
Interest rate settlements consist of $36 million related to realized losses from settlements of designated cash flow hedges and $12 million related to realized losses from settlements
of undesignated interest rate swaps (represents a portion of interest expense as reported on our Consolidated Statements of Operations).
(3)
Net commodity and interest rate derivative assets and liabilities reported in Notes 7 and 8 of the Notes to Consolidated Financial Statements.
The change since the last balance sheet date in the total value of the derivatives (both assets and liabilities) is reflected either in cash for option premiums paid or collected, in OCI, net of tax for cash flow hedges, or on our Consolidated Statements of Operations as a component (gain or loss) in earnings.
The following tables detail the components of our
total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012 (in millions):
2014
2013
2012
Realized
gain (loss)(1)
Commodity derivative instruments
$
110
$
86
$
387
Interest
rate swaps
—
—
(157
)
Total realized gain (loss)
$
110
$
86
$
230
Mark-to-market
gain (loss)(2)
Commodity derivative instruments
$
342
$
(14
)
$
(82
)
Interest
rate swaps
11
2
154
Total mark-to-market gain (loss)
$
353
$
(12
)
$
72
Total
activity, net
$
463
$
74
$
302
___________
(1)
Does
not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
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2014
2013
2012
Realized
and mark-to-market gain (loss)
Derivatives contracts included in operating revenues
$
384
$
(119
)
$
187
Derivatives
contracts included in fuel and purchased energy expense
68
191
118
Interest rate swaps included in interest expense
11
2
11
Loss
on interest rate derivatives
—
—
(14
)
Total activity, net
$
463
$
74
$
302
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, 2014, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
Fair
Value Source
2015
2016-2017
2018-2019
After 2019
Total
Prices actively quoted
$
258
$
6
$
—
$
—
$
264
Prices
provided by other external sources
41
8
1
—
50
Prices
based on models and other valuation methods
21
8
8
30
67
Total
fair value
$
320
$
22
$
9
$
30
$
381
We
measure the energy commodity price risks in our portfolio on a daily basis using a VAR model to estimate the potential one-day risk of loss based upon historical experience resulting from market movements in comparison to internally established thresholds. Our VAR is calculated for our entire portfolio which is comprised of energy commodity derivatives, expected generation and natural gas consumption from our power plants, PPAs, and other physical and financial transactions. 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,
2014 and 2013 (in millions):
2014
2013
Year ended December 31:
High
$
58
$
80
Low
$
22
$
33
Average
$
33
$
52
As
of December 31
$
29
$
46
Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material impact on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR
analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.
Since the fourth quarter of 2012, we have experienced diminished liquidity in the forward commodity markets resulting from a decrease in participation of counterparties in the marketplace with which to transact our hedging activities. Although this occurrence of diminished liquidity has not had a material adverse impact on our results of operations or financial condition, should these conditions persist, it could decrease our ability to hedge our forward commodity price risk and create volatility in our earnings.
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets
and liabilities. Increasing natural gas prices or Market Heat Rates can cause increased collateral requirements. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 9 of the Notes to Consolidated Financial Statements.
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Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties related to their contractual obligations with us. Risks surrounding counterparty performance and credit could ultimately impact the amount
and timing of expected cash flows. We also have credit risk if counterparties are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:
•
credit approvals;
•
routine monitoring of counterparties’ credit limits and their overall credit ratings;
•
limiting
our marketing, hedging and optimization activities with high risk counterparties;
•
margin, collateral, or prepayment arrangements; and
•
payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.
We have concentrations of credit risk with a few
of our commercial customers, primarily independent electric system operators, relating to our sales of power, steam and hedging and optimization activities. We believe that our credit policies and practices adequately monitor our credit risk, and currently our counterparties are performing according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts and PPAs irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Balance Sheets. Our counterparty credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our
derivative assets and (liabilities) at December 31, 2014, and the period during which the instruments will mature are summarized in the table below (in millions):
Interest
Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base rates, generally LIBOR. The following table summarizes the contract terms as well as the fair values of our debt instruments exposed to interest rate risk as of December 31, 2014. All outstanding balances and fair market values are shown gross of applicable premium or discount, if any (in millions):
Projection
based upon forward LIBOR rates inferred from spot rates at December 31, 2014.
Our variable rate financings are indexed to base rates, generally LIBOR. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. The fair value of our interest rate swaps are validated based upon external quotes. Our interest rate swaps are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate swaps expose us to any significant credit risk. Holding all other factors constant, we estimate that a 10% decrease in interest rates would result in a change in the fair value of our interest rate swaps hedging our variable rate debt of approximately $(9) million at December 31,
2014.
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APPLICATION OF CRITICAL ACCOUNTING POLICIES
The preparation of financial statements in accordance with U.S. GAAP requires management to make certain estimates and assumptions which are inherently imprecise and may differ significantly from actual results achieved. We believe the following are our more critical accounting policies due to the significance, subjectivity and judgment involved in determining our estimates used in preparing our Consolidated Financial Statements. See Note 2 of the Notes to Consolidated Financial Statements for a discussion of the application of these and other accounting policies. We evaluate our estimates and
assumptions used in preparing our Consolidated Financial Statements on an ongoing basis utilizing historic experience, anticipated future events or trends, consultation with third party advisors or other methods that involve judgment as determined appropriate under the circumstances. The resulting effects of changes in our estimates are recorded in our Consolidated Financial Statements in the period in which the facts and circumstances that give rise to the change in estimate become known.
Revenue Recognition
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. Determining the proper accounting for our power contracts
can require significant judgment and impact how we recognize revenue. In addition, we determine whether the contract should be accounted for on a gross or net basis. Determining the proper accounting treatment involves the evaluation of quantitative, as well as qualitative factors, to determine if the contract should be accounted for as one of the following:
Lease
Accounting — Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract.
Executory and Physical Contracts Exempt from Derivative Accounting — We generally recognize revenue from the sale of power or host steam thermal energy for sale to our customers for use in industrial or other heating operations,
upon transmission and delivery to the customer at the contractual price. In addition to revenues from power, host steam revenues and RECs from our Geysers Assets related to generation, our operating revenues also include:
•
power and steam revenue consisting of fixed and variable capacity payments, including capacity payments received from PJM and ISO-NE capacity auctions which are not related to generation;
•
other revenues such as RMR Contracts,
resource adequacy and certain ancillary service revenues; and
•
other service revenues.
Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues, unless qualified as a lease, are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
See “ — Accounting for Derivative Instruments” directly below for a discussion of the significant judgments and
estimates related to accounting for derivative instruments. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts that are either exempt from derivative accounting or do not meet the definition of a derivative instrument.
Gross vs. Net Accounting — We determine whether the financial statement presentation of revenues should be on a gross or net basis. Where we act as principal, we record settlement of our physical commodity contracts on a gross or net basis dependent upon whether the contract
results in physical delivery of the underlying product. With respect to our physical executory contracts, where we do not take title to the commodities but receive a variable payment to convert natural gas into power and steam in a tolling operation, we record revenues on a net basis.
Fair Value Measurements
We use fair value to measure certain of our assets, liabilities and expenses in our financial statements. Fair value is the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (i.e., the exit price). Generally, the determination of fair value requires the use of significant judgment
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and different approaches and models under varying circumstances. Under a market based approach, we consider prices of similar assets, consult with brokers and experts or employ other valuation techniques. Under an income based approach, we generally estimate future cash flows and then discount them at a risk adjusted rate.
Accordingly, the determination of fair value represents a critical accounting policy. Our most significant fair value measurements represent the valuation of our derivative assets and liabilities, which are measured on a recurring basis (each reporting period) and measurements of impairments and acquired assets on a nonrecurring basis. We primarily apply the market approach and income approach for recurring fair value measurements (primarily our derivative assets and liabilities)
using the best available information. We primarily utilize the income approach for nonrecurring fair value measurements such as impairments of our assets as market prices for similar assets may not be readily available and may not incorporate the expected future returns from our assets. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs. U.S. GAAP establishes a fair value hierarchy which classifies fair value measurements from level 1 through level 3 based upon the inputs used to measure fair value:
Level 1 — Quoted prices (unadjusted) are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide
pricing information on an ongoing basis.
Level 2 — Pricing inputs include quoted prices for similar assets and liabilities in active markets, and inputs other than quoted prices that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
Level 3 — Pricing inputs include significant inputs that are generally less observable or from unobservable sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Derivative Instruments and Valuation Techniques
The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh
and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future. Derivative contracts can be exchange-traded or OTC. For OTC derivatives that trade in liquid markets, model inputs can generally be verified and model selection does not involve significant management judgment. Certain OTC derivatives trade in less liquid markets with limited pricing information, and the determination of fair value for these derivatives is inherently more difficult.
For our level 2 and level 3 derivative
instruments, we utilize models to measure fair value. Where models are used, the selection of a particular model to value an asset or liability depends upon the contractual terms and specific risks, as well as the availability of pricing information in the market. We generally use similar models to value similar instruments. Valuation models require a variety of inputs, including contractual terms, market prices, yield curves, credit curves and measures of volatility. These models are primarily industry-standard models, including the Black-Scholes option-pricing model. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. In cases where there is no corroborating market information available to support significant model inputs, we initially use the transaction price as the best estimate
of fair value.
Our derivative instruments that are traded on the NYMEX or Intercontinental Exchange primarily consist of natural gas swaps, futures and options and are classified as level 1 fair value measurements.
Our derivative instruments that primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable are classified as level 2 fair value measurements. Generally, we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg.
Our OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions are classified as level 3 fair value measurements. Complex or structured transactions are tailored to our or our customers’ needs and can introduce the need
for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
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The determination of fair value of our derivatives also includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We assess non-performance risk by adjusting the fair value of our derivatives based on our credit standing or the credit standing of our counterparties involved and the impact
of credit enhancements, if any. Such valuation adjustments represent the amount of probable loss due to default either by us or a third party. Our credit valuation methodology is based on a quantitative approach which allocates a credit adjustment to the fair value of derivative transactions based on the net exposure of each counterparty. We develop our credit reserve based on our expectation of the market participants’ perspective of potential credit exposure. Our calculation of the credit reserve on net asset positions is based on available market information including credit default swap rates, credit ratings and historical default information. We also incorporate non-performance risk in net liability positions based on an assessment of our potential risk of default.
Impairments
When we determine that an impairment exists, we determine fair value using valuation techniques such
as the present value of expected future cash flows. In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs and changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our other earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
We also discount the estimated
future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparts. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations; however, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
Acquisitions of Assets and Liabilities
U.S. GAAP requires that the purchase price for an acquisition, such as the acquisition of our Guadalupe Energy Center and Fore River Energy Center, be assigned and allocated to the individual assets and liabilities based upon their fair value.
Generally, the amount recorded in the financial statements for an acquisition is the purchase price (value of the consideration paid), but a purchase price that exceeds the fair value of the assets acquired can result in the recognition of goodwill. In addition to the potential for the recognition of goodwill, differing fair values will impact the allocations of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded on our Consolidated Balance Sheet and can impact the timing and the amount of depreciation expense recorded in any given period. We utilize our best effort to make our determinations and review all information available including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers to help us make this determination as we deem appropriate under the circumstances.
Accounting
for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities
or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows are classified within financing activities.
Hedge Accounting — Revenues and expenses derived from derivative instruments that qualify for hedge accounting are recorded in the period and same financial statement line item as the hedged item. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting. We present the cash flows from hedging derivatives in the same category as the item being hedged within operating activities on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their
cash flows are classified within financing activities.
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Cash Flow Hedges — We report the effective portion of the mark-to-market 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 interest rate hedging instruments are recognized currently in earnings as a component of interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value
are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate and environmental product transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized
currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First
Lien Credit Facility and recorded the fair value of the swaps totaling approximately $156 million. Approximately $14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Statement of Operations for the year ended December 31, 2012, and approximately $142 million reflected the realization of losses recorded in prior periods.
See Notes 7 and 8 of the Notes to Consolidated Financial Statements for further discussion of our derivative instruments.
Accounting for VIEs and Financial Statement Consolidation Criteria
We consolidate
all VIEs where we determined that we have both the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plant's financial performance: operations and maintenance, plant dispatch, and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance
sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
•
evaluate if an entity is a
VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE's economic performance or when there are other changes in the powers held by individual variable interest holders.
Because we are required to perform ongoing reassessments of whether we are the primary beneficiary, future changes in our assessments of whether we are the primary beneficiary could require us to consolidate our VIEs that are currently not consolidated or deconsolidate our VIEs that are currently consolidated based upon our reassessments in future periods. Making these determinations can require the use of significant judgment to determine which variable interest holder has the power
to direct the most significant activities of the VIE (the primary beneficiary) and can directly impact amounts reported on our Consolidated Financial Statements.
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Disclosure Requirements
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine Corporation is substantially
limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them.
We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Balance Sheets. Our equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2014, 2013 and 2012, are recorded in (income) from unconsolidated investments in power plants.
We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us
to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.
Long-Lived Assets and Depreciation Expense
Determination of the appropriate depreciation method, proper useful lives and salvage values involves significant judgment, estimates, assumptions and historical experience. Changes in our estimates and methods can result in a significant impact in the amounts and timing of when we recognize depreciation expense and therefore significantly impact our financial condition and results of operations from period to period.
Different depreciation methods can impact the timing and amount of depreciation expense affecting our results of operations and could result in different net book values of assets at a particular time during the useful life of the asset affecting our financial position. Estimates of useful lives also significantly impact the timing and amounts of depreciation expense and include significant estimates. If useful lives are too short, then the asset is depreciated too quickly and depreciation expense is overstated. Estimated useful lives can significantly decrease if routine maintenance or certain upgrades are not performed, premature mechanical failure of the asset occurs, significant increases in the planned level of usage occur, advances in technology make the asset obsolete, or if there are adverse changes in environmental regulations. Our depreciable cost basis of our assets is reduced by the assets’ estimated salvage values. Dependent upon our ability to accurately
estimate salvage values and the timing of disposal, the salvage values actually realized for our assets could significantly increase or decrease resulting in additional gains or losses in the year of disposal.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for rotable equipment. For our Geysers Assets, we typically assume no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and the composite depreciation method for most of
all of the other natural gas-fired power plant asset groups and Geysers Assets.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments, turbine equipment and specifically identified intangibles, on an annual basis or when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Examples of such events or changes in circumstances are:
•
a significant decrease in the market price of a long-lived asset;
•
a
significant adverse change in the manner an asset is being used or its physical condition;
•
an adverse action by a regulator or legislature or an adverse change in the business climate;
80
•
an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;
•
a
current-period loss combined with a history of losses or the projection of future losses; or
•
a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.
When we believe an impairment condition on long-lived assets such as property, plant and equipment may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are
expected to be held and used. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss.
When we believe an impairment condition may exist on specifically identifiable intangibles or an investment, we must estimate their fair value to determine the amount of any impairment loss. Significant judgment is required in determining fair value as discussed above in “— Fair Value Measurements.”
All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that it is no longer probable that the projects will be completed and all capitalized costs recovered through future
operations, the carrying values of the projects would be written down to their fair value. When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of the carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
See Note 2 of the Notes to Consolidated Financial Statements for further discussion of our impairment evaluation of long-lived assets.
Accounting for Income Taxes
To arrive at our consolidated income tax provision and other tax balances, significant judgment and estimates are required. Although we believe that our estimates are reasonable,
no assurance can be given that the final tax outcome of these matters will not be different than that which is reflected in our historical tax provisions and accruals. Such differences could have a material impact on our income tax provision, other tax accounts and net income in the period in which such determination is made.
As of December 31, 2014, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $6.9 billion, which expire between 2023 and 2033, and NOL carryforwards in 22 states and the District of Columbia totaling approximately $4.0 billion, which expire between 2015 and 2034,
substantially all of which are offset with a full valuation allowance. We also have approximately $800 million in foreign NOLs, which expire between 2026 and 2034, substantially all of which are offset with a full valuation allowance. The NOL carryforwards available are subject to limitations on their annual usage. Under federal and applicable state income tax laws, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to certain time limitations as prescribed by the taxing authorities.
In the ordinary course of business, there are many transactions and calculations where the ultimate tax outcome is uncertain. Some of these uncertainties arise as a consequence of the treatment of capital assets, financing transactions,
multistate taxation of operations and segregation of foreign and domestic income and expense to avoid double taxation. We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no longer more likely than not that the tax position would be sustained upon examination. The determination and calculation of uncertain tax positions involves significant judgment in the application of complex tax laws. Resolution of these uncertainties in a manner inconsistent with our expectations could have a material impact on our financial condition or results of operations.
As of December 31, 2014, we had $56 million of unrecognized tax benefits from uncertain tax positions.
See Note 10 of the Notes to Consolidated Financial Statements for further discussion of our accounting for income taxes.
New Accounting Standards and Disclosure Requirements
See Note 2 of the Notes to Consolidated Financial Statements for a discussion of new accounting standards and disclosure requirements.
81
Item
7A.
Quantitative and Qualitative Disclosures about Market Risk
The information required hereunder is set forth under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.”
Item 8.
Financial Statements and Supplementary Data
The information required hereunder is set forth under “Report of Independent Registered Public Accounting Firm,”“Consolidated Statements of Operations,”“Consolidated Statements of Comprehensive
Income,”“Consolidated Balance Sheets,”“Consolidated Statements of Stockholders’ Equity,”“Consolidated Statements of Cash Flows,” and “Notes to Consolidated Financial Statements” included in the Consolidated Financial Statements that are a part of this Report. Other financial information and schedules are included in the Consolidated Financial Statements that are a part of this Report.
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item
9A.
Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our Exchange Act reports is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required financial disclosure.
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of
the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) or Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, the Chief Executive Officer and the Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.
Management’s Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined
in Rules 13a-15(f) and 15d-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
Our internal control over financial reporting includes those policies and procedures that:
•
pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;
•
provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and
•
provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.
Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. In making its assessment of internal control over financial
reporting, management used the criteria described in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
Based on management’s assessment, management has concluded that our internal control over financial reporting was effective as of December 31, 2014 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP.
82
The effectiveness of our internal control over financial reporting as of December 31,
2014, 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 2014, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B.
Other
Information
Steven D. Pruett, Executive Vice President and Chief Commercial Officer, notified Calpine that he will retire effective March 13, 2015.
83
PART III
Item 10.
Directors,
Executive Officers and Corporate Governance
Identification of Executive Officers
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:
Senior
Vice President and Chief Accounting Officer
Jack A. Fusco has served as Executive Chairman since May 14, 2014 and as a member of our Board of Directors since August 10, 2008. He previously served as our Chief Executive Officer from August 2008 to May 14, 2014 and President from August 2008 to December 2012. From July 2004 to February 2006, Mr. Fusco served as the Chairman and Chief Executive Officer of Texas Genco LLC. From 2002 through July 2004, Mr. Fusco was an exclusive energy investment advisor for Texas Pacific Group. From November 1998 until February 2002, he served as President and Chief Executive Officer of Orion Power Holdings, Inc. Prior
to his founding of Orion Power Holdings, Inc., Mr. Fusco was a Vice President at Goldman Sachs Power, an affiliate of Goldman, Sachs & Co. Prior to joining Goldman Sachs, Mr. Fusco was employed by Pacific Gas & Electric Company or its affiliates in various engineering and management roles for approximately 13 years. Mr. Fusco obtained a Bachelor of Science degree in Mechanical Engineering from California State University, Sacramento.
John B. (Thad) Hill has served as our President and Chief Executive Officer and as a member of our Board of Directors since May 14, 2014. He previously served as our President and Chief Operating Officer from December 2012, as our Executive Vice President and Chief Operating Officer from November 2010 to December 2012 and as our Executive Vice President and Chief Commercial Officer from September 2008 to November
2010. Prior to joining the Company, Mr. Hill served as Executive Vice President of NRG Energy, Inc. from February 2006 to September 2008 and President of NRG Texas LLC from December 2006 to September 2008. Prior to joining NRG Energy, Inc., Mr. Hill was Executive Vice President of Strategy and Business Development at Texas Genco LLC from 2005 to 2006. From 1995 to 2005, Mr. Hill was with Boston Consulting Group, Inc., where he rose to Partner and Managing Director and led the North American energy practice, serving companies in the power and natural gas sectors with a focus on commercial and strategic issues. Mr. Hill received his Bachelor of Arts degree from Vanderbilt University and a Master of Business Administration degree from the Amos Tuck School of Dartmouth College.
Zamir
Rauf has served as our Executive Vice President and Chief Financial Officer since December 17, 2008, after serving as Interim Chief Financial Officer from June 4, 2008. Previously, he served as our Senior Vice President, Finance and Treasurer from September 2007 until his appointment as Interim Chief Financial Officer. Since joining the Company in February 2000, Mr. Rauf has served as Manager, Finance from February 2000 to April 2001, Director, Finance from April 2001 to December 2002, Vice President, Finance from December 2002 to July 2005 and Senior Vice President, Finance from July 2005 to September 2007. Prior to joining the Company, Mr. Rauf held various accounting and finance
roles with Enron North America and Dynegy Inc., as well as credit and lending roles with Comerica Bank. Mr. Rauf earned his Bachelor of Arts degree in Business and Commerce and Masters in Business Administration – Finance degree from the University of Houston.
W. Thaddeus Miller has served as our Executive Vice President, Chief Legal Officer and Secretary since August 12, 2008. Prior to joining the Company, Mr. Miller served as Executive Vice President and Chief Legal Officer of Texas Genco LLC from December 2004 until February 2006. From 2002 to 2004, Mr. Miller was a consultant to Texas Pacific Group, a private equity firm. From 1999 to 2002, he served as Executive Vice President and Chief Legal Officer of Orion Power Holdings, Inc., an independent power producer. From
1994 to 1999, Mr. Miller was a Vice President of Goldman Sachs & Co., where he focused on wholesale electric and other energy commodity trading. Before joining Goldman Sachs & Co., Mr. Miller was a partner in a New York law firm. Mr. Miller earned his Bachelor of Science degree from the U.S. Merchant Marine Academy and his Juris Doctor degree from St. John’s School of Law. In addition, Mr. Miller was an officer in the U.S. Coast Guard from 1973 through 1976.
84
Steven D. Pruett has been Chief Commercial Officer since May 2014 and Executive Vice President since January 1, 2014. He has led our Commercial Operations team since joining Calpine in June 2011 and previously served as Senior Vice President
of Commercial Operations. From 1997 to 2006, Mr. Pruett was at Goldman Sachs, first as a Vice President then as a Managing Director; from 1997 to 2001 he helped launch and then run trading at Constellation Power Source, as a joint venture between Goldman Sachs and Baltimore Gas & Electric, until Goldman liquidated the joint venture; he then launched and led Goldman Sachs’ power trading unit until retiring in 2006. From 1995 to 1996, Mr. Pruett set up and managed trading operations for Cinergy (now Duke Energy). Steve began his career at PSI Energy, where he worked from 1978 to 1994 in positions of increasing responsibility, including management of wholesale power market transactions. He holds a Bachelor of Science in accounting from Indiana State University.
John Adams has served as Executive Vice President of Power Operations for Calpine since January
1, 2014. He had previously been Senior Vice President for Power Operations beginning in April 2010. Prior to joining Calpine, Mr. Adams worked at Mitsubishi Power Systems Americas, Inc., where he served as Senior Vice President of Operations from 2006 to 2010 and Vice President of Sales and Marketing from 2002 to 2006 with direct management responsibility for sales and marketing, engineering, project management, construction, commissioning and cost control. From 1980 to 2003, he worked for Foster Wheeler Energy Corporation as Vice President, Project Operations; Vice President, Commercial Operations, and Vice President, HRSG and Industrial Products. Mr. Adams holds a Bachelor of Science degree in mechanical engineering from Michigan Technological University.
Jim D. Deidiker has served as our Senior Vice President and
Chief Accounting Officer since November 15, 2010. Mr. Deidiker served as the Company’s Senior Vice President and Chief Accounting Officer since joining the Company in January 2008 until May 2010, when he resigned as the Company’s Chief Accounting Officer due to health concerns, but remained an employee. Mr. Deidiker returned to his role as the Company’s Senior Vice President and Chief Accounting Officer in November 2010. Prior to joining the Company, Mr. Deidiker served as Vice President and Controller
of Texas Genco LLC from 2005 to 2006 where he was responsible for financial and public reporting as well as management of the accounting function. From 1998 to 2005, Mr. Deidiker served as Managing Director & Vice President, Administration of AEP Energy Services, Inc. where he was responsible for management of the accounting function, financial reporting, contract administration and risk management for the gas pipeline and trading segment of AEP Energy Services, Inc. Mr. Deidiker obtained a Bachelor of Science degree in Accounting from Missouri State University and a Master in Business Administration degree from the University of Houston. In addition, Mr. Deidiker is a Certified Public Accountant and Certified Management Accountant.
The remaining information required by this Item is incorporated
herein by reference to the sections entitled “Board Meetings and Board Committee Information — Committees and Committee Charters” and “ — Audit Committee,”“Proposal 1 — Election of Directors,”“Section 16(a) Beneficial Ownership Reporting Compliance,” and “Corporate Governance Matters — Code of Conduct and Ethics” in our proxy statement for the 2015 annual meeting of stockholders to be held on May 13, 2015 (the “Proxy Statement”).
Item 11.
Executive Compensation
Information required by this Item
is incorporated herein by reference to the sections entitled “Compensation Discussion and Analysis,”“Executive Compensation,”“Director Compensation” and “Board Meeting and Board Committee Information — Compensation Committee Interlocks and Insider Participation” in the Proxy Statement.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Information required by this Item is incorporated herein by reference to the
sections entitled “Executive Compensation — Securities Authorized for Issuance Under Equity Compensation Plans” and “Security Ownership of Certain Beneficial Owners and Management and Related Shareholder Matters” in the Proxy Statement.
Item 13.
Certain Relationships and Related Transactions, and Director Independence
Information required by this Item is incorporated herein by reference to the sections entitled “Certain Relationships and Related Transactions,”“Corporate Governance Matters — Director Independence”
and “Corporate Governance Matters — Business Relationships and Related Party Transactions Policy” in the Proxy Statement.
Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the U.S. Bankruptcy Code (incorporated by reference to Exhibit 2.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 27, 2007).
2.3
Purchase
and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers and Public Service Company of Colorado, as Purchaser dated as of April 2, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed with the SEC on July 30, 2010).**,††
2.4
Purchase
Agreement by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC dated as of April 20, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on July 8, 2010).**
2.5
Purchase and Sale Agreement, dated April 17, 2014, among Calpine Corporation, Calpine Project Holdings, Inc., Calgen Expansion Company, LLC and NatGen
Southeast Power LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
Amended and Restated Indenture, dated May 25, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 8% senior secured notes due 2019 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report
on Form 8-K, filed with the SEC on May 25, 2010).
4.3
Indenture, dated July 23, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with
the SEC on July 23, 2010).
4.4
Indenture, dated October 22, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 22,
2010).
4.5
Indenture, dated January 14, 2011, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on January 14 , 2011).
First Supplemental
Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011).
88
Exhibit
Number
Description
4.8
First
Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011).
4.9
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine
Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC on April 29, 2011).
4.10
First
Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011).
4.11
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine
Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC on April 29, 2011).
4.12
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.13
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.14
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.15
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.16
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
89
Exhibit
Number
Description
4.17
Third Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine
Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.18
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.19
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.20
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.21
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.22
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.24 to Calpine’s Annual Report on Form 10-K for the year ended December 31,
2012, filed with the SEC on February 13, 2013).
4.23
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River
OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.25 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 13, 2013).
4.24
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.26 to Calpine’s Annual Report on Form 10-K for the year ended December 31,
2012, filed with the SEC on February 13, 2013).
4.25
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River
OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.27 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 13, 2013).
90
Exhibit
Number
Description
4.26
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.28 to Calpine’s Annual Report on Form 10-K for the year ended December
31, 2012, filed with the SEC on February 13, 2013).
4.27
Indenture dated as of October 31, 2013, for the senior secured notes due 2022 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on
Form 8-K, filed with the SEC on October 31, 2013).
4.28
Indenture dated as of October 31, 2013, for the senior secured notes due 2024 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Calpine’s Current Report on Form
8-K, filed with the SEC on October 31, 2013).
4.29
Fifth Supplemental Indenture dated as of October 30, 2013 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee under the indenture, dated as of October
21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.3 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 31, 2013).
Credit Agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and other parties thereto (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 13, 2010).
10.1.1.6
Credit
Agreement, dated March 9, 2011 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on March 10, 2011).
Credit Agreement, dated October 9, 2012 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners
L.P., as collateral agent, Barclays Bank PLC, Deutsche Bank Securities Inc., and RBC Capital Markets, as co-documentation agents (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 10, 2012).
10.1.1.9
Amendment to the Credit Agreement, dated February 15, 2013 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc.,
as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent (incorporated by reference to Exhibit 10.9 to Calpine’s 10-Q for the quarter ended March 31, 2013, filed with the SEC on May 2, 2013).
10.1.1.10
Amendment to the Credit Agreement, dated
February 15, 2013 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Barclays Bank PLC, Deutsche Bank Securities Inc., and RBC Capital Markets, as co-documentation agents (incorporated by reference to Exhibit 10.10 to Calpine’s 10-Q for the quarter ended March 31, 2013, filed with the SEC on May 2, 2013).
10.1.1.11
Credit
Agreement, dated May 3, 2013 among Calpine Construction Finance Company as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on May 3, 2013).
10.1.1.12
Amendment
No. 1 to the December 10, 2010 Credit Agreement, dated as of June 27, 2013, among Calpine Corporation, as borrower, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and the lenders 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 1, 2013).
10.1.1.13
Amendment
to the Credit Agreement, dated February 20, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party hereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
10.1.1.14
Incremental
Term B-2 Loan Commitment Supplement to the Credit Agreement, dated February 26, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party hereto, and Goldman Sachs Lending Partners, LLC as administrative agent and as collateral agent under the Credit Agreement, dated as of May 3, 2013 and as amended on February 20, 2014 (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
Amendment No. 2 to the Credit Agreement, dated as of July 30, 2014, among Calpine Corporation, as borrower, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and the lenders 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
31, 2014).
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (Jack A. Fusco) (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on August 12, 2008).†
Calpine
Corporation Executive Sign On Non-Qualified Stock Option Agreement (John B. (Thad) Hill) (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on September 4, 2008).†
Restricted Stock Agreement Pursuant to the Amended and Restated 2008 Equity Incentive Plan, dated May 13, 2014 among John
B. Hill and Calpine Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014).†
Calpine
Corporation Executive Sign On Non-Qualified Stock Option Agreement (Thaddeus Miller) (incorporated by reference to Exhibit 4.4 to Calpine’s Registration Statement on Form S-8 (Registration No. 333-153860) filed with the SEC on October 6, 2008).†
Calpine
Corporation 2010 Calpine Incentive Plan (incorporated by reference to Exhibit 10.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed with the SEC on July 30, 2010).†
10.2.7
Calpine Corporation 2009 Calpine Incentive Plan (incorporated by reference to Exhibit 10.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, filed
with the SEC on May 8, 2009).†
Form
of Non-Qualified Stock Option Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to Exhibit 10.4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
10.2.7.3
Form of Restricted Stock Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to Exhibit 10.4.4
to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
10.2.8
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan (incorporated by reference to Annex A to Calpine’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 5, 2010).†
Calpine Corporation Amended and Restated Change in Control and Severance Benefits Plan (incorporated
by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on November 8, 2013).†
Amended and Restated Calpine Corporation
Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on May 10, 2013).†
10.2.21
Form of Restricted Stock Award Agreement between the Company and Jack A. Fusco and W. Thaddeus Miller (Pursuant to the Amended and Restated Calpine Corporation 2008
Equity Incentive Plan, dated February 26, 2014)(incorporated by reference to Exhibit 10.4 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
Form
of Performance Share Unit Award Agreement between the Company and Jack A. Fusco and W. Thaddeus Miller (Pursuant to the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014) (incorporated by reference to Exhibit 10.6 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this Form 10-K).*
31.1
Certification
of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1
Certification
of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.‡
Management contract or compensatory plan, contract or arrangement.
**
Schedules
omitted pursuant to Item 601(b)(2) of Regulation S-K. Calpine will furnish supplementally a copy of any omitted schedule to the SEC upon request.
††
Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 under the Securities Exchange Act of 1934.
96
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
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 with power and authority to do any and all acts and
things and to execute any and all instruments which said attorney and agent determines 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.
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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014 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, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements and financial statement schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in Management's Report on Internal Control over Financial Reporting, appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedule, and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting
principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition
of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Cash and cash equivalents ($229 and $242 attributable to VIEs)
$
717
$
941
Accounts receivable, net of allowance of $4 and $5
648
552
Inventories
447
364
Margin
deposits and other prepaid expense
148
309
Restricted cash, current ($106 and $100 attributable to VIEs)
195
203
Derivative assets, current
2,058
445
Other
current assets
7
42
Total current assets
4,220
2,856
Property, plant and equipment, net ($4,342 and $4,191 attributable to VIEs)
13,190
12,995
Restricted
cash, net of current portion ($48 and $68 attributable to VIEs)
49
69
Investments in power plants
95
93
Long-term derivative assets
439
105
Other
assets ($164 and $195 attributable to VIEs)
385
441
Total assets
$
18,378
$
16,559
LIABILITIES & STOCKHOLDERS’ EQUITY
Current
liabilities:
Accounts payable
$
580
$
462
Accrued interest payable
165
162
Debt,
current portion ($150 and $140 attributable to VIEs)
199
204
Derivative liabilities, current
1,782
451
Other current liabilities
473
252
Total
current liabilities
3,199
1,531
Debt, net of current portion ($3,242 and $2,923 attributable to VIEs)
11,083
10,908
Long-term derivative
liabilities
444
243
Other long-term liabilities
221
309
Total liabilities
14,947
12,991
Commitments
and contingencies (see Note 15)
Stockholders’ equity:
Preferred stock, $0.001 par value per share; authorized 100,000,000 shares, none issued and outstanding at December 31, 2014 and 2013
—
—
Common
stock, $0.001 par value per share; authorized 1,400,000,000 shares, 502,287,022 shares issued and 381,921,264 shares outstanding at December 31, 2014, and 497,841,056 shares issued and 429,038,988 shares outstanding at December 31, 2013
1
1
Treasury stock, at cost, 120,365,758 and 68,802,068 shares, respectively
(2,345
)
(1,230
)
Additional
paid-in capital
12,440
12,389
Accumulated deficit
(6,540
)
(7,486
)
Accumulated other comprehensive loss
(178
)
(160
)
Total
Calpine stockholders’ equity
3,378
3,514
Noncontrolling interest
53
54
Total stockholders’ equity
3,431
3,568
Total
liabilities and stockholders’ equity
$
18,378
$
16,559
The accompanying notes are an integral part of these Consolidated Financial Statements.
CONSOLIDATED STATEMENTS OF CASH FLOWS — (Continued)
(in
millions)
2014
2013
2012
Cash paid during the period
for:
Interest, net of amounts capitalized
$
610
$
672
$
719
Income
taxes
$
23
$
24
$
16
Supplemental
disclosure of non-cash investing and financing activities:
Change in capital expenditures included in accounts payable
$
3
$
27
$
19
Additions
to property, plant and equipment through assumption of long-term note payable
$
—
$
—
$
8
Additions to property, plant and equipment through capital leases
$
19
$
—
$
5
____________
(1)
Includes
depreciation and amortization included in fuel and purchased energy expense and interest expense on our Consolidated Statements of Operations.
The accompanying notes are an integral part of these Consolidated Financial Statements.
We are a wholesale power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale power markets in California (included in our West segment), Texas (included in our Texas segment) and the Northeast region (included in our East segment) of the U.S. We sell wholesale power, steam, capacity, renewable energy credits and ancillary services to
our customers, which include utilities, independent electric system operators, industrial and agricultural companies, retail power providers, municipalities, power marketers and others. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power and other physical and financial contracts to hedge certain business risks and optimize our portfolio of power plants.
2.
Summary
of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Consolidated Financial Statements have been prepared in accordance with U.S. GAAP and include the accounts of all majority-owned subsidiaries that are not VIEs and all VIEs where we have determined we are the primary beneficiary. Intercompany transactions have been eliminated in consolidation.
Equity Method Investments — We use the equity method of accounting to record our net interests in VIEs where we have determined that we are not the primary beneficiary, which include Greenfield LP, a 50% partnership interest, and Whitby, a 50%
partnership interest. Our share of net income (loss) is calculated according to our equity ownership percentage or according to the terms of the applicable partnership agreement. See Note 5 for further discussion of our VIEs and unconsolidated investments.
Reclassifications — We have reclassified certain prior year amounts for comparative purposes. These reclassifications did not have a material impact on our financial condition, results of operations or cash flows.
Jointly-Owned Plants — Certain of our subsidiaries own undivided interests in jointly-owned plants. These plants are maintained and operated pursuant to their joint ownership participation and operating agreements. We are responsible for our subsidiaries’
share of operating costs and direct expenses and include our proportionate share of the facilities and related revenues and direct expenses in these jointly-owned plants in the corresponding balance sheet and income statement captions of our Consolidated Financial Statements. The following table summarizes our proportionate ownership interest in jointly-owned power plants:
Use
of Estimates in Preparation of Financial Statements
The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Financial Statements. Actual results could differ from those estimates.
Fair Value of Financial Instruments and Derivatives
The carrying values of accounts receivable, accounts payable and other receivables and payables approximate their respective fair values due to their short-term maturities. See Note 6 for disclosures regarding the fair value of our debt instruments and Note 7 for disclosures regarding the fair values of our derivative instruments and margin deposits and certain of our cash balances.
107
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 financial instruments. Certain of our cash and cash equivalents, as well as our restricted cash balances, are invested in money market accounts with investment banks that are not FDIC insured. We place our cash and cash equivalents and restricted cash in what we believe to be creditworthy financial institutions and certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Additionally, we actively monitor the credit risk of our counterparties, including our receivable, commodity and derivative
transactions. Our accounts and notes receivable are concentrated within entities engaged in the energy industry, mainly within the U.S. We generally have not collected collateral for accounts receivable from utilities and end-user customers; however, we may require collateral in the future. For financial and commodity derivative counterparties, we evaluate the net accounts receivable, accounts payable and fair value of commodity contracts and may require security deposits, cash margin or letters of credit to be posted if our exposure reaches a certain level or their credit rating declines.
Our counterparties primarily consist of three categories of entities who participate in the wholesale energy markets:
•
financial
institutions and trading companies;
•
regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers; and
•
oil, natural gas, chemical and other energy-related industrial companies.
We have concentrations of credit risk with a few of our customers relating to our sales of power, steam and hedging, optimization and trading activities. We have exposure to trends within the energy industry, including declines in the creditworthiness of
our counterparties for our commodity and derivative transactions. Currently, certain of our counterparties within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty credit risk and monitors our net exposure with each counterparty on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a counterparty credit risk threshold which is determined based on each counterparty’s credit rating and evaluation of their financial statements. We utilize these thresholds to determine the need for additional collateral or restriction of activity with the counterparty. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties are performing and financially settling timely according to their respective agreements.
Cash and
Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts, which have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects. At December 31, 2014 and 2013, we had cash and cash equivalents of $257 million and $292 million, respectively, that were subject to such project
finance facilities and lease agreements.
Restricted Cash
Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent, major maintenance and debt repurchases or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets and Statements of Cash Flows.
108
The table below represents the components of our restricted cash as of December 31, 2014 and 2013 (in millions):
2014
2013
Current
Non-Current
Total
Current
Non-Current
Total
Debt
service
$
10
$
25
$
35
$
11
$
41
$
52
Rent
reserve
4
—
4
3
—
3
Construction/major
maintenance
54
17
71
35
20
55
Security/project/insurance
127
5
132
151
6
157
Other
—
2
2
3
2
5
Total
$
195
$
49
$
244
$
203
$
69
$
272
Accounts
Receivable and Payable
Accounts receivable and payable represent amounts due from customers and owed to vendors, respectively. Accounts receivable are recorded at invoiced amounts, net of reserves and allowances, and do not bear interest. Receivable balances greater than 30 days past due are individually reviewed for collectability, and if deemed uncollectible, are charged off against the allowance account after all means of collection have been exhausted and the potential for recovery is considered remote. We use our best estimate to determine the required allowance for doubtful accounts based on a variety of factors, including the length of time receivables are past due, economic trends and conditions affecting our customer base, significant one-time events and historical write-off experience. Specific provisions are recorded for individual receivables when we become aware of a customer’s inability to meet its financial obligations.
We review the adequacy of our reserves and allowances quarterly.
The accounts receivable and payable balances also include settled but unpaid amounts relating to our marketing, hedging and optimization activities. Some of these receivables and payables with individual counterparties are subject to master netting arrangements whereby we legally have a right of offset and settle the balances net. However, for balance sheet presentation purposes and to be consistent with the way we present the majority of amounts related to marketing, hedging and optimization activities on our Consolidated Statements of Operations, we present our receivables and payables on a gross basis. We do not have any significant off balance sheet credit exposure related to our customers.
Inventory
Inventory primarily consists of spare parts, stored natural gas and fuel
oil, environmental products and natural gas exchange imbalances. Inventory, other than spare parts, is stated primarily at the lower of cost or market value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to plant operating expense or capitalized to property, plant and equipment as the parts are utilized and consumed.
Collateral
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets previously subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility as collateral under certain of our power and natural gas agreements. These agreements qualify as “eligible commodity hedge agreements”
under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. The first priority liens have been granted in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to our counterparties under such agreements. The counterparties under such agreements would share the benefits of the collateral subject to such first priority liens ratably with the lenders under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. Our interest rate swap agreements relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 9 for a further discussion on our amounts and use of collateral.
109
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 known boundaries of the steam reservoir. We have capitalized costs incurred during ownership consisting of additions, certain replacements or repairs when the repairs 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 all well costs, except well workovers and routine repairs and maintenance, have been capitalized since our purchase date.
We depreciate our assets under the straight-line method over the shorter of their estimated useful lives or lease term. For our natural gas-fired power plants, we assume an estimated salvage value which approximates 10% of the depreciable cost basis where we own the power plant or have a favorable option to purchase the power plant or take ownership of the power plant at conclusion of the lease term and approximately 0.15% of the depreciable costs basis for rotable equipment. For our Geysers Assets, we typically assume
no salvage values. We use the component depreciation method for our natural gas-fired power plant rotable parts and our information technology equipment and the composite depreciation method for most of all of the other natural gas-fired power plant asset groups and Geysers Assets.
Generally, upon normal retirement of assets under the composite depreciation method, the costs of such assets are retired against accumulated depreciation and no gain or loss is recorded. For the retirement of assets under the component depreciation method, generally, the costs and related accumulated depreciation of such assets are removed from our Consolidated Balance Sheets and a gain or loss is recorded as plant operating expense.
Impairment Evaluation of Long-Lived Assets (Including Intangibles and Investments)
We evaluate our long-lived assets, such as
property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate
fair value to determine the amount of any impairment loss. All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing and future contracts and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). 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.
110
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will
be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the impact of such variations could be material.
In August 2014, we executed a term sheet with Duke Energy Florida, Inc.
related to our Osprey Energy Center for a new PPA with a term of 27 months, after which Duke Energy Florida, Inc. would purchase our Osprey Energy Center subject to an asset sale agreement that was executed in the fourth quarter of 2014 and remains subject to federal and state regulatory approval. As a result, we conducted an impairment review of our Osprey Energy Center during the third quarter of 2014. We estimated fair value of our Osprey Energy Center under a modified market approach using the discounted cash flows under the PPA and the sale proceeds to be received, which incorporated a market participant's fair value of the power plant. We recorded an impairment loss of approximately $123 million which was recorded as a separate line item on our Consolidated Statements of Operations for the year ended December 31,
2014. We recorded an impairment loss of $16 million during the year ended December 31, 2013 related to a power plant in our West segment. During 2012, we did not record any impairment losses.
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, 2014 and 2013,
our asset retirement obligation liabilities were $47 million and $44 million, respectively, primarily relating to land leases upon which our power plants are built and the requirement that the property meet specific conditions upon its return.
Revenue Recognition
Our operating revenues are comprised of the following:
•
power and steam revenue consisting of fixed and variable capacity payments, which are not related to generation including capacity payments received from RTO and ISO capacity auctions, variable payments for power and steam, which are related to generation, host steam
and RECs from our Geysers Assets, other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues and realized settlements from our marketing, hedging, optimization and trading activities;
•
mark-to-market revenues from derivative instruments as a result of our marketing, hedging, optimization and trading activities; and
•
other service revenues.
Power
and Steam
Physical Commodity Contracts — We recognize revenue primarily from the sale of power and steam thermal energy for sale to our customers for use in industrial or other heating operations upon transmission and delivery to the customer.
We routinely enter into physical commodity contracts for sales of our generated power to manage risk and capture the value inherent in our generation. We apply lease accounting to contracts that meet the definition of a lease and accrual accounting treatment to those contracts
that are either exempt from derivative accounting or do not meet the definition of a derivative instrument. Additionally, we determine whether the financial statement presentation of revenues should be on a gross or net basis.
With respect to our physical executory contracts, where we act as a principal, we take title of the commodities and assume the risks and rewards of ownership by receiving the natural gas and using the natural gas in our operations to generate and deliver the power. Where we act as principal, we record settlement of our physical commodity contracts on a gross basis. Where we do not take title of the commodities but receive a net variable payment to convert natural gas into power and steam in a tolling operation, we record the
variable payment as revenue but do not record any fuel and purchased energy expense.
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Capacity payments, RMR Contracts, RECs, resource adequacy and other ancillary revenues, unless qualified as a lease, are recognized when contractually earned and consist of revenues received from our customers either at the market price or a contract price.
Realized and Mark-to-Market Revenues from Commodity Derivative Instruments
Realized Settlements of Commodity Derivative Instruments — The realized value
of power commodity sales and purchase contracts that are net settled or settled as gross sales and purchases, but could have been net settled, are reflected on a net basis and are included in Commodity revenue on our Consolidated Statements of Operations.
Mark-to-Market Gain (Loss) — The changes in the mark-to-market value of power-based commodity derivative instruments are reflected on a net basis as a separate component of operating revenues.
Leases — We have contracts, such as certain tolling agreements, which we account for as operating leases under U.S.
GAAP. Generally, we levelize certain components of these contract revenues on a straight-line basis over the term of the contract. The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2014, are as follows (in millions):
2015
$
561
2016
495
2017
433
2018
396
2019
357
Thereafter
1,380
Total
$
3,622
Accounting
for Derivative Instruments
We enter into a variety of derivative instruments including both exchange traded and OTC power and natural gas forwards, options as well as instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) and interest rate swaps. We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for and are designated under the normal purchase normal sale exemption. Accounting for derivatives at fair value requires us to make estimates about future prices during periods for which price quotes are not available from sources external to us, in which case we rely on internally developed price estimates. See Note 8 for further discussion on our accounting for derivatives.
Fuel and Purchased Energy Expense
Fuel
and purchased energy expense is comprised of the cost of natural gas and fuel oil purchased from third parties for the purposes of consumption in our power plants as fuel, and the cost of power and natural gas purchased from third parties for our marketing, hedging and optimization activities and realized settlements and mark-to-market gains and losses resulting from general market price movements against certain derivative natural gas contracts including financial natural gas transactions economically hedging anticipated future power sales that either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected.
Realized and Mark-to-Market Expenses from Commodity Derivative Instruments
Realized
Settlements of Commodity Derivative Instruments — The realized value of natural gas purchase and sales commodity contracts that are net settled are reflected on a net basis and included in Commodity expense on our Consolidated Statements of Operations. Power purchase commodity contracts that result in the physical delivery of power, and that also supplement our power generation, are reflected on a gross basis and are included in Commodity expense on our Consolidated Statements of Operations.
Mark-to-Market (Gain) Loss — The changes in the mark-to-market value of natural gas-based commodity derivative instruments
are reflected on a net basis as a separate component of fuel and purchased energy expense.
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Plant Operating Expense
Plant operating expense primarily includes employee expenses, utilities, chemicals, repairs and maintenance (including equipment failure and major maintenance), insurance and property taxes. We recognize these expenses when the service is performed or in the period in which the expense relates.
Income Taxes
Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values
of existing assets and liabilities and their respective tax basis and tax credit and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized in income in the period that includes the enactment date.
We recognize the financial statement effects of a tax position when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. We reverse a previously recognized tax position in the first period in which it is no
longer more-likely-than-not that the tax position would be sustained upon examination. See Note 10 for a further discussion on our income taxes.
Earnings per Share
Basic earnings 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 per share is calculated by adjusting the weighted average shares outstanding by the dilutive effect of share-based awards using the treasury stock method. See Note 11 for a further discussion of our earnings per share.
Stock-Based Compensation
We use the Black-Scholes option-pricing model or the Monte Carlo simulation model to estimate the fair value of our employee stock options
on the grant date. 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. Our performance share units are measured at fair value using a Monte Carlo simulation model at each reporting date until settlement. See Note 12 for a further discussion of our stock-based compensation.
Treasury Stock
Treasury stock purchases are accounted for under the cost method whereby the entire cost of the acquired stock is recorded as treasury stock. Upon retirement of treasury stock, the amounts in excess of par value are charged entirely to additional paid-in capital. See Note 14 for a further discussion of treasury stock.
New Accounting Standards and
Disclosure Requirements
Income Taxes — In July 2013, the FASB issued Accounting Standards Update 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists”. The provisions of the standard require an unrecognized tax benefit to be presented as a reduction to a deferred tax asset in the financial statements for a NOL carryforward, a similar tax loss, or a tax credit carryforward except in circumstances when the carryforward or tax loss is not available at the reporting date under the tax laws of the applicable jurisdiction to settle any additional income taxes or the tax law does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purposes. When those circumstances exist, the unrecognized tax benefit should be presented in the financial statements as a liability
and should not be combined with deferred tax assets. We adopted Accounting Standards Update 2013-11 in the first quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.
Financial Reporting of Discontinued Operations — In April 2014, the FASB issued Accounting Standards Update 2014-08, “Presentation of Financial Statements and Property, Plant, and Equipment”. The update limits discontinued operations reporting to disposals that represent a strategic shift that has (or will have) a major effect on an entity’s operations and financial results. The standard also requires new disclosures related to components reported as discontinued operations, as well as components of an entity that were sold and do not meet the criteria for discontinued operations reporting. The new financial statement presentation provisions relating to this standard
are prospective and effective for interim and annual periods beginning after December 15, 2014,
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with early adoption permitted. We do not anticipate a material impact on our financial condition, results of operations or cash flows as a result of adopting this standard.
Revenue Recognition — In May 2014, the FASB issued Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”. The comprehensive new revenue recognition standard will supersede all existing revenue recognition guidance. The core principle of the standard is that a company should recognize
revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard creates a five-step model for revenue recognition that requires companies to exercise judgment when considering contract terms and relevant facts and circumstances. The five-step model includes (1) identifying the contract, (2) identifying the separate performance obligations in the contract, (3) determining the transaction price, (4) allocating the transaction price to the separate performance obligations and (5) recognizing revenue when each performance obligation has been satisfied. The
standard also requires expanded disclosures surrounding revenue recognition. The standard is effective for fiscal periods beginning after December 15, 2016, including interim periods within that reporting period and allows for either full retrospective or modified retrospective adoption with early adoption being prohibited. We are currently assessing the future impact this standard may have on our financial condition, results of operations or cash flows.
Going Concern — In August 2014, the FASB issued Accounting Standards Update 2014-15, “Presentation of Financial Statements — Going Concern”. This standard requires an entity’s management to assess the entity’s ability to continue as a going concern every reporting period including interim periods and requires additional disclosures if conditions or events raise substantial doubt about an entity’s
ability to continue as a going concern. The standard is effective for annual periods ending after December 15, 2016, and for annual and interim periods thereafter with early adoption permitted. We early adopted this standard during the fourth quarter of 2014 which did not have a material impact on our financial condition, results of operations or cash flows.
3.
Acquisitions and Divestitures
Acquisition of Fore River Energy Center
On November 7, 2014, we, through our indirect, wholly-owned subsidiary
Calpine Fore River Energy Center, LLC, completed the purchase of Fore River Energy Center, a power plant with a nameplate capacity of 809 MW, and related plant inventory from a subsidiary of Exelon Corporation, for approximately $530 million, excluding working capital adjustments. The addition of this modern, efficient, natural gas-fired, combined-cycle power plant increased capacity in our East segment, specifically the constrained New England market. Built in 2003, Fore River Energy Center is located in North Weymouth, Massachusetts and features two combustion turbines, two heat recovery steam generators and one steam turbine. One turbine features dual-fuel capability that will enable it to run this winter on either natural gas or fuel oil, depending on market conditions, with the other turbine scheduled to be modified to be dual-fuel capable by winter 2016. The purchase price
was funded with cash on hand and primarily allocated to property, plant and equipment. Although the purchase price allocation has not been finalized, we do not expect to record any material adjustments to the preliminary purchase price allocation nor do we expect to recognize any goodwill as a result of this acquisition. The pro forma incremental impact of Fore River Energy Center on our results of operations for each of the years ended December 31, 2014 and 2013 is not material.
Acquisition of Guadalupe Energy Center
On February 26, 2014, we, through our indirect, wholly-owned subsidiary Calpine Guadalupe GP, LLC, completed the purchase of
a power plant owned by MinnTex Power Holdings, LLC with a nameplate capacity of 1,050 MW, for approximately $625 million, excluding working capital adjustments. The addition of this modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment, which is one of our core markets. The 110-acre site, located in Guadalupe County, Texas, which is northeast of San Antonio, Texas, includes two 525 MW generation blocks, each consisting of two GE 7FA combustion turbines, two heat recovery steam generators and one GE steam turbine. We also paid $15 million to acquire rights to an advanced development opportunity for an approximately 400 MW quick-start, natural gas-fired peaker. We funded the acquisition with $425 million
in incremental CCFC Term Loans and cash on hand. See Note 6 for a further description of the incremental CCFC Term Loans. The purchase price was primarily allocated to property, plant and equipment and was finalized during the third quarter of 2014 which did not result in any material adjustments to the preliminary purchase price allocation nor the recognition of any goodwill. The pro forma incremental impact of Guadalupe Energy Center on our results of operations for each of the years ended December 31, 2014 and 2013 is not material.
Acquisition of Bosque Energy Center
On November 7, 2012, we, through our indirect, wholly-owned subsidiary Calpine
Bosque Energy Center, LLC, completed the purchase of a power plant with a nameplate capacity of 800 MW owned by Bosque Power Co., LLC, for approximately $432 million. The modern, natural gas-fired, combined-cycle power plant increased capacity in our Texas segment and is located in
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Central Texas near the unincorporated community of Laguna Park in Bosque County. The site includes a 250 MW generation block with one natural-gas turbine, one heat recovery steam generator and one steam turbine that achieved COD in June 2001 and a 550 MW generation block with two natural-gas turbines that went online
in June 2000 as well as two heat recovery steam generators and one steam turbine that achieved COD in June 2011. We funded the $432 million purchase price with cash on hand. The purchase price, which was finalized in 2013, was primarily allocated to property, plant and equipment. We did not record any goodwill as a result of this acquisition.
Sale of Six Power Plants
On July 3, 2014, we completed the sale of six of our power plants in our East segment to NatGen Southeast Power LLC, a wholly-owned subsidiary of LS Power Equity Partners III. The purchase and sale agreement, dated April 17, 2014, stipulates the sale of 100% of the limited liability
company interests in (i) Mobile Energy LLC, (ii) Santa Rosa Energy Center, LLC, (iii) Carville Energy, LLC, (iv) Decatur Energy Center, LLC, (v) Columbia Energy LLC and (vi) Calpine Oneta Power, LLC and thereby sell assets comprising 3,498 MW of combined-cycle generation capacity in Oklahoma, Louisiana, Alabama, Florida and South Carolina for a sale price of approximately $1.57 billion in cash, plus approximately $2 million for working capital and other adjustments at closing. In accordance with the purchase and sale agreement, we have paid $12 million for certain maintenance events at December 31, 2014 and may also be required to make up to $4 million in future cash payments for planned maintenance. The divestiture of these power plants
has better aligned our asset base with our strategic focus on competitive wholesale markets.
We recorded a gain on sale of assets, net of approximately $753 million during the third quarter of 2014 and will use existing federal and state NOLs to almost entirely offset the projected taxable gains from the sale. The sale of the six power plants did not meet the criteria for treatment as discontinued operations.
The six power plants included in the transaction are as follows:
Plant
Name
Plant Capacity
Location
Oneta Energy Center
1,134
MW
Coweta, OK
Carville Energy Center(1)
501
MW
St.
Gabriel, LA
Decatur Energy Center
795
MW
Decatur, AL
Hog Bayou Energy Center
237
MW
Mobile,
AL
Santa Rosa Energy Center
225
MW
Pace, FL
Columbia Energy Center(1)
606
MW
Calhoun
County, SC
Total
3,498
MW
___________
(1)
Indicates combined-cycle cogeneration power plant.
Sale of Riverside Energy Center
Our
603 MW Riverside Energy Center had a PPA that provided WP&L an option to purchase the power plant and plant-related assets upon written notice of exercise prior to May 31, 2012. On May 18, 2012, WP&L exercised their option to purchase Riverside Energy Center, LLC, one of our VIEs which owned Riverside Energy Center. The sale closed on December 31, 2012 for approximately $402 million, and we recorded a pre-tax gain of approximately $7 million, which is included in (gain) on sale of assets, net on our Consolidated Statements of Operations. We used the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of Riverside Energy Center did
not meet the criteria for treatment as discontinued operations.
Sale of Broad River
On December 27, 2012, we, through our indirect, wholly-owned subsidiary Calpine Power Company, completed the sale of 100% of our ownership interest in each of the Broad River Entities for approximately $423 million. This transaction resulted in the disposition of our Broad River power plant, an 847 MW natural gas-fired, peaking power plant located in Gaffney, South Carolina, and includes a five-year consulting agreement with the buyer. We recorded a pre-tax gain of approximately $215 million in December 2012, which is included in (gain) on sale of assets, net on our
Consolidated Statements of Operations. We used the sale proceeds for our capital allocation activities and for general corporate purposes. The sale of the Broad River Entities did not meet the criteria for treatment as discontinued operations.
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4.
Property, Plant and Equipment, Net
As of December 31, 2014 and 2013,
the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
2014
2013
Depreciable Lives
Buildings, machinery and equipment
$
16,059
$
15,838
3
– 47 Years
Geothermal properties
1,294
1,265
13 – 59 Years
Other
203
164
3
– 47 Years
17,556
17,267
Less: Accumulated depreciation
4,984
4,897
12,572
12,370
Land
120
103
Construction
in progress
498
522
Property, plant and equipment, net
$
13,190
$
12,995
We
have various debt instruments that are collateralized by our property, plant and equipment. See Note 6 for a discussion of such instruments.
Buildings, Machinery and Equipment
This component primarily includes power plants and related equipment. Included in buildings, machinery and equipment are assets under capital leases. See Note 6 for further information regarding these assets under capital leases.
Geothermal Properties
This component primarily includes power plants and related equipment associated with our Geysers Assets.
Other
This component primarily includes software and emission reduction credits that are power plant specific and not available to be sold.
Capitalized
Interest
The total amount of interest capitalized was $19 million, $38 million and $38 million for the years ended December 31, 2014, 2013 and 2012, respectively.
5.
Variable Interest Entities and Unconsolidated Investments
We consolidate all of our VIEs where we have
determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the year ended December 31, 2014. We have the following types of VIEs consolidated in our financial statements:
Subsidiaries with Project Debt — All of our subsidiaries with project debt not guaranteed by Calpine have PPAs that provide financial support and are thus considered VIEs. We retain ownership and absorb the full risk of loss and potential for reward once the project debt is paid in full. Actions by the lender to assume control of collateral can occur only under limited circumstances
such as upon the occurrence of an event of default, which we have determined to be unlikely. See Note 6 for further information regarding our project debt and Note 2 for information regarding our restricted cash balances.
Subsidiaries with PPAs — Certain of our majority owned subsidiaries have PPAs that limit the risk and reward of our ownership and thus constitute a VIE.
VIE with a Purchase Option — OMEC has an agreement that provides a third party a fixed price option to purchase power plant assets exercisable in the year 2019. This purchase option limits the risk and reward of our ownership and, thus, constitutes a VIE.
116
Consolidation of VIEs
We consolidate our VIEs where we determine that we have both the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and the obligation to absorb losses or receive benefits from the VIE. We have determined that we hold the obligation to absorb losses and receive benefits in all of our VIEs where we hold the majority equity interest. Therefore, our determination of whether to consolidate is based upon which variable interest holder has the power to direct the most significant activities of the VIE (the primary beneficiary). Our analysis includes consideration of the following primary activities which we believe to have a significant impact on a power plant’s financial performance: operations and maintenance, plant dispatch,
and fuel strategy as well as our ability to control or influence contracting and overall plant strategy. Our approach to determining which entity holds the powers and rights is based on powers held as of the balance sheet date. Contractual terms that may change the powers held in future periods, such as a purchase or sale option, are not considered in our analysis. Based on our analysis, we believe that we hold the power and rights to direct the most significant activities of all our majority-owned VIEs.
Under our consolidation policy and under U.S. GAAP we also:
•
perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and
•
evaluate
if an entity is a VIE and whether we are the primary beneficiary whenever any changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lose the power from voting rights or similar rights of those investments to direct the activities of a VIE that most significantly impact the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
Noncontrolling Interest — We own a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which is also 25% owned by a third party. We fully consolidate this entity in our Consolidated Financial Statements and account for the third party ownership interest as a noncontrolling interest.
VIE Disclosures
Our
consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 10,365 MW and 9,427 MW, at December 31, 2014 and 2013, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of $47
million, nil and $20 million for the years ended December 31, 2014, 2013 and 2012, respectively.
U.S. GAAP requires separate disclosure on the face of our Consolidated Balance Sheets of the significant assets of a consolidated VIE that can be used only to settle obligations of the consolidated VIE and the significant liabilities of a consolidated VIE for which creditors (or beneficial interest holders) do not have recourse to the general credit of the primary beneficiary. In determining which assets of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where Calpine
Corporation is substantially limited or prohibited from access to assets (primarily cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs had project financing that prohibits the VIE from providing guarantees on the debt of others. In determining which liabilities of our VIEs meet the separate disclosure criteria, we consider that this separate disclosure requirement is met where there are agreements that prohibit the debt holders of the VIEs from recourse to the general credit of Calpine Corporation and where the amounts were material to our financial statements.
Unconsolidated VIEs and Investments in Power Plants
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are also VIEs; however, we do not have the power to direct the most significant activities
of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50%
partnership interest in Whitby.
117
We account for these entities under the equity method of accounting and include our net equity interest in investments in power plants on our Consolidated Balance Sheets. At December 31, 2014 and 2013, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
Our risk of loss related to our unconsolidated VIEs is limited to our investment balance. Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries;
therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Balance Sheets. At December 31, 2014 and 2013, equity method investee debt was approximately $342 million and $395 million, respectively, and based on our pro rata share of each of the investments, our share of such debt would be approximately $171 million and $198 million at December 31, 2014 and 2013, respectively.
Our
equity interest in the net income from Greenfield LP and Whitby for the years ended December 31, 2014, 2013 and 2012, is recorded in (income) from unconsolidated investments in power plants. The following table sets forth details of our (income) from unconsolidated investments in power plants and distributions for the years indicated (in millions):
(Income) from Unconsolidated
Investments
in Power Plants
Distributions
2014
2013
2012
2014
2013
2012
Greenfield
LP
$
(10
)
$
(16
)
$
(17
)
$
—
$
18
$
22
Whitby
(15
)
(14
)
(11
)
13
9
7
Total
$
(25
)
$
(30
)
$
(28
)
$
13
$
27
$
29
Inland
Empire Energy Center Put and Call Options — We hold a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) from GE that may be exercised between years 2017 and 2024. GE holds a put option whereby they can require us to purchase the power plant, if certain plant performance criteria are met by 2025. We determined that we are not the primary beneficiary of the Inland Empire power plant, and we do not consolidate it due to the fact that GE directs the most significant activities of the power plant including operations and maintenance.
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Significant
Unconsolidated Subsidiaries — Greenfield LP and Whitby met the criteria of significant unconsolidated subsidiaries for the years ended December 31, 2013 and 2012, based upon the relationship of our equity income from our investment in these subsidiaries, when combined, to our consolidated net income before taxes. Aggregated summarized financial data for our unconsolidated subsidiaries is set forth below
(in millions):
Our
debt agreements contain covenants which could permit lenders to accelerate the repayment of our debt by providing notice, the lapse of time, or both, if certain events of default remain uncured after any applicable grace period. We were in compliance with all of the covenants in our debt agreements at December 31, 2014.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2014, are as follows (in millions):
2015
$
199
2016
205
2017
562
2018
1,730
2019
1,217
Thereafter
7,393
Subtotal
11,306
Less:
Discount
24
Total debt
$
11,282
First Lien Notes
Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
Outstanding
at December 31,
Weighted Average
Effective Interest Rates(3)
2014
2013
2014
2013
2019 First Lien Notes(1)
$
—
$
320
—
%
8.2
%
2020
First Lien Notes(1)
—
875
—
8.2
2021 First Lien Notes(1)
—
1,600
—
7.7
2022
First Lien Notes
745
744
6.3
6.2
2023 First Lien Notes(2)
840
960
8.0
8.0
2024
First Lien Notes
490
490
6.0
5.9
Total First Lien Notes
$
2,075
$
4,989
____________
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(1)
The 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes were repaid during the third quarter of 2014 with the proceeds from the issuance of our Senior Unsecured Notes, together with cash on hand, which are described in further detail below.
(2)
In December 2014, we used cash on hand to redeem 10% of the original aggregate
principal amount of our 2023 First Lien Notes, plus accrued and unpaid interest. On February 3, 2015, we additionally repurchased approximately $150 million of our 2023 First Lien Notes with the proceeds from our 2024 Senior Unsecured Notes, which is described in further detail below.
(3)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Our First Lien Notes are secured equally and ratably with indebtedness incurred under our First Lien Term Loans and Corporate Revolving Facility, subject to certain exceptions and permitted
liens, on substantially all of our and certain of the guarantors’ existing and future assets. Additionally, our First Lien Notes rank equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness, and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee our First Lien Notes.
Subject to certain qualifications and exceptions, our First Lien Notes will, among other things, limit our ability and the ability of the guarantors to:
•
incur or guarantee additional first lien indebtedness;
•
enter
into certain types of commodity hedge agreements that can be secured by first lien collateral;
•
enter into sale and leaseback transactions;
•
create or incur liens; and
•
consolidate, merge or transfer all or substantially all of our assets and the assets of our restricted subsidiaries
on a combined basis.
Senior Unsecured Notes
Our Senior Unsecured Notes are summarized in the table below (in millions, except for interest rates):
Outstanding at December 31,
Weighted Average Effective Interest Rates(1)
2014
2013
2014
2013
2023
Senior Unsecured Notes
$
1,250
$
—
5.6
%
—
%
2025 Senior Unsecured
Notes
1,550
—
5.9
—
Total Senior Unsecured Notes
$
2,800
$
—
____________
(1)
Our
weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
On July 22, 2014, we issued $1.25 billion in aggregate principal amount of 5.375% senior unsecured notes due 2023 and $1.55 billion in aggregate principal amount of 5.75% senior unsecured notes due 2025 in a public offering. The 2023 Senior Unsecured Notes bear interest at 5.375% per annum and the 2025 Senior Unsecured Notes bear interest at 5.75% per annum, in each case payable semi-annually on April 15 and October 15 of each year, beginning on April
15, 2015. The 2023 Senior Unsecured Notes mature on January 15, 2023 and the 2025 Senior Unsecured Notes mature on January 15, 2025. Our Senior Unsecured Notes were issued at par.
Our Senior Unsecured Notes are:
•
general unsecured obligations of Calpine;
•
rank equally in right of payment with all of Calpine’s existing and future senior indebtedness;
•
effectively
subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness;
•
structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and
•
senior in right of payment to any of Calpine’s subordinated indebtedness.
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We
used the net proceeds received from the issuance of our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes, together with cash on hand, to repurchase our outstanding 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes during the third quarter of 2014. We recorded approximately $42 million in deferred financing costs and approximately $340 million in debt extinguishment costs during the third quarter of 2014 related to the repayment of our 2019 First Lien Notes, 2020 First Lien Notes and 2021 First Lien Notes.
In February 2015, we issued $650 million in aggregate principal amount of 5.5% senior unsecured notes due 2024 in a public offering. The 2024 Senior Unsecured Notes bear interest at 5.5%
per annum with interest payable semi-annually on February 1 and August 1 of each year, beginning on August 1, 2015. The 2024 Senior Unsecured Notes were issued at par, mature on February 1, 2024 and contain substantially similar covenant, qualifications, exceptions and limitations as our 2023 Senior Unsecured Notes and 2025 Senior Unsecured Notes. We used the net proceeds received from the issuance of our 2024 Senior Unsecured Notes to replenish cash on hand used for the acquisition of Fore River Energy Center in the fourth quarter of 2014 and to repurchase approximately $150 million of our 2023 First Lien Notes.
First Lien Term Loans
Our First Lien Term Loans are summarized in the table below (in millions, except for interest rates):
Outstanding
at December 31,
Weighted Average
Effective Interest Rates(1)
2014
2013
2014
2013
2018 First Lien Term Loans
$
1,597
$
1,614
4.3
%
4.3
%
2019
First Lien Term Loan
816
824
4.4
4.5
2020 First Lien Term Loan
386
390
4.3
4.3
Total
First Lien Term Loans
$
2,799
$
2,828
____________
(1)
Our
weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
Our First Lien Term Loans provide for senior secured term loan facilities and bear interest, at our option, at either (i) the base rate, equal to the higher of the Federal Funds effective rate plus 0.5% per annum or the Prime Rate (as such terms are defined in the First Lien Term Loans credit agreements), plus an applicable margin of 2.0%, or (ii) LIBOR plus 3.0% per annum subject to a LIBOR floor of 1.0%. An aggregate amount equal to 0.25% of the aggregate principal amount of the First Lien Term Loans will be payable at the end of each quarter with the remaining
balance payable on the maturity date. The First Lien Term Loans are subject to certain qualifications and exceptions, similar to our First Lien Notes. The 2018 First Lien Term Loans have a maturity date of April 1, 2018. The 2019 First Lien Term Loan and 2020 First Lien Term Loan carries substantially the same terms as the 2018 First Lien Term Loans and matures on October 9, 2019 and October 31, 2020, respectively.
Project Financing, Notes Payable and Other
The components of our project financing, notes payable and other are (in millions, except for interest rates):
Outstanding
at
December 31,
Weighted Average
Effective Interest Rates(1)
2014
2013
2014
2013
Russell
City due 2023
$
591
$
593
6.2
%
4.9
%
Steamboat due 2017
407
418
6.9
6.8
OMEC
due 2019
325
335
6.9
6.9
Los Esteros due 2023
275
305
3.1
3.4
Pasadena(2)
122
135
8.9
8.9
Bethpage
Energy Center 3 due 2020-2025(3)
82
88
7.0
7.0
Gilroy note payable due 2014
—
15
—
11.2
Other
8
12
—
—
Total
$
1,810
$
1,901
_____________
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(1)
Our weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount or premium.
(2)
Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
(3)
Represents
a weighted average of first and second lien loans for the weighted average effective interest rates.
Our project financings are collateralized solely by the capital stock or partnership interests, physical assets, contracts and/or cash flows attributable to the entities that own the power plants. The lenders’ recourse under these project financings is limited to such collateral.
CCFC Term Loans
Our CCFC Term Loans are summarized in the table below (in millions, except for interest rates):
Outstanding
at December 31,
Weighted Average
Effective Interest Rates(1)
2014
2013
2014
2013
CCFC Term Loans
$
1,596
$
1,191
3.4
%
3.3
%
____________
(1)
Our
weighted average interest rate calculation includes the amortization of deferred financing costs and debt discount.
On May 3, 2013, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility comprised of (i) a $900 million 7-year term loan and (ii) a $300 million 8.5-year term loan. The CCFC Term Loans bear interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of the Federal Funds Effective Rate plus 0.50% per annum or the Prime Rate (as such terms are defined in the Credit Agreement), plus an applicable margin of (a) 1.25% per
annum with respect to the 7-year term loan and (b) 1.50% per annum with respect to the 8.5-year term loan, or (ii) LIBOR plus (a) 2.25% per annum with respect to the 7-year term loan and (b) 2.50% per annum with respect to the 8.5-year term loan (in each case subject to a LIBOR floor of 0.75%). The term loans were offered to investors at an issue price equal to 99.75% of face value.
An amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loans are payable
at the end of each quarter commencing in September 2013, with the remaining balance payable on the relevant maturity date (May 3, 2020 with respect to the 7-year term loan and January 31, 2022 with respect to the 8.5-year term loan). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loans from LIBOR loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the term loans, in whole or in part, without premium or penalty, upon irrevocable notice to the administrative agent.
In February 2014, we executed an amendment to the credit agreement associated with the CCFC Term Loans, which allowed us to issue $425 million in
incremental CCFC Term Loans to fund a portion of the purchase price paid in connection with the closing of our acquisition of Guadalupe Energy Center on February 26, 2014. Guadalupe Energy Center was purchased by Calpine Guadalupe GP, LLC, a wholly-owned subsidiary of CCFC. The incremental term loans carry substantially the same terms and conditions as the $300 million in aggregate principal amount of CCFC Term Loans issued in June 2013. The incremental term loans were offered to investors at an issue price equal to 98.75% of face value.
The CCFC Term Loans are secured by certain real and personal property of CCFC consisting primarily of seven natural gas-fired power plants. The CCFC Term Loans are not guaranteed by Calpine Corporation and are without recourse to Calpine Corporation or
any of our non-CCFC subsidiaries or assets; however, CCFC generates the majority of its cash flows from an intercompany tolling agreement with Calpine Energy Services, L.P. and has various service agreements in place with other subsidiaries of Calpine Corporation.
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Capital Lease Obligations
The following is a schedule by year of future minimum lease payments under capital leases and a failed sale-leaseback transaction related to our Pasadena Power Plant together with the present value of the
net minimum lease payments as of December 31, 2014 (in millions):
Sale-Leaseback Transactions(1)
Capital Lease
Total
2015
$
25
$
47
$
72
2016
25
41
66
2017
17
39
56
2018
21
38
59
2019
21
20
41
Thereafter
85
151
236
Total
minimum lease payments
194
336
530
Less: Amount representing interest
72
134
206
Present
value of net minimum lease payments
$
122
$
202
$
324
____________
(1)
Amounts
are accounted for as financing transactions under U.S. GAAP and are included in our project financing, notes payable and other amounts above.
The primary types of property leased by us are power plants and related equipment. The leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property. The remaining lease terms range up to 34 years (including lease renewal options). Some of the lease agreements contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project financing agreements. At December 31, 2014 and 2013,
the asset balances for the leased assets totaled approximately $933 million and $862 million with accumulated amortization of $395 million and $343 million, respectively. Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations. See Note 15 for discussion of capital leases guaranteed by Calpine Corporation.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at December 31, 2014 and 2013
(in millions):
2014
2013
Corporate Revolving Facility
$
223
$
242
CDHI
214
218
Various
project financing facilities
207
170
Total
$
644
$
630
On
July 30, 2014, we executed Amendment No. 2 to the Corporate Revolving Facility to increase the capacity by an additional $500 million to $1.5 billion.
The Corporate Revolving Facility represents our primary revolving facility. Borrowings under the Corporate Revolving Facility bear interest, at our option, at either a base rate or LIBOR rate. Base rate borrowings shall be at the base rate, plus an applicable margin ranging from 1.00% to 1.25% as provided in the Corporate Revolving Facility credit agreement. Base rate is defined as the higher of (i) the Federal Funds Effective Rate, as published by the Federal Reserve Bank of New York, plus 0.50%
and (ii) the rate the administrative agent announces from time to time as its prime per annum rate. LIBOR rate borrowings shall be at the British Bankers’ Association Interest Settlement Rates for the interest period as selected by us as a one, two, three, six or, if agreed by all relevant lenders, nine or twelve month interest period, plus an applicable margin ranging from 2.00% to 2.25%. Interest payments are due on the last business day of each calendar quarter for base rate loans and the earlier of (i) the last day of the interest period selected or (ii) each day that is three months (or a whole
multiple thereof) after the first day for the interest period selected for LIBOR rate loans. Letter of credit fees for issuances of letters of credit include fronting fees equal to that percentage per annum as may be separately agreed upon between us and the issuing lenders and a participation fee for the lenders equal to the applicable interest margin for LIBOR rate borrowings. Drawings under letters of credit shall be repaid within two
124
business days or be converted into borrowings as provided in the Corporate Revolving Facility credit agreement. We incur an unused commitment fee ranging from 0.25% to 0.50%
on the unused amount of commitments under the Corporate Revolving Facility.
The Corporate Revolving Facility does not contain any requirements for mandatory prepayments, except in the case of certain designated asset sales in excess of $3.0 billion in the aggregate. However, we may voluntarily repay, in whole or in part, the Corporate Revolving Facility, together with any accrued but unpaid interest, with prior notice and without premium or penalty. Amounts repaid may be reborrowed, and we may also voluntarily reduce the commitments under the Corporate Revolving Facility without premium or penalty. The Corporate Revolving Facility matures on June 27, 2018.
The Corporate Revolving Facility is guaranteed and secured by each of our current domestic subsidiaries
that was a guarantor under the First Lien Credit Facility and will also be additionally guaranteed by our future domestic subsidiaries that are required to provide such a guarantee in accordance with the terms of the Corporate Revolving Facility. The Corporate Revolving Facility ranks equally in right of payment with all of our and the guarantors’ other existing and future senior indebtedness and will be effectively subordinated in right of payment to all existing and future liabilities of our subsidiaries that do not guarantee the Corporate Revolving Facility. The Corporate Revolving Facility also requires compliance with financial covenants that include a minimum cash interest coverage ratio and a maximum net leverage ratio.
CDHI
We
have a $300 million letter of credit facility related to CDHI. During the first quarter of 2014, we amended our CDHI letter of credit facility to lower our fees and extend the maturity to January 2, 2018.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount. We did not elect to apply the alternative U.S. GAAP provisions of the fair value option for recording financial assets and financial liabilities. The following table details the fair values and carrying values of our debt instruments at December 31, 2014 and 2013 (in millions):
2014
2013
Fair Value
Carrying
Value
Fair Value
Carrying
Value
First
Lien Notes
$
2,247
$
2,075
$
5,317
$
4,989
Senior
Unsecured Notes
2,832
2,800
—
—
First Lien Term Loans
2,769
2,799
2,845
2,828
Project
financing, notes payable and other(1)
1,734
1,688
1,772
1,766
CCFC Term Loans
1,540
1,596
1,179
1,191
Total
$
11,122
$
10,958
$
11,113
$
10,774
____________
(1)
Excludes
a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
We measure the fair value of our First Lien Notes, Senior Unsecured Notes, First Lien Term Loans and CCFC Term Loans using market information, including quoted market prices or dealer quotes for the identical liability when traded as an asset (categorized as level 2). We measure the fair value of our project financing, notes payable and other debt instruments using discounted cash flow analyses based on our current borrowing rates for similar types of borrowing arrangements (categorized as level 3). We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
7.
Assets
and Liabilities with Recurring Fair Value Measurements
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. Our cash equivalents are classified within level 1 of the fair value hierarchy.
Margin Deposits and Margin Deposits Posted with Us by Our Counterparties — Margin deposits and margin deposits posted with us by our counterparties represent cash collateral paid between our counterparties and us to support our commodity contracts.
Our margin deposits and margin deposits posted with us by our counterparties are generally cash and cash equivalents and are classified within level 1 of the fair value hierarchy.
125
Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate swaps. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the
future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs.
We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and the impact of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate swaps and OTC power and natural gas forwards for which market-based pricing inputs are observable. Generally,
we obtain our level 2 pricing inputs from market sources such as the Intercontinental Exchange and Bloomberg. To the extent we obtain prices from brokers in the marketplace, we have procedures in place to ensure that prices represent executable prices for market participants. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are
unobservable, as well as other complex and structured transactions. Complex or structured transactions are tailored to our or our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods. OTC options are valued using industry-standard models, including the Black-Scholes option-pricing model. At each balance sheet date, we perform an analysis of all instruments subject to fair value measurement and include in level 3 all of those whose fair value is based on significant unobservable inputs.
126
Financial
assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2014 and 2013, by level within the fair value hierarchy:
Assets and Liabilities with Recurring Fair Value Measures
as of December 31, 2014
Level 1
Level 2
Level 3
Total
(in millions)
Assets:
Cash
equivalents(1)
$
896
$
—
$
—
$
896
Margin
deposits
96
—
—
96
Commodity instruments:
Commodity
exchange traded futures and swaps contracts
As
of December 31, 2014 and 2013, we had cash equivalents of $679 million and $889 million included in cash and cash equivalents and $217 million and $245 million included in restricted cash, respectively.
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(2)
Includes OTC
swaps and options.
At December 31, 2014 and 2013, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices; however, given the nature of our net derivative position, we do not believe that a significant change in market commodity prices
would have a material impact on our level 3 net fair value. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2014 and 2013:
Quantitative
Information about Level 3 Fair Value Measurements
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, 2014, 2013 and 2012 (in millions):
2014
2013
2012
Balance,
beginning of period
$
14
$
16
$
17
Realized and mark-to-market gains:
Included
in net income:
Included in operating revenues(1)
70
5
8
Included
in fuel and purchased energy expense(2)
5
—
—
Purchases, issuances and settlements:
Purchases
6
6
3
Issuances
—
(2
)
(1
)
Settlements
(10
)
(11
)
(11
)
Transfers
in and/or out of level 3(3):
Transfers into level 3(4)
—
—
—
Transfers
out of level 3(5)
—
—
—
Balance, end of period
$
85
$
14
$
16
Change
in unrealized gains relating to instruments still held at end of period
$
75
$
5
$
8
___________
(1)
For
power contracts and other power-related products, included on our Consolidated Statements of Operations.
(2)
For natural gas contracts, swaps and options, included on our Consolidated Statements of Operations.
128
(3)
We
transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 during the years ended December 31, 2014, 2013 and 2012.
(4)
There were no transfers out of level 2 into level 3 for the years ended December 31, 2014, 2013 and 2012.
(5)
There
were no transfers out of level 3 for the years ended December 31, 2014, 2013 and 2012.
8.
Derivative Instruments
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, environmental products and other energy
commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities, as authorized by our Board of Directors and monitored by our Chief Risk Officer
and Risk Management Committee of senior management, related to our commodity derivative portfolio which exposes us to certain market risks that are segregated from the market risks of our underlying asset portfolio. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading gains and losses were not material for the years ended December 31, 2014, 2013 and 2012.
Interest Rate Swaps — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate swaps to adjust the mix between fixed and floating rate debt to hedge our interest rate risk
for potential adverse changes in interest rates. As of December 31, 2014, the maximum length of time over which we were hedging using interest rate derivative instruments designated as cash flow hedges was 9 years.
As of December 31, 2014 and 2013, the net forward notional buy (sell) position of our outstanding commodity and interest rate swap contracts that did not qualify or were not designated under the normal purchase normal sale exemption were as follows (in millions):
Derivative
Instruments
Notional Amounts
2014
2013
Power (MWh)
(62
)
(29
)
Natural
gas (MMBtu)
291
448
Interest rate swaps
$
1,431
$
1,527
Certain
of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. Currently, we do not believe that it is probable that any additional collateral posted as a result of a one credit notch downgrade from its current level would be material. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of December 31, 2014, was $19 million for which we have posted collateral of $11 million by posting margin deposits
or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of $5 million would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated Statements of Operations
until the period of delivery. Revenues and expenses derived from instruments that qualified for hedge accounting or represent an economic hedge are recorded in the same financial statement line item as the item being hedged. Hedge accounting requires us to formally document, designate and assess the effectiveness of transactions that receive hedge accounting.
129
We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities or investing activities (in the case of settlements for our interest rate swaps formerly hedging our First Lien Credit Facility term loans) on our Consolidated Statements of Cash Flows unless they contain an other-than-insignificant financing element in which case their cash flows
are classified within financing activities.
Cash Flow Hedges — We report the effective portion of the mark-to-market 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 interest rate hedging instruments are recognized currently in earnings as a component of interest expense (for interest rate swaps except as discussed below). If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated
gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction impacts earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate and environmental product transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues
(for power and Heat Rate swaps and options) and fuel and purchased energy expense (for natural gas contracts, environmental product contracts, swaps and options). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense (for interest rate swaps except as discussed below).
Interest Rate Swaps Formerly Hedging our First Lien Credit Facility — On March 26, 2012, we terminated the legacy interest rate swaps formerly hedging our First Lien Credit Facility and recorded the fair value of the swaps totaling approximately $156 million. Approximately
$14 million of the settlement amount was recorded as a component of loss on interest rate derivatives on our Consolidated Statement of Operations for the year ended December 31, 2012, and approximately $142 million reflected the realization of losses recorded in prior periods.
Derivatives Included on Our Consolidated Balance Sheet
The following tables present the fair values of our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2014 and 2013 (in millions):
Derivatives
designated as cash flow hedging instruments:
Interest rate swaps
$
4
$
112
$
9
$
115
Total
derivatives designated as cash flow hedging instruments
$
4
$
112
$
9
$
115
Derivatives
not designated as hedging instruments:
Commodity instruments
$
2,493
$
2,112
$
541
$
565
Interest
rate swaps
—
2
—
14
Total derivatives not designated as hedging instruments
$
2,493
$
2,114
$
541
$
579
Total
derivatives
$
2,497
$
2,226
$
550
$
694
We
elected not to offset fair value amounts recognized as derivative instruments on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements or other contractual netting provisions negotiated with the counterparty. Our netting arrangements include a right to set off or net together purchases and sales of similar products in the margining or settlement process. In some instances, we have also negotiated cross commodity netting rights which allow for the net presentation of activity with a given counterparty regardless of product purchased or sold. We also post cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty. The tables below set forth our net exposure to derivative instruments after offsetting amounts subject to a master netting arrangement with the same counterparty at December 31,
2014 and 2013 (in millions):
Negative
balances represent margin deposits posted with us by our counterparties related to our derivative activities that are subject to a master netting arrangement. Positive balances reflect margin deposits and natural gas and power prepayments posted by us with our counterparties related to our derivative activities that are subject to a master netting arrangement. See Note 9 for a further discussion of our collateral.
Derivatives Included on Our Consolidated Statements of Operations
Changes in the fair values of our derivative instruments (both assets and liabilities) are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Statements of Operations as a component of mark-to-market activity
within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012 (in millions):
132
2014
2013
2012
Realized
gain (loss)(1)
Commodity derivative instruments
$
110
$
86
$
387
Interest
rate swaps
—
—
(157
)
Total realized gain (loss)
$
110
$
86
$
230
Mark-to-market
gain (loss)(2)
Commodity derivative instruments
$
342
$
(14
)
$
(82
)
Interest
rate swaps
11
2
154
Total mark-to-market gain (loss)
$
353
$
(12
)
$
72
Total
activity, net
$
463
$
74
$
302
___________
(1)
Does
not include the realized value associated with derivative instruments that settle through physical delivery.
(2)
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes de-designation of interest rate swap cash flow hedges and related reclassification from AOCI into earnings, hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
2014
2013
2012
Realized
and mark-to-market gain (loss)
Derivatives contracts included in operating revenues
$
384
$
(119
)
$
187
Derivatives
contracts included in fuel and purchased energy expense
68
191
118
Interest rate swaps included in interest expense
11
2
11
Loss
on interest rate derivatives
—
—
(14
)
Total activity, net
$
463
$
74
$
302
Derivatives
Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the years ended December 31, 2014, 2013 and 2012 (in millions):
Gains (Loss) Recognized
in
OCI (Effective Portion)(3)
Gain (Loss) Reclassified from
AOCI into Income (Effective
Portion)(4)
2014
2013
2012
2014
2013
2012
Affected
Line Item on the Consolidated Statements of Operations
Commodity derivative instruments(1):
Power
derivative instruments
$
—
$
—
$
(97
)
$
—
$
—
$
118
Commodity
revenue
Natural gas derivative instruments
—
—
59
—
—
(66
)
Commodity
expense
Interest rate swaps(2)
(2
)
86
(43
)
(46
)
(5)
(51
)
(5)
(32
)
Interest
expense
Total(3)
$
(2
)
$
86
$
(81
)
$
(46
)
$
(51
)
$
20
____________
(1)
There
were no commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2014 and 2013. We recorded a gain on hedge ineffectiveness of $2 million related to our commodity derivative instruments designated as cash flow hedges during the year ended December 31, 2012.
(2)
We did not record any gain (loss) on hedge ineffectiveness related to our interest rate swaps designated as cash flow hedges during the years ended December 31,
2014, 2013 and 2012.
(3)
We recorded income tax expense of nil and $3 million for the years ended December 31, 2014 and 2013, respectively, and an income tax benefit of $11 million for the year ended December 31, 2012, in AOCI related to our cash flow hedging activities.
133
(4)
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $149 million, $148 million and $222 million at December 31, 2014, 2013 and 2012, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $12 million, $11 million
and $20 million at December 31, 2014, 2013 and 2012, respectively.
(5)
Includes a loss of $10 million and $12 million that was reclassified from AOCI to interest expense for the years ended December 31, 2014 and 2013, respectively, where the hedged transactions are no longer expected
to occur.
We estimate that pre-tax net losses of $46 million would be reclassified from AOCI into interest expense during the next 12 months as the hedged transactions settle; however, the actual amounts that will be reclassified will likely vary based on changes in interest rates. Therefore, we are unable to predict what the actual reclassification from AOCI into earnings (positive or negative) will be for the next 12 months.
9.
Use of Collateral
We use margin deposits, prepayments and letters of credit as credit support with and
from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate swap agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of December 31,
2014 and 2013 (in millions):
2014
2013
Margin deposits(1)
$
96
$
261
Natural
gas and power prepayments
22
28
Total margin deposits and natural gas and power prepayments with our counterparties(2)
$
118
$
289
Letters
of credit issued
$
450
$
488
First priority liens under power and natural gas agreements
48
31
First
priority liens under interest rate swap agreements
116
132
Total letters of credit and first priority liens with our counterparties
$
614
$
651
Margin
deposits posted with us by our counterparties(1)(3)
$
47
$
5
Letters of credit posted with us by our counterparties
61
2
Total
margin deposits and letters of credit posted with us by our counterparties
$
108
$
7
___________
(1)
Balances are subject to master netting arrangements and presented on a gross basis on our Consolidated Balance Sheets. We do not offset fair
value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation, and we do not offset amounts recognized for the right to reclaim, or the obligation to return, cash collateral with corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
(2)
At December 31, 2014 and 2013, $109 million and $272
million, respectively, were included in margin deposits and other prepaid expense and $9 million and $17 million, respectively, were included in other assets on our Consolidated Balance Sheets.
(3)
Included in other current liabilities on our Consolidated Balance Sheets.
Future collateral requirements for cash, first priority liens and letters of credit may increase or decrease based on the extent of our involvement in hedging and optimization contracts, movements in commodity
prices, and also based on our credit ratings and general perception of creditworthiness in our market.
134
10.
Income Taxes
Income Tax Expense
The jurisdictional components of income from continuing operations before income tax expense, attributable to Calpine, for the years ended December 31, 2014, 2013
and 2012, are as follows (in millions):
2014
2013
2012
U.S.
$
942
$
(13
)
$
194
International
26
29
24
Total
$
968
$
16
$
218
The
components of income tax expense from continuing operations for the years ended December 31, 2014, 2013 and 2012, consisted of the following (in millions):
2014
2013
2012
Current:
Federal
$
(1
)
$
(2
)
$
(12
)
State
19
(9
)
16
Foreign
(1
)
(1
)
14
Total
current
17
(12
)
18
Deferred:
Federal
—
1
11
State
(1
)
4
(5
)
Foreign
6
9
(5
)
Total
deferred
5
14
1
Total income tax expense
$
22
$
2
$
19
For
the years ended December 31, 2014, 2013 and 2012, 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, 2014, 2013 and 2012, is as follows:
2014
2013
2012
Federal
statutory tax expense (benefit) rate
35.0
%
35.0
%
35.0
%
State tax expense (benefit), net of federal benefit
1.9
(69.8
)
3.2
Depletion
in excess of basis
(0.3
)
(14.7
)
(0.2
)
Federal refunds
—
—
(4.7
)
Valuation
allowances against future tax benefits
(35.8
)
89.8
(30.3
)
Valuation allowance related to foreign taxes
—
(19.8
)
(8.2
)
Distributions
from foreign affiliates and foreign taxes
1.2
(10.8
)
3.7
Intraperiod allocation
—
4.5
4.6
Change
in unrecognized tax benefits
(0.4
)
(30.1
)
5.1
Disallowed compensation
0.1
11.7
0.4
Stock-based
compensation
0.1
8.6
0.2
Lobbying contributions
0.1
3.3
0.3
Other
differences
0.4
4.8
(0.4
)
Effective income tax expense rate
2.3
%
12.5
%
8.7
%
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Deferred Tax Assets and Liabilities
The components of deferred income taxes as of December 31, 2014 and 2013, are as follows (in millions):
2014
2013
Deferred
tax assets:
NOL and credit carryforwards
$
2,873
$
3,120
Taxes related to risk management activities and derivatives
61
60
Reorganization
items and impairments
216
262
Foreign capital losses
16
18
Other differences
—
104
Deferred
tax assets before valuation allowance
3,166
3,564
Valuation allowance
(1,836
)
(2,246
)
Total deferred tax assets
1,330
1,318
Deferred
tax liabilities:
Property, plant and equipment
(1,305
)
(1,310
)
Other differences
(21
)
—
Total
deferred tax liabilities
(1,326
)
(1,310
)
Net deferred tax asset
4
8
Less: Current portion deferred tax asset (liability)
(14
)
12
Less:
Non-current deferred tax asset
19
7
Deferred income tax liability, non-current
$
(1
)
$
(11
)
Intraperiod
Tax Allocation — In accordance with U.S. GAAP, intraperiod tax allocation provisions require allocation of a tax expense (benefit) to continuing operations due to current OCI gains (losses) with a partial offsetting amount recognized in OCI. The following table details the effects of our intraperiod tax allocations for the years ended December 31, 2014, 2013 and 2012 (in millions).
2014
2013
2012
Intraperiod
tax allocation expense included in continuing operations
$
—
$
1
$
9
Intraperiod tax allocation benefit included in OCI
$
—
$
(1
)
$
(9
)
NOL
Carryforwards — As of December 31, 2014, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $6.9 billion, which expire between 2023 and 2033, and NOL carryforwards in 22 states and the District of Columbia totaling approximately $4.0 billion, which expire between 2015 and 2034, substantially all of which are offset with a full valuation allowance. We also have approximately $800 million in foreign NOLs, which expire between 2026 and 2034,
substantially all of which are offset with a full valuation allowance. The NOL carryforwards available are subject to limitations on their annual usage. Under federal and applicable state income tax laws, a corporation is generally permitted to deduct from taxable income in any year NOLs carried forward from prior years subject to certain time limitations as prescribed by the taxing authorities.
Deferred tax assets relating to tax benefits of employee stock-based compensation do not reflect stock options exercised and restricted stock that vested between 2011 and 2014. Some stock option exercises and restricted stock vestings result in tax deductions in excess of previously recorded deferred tax benefits based on the equity award value at the grant date. Although these additional tax benefits or “windfalls” are reflected in NOL carryforwards pursuant to accounting for stock-based compensation under U.S. GAAP, the additional
tax benefit associated with the windfall is not recognized until the deduction reduces taxes payable, which will not occur for Calpine until a future period. Accordingly, since the tax benefit does not reduce our current taxes payable for the years ended December 31, 2014 and 2013 due to NOL carryforwards, these windfall tax benefits are not reflected in our NOLs in deferred tax assets at December 31, 2014 and 2013. The cumulative windfall balance included in federal and state NOL carryforwards, but not reflected in gross deferred tax assets as of December 31,
2014 and 2013 were $37 million and $25 million for federal, respectively, and $21 million and $16 million for state, respectively.
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could
136
be
subject to IRS examination regardless of when the NOLs occurred. Any adjustment of state or federal returns would likely result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs.
Canadian Tax Audits — In January 2013, we received an adjusted reassessment on one of two transfer pricing issues that we were disputing with the Canadian Revenue Authority (“CRA”). We proposed a settlement of the adjusted reassessment with the CRA and the CRA accepted our proposal. The adjustment to our transfer pricing increased taxable income and was offset by existing NOLs to which a valuation allowance had been applied and did not have a material impact on our Consolidated Financial Statements.
On January 28, 2014, we received a letter from the CRA which
informed us that they did not agree with our transfer price on the second issue and proposed an increase to taxable income for tax years 2006 and 2007. On June 6, 2014, we proposed a settlement, and on June 14, 2014, the CRA accepted our proposal. The adjustment to our transfer price increased taxable income for one of our Canadian affiliates and was offset by existing NOLs to which a valuation allowance had been applied. As part of the settlement, we agreed to pay some interest and withholding taxes which did not have a material impact on our Consolidated Financial Statements.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed
to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
As of December 31, 2014, we have provided a valuation allowance of approximately $1.8 billion on certain federal, state and foreign tax jurisdiction deferred tax assets to reduce the amount of these assets to the extent necessary to result in an amount that is more likely than not to be realized. The net change in our valuation allowance was
a decrease of $410 million for the year ended December 31, 2014 and $114 million for the year ended December 31, 2012 and an increase of $24 million for the year ended December 31, 2013, respectively; all primarily related to income generated in these periods.
As a result of a recent favorable response to an IRS letter ruling request, during the first quarter of 2014, we made an election which increased the tax basis of certain assets resulting in an increase to our net state deferred tax assets by approximately
$18 million with a corresponding decrease in our state income tax expense.
Tangible Property Regulations — On September 13, 2013, the United States Treasury Department and the IRS issued final regulations providing comprehensive guidance on the tax treatment of costs incurred to acquire, repair or improve tangible property. The final regulations are generally effective for taxable years beginning on or after January 1, 2014. On January 24, 2014, the IRS issued procedural guidance pursuant to which taxpayers will be granted automatic consent to change their tax accounting methods to comply with the final regulations. These regulations did not have a material impact on our financial
condition, results of operations or cash flows.
Unrecognized Tax Benefits
At December 31, 2014, we had unrecognized tax benefits of $56 million. If recognized, $13 million of our unrecognized tax benefits could impact the annual effective tax rate and $43 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no impact to our effective tax rate. We had accrued interest and penalties of $11 million and $13 million for income tax matters at December 31,
2014 and 2013, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Statements of Operations and recorded $(2) million, $(11) million and $4 million for the years ended December 31, 2014, 2013 and 2012, respectively.
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2014,
2013 and 2012, is as follows (in millions):
2014
2013
2012
Balance,
beginning of period
$
(68
)
$
(92
)
$
(74
)
Increases related to prior year tax positions
(4
)
(7
)
(19
)
Decreases
related to prior year tax positions
8
8
1
Decreases related to settlements
8
10
—
Decrease
related to lapse of statute of limitations
—
13
—
Balance, end of period
$
(56
)
$
(68
)
$
(92
)
137
U.S. Federal Income Tax Refund
In 2004, we deducted a portion of our foreign dividends as allowed by the IRC when we filed our federal income tax return. Upon further review and analysis, we determined our foreign dividends should have been offset against our current 2004 operating loss. In 2009, we filed an amended federal income tax return that reflected this change and would result in a refund of approximately $10 million. This amended federal return has been under audit by the IRS since it was filed. In October 2012, the IRS approved our amended tax return, and we received a refund of approximately $13 million which included approximately
$3 million in accrued interest. The benefit of this refund is reflected in our Consolidated Financial Statements in the fourth quarter of 2012.
11.
Earnings per Share
We include restricted stock units for which no future service is required as a condition to the delivery of the underlying common stock in our calculation of weighted average shares outstanding. Reconciliations of the amounts used in the basic and diluted earnings per common share computations for the years ended December 31, 2014,
2013 and 2012, are as follows (shares in thousands):
2014
2013
2012
Diluted weighted average shares calculation:
Weighted
average shares outstanding (basic)
404,837
440,666
467,752
Share-based awards
4,523
4,107
3,591
Weighted
average shares outstanding (diluted)
409,360
444,773
471,343
We excluded the following items from diluted earnings per common share for the years ended December 31, 2014, 2013 and 2012, because
they were anti-dilutive (shares in thousands):
2014
2013
2012
Share-based awards
2,859
5,062
10,302
12.
Stock-Based
Compensation
Calpine Equity Incentive Plans
The Calpine Equity Incentive Plans provide for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. The equity awards may include incentive or non-qualified stock options, restricted stock, restricted stock units, stock appreciation rights, performance compensation awards and other share-based awards. The equity awards granted under the Calpine Equity Incentive Plans include both graded and cliff vesting awards which vest over periods between one and five years, contain contractual terms between approximately five and ten years and are subject to forfeiture provisions
under certain circumstances, including termination of employment prior to vesting. At December 31, 2014, there were 567,000 and 40,533,000 shares of our common stock authorized for issuance to participants under the Director Plan and the Equity Plan, respectively. At December 31, 2014, 186,816 shares and 13,077,526 shares remain available for future issuance under the Director Plan and the Equity Plan, respectively.
Equity Classified Share-Based Awards
We use the Black-Scholes option-pricing model or the Monte
Carlo simulation model, as appropriate, to estimate the fair value of our employee stock options on the grant date, which takes into account the exercise price and expected term of the stock option, the current price of the underlying stock and its expected volatility, expected dividends on the stock and the risk-free interest rate for the expected term of the stock option as of the grant date. For our restricted stock and restricted stock units, we use our closing stock price on the date of grant, or the last trading day preceding the grant date for restricted stock granted on non-trading days, as the fair value for measuring compensation expense. Stock-based compensation expense is recognized over the period in which the related employee services are rendered. The service period is generally presumed to begin on the grant date and end when the equity award is fully vested. We use the graded vesting attribution method to recognize fair value of the equity award over
the service period. For example, the graded vesting attribution method views one three-year restricted stock grant with annual graded vesting as three separate sub-grants, each representing 33 1/3% of the total number of shares of restricted stock 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 restricted stock grant with cliff vesting is viewed as one grant vesting over three years.
138
Stock-based
compensation expense recognized for our equity classified share-based awards was $31 million, $34 million and $25 million for the years ended December 31, 2014, 2013 and 2012, respectively. We did not record any significant tax benefits related to stock-based compensation expense in any period as we are not benefiting from a significant portion of our deferred tax assets, including deductions related to stock-based compensation expense. In addition, we did not capitalize any stock-based compensation expense as part of the cost of an asset for the years ended December 31, 2014,
2013 and 2012. At December 31, 2014, there was unrecognized compensation cost of $26 million related to restricted stock which is expected to be recognized over a weighted average period of 1.1 years. We issue new shares from our share reserves set aside for the Calpine Equity Incentive Plans and employment inducement options when stock options are exercised and for other share-based awards.
A summary of all of our non-qualified stock option activity for the Calpine Equity Incentive Plans for the year ended December 31, 2014, is as follows:
The total intrinsic value of our employee stock options exercised was $21
million, $22 million and $1 million for the years ended December 31, 2014, 2013 and 2012, respectively. The total cash proceeds received from our employee stock options exercised was $20 million, $20 million and $5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
There
were no stock options granted during the year ended December 31, 2014. The fair value of options granted during the years ended December 31, 2013 and 2012, was determined on the grant date using the Black-Scholes option-pricing model. Certain assumptions were used in order to estimate fair value for options as noted in the following table.
2013
2012
Expected
term (in years)(1)
6.5
6.5
Risk-free interest rate(2)
1.4
%
1.2 – 1.6
%
Expected
volatility(3)
25.6
%
27.0 – 30.5
%
Dividend yield(4)
—
—
Weighted
average grant-date fair value (per option)
$
5.31
$
5.18
___________
(1)
Expected term calculated using the simplified method prescribed by the SEC due to the lack of sufficient
historical exercise data to provide a reasonable basis to estimate the expected term.
(2)
Zero Coupon U.S. Treasury rate or equivalent based on expected term.
(3)
Volatility calculated using the implied volatility of our exchange traded stock options.
(4)
We have never paid cash dividends on
our common stock, and we do not anticipate any cash dividend payments on our common stock in the near future.
139
A summary of our restricted stock and restricted stock unit activity for the Calpine Equity Incentive Plans for the year ended December 31, 2014, is as follows:
The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2014, 2013 and 2012, was approximately $35 million, $25
million and $20 million, respectively.
Liability Classified Share-Based Awards
During the first quarter of 2014, our Board of Directors approved the award of performance share units to certain senior management employees. These performance share units will be settled in cash with payouts based on the relative performance of Calpine’s TSR over the three-year performance period of January 1, 2014 through December 31, 2016 compared with the TSR performance of the S&P 500 companies over the same period. The performance share units vest on the last day of the performance period and will be settled in cash; thus, these awards are liability classified and are measured at fair value using a Monte Carlo simulation model
at each reporting date until settlement. Stock-based compensation expense recognized related to our liability classified share-based awards was $5 million and $2 million for the years ended December 31, 2014 and 2013, respectively.
A summary of our performance share unit activity for the year ended December 31, 2014, is as follows:
In accordance with the applicable performance share unit agreements, performance share units granted to employees who meet the retirement eligibility requirements stipulated in the Equity Plan are fully
vested upon the later of the date on which the employee becomes eligible to retire or one-year anniversary of the grant date.
13.
Defined Contribution and Defined Benefit Plans
We maintain two defined contribution savings plans that are intended to be tax exempt under Sections 401(a) and 501(a) of the IRC. Our non-union plan generally covers employees who are not covered by a collective bargaining agreement, and our union plan covers employees who are covered by a collective bargaining agreement. We recorded expenses for these plans of approximately $12 million, $11
million and $12 million for the years ended December 31, 2014, 2013 and 2012, respectively. Employer matching contributions are 100% of the first 5% of compensation a participant defers for the non-union plan. The employee deferral limit is 75% of eligible compensation under both plans.
We also maintain a defined benefit pension plan whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. As of December 31,
2014 and 2013, our pension assets, liabilities and related costs were not material to us. As of December 31, 2014 and 2013, there were approximately $15 million and $14 million in plan assets and approximately $24 million and $20 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2014 and 2013,
was approximately $9 million and $6 million, respectively. For the years ended December 31, 2014, 2013 and 2012, we recognized net periodic benefit costs of approximately $1 million, $2 million and $1 million, respectively. Our net periodic benefit cost is included in plant operating
140
expense on our Consolidated Statements of Operations. As of December 31,
2014 and 2013, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $5 million and $1 million, respectively.
In making our estimates of our pension obligation and related costs, we utilize discount rates, rates of compensation increases and rates of return on our assets that we believe are reasonable. Due to relatively small size of our pension liability (which is not considered material), significant changes in these assumptions would not have a material effect on our pension liability. During 2014 and 2013, we made contributions of approximately $2
million and $1 million, respectively, and estimated contributions to the pension plan are expected to be approximately $1 million in 2015. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $1 million in each year.
14.
Capital Structure
Common Stock
Our authorized common stock consists of 1.4 billion
shares of Calpine Corporation common stock. Common stock issued as of December 31, 2014 and 2013, was 502,287,022 shares and 497,841,056 shares, respectively, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2014 and 2013, was 381,921,264 shares and 429,038,988 shares, respectively. The table below summarizes our common stock
activity for the years ended December 31, 2014, 2013 and 2012.
As of December 31, 2014 and 2013, we had treasury stock of 120,365,758 shares and 68,802,068 shares, respectively, with a cost of $2.3 billion and $1.2 billion, respectively. During 2014, we repurchased a total of 36.5 million shares of our outstanding common stock for approximately $789 million at an average price of $21.62 per share, excluding the shareholder transaction described below. In 2015, through the
filing of this Report, we have repurchased a total of 5.8 million shares of our outstanding common stock for approximately $125 million at an average price of $21.68 per share. Our treasury stock also consists of our common stock withheld to satisfy federal, state and local income tax withholding requirements for vested employee restricted stock awards and net share employee stock options exercises under the Equity Plan. All treasury stock is held at cost.
Shareholder Transaction
On July 8, 2014, we entered into a share repurchase agreement, at the prevailing market price, with a shareholder that beneficially owned slightly less than 10% of our outstanding
common stock to purchase 13,213,372 shares of our common stock for the aggregate purchase price of $311,464,283 in a private transaction. We used cash on hand to fund the transaction which settled on July 10, 2014, and the repurchased shares have been returned to treasury stock.
15.
Commitments and Contingencies
Long-Term Service Agreements
As of December 31, 2014,
the total estimated commitments for LTSAs associated with turbines were approximately $189 million. These commitments are payable over the terms of the respective agreements, which range from 1 to 11 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution and are subject to an annual inflationary adjustment. Certain of these agreements have terms that allow us to cancel the contracts for a fee. If we cancel such contracts, the estimated commitments remaining for LTSAs would be reduced.
141
Power Plant, Land and Other Operating Leases
We have entered into certain long-term operating leases for power plants, extending through 2020, which include renewal options or purchase options at fair value and contain customary restrictions on dividends up to Calpine Corporation, additional debt and further encumbrances similar to those typically found in project finance agreements. Payments on our operating leases, which may contain escalation clauses or step rent provisions, are recognized on a straight-line basis. Certain capital improvements associated with leased power plants may be deemed to be leasehold improvements and are amortized over the shorter of the term of the lease or the economic life of the capital improvement. We have also entered
into various land and other operating leases for ground facilities and operations, which extend through 2069. Future minimum rent payments under these lease agreements, including renewal options and rent escalation clauses, are as follows (in millions):
Initial
Year
2015
2016
2017
2018
2019
Thereafter
Total
Land
and other operating leases
various
$
15
$
16
$
15
$
15
$
15
$
201
$
277
Power
plant operating leases:
Greenleaf
1998
$
4
$
—
$
—
$
—
$
—
$
—
$
4
KIAC
2000
23
22
22
22
30
—
119
Total
power plant leases
$
27
$
22
$
22
$
22
$
30
$
—
$
123
Total
leases
$
42
$
38
$
37
$
37
$
45
$
201
$
400
During
the years ended December 31, 2014, 2013 and 2012, rent expense for power plant, land and other operating leases amounted to $46 million, $47 million and $51 million, respectively.
Production Royalties and Leases
We are obligated under numerous geothermal leases and right-of-way, easement and surface agreements. The geothermal leases generally provide for royalties based on production revenue with reductions for property taxes paid. The right-of-way, easement and surface agreements are based on flat rates or adjusted based on consumer price index changes
and are not material. Under the terms of most geothermal leases, the royalties accrue as a percentage of power revenues. Certain properties also have net profits and overriding royalty interests that are in addition to the land base lease royalties. Some lease agreements contain clauses providing for minimum lease payments to lessors if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2014, 2013 and 2012, were $28 million, $27 million and $22 million, respectively.
Office Leases
We
lease our corporate and regional offices under noncancelable operating leases extending through 2020. Future minimum lease payments under these leases are as follows (in millions):
2015
$
11
2016
10
2017
9
2018
9
2019
8
Thereafter
8
Total
$
55
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, 2014, 2013 and 2012, rent expense for noncancelable operating leases was $11 million, $12 million and $12 million, respectively.
142
Natural Gas Purchases
We enter into natural gas purchase contracts
of various terms with third parties to supply natural gas to our natural gas-fired power plants. The majority of our purchases are made in the spot market or under index-priced contracts. These contracts are accounted for as executory contracts and therefore not recognized as liabilities on our Consolidated Balance Sheet. At December 31, 2014, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
2015
$
390
2016
297
2017
193
2018
152
2019
109
Thereafter
622
Total
$
1,763
Guarantees
and Indemnifications
As part of our normal business operations, we enter into various agreements providing, or otherwise arranging, financial or performance assurance to third parties on behalf of our subsidiaries in the ordinary course of such subsidiaries’ respective business. Such arrangements include guarantees, standby letters of credit and surety bonds for power and natural gas purchase and sale arrangements and contracts associated with the development, construction, operation and maintenance of our fleet of power plants. These arrangements are entered into primarily to support or enhance the creditworthiness otherwise attributed to a subsidiary on
a stand-alone basis, thereby facilitating the extension of sufficient credit to accomplish the subsidiaries’ intended commercial purposes.
At December 31, 2014, 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
2015
2016
2017
2018
2019
Thereafter
Total
Guarantee
of subsidiary debt(1)
$
37
$
36
$
26
$
31
$
30
$
148
$
308
Standby
letters of credit(2)(3)(5)
572
14
20
—
—
38
644
Surety
bonds(4)(5)(6)
—
—
—
—
—
4
4
Guarantee
of subsidiary operating lease payments(5)
4
—
—
—
—
—
4
Total
$
613
$
50
$
46
$
31
$
30
$
190
$
960
____________
(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 6.
(3)
Letters of credit are renewed annually and as such all amounts are reflected in the year of letter of credit expiration. The related commercial obligations extend for multiple years, therefore, renewal of the letter of credit will likely follow the term of the associated
commercial obligation.
(4)
The majority of surety bonds do not have expiration or cancellation dates.
(5)
These are contingent off balance sheet obligations.
(6)
As of December 31, 2014, $2
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 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
143
third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to ten days. To the extent liabilities are incurred as a result of activities covered by letters of credit or the surety bonds, such liabilities are included on our Consolidated Balance Sheets.
Commercial Agreements — In connection with the purchase and sale of power, natural gas and emission allowances to and from third parties with respect to the operation of our power plants, we may be required to
guarantee a portion of the obligations of certain of our subsidiaries. These guarantees may include future payment obligations and effectively guarantee our future performance under certain agreements.
Asset Acquisition and Disposition Agreements — In connection with our purchase and sale agreements, we have frequently provided for indemnification to the counterparty for liabilities incurred as a result of a breach of a representation, warranty or covenant by the indemnifying party. These indemnification obligations generally have a discrete term and are intended to protect the parties against risks that are difficult to predict or impossible to quantify at the time of the consummation of a particular transaction.
Other — Additionally, we and our
subsidiaries from time to time assume other guarantee and indemnification obligations in conjunction with other transactions such as parts supply agreements, construction agreements, maintenance and service agreements and equipment lease agreements. These guarantee and indemnification obligations may include indemnification from personal injury or other claims by our employees as well as future payment obligations and effectively guarantee our future performance under certain agreements.
Our potential exposure under guarantee and indemnification obligations can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. Our total maximum exposure under our guarantee and indemnification obligations is not estimable due to uncertainty as to whether claims will be made
or how any potential claim will be resolved. As of December 31, 2014, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations.
Litigation
We are party to various litigation matters, including regulatory and administrative proceedings arising out of the normal course of business. At the present time, we do not expect that the outcome of any of these proceedings will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, we review our litigation activities and determine
if an unfavorable outcome to us is considered “remote,”“reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated. As
a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material impact on our financial condition, results of operations or cash flows or that would significantly change our operations.
Bay Area Air Quality Management District (“BAAQMD”). On March 13, 2014, the Hearing
Board of the BAAQMD entered into a stipulated conditional order for abatement agreed to by Russell City Energy Company, LLC (“RCEC”), our indirect, majority-owned subsidiary, and the BAAQMD concerning a violation of the vendor-guaranteed water droplet drift rate for RCEC’s cooling tower discovered during initial performance testing. RCEC installed additional drift eliminators and came into compliance with its water droplet drift rate on April 17, 2014. The BAAQMD reserved its rights to assert any penalty claims associated with this violation and RCEC reserved its rights to assert any defenses to such claims in future proceedings.
144
16.
Segment
and Significant Customer Information
We assess our business on a regional basis due to the impact on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors impacting supply and demand. During the third quarter of 2014, we altered the composition of our geographic segments to combine our former North and Southeast segments into one segment which was renamed the East segment. This change reflects the manner in which our geographic information is presented internally to our chief operating decision maker following the sale of six power plants in July 2014 from what was formerly our Southeast segment. Thus, at December 31, 2014, our reportable segments were West (including geothermal), Texas and East (including Canada). We
continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result.
Commodity Margin is a key operational measure reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments for the periods indicated (in millions).
Add:
Mark-to-market commodity activity, net and other(2)
(93
)
87
(47
)
(31
)
(84
)
Less:
Plant
operating expense
368
247
337
(30
)
922
Depreciation
and amortization expense
203
142
219
(2
)
562
Sales,
general and other administrative expense
36
47
57
—
140
Other
operating expenses
42
5
34
(3
)
78
(Gain)
on sale of assets, net
—
—
(222
)
—
(222
)
(Income)
from unconsolidated investments in power plants
—
—
(28
)
—
(28
)
Income
from operations
252
216
530
4
1,002
Interest
expense, net of interest income
725
Loss on interest rate derivatives
14
Debt
extinguishment costs and other (income) expense, net
45
Loss before income taxes
$
218
__________
146
(1)
Our East segment includes Commodity Margin of $81 million, $152 million and $131 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to the six power plants in our East segment that were sold in July 2014.
(2)
Includes
$(5) million, $6 million and $1 million of lease levelization and $14 million, $14 million and $14 million of amortization expense for the years ended December 31, 2014, 2013 and 2012, respectively.
(3)
Our East segment includes Commodity Margin of $52 million for the year ended December
31, 2012, related to Broad River, which was sold in December 2012.
(4)
Our East segment includes Commodity Margin of $73 million for the year ended December 31, 2012, related to Riverside Energy Center, LLC, which was sold in December 2012.
Significant Customers
For the years ended December 31, 2014 and 2012,
we had only one significant customer, PJM Settlement, Inc. that individually accounted for more than 10% of our annual consolidated revenues. For the year ended December 31, 2013, we had two significant customers, PJM Settlement, Inc. and PG&E, that individually accounted for more than 10% of our annual consolidated revenues. Our revenues from PJM Settlement, Inc. for the years ended December 31, 2014, 2013 and 2012 were approximately $1.0 billion, $820 million and $713 million respectively, and were attributed to our East segment. Our revenues
from PG&E was approximately $694 million for the year ended December 31, 2013, which was attributed to our West segment.
147
17.
Quarterly Consolidated Financial Data (unaudited)
Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our
restructuring activities (including asset sales), the completion of development projects, the timing and amount of curtailment of operations under the terms of certain PPAs, the degree of risk management and marketing, hedging, optimization and trading activities, energy commodity market prices and variations in levels of production. Furthermore, the majority of the dollar value of capacity payments under certain of our PPAs are received during the months of May through October.
Quarter
Ended
December 31
September 30
June 30
March 31
(in millions, except per share amounts)
2014
Operating
revenues
$
1,939
$
2,187
$
1,939
$
1,965
Income
from operations
$
390
$
1,126
$
329
$
144
Net
income (loss) attributable to Calpine
$
210
$
614
$
139
$
(17
)
Net
income (loss) per common share attributable to Calpine — Basic
$
0.55
$
1.54
$
0.33
$
(0.04
)
Net
income (loss) per common share attributable to Calpine — Diluted
$
0.54
$
1.52
$
0.33
$
(0.04
)
2013
Operating
revenues
$
1,438
$
2,050
$
1,572
$
1,241
Income
from operations
$
151
$
597
$
122
$
4
Net
income (loss) attributable to Calpine
$
(97
)
$
306
$
(70
)
$
(125
)
Net
income (loss) per common share attributable to Calpine — Basic
$
(0.23
)
$
0.70
$
(0.16
)
$
(0.28
)
Net
income (loss) per common share attributable to Calpine — Diluted
Findings of Fact, Conclusions of Law, and Order Confirming Sixth Amended Joint Plan of Reorganization Pursuant to Chapter 11
of the U.S. Bankruptcy Code (incorporated by reference to Exhibit 2.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 27, 2007).
2.3
Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers and Public Service Company of Colorado, as Purchaser dated as of April 2, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Quarterly Report
on Form 10-Q for the quarter ended June 30, 2010, filed with the SEC on July 30, 2010).**,††
2.4
Purchase Agreement by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC dated as of April 20, 2010 (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC
on July 8, 2010).**
2.5
Purchase and Sale Agreement, dated April 17, 2014, among Calpine Corporation, Calpine Project Holdings, Inc., Calgen Expansion Company, LLC and NatGen Southeast Power LLC (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 8, 2014).
Amended and Restated Indenture, dated May 25, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including
the form of the 8% senior secured notes due 2019 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on May 25, 2010).
4.3
Indenture, dated July 23, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.875% senior
secured notes due 2020 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on July 23, 2010).
4.4
Indenture, dated October 22, 2010, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.50% senior secured notes due
2021 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 22, 2010).
4.5
Indenture, dated January 14, 2011, among Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee, including the form of the 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on January 14 , 2011).
First Supplemental
Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011).
150
Exhibit
Number
Description
4.8
First
Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011).
4.9
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine
Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC on April 29, 2011).
4.10
First
Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March
31, 2011, filed with the SEC on April 29, 2011).
4.11
First Supplemental Indenture dated as of April 26, 2011, among each of New Development Holdings, LLC, Calpine Mid-Atlantic Energy, LLC, Calpine Mid-Atlantic Operating, LLC, Calpine Bethlehem, LLC, Calpine New Jersey Generation, LLC, Calpine Mid-Atlantic Generation, LLC, Calpine Solar, LLC, Calpine Vineland Solar, LLC and Calpine
Mid-Atlantic Marketing, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, filed with the SEC on April 29, 2011).
4.12
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.13
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.14
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.15
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
4.16
Second
Supplemental Indenture dated as of July 22, 2011, among each of Deer Park Energy Center LLC, Deer Park Holdings, LLC, Metcalf Energy Center, LLC, Metcalf Holdings, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed with the SEC on July 29, 2011).
151
Exhibit
Number
Description
4.17
Third Supplemental Indenture dated as of August 20,
2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.1 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.18
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.19
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.20
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.4 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.21
Third
Supplemental Indenture dated as of August 20, 2012, among each of Calpine Energy Services GP, LLC and Calpine Energy Services LP, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.5 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2012, filed with the SEC on November 6, 2012).
4.22
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.24 to Calpine’s Annual Report on Form 10-K for the year ended December 31,
2012, filed with the SEC on February 13, 2013).
4.23
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River
OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of May 25, 2010, providing for the issuance of 8.0% senior secured notes due 2019 (incorporated by reference to Exhibit 4.25 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 13, 2013).
4.24
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of July 23, 2010, providing for the issuance of 7.875% senior secured notes due 2020 (incorporated by reference to Exhibit 4.26 to Calpine’s Annual Report on Form 10-K for the year ended December 31,
2012, filed with the SEC on February 13, 2013).
4.25
Fourth Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River
OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of October 22, 2010, providing for the issuance of 7.50% senior secured notes due 2021 (incorporated by reference to Exhibit 4.27 to Calpine’s Annual Report on Form 10-K for the year ended December 31, 2012, filed with the SEC on February 13, 2013).
152
Exhibit
Number
Description
4.26
Fourth
Supplemental Indenture dated as of November 26, 2012, among each of South Point Holdings, LLC, South Point Energy Center, LLC, Broad River Energy LLC, South Point OL-1, LLC, South Point OL-2, LLC, South Point OL-3, LLC, South Point OL-4, LLC, Broad River OL-1, LLC, Broad River OL-2, LLC, Broad River OL-3, LLC and Broad River OL-4, LLC and Wilmington Trust Company, as trustee under the indenture, dated as of January 14, 2011, providing for the issuance of 7.875% senior secured notes due 2023 (incorporated by reference to Exhibit 4.28 to Calpine’s Annual Report on Form 10-K for the year ended December
31, 2012, filed with the SEC on February 13, 2013).
4.27
Indenture dated as of October 31, 2013, for the senior secured notes due 2022 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.1 to Calpine’s Current Report on
Form 8-K, filed with the SEC on October 31, 2013).
4.28
Indenture dated as of October 31, 2013, for the senior secured notes due 2024 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, National Association, as trustee (incorporated by reference to Exhibit 4.2 to Calpine’s Current Report on Form
8-K, filed with the SEC on October 31, 2013).
4.29
Fifth Supplemental Indenture dated as of October 30, 2013 among each of Calpine Corporation, the guarantors party thereto and Wilmington Trust Company, as trustee under the indenture, dated as of October
21, 2009, providing for the issuance of 7.25% senior secured notes due 2017 (incorporated by reference to Exhibit 4.3 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 31, 2013).
Credit Agreement, dated as of December 10, 2010, among Calpine Corporation, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, the lenders party thereto and other parties thereto (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on December 13, 2010).
10.1.1.6
Credit
Agreement, dated March 9, 2011 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K filed with the SEC on March 10, 2011).
Credit Agreement, dated October 9, 2012 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior
Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Barclays Bank PLC, Deutsche Bank Securities Inc., and RBC Capital Markets, as co-documentation agents (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on October 10, 2012).
10.1.1.9
Amendment to the Credit Agreement, dated February 15, 2013 among Calpine Corporation as borrower
and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Citibank, N.A., Credit Suisse Securities (USA) LLC and Deutsche Bank Securities Inc., as co-documentation agents and Goldman Sachs Bank USA as syndication agent (incorporated by reference to Exhibit 10.9 to Calpine’s 10-Q for the quarter ended March 31, 2013, filed with the SEC on May 2, 2013).
10.1.1.10
Amendment
to the Credit Agreement, dated February 15, 2013 among Calpine Corporation as borrower and the lenders party hereto, and Morgan Stanley Senior Funding, Inc., as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, Barclays Bank PLC, Deutsche Bank Securities Inc., and RBC Capital Markets, as co-documentation agents (incorporated by reference to Exhibit 10.10 to Calpine’s 10-Q for the quarter ended March 31, 2013, filed with the SEC on May 2, 2013).
10.1.1.11
Credit
Agreement, dated May 3, 2013 among Calpine Construction Finance Company as borrower and the lenders party thereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K, filed with the SEC on May 3, 2013).
10.1.1.12
Amendment
No. 1 to the December 10, 2010 Credit Agreement, dated as of June 27, 2013, among Calpine Corporation, as borrower, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and the lenders 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 1, 2013).
10.1.1.13
Amendment
to the Credit Agreement, dated February 20, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party hereto, and Goldman Sachs Lending Partners, LLC (“GSLP”) as administrative agent and as collateral agent, CoBank ACB, ING Capital LLC., Royal Bank of Canada, and The Royal Bank of Scotland PLC as co-documentation agents, GSLP, Deutsche Bank Securities Inc., Credit Suisse Securities (USA) LLC, Merrill Lynch, Pierce Fenner and Smith Incorporated and Union Bank, N.A., as joint lead arrangers, joint bookrunners and co-syndication agents, and the lenders party thereto (incorporated by reference to Exhibit 10.1 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
10.1.1.14
Incremental
Term B-2 Loan Commitment Supplement to the Credit Agreement, dated February 26, 2014, among Calpine Construction Finance Company, L.P. as borrower and the lenders party hereto, and Goldman Sachs Lending Partners, LLC as administrative agent and as collateral agent under the Credit Agreement, dated as of May 3, 2013 and as amended on February 20, 2014 (incorporated by reference to Exhibit 10.2 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014).
Amendment No. 2 to the Credit Agreement, dated as of July 30, 2014, among Calpine Corporation, as borrower, Goldman Sachs Bank USA, as administrative agent, Goldman Sachs Credit Partners L.P., as collateral agent, and the lenders 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
31, 2014).
Calpine Corporation Executive Sign On Non-Qualified Stock Option Agreement (Jack A. Fusco) (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on August 12, 2008).†
Calpine
Corporation Executive Sign On Non-Qualified Stock Option Agreement (John B. (Thad) Hill) (incorporated by reference to Exhibit 10.2 to Calpine’s Current Report on Form 8-K, filed with the SEC on September 4, 2008).†
Restricted Stock Agreement Pursuant to the Amended and Restated 2008 Equity Incentive Plan, dated May 13, 2014 among John
B. Hill and Calpine Corporation (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed with the Securities and Exchange Commission on May 15, 2014).†
Calpine
Corporation Executive Sign On Non-Qualified Stock Option Agreement (Thaddeus Miller) (incorporated by reference to Exhibit 4.4 to Calpine’s Registration Statement on Form S-8 (Registration No. 333-153860) filed with the SEC on October 6, 2008).†
Calpine
Corporation 2010 Calpine Incentive Plan (incorporated by reference to Exhibit 10.6 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed with the SEC on July 30, 2010).†
10.2.7
Calpine Corporation 2009 Calpine Incentive Plan (incorporated by reference to Exhibit 10.2 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2009, filed
with the SEC on May 8, 2009).†
Form
of Non-Qualified Stock Option Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to Exhibit 10.4.3 to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
10.2.7.3
Form of Restricted Stock Agreement (Pursuant to the 2008 Equity Incentive Plan) (incorporated by reference to Exhibit 10.4.4
to Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008, filed with the SEC on May 12, 2008).†
10.2.8
The Amended and Restated Calpine Corporation 2008 Director Incentive Plan (incorporated by reference to Annex A to Calpine’s Definitive Proxy Statement on Schedule 14A filed with the SEC on April 5, 2010).†
Calpine Corporation Amended and Restated Change in Control and Severance Benefits Plan (incorporated
by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on November 8, 2013).†
Amended and Restated Calpine Corporation
Equity Incentive Plan (incorporated by reference to Exhibit 10.1 to Calpine’s Current Report on Form 8-K, filed with the SEC on May 10, 2013).†
10.2.21
Form of Restricted Stock Award Agreement between the Company and Jack A. Fusco and W. Thaddeus Miller (Pursuant to the Amended and Restated Calpine Corporation 2008
Equity Incentive Plan, dated February 26, 2014)(incorporated by reference to Exhibit 10.4 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
Form
of Performance Share Unit Award Agreement between the Company and Jack A. Fusco and W. Thaddeus Miller (Pursuant to the Amended and Restated Calpine Corporation 2008 Equity Incentive Plan, dated February 26, 2014) (incorporated by reference to Exhibit 10.6 to the Calpine’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, filed with the SEC on May 1, 2014). †
Power of Attorney of Officers and Directors of Calpine Corporation (set forth on the signature pages of this Form 10-K).*
31.1
Certification
of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2
Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32.1
Certification
of Chief Executive Officer and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.‡
Management contract or compensatory plan, contract or arrangement.
**
Schedules
omitted pursuant to Item 601(b)(2) of Regulation S-K. Calpine will furnish supplementally a copy of any omitted schedule to the SEC upon request.
††
Portions of this exhibit have been omitted pursuant to a request for confidential treatment under Rule 24b-2 under the Securities Exchange Act of 1934.
158
Dates Referenced Herein and Documents Incorporated by Reference
