PART I
BUSINESS AND STRATEGY
We are a premier competitive power company with 77 power plants, including one under construction, primarily in the U.S. We sell power and related services to our wholesale customers who include commercial and industrial end-users, state and regional wholesale market operators, and our retail customers. We measure our success by delivering long-term value. We accomplish this through our focus on operational excellence at our power plants and in our customer and commercial activity, as well as through our disciplined approach to capital allocation.
Our capital allocation philosophy seeks to maximize levered cash returns to equity while maintaining a strong balance sheet. We seek to enhance value through a diverse and balanced capital allocation approach that includes portfolio management including select asset sales, organic or acquisitive growth, returning capital to owners and debt reduction. The mix of this activity shifts over time given the external market environment and the opportunity set. During the year ended December 31, 2019, we paid cash distributions to our parent, CPN Management, totaling $1.15 billion. Since the beginning of 2017 through the end of January 2020, we have reduced our total debt by approximately $1.6 billion and funded approximately $350 million of expansion/growth projects. We further optimized our capital structure by refinancing, redeeming, repricing or amending several of our debt instruments during the year ended December 31, 2019 achieving substantial annual interest savings.
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 and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions 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 flexible and reliable power plants. Our portfolio is primarily comprised of two types of power generation technologies: efficient combined-cycle power plants, which use natural gas-fired combustion turbines, 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. as well as the largest single producing power generation asset of all renewable energy in the state of California.
We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power and related products for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants. Seasonality and weather can have a significant effect on our results of operations and are also considered in our hedging and optimization activities.
We assess our wholesale business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. Our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business.
Our wholesale power plant portfolio, including partnership interests, consists of 77 power plants, including one under construction, with an aggregate current generation capacity of 26,035 MW and 361 MW under construction. In March 2019, our York 2 Energy Center commenced commercial operations, bringing online approximately 828 MW of combined cycle, natural gas-fired capacity with dual-fuel capability. Our fleet consists of 62 natural gas-fired combustion turbine-based plants, one natural gas and fuel oil-fired steam-based plant, 13 geothermal steam turbine-based plants and one photovoltaic solar plant. Our wholesale geographic segments have an aggregate generation capacity of 7,590 MW in the West, 9,115 MW in Texas and 9,330 MW with an additional 361 MW under construction in the East. Inclusive of our power generation portfolio and our retail sales platforms, we serve customers in 23 states in the U.S. and in Canada and Mexico.
Our goal is to be recognized as the premier competitive power company in the U.S. as viewed by our employees, owners, customers and policy-makers as well as the communities in which our facilities are located. We seek to deliver long-term value through operational excellence at our power plants and in our customer and commercial activity, as well as through our disciplined approach to capital allocation.
THE MARKET FOR POWER
Our Power Markets and Market Fundamentals
The power industry represents one of the largest industries in the U.S. and affects nearly every aspect of our economy, with an estimated end-user market of approximately $398 billion in power sales in 2019 according to the EIA. 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 or retail market competition. California (included in our West segment), Texas (included in our Texas segment) and the Northeast and Mid-Atlantic regions (included in our East segment), which are the markets in which we have our largest presence, have emerged as among the most competitive wholesale and retail power markets in the U.S. We also operate, to a lesser extent, in competitive wholesale power markets in the Southeast. In addition to our sales of electrical power to wholesale and retail customers, our power plants produce and our customers require several other products. A description of the products we provide to our customers is below:
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First, we provide power to utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. 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.
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Second, we provide capacity for sale to utilities, independent electric system operators and retail power providers. In various markets, retail power providers, including our affiliates, (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 market product known as capacity from power plant owners or resellers. Capacity auctions are held in the Northeast, Mid-Atlantic and certain Midcontinent regional markets. California has a bilateral capacity program. Texas does not presently have a capacity market or a requirement for retailers to ensure adequate resources.
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Third, we produce RECs primarily from our Geysers Assets in northern California. California has an RPS that requires load serving entities to have RECs for a certain percentage of their demand for the purpose of guaranteeing a certain level of renewable generation in the state 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. We also purchase RECs from other sources for resale to our customers.
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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.
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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.
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Of the five products above, we are active not only in production but also in the procurement of four of the five (excluding steam) on behalf of our retail customers.
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We also buy and sell emission allowances and credits, including those under California’s AB 32 GHG reduction program, Massachusetts’ CO2 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 retail channels and sell power into shorter term markets throughout the regions in which we participate.
The Price and Supply of Natural Gas
Approximately 96%, or 24,915 MW, 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 391 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 6,100 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 is constrained, some of our power plants benefit from the ability to operate on fuel oil instead of natural gas.
The price of natural gas, economic growth and environmental regulations affect our Commodity Margin and liquidity. The effect 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 and Mid-Atlantic (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., when electricity demand exceeds available renewable generation and natural gas prices exceed the cost of available coal generation), 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 until the point we are cheaper than any available coal on marginal economics. Additionally, in the Northeast and Mid-Atlantic regions, 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 effect 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 or power prices, we could be required to post additional cash collateral or letters of credit.
Weather Patterns and Natural Events
Weather generally has a significant short-term effect 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 affected by relatively cool summers or mild winters. However, our geographically diverse portfolio mitigates the effect 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 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, operating Heat Rate and operating and maintenance expense. 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 effect on our Commodity Margin.
Regulatory and Environmental Trends
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 various risk factors which could affect our business. A description of these risk factors is included under Item 1A. “Risk Factors.”
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, the Northeast and Mid-Atlantic, our natural gas-fired power plants compete directly with all other sources of power. The EIA estimates that in 2019, 38% of the power generated in the U.S. was fueled by natural gas, 24% by coal, 20% by nuclear facilities and the remaining 18% 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. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters.”
Competition from renewable generation and energy storage is likely to continue to increase in the future. Federal and state financial incentives and RPS requirements continue to foster renewables development.
Retail electricity and natural gas is similarly a commodity-driven business with numerous industry participants. We compete against other integrated power companies, regulated utilities, other retail power providers, brokers, trading companies including those owned by financial institutions, retail load aggregators, municipalities and cooperatives to supply power and power-related products to our customers in major markets in the U.S. and Canada.
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. Our retail portfolio has been established to provide an additional source of liquidity for our generation fleet as we hedge retail load from our wholesale generation assets as appropriate.
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 the Northeast 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.
Our operations are commodity intensive. We produced approximately 103 billion KWh of electricity in 2019 across North America and consumed approximately 790 Bcf of natural gas, making us one of the largest producers of electricity and consumers of natural gas in North America. Additionally, our retail affiliates provided approximately 60 billion KWh to customers in 2019. We actively manage our commodity 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, retail power sales including through our retail subsidiaries, steam sales, buying and selling standard physical power and natural gas products, buying and selling exchange traded instruments, buying and selling environmental and capacity products, natural gas transportation and storage arrangements, electric transmission service and other contracts for the sale and purchase of power products. We utilize these instruments to maximize the risk-adjusted returns for our Commodity Margin.
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 as well as retail load supply obligations, where appropriate, mostly through power and natural gas forward physical and financial transactions including retail power sales; however, we currently remain susceptible to significant price movements for 2020 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 actively managing hedge positions to lock in margin. We 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 and retail units 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 hedging instruments to adjust the mix between our fixed and variable rate debt. To the extent eligible, our interest rate hedging instruments have been designated as cash flow hedges, and changes in fair value are recorded in OCI with gains and losses reclassified into earnings in the same period during which the hedged forecasted transaction affects earnings.
SEGMENT AND SIGNIFICANT CUSTOMER INFORMATION
See Note 18 of the Notes to Consolidated Financial Statements for a discussion of financial information by reportable segment and geographic area and significant customer information for the years ended December 31, 2019, 2018 and 2017.
DESCRIPTION OF OUR OPERATIONS
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Geographic Diversity
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Dispatch Technology
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Power Plants in Operation
We own 77 power plants, including one under construction, with an aggregate generation capacity of 26,035 MW and 361 MW under construction.
Natural Gas-Fired Fleet
Our natural gas-fired power plants primarily utilize two types of designs: 1,640 MW of simple-cycle combustion turbines and 22,941 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 fuel 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, our retail customers or an intermediary such as a marketing company. At 12 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 2019 for the power plants we operate was 7,326 Btu/KWh which results in a power conversion efficiency of approximately 47%. The power conversion efficiency is a measure of how efficiently a fossil fuel power plant converts thermal energy to electrical energy. Our 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 19 years.
Geothermal Fleet
Our Geysers Assets are a 725 MW fleet of 13 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. Unlike other renewable resources such as wind or sunlight, which depend on intermittent sources to generate power, geothermal power provides a consistent source of energy as evidenced by our Geysers Assets’ availability of approximately 86% in 2019, which reflects the impact of a third-party transmission outage at our Geysers Assets associated with a wildfire during the fourth quarter of 2019. The sale of RECs to customers is an important separate income stream for our Geysers Assets.
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 15 million gallons of reclaimed water per day into the geothermal steam reservoir at The Geysers where the water is naturally heated by the Earth, creating additional steam to fuel our Geysers Assets. Approximately 12 million gallons per day are received from the Santa Rosa Geysers Recharge Project, which we developed jointly with the City of Santa Rosa, and we receive, on average, approximately three 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.
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 2019. 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 2079. In reaching this conclusion, our evaluation, consistent with the due diligence study of 2019, 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 105 leases comprising approximately 28,000 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 2019 is:
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26% related to leases with the federal government via the Office of Natural Resources Revenue,
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31% related to leases with the California State Lands Commission and
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43% related to leases with private landowners/leaseholders.
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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 thereafter as geothermal resources are produced and sold. Most 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 four 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
We also have 725 MW of older, less efficient technology at our Edge Moor Energy Center which has conventional steam turbine technology and 4 MW of capacity from solar power generation technology at our Vineland Solar Energy Center in New Jersey.
Retail Operations
Our retail segment provides energy and related services to commercial, industrial, governmental and residential customers through our retail subsidiaries which consist of Calpine Solutions and Champion Energy (including North American Power). Our retail operations have an overlapping presence with our wholesale business in California, Texas and the Northeast and Mid-Atlantic regions of the U.S and provided approximately 60 billion KWh to customers in 2019 consisting of approximately 6 million annualized residential customer equivalents. Thus, our retail segment geographically and strategically complements our wholesale generation fleet providing access to forward market liquidity through both direct and mass market retail sales channels.
Table of Operating Power Plants and Project Under Construction
Set forth below is certain information regarding our operating power plants and project under construction at January 28, 2020.
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SEGMENT / Power Plant
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NERC
Region
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U.S. State or
Canadian
Province
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Technology
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Calpine
Interest
Percentage
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Calpine Net
Interest
Baseload
(MW)(1)(3)
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Calpine Net
Interest
With Peaking
(MW)(2)(3)
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2019
Total MWh
Generated(4)
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WEST
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Geothermal
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McCabe #5 & #6
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WECC
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CA
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Renewable
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100
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%
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84
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84
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635,462
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Ridge Line #7 & #8
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WECC
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CA
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Renewable
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100
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%
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76
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76
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546,804
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Calistoga
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WECC
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CA
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Renewable
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100
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%
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69
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69
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400,526
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Eagle Rock
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WECC
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CA
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Renewable
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100
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%
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68
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68
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606,753
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Big Geysers
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WECC
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CA
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Renewable
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100
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%
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61
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61
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351,745
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Lake View
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WECC
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CA
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Renewable
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100
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%
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54
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54
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491,695
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Quicksilver
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WECC
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CA
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Renewable
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100
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%
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53
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53
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368,140
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Sonoma
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WECC
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CA
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Renewable
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100
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%
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53
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53
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350,221
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Cobb Creek
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WECC
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CA
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Renewable
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100
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%
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51
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51
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350,775
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Socrates
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WECC
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CA
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Renewable
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100
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%
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50
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50
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299,620
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Sulphur Springs
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WECC
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CA
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Renewable
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100
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%
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47
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47
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456,099
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Grant
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WECC
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CA
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Renewable
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100
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%
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41
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41
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244,322
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Aidlin
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WECC
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CA
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Renewable
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100
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%
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18
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18
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106,159
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Natural Gas-Fired
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Delta Energy Center
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WECC
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CA
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Combined Cycle
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100
|
%
|
|
835
|
|
|
857
|
|
|
3,540,562
|
|
Pastoria Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
780
|
|
|
759
|
|
|
4,061,160
|
|
Hermiston Power Project
|
|
WECC
|
|
OR
|
|
Combined Cycle
|
|
100
|
%
|
|
566
|
|
|
635
|
|
|
4,303,231
|
|
Russell City Energy Center(5)
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
572
|
|
|
619
|
|
|
662,160
|
|
Otay Mesa Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
513
|
|
|
608
|
|
|
751,810
|
|
Metcalf Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
564
|
|
|
605
|
|
|
2,566,516
|
|
Sutter Energy Center
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
542
|
|
|
578
|
|
|
653,076
|
|
Los Medanos Energy Center
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
518
|
|
|
572
|
|
|
2,707,147
|
|
South Point Energy Center
|
|
WECC
|
|
AZ
|
|
Combined Cycle
|
|
100
|
%
|
|
520
|
|
|
530
|
|
|
1,883,597
|
|
Los Esteros Critical Energy Facility
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
243
|
|
|
309
|
|
|
216,237
|
|
Gilroy Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
141
|
|
|
26,680
|
|
Gilroy Cogeneration Plant
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
109
|
|
|
130
|
|
|
89,536
|
|
King City Cogeneration Plant
|
|
WECC
|
|
CA
|
|
Cogen
|
|
100
|
%
|
|
120
|
|
|
120
|
|
|
161,388
|
|
Wolfskill Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
48
|
|
|
7,008
|
|
Yuba City Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
28,995
|
|
Feather River Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
12,321
|
|
Creed Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
11,763
|
|
Lambie Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
12,245
|
|
Goose Haven Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
11,509
|
|
Riverview Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
47
|
|
|
20,042
|
|
King City Peaking Energy Center
|
|
WECC
|
|
CA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
44
|
|
|
6,038
|
|
Agnews Power Plant
|
|
WECC
|
|
CA
|
|
Combined Cycle
|
|
100
|
%
|
|
28
|
|
|
28
|
|
|
6,613
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
6,635
|
|
|
7,590
|
|
|
26,947,955
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
2019
Total MWh
Generated(4)
|
TEXAS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deer Park Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
1,103
|
|
|
1,204
|
|
|
6,775,720
|
|
Guadalupe Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
1,009
|
|
|
1,000
|
|
|
5,481,210
|
|
Baytown Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
810
|
|
|
896
|
|
|
4,746,868
|
|
Channel Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
732
|
|
|
817
|
|
|
4,172,535
|
|
Pasadena Power Plant(6)
|
|
TRE
|
|
TX
|
|
Cogen/Combined Cycle
|
|
100
|
%
|
|
763
|
|
|
781
|
|
|
4,266,517
|
|
Bosque Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
760
|
|
|
782
|
|
|
4,257,071
|
|
Freestone Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
75
|
%
|
|
779
|
|
|
746
|
|
|
5,536,148
|
|
Magic Valley Generating Station
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
682
|
|
|
712
|
|
|
2,865,506
|
|
Jack A. Fusco Energy Center(7)
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
100
|
%
|
|
523
|
|
|
609
|
|
|
2,343,664
|
|
Corpus Christi Energy Center
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
426
|
|
|
500
|
|
|
2,047,276
|
|
Texas City Power Plant
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
400
|
|
|
453
|
|
|
1,743,106
|
|
Hidalgo Energy Center
|
|
TRE
|
|
TX
|
|
Combined Cycle
|
|
78.5
|
%
|
|
397
|
|
|
379
|
|
|
2,136,301
|
|
Freeport Energy Center(8)
|
|
TRE
|
|
TX
|
|
Cogen
|
|
100
|
%
|
|
210
|
|
|
236
|
|
|
1,092,978
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
8,594
|
|
|
9,115
|
|
|
47,464,900
|
|
EAST
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bethlehem Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
960
|
|
|
1,130
|
|
|
4,721,711
|
|
Hay Road Energy Center
|
|
RFC
|
|
DE
|
|
Combined Cycle
|
|
100
|
%
|
|
931
|
|
|
1,130
|
|
|
1,473,514
|
|
York 2 Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
668
|
|
|
828
|
|
|
4,073,106
|
|
Morgan Energy Center
|
|
SERC
|
|
AL
|
|
Cogen
|
|
100
|
%
|
|
720
|
|
|
807
|
|
|
3,121,040
|
|
Fore River Energy Center
|
|
NPCC
|
|
MA
|
|
Combined Cycle
|
|
100
|
%
|
|
750
|
|
|
731
|
|
|
4,403,186
|
|
Edge Moor Energy Center
|
|
RFC
|
|
DE
|
|
Steam Cycle
|
|
100
|
%
|
|
—
|
|
|
725
|
|
|
146,670
|
|
Granite Ridge Energy Center
|
|
NPCC
|
|
NH
|
|
Combined Cycle
|
|
100
|
%
|
|
745
|
|
|
695
|
|
|
3,025,593
|
|
York Energy Center
|
|
RFC
|
|
PA
|
|
Combined Cycle
|
|
100
|
%
|
|
464
|
|
|
565
|
|
|
1,379,992
|
|
Westbrook Energy Center
|
|
NPCC
|
|
ME
|
|
Combined Cycle
|
|
100
|
%
|
|
552
|
|
|
552
|
|
|
958,466
|
|
Greenfield Energy Centre(9)
|
|
NPCC
|
|
ON
|
|
Combined Cycle
|
|
50
|
%
|
|
422
|
|
|
519
|
|
|
1,075,167
|
|
Zion Energy Center
|
|
RFC
|
|
IL
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
503
|
|
|
663,766
|
|
Pine Bluff Energy Center
|
|
SERC
|
|
AR
|
|
Cogen
|
|
100
|
%
|
|
184
|
|
|
215
|
|
|
1,169,631
|
|
Cumberland Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
191
|
|
|
95,697
|
|
Kennedy International Airport Power Plant
|
|
NPCC
|
|
NY
|
|
Cogen
|
|
100
|
%
|
|
110
|
|
|
121
|
|
|
483,081
|
|
Sherman Avenue Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
92
|
|
|
24,265
|
|
Bethpage Energy Center 3
|
|
NPCC
|
|
NY
|
|
Combined Cycle
|
|
100
|
%
|
|
60
|
|
|
80
|
|
|
111,104
|
|
Carll’s Corner Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
73
|
|
|
5,911
|
|
Mickleton Energy Center
|
|
RFC
|
|
NJ
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
67
|
|
|
60
|
|
Bethpage Power Plant
|
|
NPCC
|
|
NY
|
|
Combined Cycle
|
|
100
|
%
|
|
55
|
|
|
56
|
|
|
195,701
|
|
Christiana Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
53
|
|
|
189
|
|
Bethpage Peaker
|
|
NPCC
|
|
NY
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
48
|
|
|
45,293
|
|
Stony Brook Power Plant
|
|
NPCC
|
|
NY
|
|
Cogen
|
|
100
|
%
|
|
45
|
|
|
47
|
|
|
288,650
|
|
Tasley Energy Center
|
|
RFC
|
|
VA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
33
|
|
|
657
|
|
Delaware City Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
23
|
|
|
157
|
|
West Energy Center
|
|
RFC
|
|
DE
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
20
|
|
|
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
2019
Total MWh
Generated(4)
|
Bayview Energy Center
|
|
RFC
|
|
VA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
12
|
|
|
2,585
|
|
Crisfield Energy Center
|
|
RFC
|
|
MD
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
10
|
|
|
657
|
|
Vineland Solar Energy Center
|
|
RFC
|
|
NJ
|
|
Renewable
|
|
100
|
%
|
|
—
|
|
|
4
|
|
|
5,348
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
6,666
|
|
|
9,330
|
|
|
27,471,275
|
|
Total operating power plants
|
|
76
|
|
|
|
|
|
|
|
21,895
|
|
|
26,035
|
|
|
101,884,130
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Power plants sold during 2019
|
|
|
|
|
|
|
|
|
|
|
RockGen Energy Center
|
|
MRO
|
|
WI
|
|
Simple Cycle
|
|
100
|
%
|
|
n/a
|
|
|
n/a
|
|
|
152,712
|
|
Garrison Energy Center
|
|
RFC
|
|
DE
|
|
Combined Cycle
|
|
100
|
%
|
|
n/a
|
|
|
n/a
|
|
|
976,547
|
|
Whitby Cogeneration(10)
|
|
NPCC
|
|
ON
|
|
Cogen
|
|
50
|
%
|
|
n/a
|
|
|
n/a
|
|
|
75,260
|
|
Subtotal
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,204,519
|
|
Total operating and sold power plants
|
|
|
|
|
|
|
|
|
|
|
|
|
|
103,088,649
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Project Under Construction
|
Washington Parish Energy Center(11)
|
|
SERC
|
|
LA
|
|
Simple Cycle
|
|
100
|
%
|
|
—
|
|
|
361
|
|
|
n/a
|
|
Total operating power plants and project under construction
|
|
|
|
|
|
|
|
|
|
21,895
|
|
|
26,396
|
|
|
|
___________
|
|
(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)
|
On January 28, 2020 we purchased the 25% interest in Russell City Energy Center owned by a third party. MWh generation for 2019 reflects our net interest at the time of generation. Subsequent to the acquisition, we will reflect 100% of the results of our 619 MW Russell City Energy Center in our earnings.
|
|
|
(6)
|
Pasadena is comprised of 260 MW of cogen technology and 521 MW of combined cycle (non-cogen) technology.
|
|
|
(7)
|
Formerly our Brazos Valley Power Plant, which was renamed in December 2017.
|
|
|
(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)
|
On November 20, 2019, we sold our 50% partnership interest in Whitby Cogeneration.
|
|
|
(11)
|
A third party will purchase a 100% ownership interest in this power plant upon achieving commercial operation.
|
Substantially all of the power plants in which we have an interest are located on sites which we either own or lease on a long-term basis.
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, including those by ISO/RTOs, continue to have an effect on our business. Some of the more significant governmental and regulatory matters that affect our business are discussed below.
Power and Natural Gas Matters
Federal Regulation of Power
FERC Jurisdiction
The Federal Power Act (“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.
Our power plants, outside of ERCOT, are subject to FERC’s jurisdiction as either exempt wholesale generators (“EWGs”) under the FPA or QFs under PURPA. Most of our affiliates have been granted authority to sell power at market-based rates and have been granted certain waivers of FERC reporting and accounting regulations. However, we cannot assure that such authorities or waivers will not be revoked in the future for these affiliates.
The 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. The FERC is authorized to assess a maximum civil penalty of approximately $1.29 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 the Energy Policy Act of 2005 (“EPAct 2005”).
Pursuant to EPAct 2005, NERC has been certified by the FERC as the Electric Reliability Organization to develop and enforce reliability standards and critical infrastructure protection standards, which protect the bulk power system against potential disruptions from cyber and physical security breaches. The NERC standards are applicable throughout the U.S. and are subject to FERC review and approval. FERC-approved reliability standards may be enforced by the FERC independently, or, alternatively, by the NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to the FERC’s oversight. The critical infrastructure protection standards focus on controlling access to critical physical and cybersecurity assets, including supervisory control and data acquisition systems for the electric grid. Compliance with these standards is mandatory. Monetary penalties of approximately $1.29 million per day per violation may be assessed for violations of the reliability and critical infrastructure protection standards.
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 generation affiliates are either QFs or EWGs, none of them 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.
With regard to our retail sales affiliates, state PUCs have the ability to set policies that either enhance or limit customer choice. Each state that has adopted retail electric choice creates its own laws, regulations and compliance requirements which evolve over time and could impact our ability to maintain or expand retail operations.
Power Regions
The following is a brief overview of our core power regions – CAISO, ERCOT, PJM, ISO-NE and NYISO. The CAISO market is in our West segment. The ERCOT market is in our Texas segment. The PJM, ISO-NE and NYISO markets are in our East segment. These markets are constantly evolving in response to external factors that may disrupt the competitive balance within the wholesale markets.
Recently, several initiatives at the state and regional levels to provide out-of-market financial subsidies to certain generation resources in states and power regions with competitive wholesale markets threaten to undermine the operation of these power markets. Some of these initiatives have been enacted while others are currently being developed for future implementation. If these anticompetitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets which in turn could have a material adverse effect on our business prospects and financial results.
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 determines Resource Adequacy (“RA”) requirements for load serving entities (“LSEs”) and for specified local areas utilizing inputs from the CAISO in order to ensure the reliability of electric service in California. CPUC rules require LSEs to contract for capacity with sufficient generation resources in order to ensure capacity is available when and where it is needed. To the extent LSE’s have not procured sufficient capacity through the CPUC administered process, the CAISO will implement a backstop procurement process called the Capacity Procurement Mechanism (“CPM”) to meet its reliability needs. Currently, there are active proceedings at both the CAISO and CPUC which could entail changes to both the RA and CPM constructs. We do not know at this point whether these changes will be impactful to our business.
ERCOT
ERCOT is the ISO that manages approximately 90% 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.
In early 2018, the PUCT approved changes to energy price formation and scarcity pricing. These changes affect the shape of the Operating Reserve Demand Curve (“ORDC”), which produces a price “adder” to the clearing price of energy that increases as reserve capacity declines. The effect of these changes to the ORDC is to produce a more robust price signal than previously existed as reserve capacity declines.
PJM
PJM operates wholesale power markets, a locationally based energy market, a forward capacity market and ancillary service markets. PJM also performs transmission planning and operation for the region. The rules and regulations affecting PJM power markets and transmission are subject to change over time.
On June 29, 2018, the FERC issued a decision finding PJM’s current tariff to be unjust and unreasonable due to the price-suppressive effects of out-of-market compensation provided to certain generation resources by states within the PJM market. The FERC rejected both replacement proposals submitted by PJM to address the issue and instead opted for a paper hearing to identify a reasonable replacement mechanism. PJM’s annual capacity auction, which was scheduled to be held in May 2019, has been postponed pending the issuance of a FERC decision in this proceeding.
On December 19, 2019, the FERC issued an order in the paper hearing docket, directing PJM to expand its minimum offer price rule (“MOPR”) to apply to most generators receiving a state subsidy, although certain existing resources are exempted from the MOPR requirement. For non-exempt resources receiving a state subsidy, the MOPR will be set at the net Cost of New Entry for new resources and the Net Avoidable Cost Rate for existing resources. PJM is directed to submit a compliance filing by March 18, 2020. PJM must also propose dates in this filing for when the postponed May 2019 auction will be held. PJM has indicated that several future auctions will be delayed. Multiple parties have sought rehearing of the FERC’s order. The FERC has not ruled on those rehearing requests.
In addition, subsequent to the December 19, 2019 order, several states in the PJM region have expressed interest in using the “Fixed Resource Requirement” (FRR) provisions of the PJM tariff to bilaterally contract for capacity instead of participating in PJM’s market. It is unknown at this time whether or not states will pursue this approach, and what the resulting impact on our business will be.
The Independent Market Monitor (“IMM”) for PJM filed a complaint with the FERC on February 21, 2019 alleging that a component of PJM’s Reliability Pricing Model (“RPM”) allows sellers of the Capacity Performance product (“CP”) to offer CP at prices above the competitive level, thereby potentially allowing them to exercise market power. The IMM argues that this
provision of the tariff is unjust and unreasonable because the tariff does not provide a mechanism for the IMM to review these offers. Additionally, the IMM argues that the tariff should be revised to lower the Market Seller Offer Cap. This change would require nearly all competitive suppliers to submit their offers to the IMM for review prior to bidding in the RPM. In response to the IMM’s complaint, Calpine joined with many other competitive suppliers to urge the FERC to reject the IMM’s proposed resolution as inconsistent with CP and, alternatively, to enhance the penalty provisions of CP. This course of action would address the IMM’s concerns and would also be more consistent with the CP design. FERC action on the IMM’s complaint is pending.
ISO-NE
We have three power plants in our East segment located in Massachusetts, Maine and New Hampshire, all of which participate in the regional wholesale market in which ISO-NE is the RTO. ISO-NE has broad authority over the day-to-day operation of the transmission system and, among other responsibilities, operates a day-ahead and real-time wholesale energy market, a forward capacity market and an ancillary services market.
In response to reliability concerns related to fuel security in the New England region, ISO-NE filed a proposal with the FERC in mid-2018 that would allow it to retain certain generators under cost-of-service RMR Contracts that it believes are necessary to ensure fuel security on the system. The only units ISO-NE has contracted with to date are Mystic Units 8 and 9 (the “Mystic Units”). Included in ISO-NE’s proposal is a requirement that the cost-of-service units participate in ISO-NE’s forward capacity auction (“FCA”) as price takers. Calpine and many other generators opposed ISO-NE’s proposal, arguing that having these generators act as price takers will suppress capacity market clearing prices. The FERC rejected the price suppression concerns and accepted ISO-NE’s filing on December 3, 2018. Several companies have sought rehearing of the FERC’s decision. The Mystic Units were price takers in the FCA 13 and 14 auctions held in February 2019 and 2020, respectively, which likely contributed to lower capacity market clearing prices.
ISO-NE concedes that treating the cost-of-service units (i.e., the Mystic Units) as price takers in the FCA suppresses clearing prices. As a result, ISO-NE filed with the FERC an interim, administrative mechanism, referred to as the Energy Inventory Program, to provide additional compensation to all generators that provide fuel security to the system during the winter months of 2023-2024 and 2024-2025. The FERC was unable to issue an order on the proposal due to a lack of quorum. Consequently, on May 28, 2019, the Energy Inventory Program became effective by operation of law. Certain stakeholders have appealed the FERC’s decision to the U.S. Court of Appeals for the District of Columbia Circuit. Briefing has not yet commenced.
Additionally, ISO-NE has committed to the FERC to develop a long-term market-based solution to incent and retain fuel secure resources and is conducting stakeholder meetings to develop a solution. ISO-NE intends to submit this long-term solution to the FERC by April 15, 2020. Stakeholder meetings are continuing.
NYISO
We have five power plants in our East segment located in New York where NYISO is the RTO which manages the transmission system in New York and operates the state’s wholesale power markets. NYISO manages both day-ahead and real-time energy markets using a locationally based marginal pricing mechanism that pays each generator the zonal marginally accepted bid price for the energy it produces. NYISO also manages a forward capacity market where capacity prices are determined through auctions.
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 affected by federal regulation of natural gas transportation and sales. We own two pipelines in Texas that are subject to the Texas Railroad Commission regulation as Texas gas utilities.
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.
The FERC has civil penalty authority for violations of the Natural Gas Act (“NGA”) and Natural Gas Policy Act (“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 approximately $1.29 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).
Environmental Matters
Federal Air Emissions Regulations
CAA
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. In addition to regulation of air emissions at the federal level, a number of states in which we do business have implemented regulations that go beyond current federal environmental requirements. We continue to monitor and actively participate in federal and state initiatives which further our environmental and business objectives and where we anticipate an effect 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 HAPs from specific industrial sectors. The EPA also regulates emissions of certain pollutants that affect visibility in national parks and wilderness areas (“Regional Haze”). Finally, the EPA has begun regulating GHG emissions from various industries, including the power sector.
CAA regulations primarily affect higher-emitting units in the national power generating fleet. Our commitment to environmental stewardship is reflected in our history of investing in low-emitting power plant technologies. As a result, these regulations generally do not have a meaningful, direct adverse effect on our generating fleet, although they may impose significant costs on the power industry overall.
NAAQS — Ozone
As part of its ongoing CAA obligation to periodically review NAAQS to ensure that air quality is protective of human health and the environment, on October 1, 2015, the EPA set a new standard for ground-level of ozone of 70 parts per billion, down from the standard set in 2008 of 75 parts per billion. This is significant to the power sector because ground-level ozone is a product of complex chemical reactions contributed to by NOx, which are one of the primary emissions of concern from power plants.
Air quality in the Houston area, where six of our power plants are located, has improved over the last two decades. As a result, the Houston area was determined by the EPA to be attaining the 1-hour ozone standard, effective November 19, 2015, and the 1997 8-hour ozone standard, effective January 29, 2016. The Houston area remains in nonattainment relative to the 2008 ozone standard, and in fact, was downgraded in overall status relative to that standard effective September 23, 2019. The area’s status is also in nonattainment under the 2015 ozone standard, which could lead to further, more stringent regulation of NOx emissions from mobile sources and a number of industry sources, particularly the power industry.
Pursuant to authority granted under the CAA, the Texas Commission on Environmental Quality adopted regulations to attain the earlier NAAQS for ozone including the establishment of a Cap-and-Trade program for NOx emitted by industrial sources in the Houston-Galveston-Brazoria ozone nonattainment area, including power plants. We own and operate six 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. Due to the ongoing noncompliance of the Houston-Galveston-Brazoria area with the 2008 and 2015 standards, 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 program changes are proposed and finalized.
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. The Regional Haze program includes two major components: demonstration of Reasonable Further Progress, and installation of Best Achievable Retrofit Technology (“BART”). States submit State Implementation Plans (“SIP”) to the EPA for approval. These SIPs delineate all of the relevant emission controls programs in the state, and demonstrate that the state is making reasonable progress toward the Regional Haze program visibility goals. In addition, states must require the installation of a minimum level of controls that are considered cost-effective on coal- and oil-fired power plants within the state. In the eastern U.S., regional NOx and SO2 programs are relied upon in Regional Haze SIPs to achieve much of the required emission reductions, and are also allowed by EPA policy to substitute for the installation of BART. If the EPA does not approve a SIP, it may instead issue a Federal Implementation Plan, which will specify the control requirements for sources in a state.
GHG Emissions
Over the past several years, the EPA has proposed and issued rules related to GHG emissions within the power sector. The current presidential administration, however, has not indicated support for some of these rules, including, most notably, the Clean Power Plan.
The EPA’s regulation of GHG in response to the 2007 decision of the U.S. Supreme Court in Massachusetts v. EPA has been controversial and heavily litigated at every step of the regulatory process. Within the power industry, the EPA first proposed to regulate GHG emissions through the PSD and Title V programs, the two major permitting programs of the CAA.
These permitting rules were the subject of more than 60 petitions for review by industry and the states. The U.S. Supreme Court ultimately heard the case, and on June 23, 2014, rejected the PSD and Title V permitting rules in part 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. Our clean portfolio and additions thereto generally meet the technology that would be required if they triggered PSD permitting requirements. Therefore, we believe we are well-positioned to benefit from this regulatory development.
On October 23, 2015, the EPA finalized the New Source Performance Standard (“NSPS”) for GHG emissions from new, modified and reconstructed power plants and the Clean Power Plan. On June 19, 2019, the EPA issued the Affordable Clean Energy (“ACE”) rule which replaced the Clean Power Plan. The ACE rule regulates GHG emissions from existing coal-fired power plants and establishes a “best system of emission reduction” for reducing carbon emissions. Litigation challenging the ACE rule is ongoing.
State Air Emissions Regulations
In addition to federal GHG rules, several states and regional organizations have developed state-specific or regional initiatives to reduce GHG emissions through mandatory programs. The most advanced programs include California’s suite of GHG policies promulgated pursuant to AB 32, including its Cap-and-Trade program, Massachusetts’ CO2 reduction program and RGGI in the Northeast. The evolution of these programs could have a material effect on our business.
In 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 through bilateral or exchange transactions and pursuant to the terms of PPAs.
California: GHG - Cap-and-Trade Regulation
California’s climate policies and GHG reduction targets are among the most ambitious and aggressive in the world. Assembly Bill (“AB”) 32, as amended by Senate Bill (“SB”) 32 in 2016, requires California to reduce statewide GHG emissions to 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. To meet this mandate, the CARB has promulgated a suite of complementary regulatory measures, including the Cap-and-Trade Regulation and Mandatory Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. AB 398, enacted in 2017, authorized extension of the Cap-and-Trade Regulation through 2030.
AB 398 required several changes in the post-2020 Cap-and-Trade Regulation, including a requirement that CARB impose a price ceiling and two reserve tiers to control the pace of price increases, as well as limitations on the percentage of offset credits that covered entities can surrender to meet their compliance obligation. In subsequently adopting regulatory amendments to implement AB 398’s mandates, the CARB adopted an initial price ceiling value for 2021 at $65, which will increase each year by
five percent plus the rate of inflation. Assuming an annual inflation rate of two percent, the 2030 price ceiling will approach $119, above which an unlimited number of additional metric tons will be available to covered entities if needed for compliance.
In October 2019, the United States sued California in the U.S. Court for the Eastern District of California, alleging that California’s linkage of its Cap-and-Trade program with a cap-and-trade system implemented by the Canadian province of Québec, as well as the California Cap-and-Trade Regulation’s linkage authority and regulations, violate several provisions of the U.S. Constitution relating to foreign affairs. In addition, the Utah Legislature has appropriated funding for the State of Utah to sue California in federal court challenging the California Cap-and-Trade Regulation’s treatment of imported electricity as a violation of the dormant Commerce Clause and an intrusion into FERC’s exclusive jurisdiction over the sale of electricity at wholesale in interstate commerce.
Several of our natural gas-fired power plants in California will likely remain subject to the Cap-and-Trade Regulation through 2030 as a result of passage of AB 398. If the United States’ pending challenge to the Cap-and-Trade Program were to succeed, we do not anticipate it would have any material impact on us. If the State of Utah should file a lawsuit challenging the Cap-and-Trade Regulation’s imported power provisions and, as a consequence, the CARB should be enjoined from further implementation of those provisions, it is possible that the CARB would continue applying the program’s compliance obligation to in-state electricity generation, but not to imported electricity, in which case in-state natural gas-fired power plants could be competitively disadvantaged relative to out-of-state fossil generation.
Northeast GHG Regulation: RGGI
Ten states in the Northeast participate in RGGI, a Cap-and-Trade program, which affects our power plants in Maine, Massachusetts, New Hampshire, New Jersey, New York and Delaware (together emitting about 5.1 million tons of CO2 annually). The governors of Pennsylvania and Virginia are currently taking actions to have their state join RGGI.
We receive annual allocations from New York’s long-term contract set-aside pool to cover some of the CO2 emissions attributable to our PPA at our Stony Brook Power Plant. We do not anticipate any significant business or financial effect from RGGI, given the efficiency of our power plants in RGGI states.
Massachusetts: Global Warming Solutions Act
On December 16, 2016, the Massachusetts Department of Environmental Protection proposed regulations that would impose new GHG limits on power plants and other sources. These regulations are notable because they are structured as annually-declining hard caps on CO2 emissions from regulated facilities. The Massachusetts Department of Environmental Protection issued a final rule on August 11, 2017, which became effective on January 1, 2018. The rule establishes an allowance trading system and auction platform. Although we view the regulations as likely to result in market distortions impeding the efficient operation of both power and emissions markets, we believe that we will be able to comply with its provisions.
Other Environmental Regulations
RPS
We are subject to an RPS in multiple states in which we do business. 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.
California RPS
California’s RPS requires retail power providers to generate or procure 33% and 60% of the power they sell to retail customers from renewable resources by 2020 and 2030, respectively, with intermediate targets leading up to 2020 and 2030. Behind-the-meter solar generally does not count towards California’s RPS requirements. Under California’s RPS, there are limits on different “buckets” of procurement that can be used to satisfy the RPS. Load-serving entities must satisfy a growing fraction of their compliance obligations with renewable power from resources located in California or delivered into California within the hour, such as our Geysers Assets. Beginning in 2021, load-serving entities are required to meet 65% of their compliance obligations with contracts with terms of ten years or longer. The law that increased the 2030 RPS target to 60%, SB 100, also sets a state policy that eligible renewable energy and zero-carbon resources supply 100% of all retail sales of electricity in California by 2045. While this goal is aspirational and the legislation does not establish an enforceable framework or mechanism by which it will be achieved, it will nevertheless guide procurement and planning decisions. In addition, a recently signed executive order articulates a carbon neutrality goal for the entire state, not just the electricity sector, by 2045, which is five years earlier than the existing target of reducing greenhouse gas emissions to 80% below 1990 levels. While the RPS generally depresses wholesale energy prices, the intermittency of many renewable resources raises operational flexibility challenges that present opportunities for natural
gas-fired generation to provide capacity and ancillary services products. Additionally, the RPS could result in the retirement of non-renewable generating units creating opportunities for our fleet.
Other States
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 an enforceable RPS in the future. Our retail subsidiaries operate in states that have an RPS in place and are required to procure a certain amount of power from renewable sources or purchase renewable energy credits in order to comply with the RPS requirements.
Miscellaneous
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
The federal Clean Water Act establishes requirements relating to the discharge of pollutants into waters of the U.S., including from cooling water intake structures. Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse effects on the environment. We are required to obtain wastewater and storm water discharge permits for wastewater and runoff, respectively, for some of our power plants. We are subject to the requirements for cooling water intake structures at many of our power plants. In addition, we are required to maintain spill prevention control and countermeasure plans for some of our power plants. We do not use once-through cooling technology at any of the power plants in our fleet. We believe that our facilities that are subject to the Clean Water Act are in compliance with applicable discharge requirements of the Clean Water Act.
Safe Drinking Water Act
Part C of the Safe Drinking Water Act establishes the underground injection control program that regulates the disposal of wastes by means of deep well injection. Although geothermal production wells, which are wells that bring steam to the surface, are exempt under EPAct 2005, we use geothermal re-injection wells to inject reclaimed wastewater back into the steam reservoir, which are subject to the underground injection control program. We believe that we are in compliance with Part C of the Safe Drinking Water Act.
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 these 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.
EMPLOYEES
At December 31, 2019, we employed 2,256 full-time employees, of whom 179 were represented by collective bargaining agreements. Two collective bargaining agreements, representing a total of 28 employees, will expire within one year. We have never experienced a work stoppage or a strike.
Commercial Operations
Our financial performance is affected by commodity price fluctuations in the wholesale and retail 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. Depending upon price risk management activity undertaken by us, a decline in market prices for power, generation capacity, and ancillary services may adversely affect our financial performance. Long- and short-term power and natural gas prices may also fluctuate substantially due to other factors outside of our control, including:
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increases and decreases in generation capacity in our markets;
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changes in power transmission or fuel transportation capacity constraints or inefficiencies;
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volatile weather conditions, particularly unusually hot or mild summers or unusually cold or warm winters in our market areas;
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an economic downturn which could negatively affect demand for power;
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changes in the supply of commodities utilized as fuel sources for power generation, including but not limited to coal, natural gas and fuel oil;
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technological shifts resulting in changes in the demand for power or in patterns of power usage, including the potential development of demand-side management tools, expansion and technological advancements in power storage capability and the development of new fuels or new technologies for the production or storage of power;
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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;
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changes in prices related to RECs and other environmental allowance products; and
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changes in capacity prices and capacity markets.
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These factors have caused our operating results to fluctuate in the past and will continue to cause them to do so in the future.
Our revenues and results of operations depend on market rules, regulation and other forces beyond our control.
Our revenues and results of operations are influenced by factors that are beyond our control, including:
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rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;
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regulations promulgated by the FERC, the CFTC and state public utility commissions;
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sufficient liquidity in the forward commodity markets to conduct our hedging activities;
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some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may affect our ability to sell our power at economical rates;
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structure and operating characteristics of our capacity markets such as the PJM and ISO-NE capacity auctions and the NYISO and California markets; and
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regulations and market rules related to our RECs.
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Accounting for derivative 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 forward commodity market price risk exposure utilizing both physical and financial commodity purchases and sales commitments. Some of these contracts are accounted for as derivatives under U.S. GAAP, which requires us to record the fair value of the commitment on the balance sheet with changes in the fair value of all derivatives reflected within current period earnings. As current period earnings are impacted by non-cash mark-to-market gains/losses associated with price risk management hedges of future period activity that are accounted for as derivatives, we are unable to accurately predict the effect that our risk management decisions may have on our quarterly and annual financial results prepared in accordance with U.S. GAAP.
The use of hedging agreements may not work as planned or fully protect us and could result in financial losses.
In accordance with internal policies and procedures designed to monitor hedging activities and positions, we 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 or customer fails to perform under a contract, it could harm our financial condition, results of operations and cash flows.
We do not typically hedge the entire exposure of our operations against commodity price volatility. To the extent we do not hedge against commodity price volatility, our financial condition, results of operations and cash flows may be diminished based upon adverse movement in commodity prices.
Our ability to enter into hedging agreements and manage our counterparty and customer credit risk could adversely affect us.
Our wholesale counterparties, retail customers and suppliers 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 affect our business and create more volatility in our earnings. Additionally, these conditions may cause our counterparties or customers 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.
Extensive competition in our wholesale and retail businesses 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.
Additionally, there is extensive competition in the retail power markets in which our retail subsidiaries operate. Competitors may offer lower prices or other incentives which may attract customers away from our retail subsidiaries. We may also face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with our retail subsidiaries.
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 or customer and/or may allow the counterparty or customer to seek liquidated damages.
The situations that could allow a counterparty or customer to terminate the contract and/or seek liquidated damages include:
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the cessation or abandonment of the development, construction, maintenance or operation of a power plant;
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failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;
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failure of a power plant to achieve certain output or efficiency minimums;
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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;
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failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;
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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
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events of liquidation, dissolution, insolvency or bankruptcy.
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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 extend contracts or 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. Without the benefit of long-term PPAs, we may not be able to sell any or all of the capacity from these power plants at commercially attractive rates and these power plants may not be able to operate profitably. Certain of our PPAs have values in excess of current market prices. If a counterparty to a PPA were to seek bankruptcy protection under Chapter 11 or liquidation under Chapter 7 of the U.S. Bankruptcy Code, they may be able to terminate the PPA. 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.
For example, our wholesale business currently has contracts with investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires.
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings. However, should the outcome in the matter be unfavorable, our business may be adversely affected.
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 effect 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 affect 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 which are an inherent risk of our business. Unplanned outages typically can result in lost revenues, inability to perform and potential recognition of liquidated damages owed and/or termination of existing long-term PPAs, 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.
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 including, but not limited to, the risk of events such as wildfires that may affect the ability for our power plants to operate 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 Note 16 of the Notes to Consolidated Financial Statements for a description of our more significant litigation matters.
We rely on power transmission and fuel distribution facilities owned and operated by other companies.
We depend on facilities and assets that we do not own or control for the transmission to our customers of the power produced by our power plants and the distribution of natural gas 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 affect our business.
Our power project development and construction activities involve risk and may not be successful.
We are currently constructing one natural gas-fired power plant and may construct other facilities in the future, including battery storage facilities. The development and construction of power plants is subject to substantial risks. In connection with the development of a power plant, we must generally obtain:
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necessary power generation or storage equipment;
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governmental permits and approvals including environmental permits and approvals;
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fuel supply and transportation agreements;
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sufficient equity capital and debt financing;
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power transmission agreements;
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water supply and wastewater discharge agreements or permits; and
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site agreements and construction contracts.
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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.
Additionally, the PJM and ISO-NE power markets have recently experienced an increase in natural gas-fired generation assets that supply electricity to the area. As a result, there has been a corresponding increase in the need for natural gas transmission assets to supply the generation assets with fuel to generate power. When extreme cold temperatures rapidly increase the demand for natural gas used for residential heating, it can also create constraints on natural gas pipelines that serve power generation assets. When these conditions exist, it could interrupt the fuel supply to our natural gas-fired power plants in these power markets, although some of our natural gas-fired power plants in this region are dual-fuel and benefit from the ability to operate on both natural gas and fuel oil.
While adequate supplies of natural gas and fuel oil are currently available to us at prices we believe are reasonable for each of our power plants, we are exposed to increases in the price of natural gas and fuel oil, and it is possible that sufficient supplies to operate our portfolio profitably may not continue to be available to us. In addition, we face risks with regard to the delivery to and the use of natural gas and fuel oil by our power plants including the following:
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transportation may be unavailable if pipeline infrastructure is damaged or disabled;
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pipeline tariff changes may adversely affect our ability to, or cost to, deliver natural gas and fuel oil supply;
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new pipelines and pipeline expansions may not be permitted in a timely manner due to environmental concerns or prolonged regulatory processes;
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third-party suppliers may default on natural gas supply obligations, and we may be unable to replace supplies currently under contract;
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market liquidity for physical natural gas and fuel oil or availability of natural gas and fuel oil services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;
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natural gas and fuel oil quality variation may adversely affect our power plant operations;
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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;
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fuel supplies diverted to residential heating for humanitarian reasons; and
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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 effect 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:
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the heat content of the extractable steam or fluids;
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the geology of the reservoir;
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the total amount of recoverable reserves;
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operating expenses relating to the extraction of steam or fluids;
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price levels relating to the extraction of steam, fluids or power generated; and
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capital expenditure requirements relating primarily to the drilling of new wells.
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Significant events beyond our control, such as natural disasters, including weather-related events, or acts of terrorism, could damage our power plants or our corporate offices or cause a loss of system load and may affect us in unpredictable ways.
Certain of our geothermal and natural gas-fired power plants, particularly in the West, have been in the past and remain 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, routinely experience tornados and hurricanes. Operations at our corporate offices in Houston, Texas could be substantially affected by a hurricane. Any significant loss of system load resulting from a weather-related event could negatively affect our wholesale business and retail subsidiaries. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our wholesale business and retail subsidiaries are 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, earthquake, property damage or business interruption insurance may be inadequate to cover all potential losses sustained in the event of extensive damages to our power plants or disruptions to our wholesale and retail operations due to natural disasters.
Periodic wildfires in the West, particularly California, could damage our power plants or cause a loss of system load and may affect us in unpredictable ways.
Our geothermal and natural gas-fired power plants in the West have been in the past and remain subject to an ongoing risk of wildfires. Severe drought conditions, unseasonably warm temperatures and stronger winds have increased the severity and prevalence of wildfires in California. Although such wildfires have not resulted in material damages to us in the past, we cannot be certain that any such events would not materially and adversely affect our operations in the future. Such events could damage or shut down our power plants, power transmission or the fuel supply facilities upon which our power plants are dependent or cause serious injuries, fatalities, property damage or service interruptions, which could expose us to liabilities that could be material. Although we believe we maintain adequate insurance protection, property damage liability or business interruption insurance may be inadequate to cover all potential losses sustained in the event of extensive damages to our power plants or disruptions to our operations due to wildfires. The recent wildfires in California may exacerbate these insurance risks by leading to adverse changes in insurance deductibles, premiums, coverage and/or limits. If we incur a substantial liability and the damages are above our estimates for self-insured claims, or such damages are not covered by our insurance policies or are in excess of policy limits, or if we incur liability at a time when we do not have liability insurance, our results of operations and cash flows could be materially and adversely affected.
In addition, electric utilities in California are authorized to shut down power for public safety reasons, such as during periods of extreme fire hazard, if the utility reasonably believes that there is an imminent and significant risk that strong winds may topple power lines or cause vegetation to come into contact with power lines leading to increased risk of fire. Any shut down of power for public safety reasons may reduce our revenues.
Our business, financial condition and results of operations could be adversely affected 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.
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.
Failures in our systems or a cyber attack or breach of our information technology systems or technology could significantly disrupt our business operations or result in sensitive customer information being compromised, which would negatively affect our reputation and/or results of operations.
Our information technology systems contain personal, financial and other information that is entrusted to us by our customers and employees as well as financial, proprietary and other confidential information related to our business, which makes us a target of cyber attacks on our systems. We rely on electronic networks, computers, systems, including our gateways, programs
to run our business and operations, our employees and third party technology and information technology infrastructure providers and, as a result, are potentially exposed to the risk of security breaches, computer or other malware, viruses, social engineering or general hacking, industrial espionage, employee or third party error or malfeasance, or other irregularities or compromises on our systems or those to third parties, which could result in the loss or misappropriation of sensitive data or other disruption to our operations.
We depend on computer and telecommunications systems we do not own or control. We have entered into agreements with third parties for hardware, software, telecommunications and 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 that we, or a third party that we rely on, could incur interruptions from a loss of communications, hardware or software failures, a cyber attack or a breach of our information technology systems or technology, computer viruses or malware. We believe that we have positive relations with our 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 to our information systems or any of those operated by a third party that we rely on could significantly disrupt our business operations.
A cyber attack on our systems or networks that impairs our information technology systems could disrupt our business operations and result in loss of service to customers. We have a comprehensive cybersecurity program designed to protect and preserve the integrity of our information technology systems. We have experienced and expect to continue to experience actual or attempted cyber attacks on our information technology systems or networks; however, none of these actual or attempted cyber attacks has had a material effect on our operations or financial condition. Even when a security breach is detected, the full extent of the breach may not be determined for some time. The risk of a security breach or disruption, particularly through a cyber attack or a cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, has magnified as the number, intensity and sophistication of attempted attacks and intrusions from around the world has increased. An increasing number of companies have disclosed security breaches of their information technology systems and networks, some of which have involved sophisticated and highly targeted attacks. We believe such incidents are likely to continue, and we are unable to predict the direct or indirect effect of any future attacks on our business.
Additionally, our retail subsidiaries require access to sensitive customer information in the ordinary course of business. If a significant data breach occurred, the reputation of our retail subsidiaries may be adversely affected, customer confidence may be diminished, and our retail subsidiaries may become subject to legal claims, any of which may contribute to the loss of customers and have a material adverse effect on our retail subsidiaries.
Capital Resources; Liquidity
We have substantial liquidity needs and could face liquidity pressure.
As of December 31, 2019, our consolidated debt outstanding was $11.7 billion, of which approximately $9.7 billion was outstanding under our Senior Unsecured Notes, First Lien Term Loans and First Lien Notes. In addition, we had $1,085 million issued in letters of credit and our pro rata share of unconsolidated subsidiary debt was approximately $150 million. Although we significantly extended our maturities during the last several 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.
We also have exposure to many different financial institutions and counterparties including those under our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, 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 affect our financial health and limit our operations.
Our indebtedness has important consequences, including:
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limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth or other purposes;
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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;
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increasing our vulnerability to general adverse economic and industry conditions;
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limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in governmental regulation;
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limiting our ability or increasing the costs to refinance indebtedness; and
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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. Other factors include:
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low credit ratings may prevent us from obtaining any material amount of additional debt financing;
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conditions in energy commodity markets;
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regulatory developments;
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credit availability from banks or other lenders for us and our industry peers;
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investor confidence in the industry and in us;
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the continued reliable operation of our current power plants; and
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provisions of tax, regulatory and securities laws that are conducive to raising capital.
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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 Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan 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 Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and other debt instruments could adversely affect us by limiting our ability to plan for or react to market
conditions or to meet our capital needs and, if we were unable to comply with these restrictions, could result in an event of default under these debt instruments. These restrictions require us to meet certain financial performance tests on a quarterly basis and limit or prohibit our ability, subject to certain exceptions to, among other things:
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incur or guarantee additional first lien indebtedness up to certain consolidated net tangible asset ratios;
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enter into certain types of commodity hedge agreements that can be secured by first lien collateral;
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enter into sale and leaseback transactions;
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make certain investments;
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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;
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lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;
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engage in certain business activities; and
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enter into certain transactions with our affiliates.
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Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and our other debt instruments contain events of default customary for financings of their type, including a cross default to debt other than non-recourse project financing debt, a cross-acceleration to non-recourse project financing debt and certain change of control events. If we fail to comply with the covenants and are unable to obtain a waiver or amendment, or a default exists and is continuing under such debt, the lenders or the holders or trustee, 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 Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan 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 affect 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 affect 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 affect our liquidity.
These letter of credit and cash collateral requirements increase our cost of doing business and could have an adverse effect 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, 2019, we had $1,085 million issued in letters of credit under our Corporate Revolving Facility and other facilities, with $1,392 million remaining available for borrowing or for letter of credit support under our Corporate Revolving Facility. In addition, we have ratably secured our obligations under certain of our power and natural gas agreements that qualify as eligible commodity hedge agreements 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.
We may not have sufficient liquidity to hedge market risks effectively.
We are exposed to market risks through our purchase and sale of power, capacity and related products, 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 Term Loans, First Lien Notes 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 Term Loans, First Lien Notes 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, 2019, our subsidiaries had approximately $967 million in debt from our CCFC subsidiary and approximately $1.0 billion in secured project financing from other subsidiaries, which are effectively senior to our First Lien Term Loans, First Lien Notes 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.
Governmental Regulation
Federal tax incentives and regulations, existing and proposed state RPS and energy efficiency standards, as well as economic support for renewable sources of power under federal or state legislation could adversely affect our operations.
Renewables have the ability to take market share from us and to lower overall wholesale power prices which could negatively affect us. In December 2015, the Consolidated Appropriations Act extended the production tax credit for wind through the end of 2016 with gradual decreases thereafter until the tax credit was to expire completely in 2019 and extended the 30% investment tax credit for solar through the end of 2019 with gradual decreases through 2021 after which the investment tax credit declines to 10%. On December 20, 2019, President Trump signed the federal government budget appropriation bill which included a one year extension of the production tax credit for wind, allowing wind facilities that begin construction in 2020 to be eligible for a 60% production tax credit. California has a RPS in effect and recently enacted legislation requiring implementation of a 100% CO2-free electricity requirement by 2045. A number of additional states, including Maine, 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 more robust RPS in states in which we are active, coupled with federal tax incentives, would likely initially drive up the number of wind and solar resources, increasing power supply to various markets which could negatively affect the dispatch of our natural gas-fired power plants, primarily in Texas and California.
Similarly, several states 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 affect the dispatch of our natural gas-fired power plants.
Increased oversight and investigation by the CFTC relating to derivative transactions, as well as certain financial institutions, could have an adverse effect 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 affect us.
We have a significant presence in the major competitive power markets of California, Texas and the Northeast and Mid-Atlantic regions 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 affected.
Additionally, state PUCs have the ability to set policies that either enhance or limit customer choice. Each state that has adopted retail electric choice creates its own laws, regulations and compliance requirements which evolve over time and could impact our ability to maintain or expand retail operations and negatively affect our retail business.
State legislative and regulatory action could adversely affect our competitive position and business.
Certain states have taken or are considering taking anticompetitive actions by subsidizing or otherwise providing economic support to existing, uneconomic power plants in a manner that could have an adverse effect on the deregulated power markets. In addition, certain states in which we have retail operations are taking actions which we believe limit customer choice as well as other actions that we believe are anticompetitive and could negatively affect our retail operations. We are actively participating in many of the legislative, regulatory and judicial processes challenging these actions at the state and federal levels. If these anticompetitive actions are ultimately upheld and implemented, they could adversely affect capacity and energy prices in the deregulated electricity markets or impede our ability to maintain or expand our retail operations which in turn could have a material adverse effect on our business prospects and financial results.
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 a potential that carbon taxes or limits on carbon, CO2 and other GHG emissions could be implemented at the federal or expanded at the state or regional levels. We continue to monitor and actively participate in initiatives where we anticipate a material effect on our business.
Currently, ten states in the Northeast are required to comply with 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, the 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 including transportation fuels and natural gas distribution. The Massachusetts Department of Environmental Protection issued a final rule in August 2017 that imposes new GHG limits on power plants and other sources.
Environmental regulations could also affect the availability and price of natural gas used in our generation facilities. Permitting of new natural gas transportation pipelines has become more difficult in some regions such as the Northeast, and restrictions on natural gas production have been implemented or proposed in some locations.
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 the 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 effect 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 common ownership by certain significant investors, 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 ownership 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 owners 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 the FERC makes the determination that we have market power, the 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 affect 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 effect on our financial condition, results of operations and cash flows.
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Item 1B.
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Unresolved Staff Comments
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None.
Our principal offices are located in Houston, Texas with the principal offices of our retail affiliates located in Houston, Texas and San Diego, California.
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.”
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Item 3.
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Legal Proceedings
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See Note 16 of the Notes to Consolidated Financial Statements for a description of our legal proceedings.
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Item 4.
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Mine Safety Disclosures
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Not applicable.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Years Ended December 31, 2019, 2018 and 2017
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1.
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Organization and Operations
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We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power and related products for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
Merger
On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) ceased to be outstanding and was converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. See Note 13 for a discussion of the treatment of the outstanding share-based awards to employees at the effective time of the Merger.
For the years ended December 31, 2019, 2018 and 2017, we recorded approximately nil, $33 million and $15 million, respectively, in Merger-related costs which was recorded in other operating expenses on our Consolidated Statements of Operations and primarily related to legal, investment banking and other professional fees associated with the Merger. We elected not to apply pushdown accounting in connection with the consummation of the Merger. As a result, our assets and liabilities are recorded at historical cost and do not reflect the fair value ascribed in the Merger.
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2.
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Summary of Significant Accounting Policies
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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 Calpine Receivables, a 100% membership 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 or limited liability company operating agreement. See Note 7 for further discussion of our VIEs and unconsolidated investments.
Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect 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:
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As of December 31, 2019
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Ownership Interest
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|
Property, Plant & Equipment
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Accumulated Depreciation
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|
Construction in Progress
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(in millions, except percentages)
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Freestone Energy Center
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|
75.0
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%
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$
|
379
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|
|
$
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(177
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)
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|
$
|
—
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|
Hidalgo Energy Center
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|
78.5
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%
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|
$
|
250
|
|
|
$
|
(113
|
)
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|
$
|
—
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|
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
See Note 8 for disclosures regarding the fair value of our debt instruments and Note 9 for disclosures regarding the fair values of our derivative instruments and related margin deposits and certain of our cash balances.
Concentrations of Credit Risk
Financial instruments that potentially subject us to credit risk consist of cash and cash equivalents, restricted cash, accounts and notes receivable and derivative 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 and customers, 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 and customers, 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 and customers primarily consist of four categories of entities who participate in the energy markets:
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•
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financial institutions and trading companies;
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•
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regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers;
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|
|
•
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oil, natural gas, chemical and other energy-related industrial companies; and
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|
|
•
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commercial, industrial and residential retail customers.
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We have concentrations of credit risk with a few of our wholesale counterparties and retail customers relating to our sales of power and steam and our hedging, optimization and trading activities. For example, our wholesale business currently has contracts with investor owned California utilities which could be affected should they be found liable for recent wildfires in California and, accordingly, incur substantial costs associated with the wildfires.
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. We currently have several power plants that provide energy and energy-related products to PG&E under PPAs, many of which have PG&E collateral posting requirements. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. We also currently have numerous other agreements with PG&E related to the operation of our power plants in Northern California, under which PG&E has continued to provide service since its bankruptcy filing. We cannot predict the ultimate outcome of this matter and continue to monitor the bankruptcy proceedings.
We have exposure to trends within the energy industry, including declines in the creditworthiness of our counterparties and customers for our commodity and derivative transactions. Currently, certain of our counterparties and customers within the energy industry have below investment grade credit ratings. Our risk control group manages counterparty and customer credit risk and monitors our net exposure with each counterparty or customer on a daily basis. The analysis is performed on a mark-to-market basis using forward curves. The net exposure is compared against a credit risk threshold which is determined based on each counterparties’ and customer’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 or customer. We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk. Currently, our wholesale counterparties and retail customers are performing and financially settling timely according to their respective agreements with the exception of certain retail customers where our credit exposure is not material.
Cash and Cash Equivalents
We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash
Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Balance Sheets.
The table below represents the components of our restricted cash as of December 31, 2019 and 2018 (in millions):
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|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Current
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|
Non-Current
|
|
Total
|
|
Current
|
|
Non-Current
|
|
Total
|
Debt service
|
$
|
58
|
|
|
$
|
8
|
|
|
$
|
66
|
|
|
$
|
13
|
|
|
$
|
8
|
|
|
$
|
21
|
|
Construction/major maintenance
|
28
|
|
|
6
|
|
|
34
|
|
|
23
|
|
|
24
|
|
|
47
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|
Security/project/insurance
|
209
|
|
|
31
|
|
|
240
|
|
|
120
|
|
|
—
|
|
|
120
|
|
Other
|
4
|
|
|
1
|
|
|
5
|
|
|
11
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|
|
2
|
|
|
13
|
|
Total
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$
|
299
|
|
|
$
|
46
|
|
|
$
|
345
|
|
|
$
|
167
|
|
|
$
|
34
|
|
|
$
|
201
|
|
Business Interruption Proceeds
We record business interruption insurance proceeds when they are realizable and recorded approximately $11 million, $14 million and $27 million of business interruption proceeds in operating revenues for the years ended December 31, 2019, 2018, and 2017, respectively.
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 reviewed for collectability, depending upon the nature of the customer, 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.
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 net realizable value under the weighted average cost method. Spare parts inventory is valued at weighted average cost and is expensed to operating and maintenance 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 and customers 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. Certain of our interest rate hedging instruments relate to hedges of certain of our project financings collateralized by first priority liens on the underlying assets. See Note 11 for a further discussion on our amounts and use of collateral.
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 a de minimis amount of the depreciable costs basis for componentized 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, certain componentized balance of plant parts and our information technology equipment and the composite depreciation method for 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 any gain or loss is recorded as operating and maintenance expense.
Goodwill and Intangible Assets
Goodwill represents the excess of the purchase price over the fair value of the net assets acquired at the time of an acquisition. We assess the carrying amount of our goodwill annually for impairment during the third quarter and whenever the events or changes in circumstances indicate that the carrying value may not be recoverable.
Our goodwill resulted from the acquisition of our retail business. As such, our goodwill balance of $242 million was allocated to our Retail segment. We did not record any changes in the carrying amount of our goodwill during the years ended December 31, 2019 and 2018.
We record intangible assets, such as acquired contracts, customer relationships and trademark and trade name at their estimated fair values at acquisition. We use all information available to estimate fair values including quoted market prices, if available, and other widely accepted valuation techniques. Certain estimates and judgments are required in the application of the techniques used to measure fair value of our intangible assets, including estimates of future cash flows, selling prices, replacement costs, economic lives and the selection of a discount rate, which are not observable in the market and represent a level 3 measurement. All recognized intangible assets consist of rights and obligations with finite lives.
As of December 31, 2019 and 2018, the components of our intangible assets were as follows (in millions):
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|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Lives
|
Acquired contracts
|
$
|
444
|
|
|
$
|
458
|
|
|
0 – 9 Years
|
Customer relationships
|
445
|
|
|
445
|
|
|
7 – 14 Years
|
Trademark and trade name
|
40
|
|
|
40
|
|
|
15 Years
|
Other
|
4
|
|
|
88
|
|
|
39 – 44 Years
|
|
933
|
|
|
1,031
|
|
|
|
Less: Accumulated amortization
|
593
|
|
|
619
|
|
|
|
Intangible assets, net
|
$
|
340
|
|
|
$
|
412
|
|
|
|
Amortization expense related to our intangible assets for the years ended December 31, 2019, 2018 and 2017 was $72 million, $100 million and $175 million, respectively.
The estimated aggregate amortization expense of our intangible assets for the next five years is as follows (in millions):
|
|
|
|
|
2020
|
$
|
44
|
|
2021
|
$
|
39
|
|
2022
|
$
|
36
|
|
2023
|
$
|
28
|
|
2024
|
$
|
28
|
|
Impairment Evaluation of Long-Lived Assets (Including Goodwill, Intangibles and Investments)
We evaluate our long-lived assets, such as property, plant and equipment, equity method investments and definite-lived intangible assets for impairment, when events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. Equipment assigned to each power plant is not evaluated for impairment separately; instead, we evaluate our operating power plants and related equipment as a whole unit. When we believe an impairment condition may have occurred, we are required to estimate the undiscounted future cash flows associated with a long-lived asset or group of long-lived assets at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities for long-lived assets that are expected to be held and used. We use a fundamental long-term view of the power market which is based on long-term production volumes, price curves and operating costs together with the regulatory and environmental requirements within each individual market to prepare our multi-year forecast. Since we manage and market our power sales as a portfolio rather than at the individual power plant level or customer level within each designated market, pool or segment, we group our power plants based upon the corresponding market for valuation purposes. If we determine that the undiscounted cash flows from an asset or group of assets to be held and used are less than the associated carrying amount, or if we have classified an asset as held for sale, we must estimate fair value to determine the amount of any impairment loss.
We test goodwill and all intangible assets not subject to amortization for impairments at least annually, or more frequently whenever an event or change in circumstances occurs that would more likely than not reduce the fair value of a reporting unit below its carrying amount. We test goodwill for impairment at the reporting unit level, which is identified one level below the Company’s operating segments for which discrete financial information is available and management regularly reviews the operating results. We perform an annual impairment assessment in the third quarter of each year, or more frequently if indicators of potential impairment exist, to determine whether it is more likely than not that the fair value of a reporting unit in which goodwill resides is less than its carrying value. For reporting units in which this assessment concludes that it is more likely than not that
the fair value is more than its carrying value, goodwill is not considered impaired and we are not required to perform the goodwill impairment test. Qualitative factors considered in this assessment include industry and market considerations, overall financial performance, and other relevant events and factors affecting the reporting unit.
For reporting units in which the impairment assessment concludes that it is more likely than not that the fair value is less than its carrying value, we perform the goodwill impairment test, which compares the fair value of the reporting unit to its carrying value. If the fair value of the reporting unit exceeds the carrying value of the net assets assigned to that unit, goodwill is not considered impaired and we are not required to perform additional analysis. If the carrying value of the net assets assigned to the reporting unit exceeds the fair value of the reporting unit, then we record an impairment loss equal to the difference not to exceed the goodwill balance assigned to the reporting unit. We did not record an impairment of our goodwill during the years ended December 31, 2019, 2018 and 2017.
All construction and development projects are reviewed for impairment whenever there is an indication of potential reduction in fair value. If it is determined that a construction or development project is no longer probable of completion and the capitalized costs will not be recovered through future operations, the carrying value of the project will be written down to its fair value.
In order to estimate future cash flows, we consider historical cash flows, existing contracts, capacity prices and PPAs, changes in the market environment and other factors that may affect future cash flows. To the extent applicable, the assumptions we use are consistent with forecasts that we are otherwise required to make (for example, in preparing our earnings forecasts). The use of this method involves inherent uncertainty. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material.
When we determine that our assets meet the assets held-for-sale criteria, they are reported at the lower of their carrying amount or fair value less the cost to sell. We are also required to evaluate our equity method investments to determine whether or not they are impaired when the value is considered an “other than a temporary” decline in value.
Generally, fair value will be determined using valuation techniques such as the present value of expected future cash flows. We will also discount the estimated future cash flows associated with the asset using a single interest rate representative of the risk involved with such an investment including contract terms, tenor and credit risk of counterparties. We may also consider prices of similar assets, consult with brokers, or employ other valuation techniques. We use our best estimates in making these evaluations and consider various factors, including forward price curves for power and fuel costs and forecasted operating costs. However, actual future market prices and project costs could vary from the assumptions used in our estimates, and the effect of such variations could be material.
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through application of collateral. As of December 31, 2019, our Consolidated Balance Sheet included net long-lived assets at Russell City Energy Center and Los Esteros Critical Energy Facility of approximately $647 million and $427 million, respectively, and non-recourse project finance debt at Russell City Energy Center and Los Esteros Critical Energy Facility of approximately $272 million and $135 million, respectively. We cannot predict whether the PPAs will be assumed through the bankruptcy proceeding, however, we believe that even if the contracts were not to be assumed, the undiscounted future cash flows of the power plants would exceed the carrying values of each of the facilities. We continue to monitor the bankruptcy proceedings for any changes in circumstances that would impact the carrying value of either power plant.
We recorded impairment losses of $84 million during the year ended December 31, 2019 related to the sale of our Garrison and RockGen Energy Centers in our East segment, spare turbine equipment in our Texas segment and certain capitalized costs related to wind development projects in our Texas and East segments. We recorded impairment losses of $10 million during the year ended December 31, 2018 related to scrapped power plant equipment in our East segment. We recorded impairment losses of $41 million during the year ended December 31, 2017 related to our South Point Energy Center in our West segment and spare turbine equipment in our Texas segment.
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, 2019 and 2018, our asset retirement obligation liabilities were $68 million and $63 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.
Debt Issuance 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, debt issuance costs are accounted for depending on whether the transaction qualifies as an extinguishment or modification, which requires us to either write-off the original debt issuance costs and capitalize the new issuance costs, or continue to amortize the original debt issuance costs and immediately expense the new issuance costs. Our debt issuance costs related to a recognized debt liability are presented as a direct deduction from the carrying amount of the related debt liability, which is consistent with the presentation of debt discounts.
Revenue Recognition
Our operating revenues are comprised of the following:
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•
|
power and steam revenue consisting of variable payments related to generation, retail power and gas sales activities, power revenues consisting of fixed and variable capacity payments not related to generation including capacity payments received from RTO and ISO capacity auctions, host steam, REC revenue 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
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|
|
•
|
sales of natural gas and other service revenues.
|
See Note 3 for further information related to our accounting for revenue from contracts with customers.
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.
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.
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 hedging 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 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 may not be available from sources external to us, in which case we rely on internally developed price estimates. See Note 10 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, the cost of power purchased from third parties for sale to retail customers, 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 and power 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 commodity purchase and sales 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 and certain power-based commodity derivative instruments are reflected on a net basis as a separate component of fuel and purchased energy expense.
Operating and Maintenance Expense
Operating and maintenance 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 to 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 12 for a further discussion on our income taxes.
New Accounting Standards and Disclosure Requirements
Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Statement of Operations or Consolidated Statement of Cash Flows for the year ended December 31, 2019. See Note 4 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows.
Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Income Taxes — In December 2019, the FASB issued Accounting Standards Update 2019-12, “Simplifying the Accounting for Income Taxes.” The standard is intended to simplify the accounting for income taxes by removing certain exceptions and improve consistent application by clarifying guidance related to the accounting for income taxes. The standard is effective for fiscal years beginning after December 15, 2020. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
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|
3.
|
Revenue from Contracts with Customers
|
Disaggregation of Revenues with Customers
The following tables represent a disaggregation of our revenue for the years ended December 31, 2019 and 2018 by reportable segment (in millions). See Note 18 for a description of our segments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2019
|
|
Wholesale
|
|
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Third Party:
|
|
|
|
|
|
|
|
|
|
|
|
Energy & other products
|
$
|
948
|
|
|
$
|
1,406
|
|
|
$
|
609
|
|
|
$
|
1,694
|
|
|
$
|
—
|
|
|
$
|
4,657
|
|
Capacity
|
173
|
|
|
125
|
|
|
547
|
|
|
—
|
|
|
—
|
|
|
845
|
|
Revenues relating to physical or executory contracts – third party
|
$
|
1,121
|
|
|
$
|
1,531
|
|
|
$
|
1,156
|
|
|
$
|
1,694
|
|
|
$
|
—
|
|
|
$
|
5,502
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate(1):
|
$
|
44
|
|
|
$
|
55
|
|
|
$
|
99
|
|
|
$
|
9
|
|
|
$
|
(207
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues relating to leases and derivative instruments(2)
|
|
|
|
|
|
|
|
|
|
|
$
|
4,570
|
|
Total operating revenues
|
|
|
|
|
|
|
|
|
|
|
$
|
10,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Wholesale
|
|
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Third Party:
|
|
|
|
|
|
|
|
|
|
|
|
Energy & other products
|
$
|
1,070
|
|
|
$
|
1,500
|
|
|
$
|
621
|
|
|
$
|
1,857
|
|
|
$
|
—
|
|
|
$
|
5,048
|
|
Capacity
|
152
|
|
|
94
|
|
|
657
|
|
|
—
|
|
|
—
|
|
|
903
|
|
Revenues relating to physical or executory contracts – third party
|
$
|
1,222
|
|
|
$
|
1,594
|
|
|
$
|
1,278
|
|
|
$
|
1,857
|
|
|
$
|
—
|
|
|
$
|
5,951
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Affiliate(1):
|
$
|
30
|
|
|
$
|
34
|
|
|
$
|
89
|
|
|
$
|
4
|
|
|
$
|
(157
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues relating to leases and derivative instruments(2)
|
|
|
|
|
|
|
|
|
|
|
$
|
3,561
|
|
Total operating revenues
|
|
|
|
|
|
|
|
|
|
|
$
|
9,512
|
|
___________
|
|
(1)
|
Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
|
|
|
(2)
|
Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Statements of Operations.
|
For contracts that do not meet the requirements of a lease and either do not meet the definition of a derivative instrument or are exempt from derivative accounting, we have applied the new revenue recognition standard beginning in the first quarter of 2018. Under the new standard, the majority of our operating revenue continues to be recognized as the underlying commodity or service is delivered to our customers.
Energy and Other Products
Variable payments for power and steam that are based on generation, including retail sales of power, are recognized over time as the underlying commodity is generated or purchased and control is transferred to our customer upon transmission and delivery. Ancillary service revenues are also included within energy-related revenues and are recognized over time as the service is provided.
For our power, steam and ancillary service contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time based on the quantity of the commodity delivered to the customer for power and steam sales and over time as the service is provided for our ancillary service sales.
Energy and other revenues also includes revenues generated from the sale of natural gas and environmental products, including RECs and are recognized at either a point in time or over time when control of the commodity has transferred. Revenues from the sale of RECs are primarily related to credits that are generated upon generation of renewable power from our Geysers Assets and are recognized over a period of time similar to the timing of the related energy sale. Revenues from sales of RECs or other environmental products that are not generated from our assets are recognized once all certifications have been completed and the credits are delivered to the customer at a point in time. Revenues from our natural gas sales are recognized at a point in time when delivery of the natural gas is provided. Revenues from natural gas and emission product sales are generally at the contracted transaction price, which may be fixed or index-based.
Capacity
Capacity revenues include fixed and variable capacity payments, which are based on generation volumes and include capacity payments received from RTO and ISO capacity auctions as well as contractual capacity under long-term PPAs. For these contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time as the service is being provided to the customer.
Performance Obligations and Contract Balances
Certain of our contracts have multiple performance obligations. The revenues associated with each individual performance obligation is based on the relative stand-alone sales price of each good or service or, when not available, is based on a cost incurred plus margin approach. For a significant portion of our contracts with multiple performance obligations, management has applied the practical expedient that results in recognition of revenue commensurate with the invoiced amount and no allocation is required as all performance obligations are transferred over the same period of time.
Certain of our contracts include volumetric optionality based on our customer’s needs. The transaction price within these contracts are based on a stand-alone sale price of the good or service being provided and revenue is recognized based on our customer’s usage. On a monthly basis, revenue is recognized based on estimated or actual usage by our customer at the transaction price. To the extent estimated usage is used in the recognition of revenue, revenues are adjusted for actual usage once known; however, this adjustment is not material to the revenues recognized. Generally, we have applied the practical expedient that allows us to recognize revenue based on the invoiced amount for these contracts.
Changes in estimates for our contracts are not material and revisions to estimates are recognized when the amounts can be reasonably estimated. Unbilled retail sales are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed. During the years ended December 31, 2019 and 2018, there were no significant changes to revenue amounts recognized in prior periods as a result of a change in estimates. Sales and other taxes we collect concurrent with revenue-producing activities are excluded from our operating revenues.
Billing requirements for our wholesale customers generally result in billing customers on a monthly basis in the month following the delivery of the good or service. Once billed, payment is generally required within 20 days resulting in payment for the delivery of the good or service in the month following delivery of the good or service. Billing requirements for our retail customers are generally once every 30 days and may result in billed amounts relating to our retail customers extending up to 60 days. Based on the terms of our agreements, payment is generally received at or shortly after delivery of the good or service.
Changes in accounts receivable relating to our customers is primarily due to the timing difference between payment and when the good or service is provided. During the years ended December 31, 2019 and 2018, there were no significant changes in accounts receivable other than normal billing and collection transactions and there were no material credit or impairment losses recognized relating to accounts receivable balances associated with contracts with customers.
When we receive consideration from a customer prior to transferring goods or services to the customer under the terms of a contract, we record deferred revenue, which represents a contract liability. Such deferred revenue typically results from consideration received prior to the transfer of goods and services relating to our capacity contracts and the sale of RECs that are not generated from our power plants. Based on the nature of these contracts and the timing between when consideration is received and delivery of the good or service is provided, these contracts do not contain any material financing elements.
At December 31, 2019 and 2018, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Balance Sheets and primarily relate to sales of environmental products and capacity. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balance outstanding at December 31, 2019 and 2018, was $14 million and $14 million, respectively. The revenue recognized during the years ended December 31, 2019 and 2018, relating to the deferred revenue balance at the beginning of the period was $14 million and $15 million and resulted from our performance under the customer contracts. The change in the deferred revenue balance during the years ended December 31, 2019 and 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.
Contract Costs
For certain retail contracts, we incur third party incremental broker costs that are capitalized on our Consolidated Balance Sheets. Capitalized contract costs are amortized on a straight line basis over the term of the underlying sales contract to the extent the term extends beyond one year. Contract costs associated with sales contracts that are less than one year are expensed as incurred under a practical expedient.
At December 31, 2019 and 2018, the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the years ended December 31, 2019 and 2018 and amortization of contract costs during the years ended December 31, 2019 and 2018 was immaterial.
Performance Obligations not yet Satisfied
As of December 31, 2019, we have entered into certain contracts for fixed and determinable amounts with customers under which we have not yet completed our performance obligations which primarily includes agreements for which we are providing capacity from our generating facilities. We have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $639 million, $633 million, $408 million, $141 million and $49 million that will be recognized during the years ending December 31, 2020, 2021, 2022, 2023 and 2024, respectively, and $63 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.
Accounting for Leases – Lessee
We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term.
We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees.
Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as an operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees.
We have entered into finance leases for certain power plants and related equipment with terms that range up to 30 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property.
In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including:
|
|
•
|
we elected not to separate lease and non-lease components for our current classes of underlying leased assets as the lessee;
|
|
|
•
|
we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and
|
|
|
•
|
we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019.
|
Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases.
The components of our operating and finance lease expense are as follows for the year ended December 31, 2019 (in millions):
|
|
|
|
|
|
December 31, 2019
|
Operating Leases
|
|
Operating lease expense
|
$
|
46
|
|
|
|
Finance Leases
|
|
Amortization of the right-of-use assets
|
8
|
|
Interest expense
|
8
|
|
Finance lease expense
|
$
|
16
|
|
|
|
Variable lease expense
|
9
|
|
|
|
Total lease expense
|
$
|
71
|
|
The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of December 31, 2019 (in millions):
|
|
|
|
|
|
|
|
|
|
Operating Leases(1)
|
|
Finance Leases(2)
|
2020
|
$
|
21
|
|
|
$
|
16
|
|
2021
|
22
|
|
|
16
|
|
2022
|
20
|
|
|
15
|
|
2023
|
19
|
|
|
19
|
|
2024
|
18
|
|
|
8
|
|
Thereafter
|
185
|
|
|
26
|
|
Total minimum lease payments
|
285
|
|
|
100
|
|
Less: Amount representing interest
|
103
|
|
|
27
|
|
Total lease obligation
|
182
|
|
|
73
|
|
Less: current lease obligation
|
12
|
|
|
10
|
|
Long-term lease obligation
|
$
|
170
|
|
|
$
|
63
|
|
____________
|
|
(1)
|
The lease liabilities associated with our operating leases as of December 31, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Balance Sheet.
|
|
|
(2)
|
The lease liabilities associated with our finance leases as of December 31, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Balance Sheet.
|
Supplemental balance sheet information related to our operating and finance leases is as follows as of December 31, 2019 (in millions, except lease term and discount rate):
|
|
|
|
|
|
|
|
December 31, 2019
|
Operating leases(1)
|
|
|
Right-of-use assets associated with operating leases
|
|
$
|
171
|
|
|
|
|
Finance leases(2)
|
|
|
Property, plant and equipment, gross
|
|
212
|
|
Accumulated amortization
|
|
(105
|
)
|
Property, plant and equipment, net
|
|
$
|
107
|
|
|
|
|
Weighted average remaining lease term (in years)
|
|
|
Operating leases
|
|
17.5
|
|
Finance leases
|
|
6.8
|
|
|
|
|
Weighted average discount rate
|
|
|
Operating leases
|
|
5.1
|
%
|
Finance leases
|
|
8.0
|
%
|
____________
|
|
(1)
|
The right-of-use assets associated with our operating leases as of December 31, 2019 are included in other assets on our Consolidated Balance Sheet.
|
|
|
(2)
|
The right-of-use assets associated with our finance leases as of December 31, 2019 are included in property, plant and equipment, net on our Consolidated Balance Sheet.
|
Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions):
|
|
|
|
|
|
|
|
December 31, 2019
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
Operating cash flows from operating leases
|
|
$
|
54
|
|
Operating cash flows from finance leases
|
|
$
|
8
|
|
Financing cash flows from finance leases
|
|
$
|
11
|
|
|
|
|
Right-of-use assets obtained in exchange for lease obligations:
|
|
|
Operating leases
|
|
$
|
14
|
|
Finance leases
|
|
$
|
—
|
|
Accounting for Leases – Lessor
We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019.
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. Our operating leases that have commenced contain terms extending through May 2042. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements.
Revenue recognized related to fixed lease payments on our operating leases for the period presented is as follows (in millions):
|
|
|
|
|
|
2019
|
Operating Leases(1)
|
|
Fixed lease payments
|
$
|
341
|
|
____________
|
|
(1)
|
Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Statement of Operations.
|
The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at December 31, 2019, are as follows (in millions):
|
|
|
|
|
2020
|
$
|
286
|
|
2021
|
261
|
|
2022
|
226
|
|
2023
|
144
|
|
2024
|
50
|
|
Thereafter
|
236
|
|
Total
|
$
|
1,203
|
|
We do not recognize lease receivables associated with our operating leases as the long-lived assets subject to the lease contracts are recorded on our Consolidated Balance Sheet and are being depreciated over their estimated useful lives. Amounts recorded on our Consolidated Balance Sheet associated with the long-lived assets subject to our operating leases as of December 31, 2019 are as follows (in millions):
|
|
|
|
|
|
December 31, 2019
|
Assets subject to contracts accounted for as operating leases
|
|
Property, plant and equipment, gross
|
$
|
2,561
|
|
Accumulated depreciation
|
(770
|
)
|
Property, plant and equipment, net(1)
|
$
|
1,791
|
|
____________
|
|
(1)
|
Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts.
|
We also record lease levelization assets and liabilities for any difference between the timing of the contractual payments made related to our operating lease contracts and revenue recognized on a straight-line basis. These balances are included in current and long-term assets and liabilities on our Consolidated Balance Sheet.
Disclosures for periods prior to the adoption of Topic 842
Lessee
The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
Operating Leases(1)
|
|
Capital Leases(2)
|
2019
|
$
|
50
|
|
|
$
|
40
|
|
2020
|
19
|
|
|
40
|
|
2021
|
20
|
|
|
38
|
|
2022
|
18
|
|
|
33
|
|
2023
|
17
|
|
|
27
|
|
Thereafter
|
192
|
|
|
92
|
|
Total minimum lease payments
|
$
|
316
|
|
|
270
|
|
Less: Amount representing interest
|
|
|
89
|
|
Present value of net minimum lease payments
|
|
|
$
|
181
|
|
____________
|
|
(1)
|
During the years ended December 31, 2018 and 2017, expense for operating leases amounted to $53 million and $50 million, respectively.
|
|
|
(2)
|
Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.
|
At December 31, 2018, the asset balance for our assets under capital leases totaled approximately $715 million with accumulated amortization of $353 million. Amortization of assets under capital leases is recorded in depreciation and amortization expense on our Consolidated Statements of Operations.
Lessor
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions):
|
|
|
|
|
2019
|
$
|
342
|
|
2020
|
261
|
|
2021
|
257
|
|
2022
|
224
|
|
2023
|
141
|
|
Thereafter
|
239
|
|
Total
|
$
|
1,464
|
|
|
|
5.
|
Acquisitions and Divestitures
|
Acquisition of North American Power
On January 17, 2017, we, through an indirect, wholly-owned subsidiary, completed the purchase of 100% of the outstanding limited liability company membership interests in North American Power for approximately $105 million, excluding working capital and other adjustments. North American Power is a retail energy supplier for homes and small businesses and is primarily concentrated in the Northeast U.S. where Calpine has a substantial power generation presence and where Champion Energy has a substantial retail sales footprint that is enhanced by the addition of North American Power, which has been integrated into our Champion Energy retail platform. We funded the acquisition with cash on hand and the purchase price is allocated to the net assets of the business including intangible assets for the value of customer relationships and goodwill. The goodwill recorded associated with our acquisition of North American Power is deductible for tax purposes. The purchase price allocation was finalized during the fourth quarter of 2017 which did not result in any material adjustments. The pro forma incremental effect of North American Power on our results of operations for the year ended December 31, 2017 is not material.
Sale of Garrison Energy Center and RockGen Energy Center
On July 10, 2019, we, through our indirect, wholly owned subsidiaries Calpine Holdings, LLC and Calpine Northbrook Project Holdings, LLC, completed the sale of 100% of our ownership interests in Garrison Energy Center LLC (“Garrison”) and RockGen Energy LLC (“RockGen”) to Cobalt Power, L.L.C. for approximately $360 million, subject to certain immaterial working capital adjustments and the execution of financial commodity contracts. Upon closing, we recognized a liability of $52 million for the fair value of the financial commodity contracts on our Consolidated Balance Sheet, and the related proceeds are reflected within the financing section on our Consolidated Statement of Cash Flows. Garrison owns the Garrison Energy Center, a 309 MW natural gas-fired, combined-cycle power plant located in Dover, Delaware, and RockGen owns the RockGen Energy Center, a 503 MW natural gas-fired, simple-cycle power plant located in Christiana, Wisconsin. We used the sale proceeds, together with cash on hand, to fund a dividend of $400 million to our parent, CPN Management.
We recorded an immaterial gain on the sale during the third quarter of 2019 and an impairment loss of $55 million for the year ended December 31, 2019, to adjust the carrying value of the assets to reflect fair value less cost to sell.
Sale of Osprey Energy Center
On January 3, 2017, we completed the sale of our Osprey Energy Center to Duke Energy Florida, Inc. for approximately $166 million, excluding working capital and other adjustments. This transaction supports our effort to divest non-core assets outside our strategic concentration. We recorded a gain on sale of assets, net of approximately $27 million during the year ended December 31, 2017 associated with the sale of the Osprey Energy Center.
|
|
6.
|
Property, Plant and Equipment, Net
|
As of December 31, 2019 and 2018, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Depreciable Lives
|
Buildings, machinery and equipment
|
$
|
16,510
|
|
|
$
|
16,400
|
|
|
1.5 – 50 Years
|
Geothermal properties
|
1,553
|
|
|
1,501
|
|
|
13 – 58 Years
|
Other
|
291
|
|
|
286
|
|
|
3 – 50 Years
|
|
18,354
|
|
|
18,187
|
|
|
|
Less: Accumulated depreciation
|
6,851
|
|
|
6,832
|
|
|
|
|
11,503
|
|
|
11,355
|
|
|
|
Land
|
128
|
|
|
121
|
|
|
|
Construction in progress
|
332
|
|
|
966
|
|
|
|
Property, plant and equipment, net
|
$
|
11,963
|
|
|
$
|
12,442
|
|
|
|
Total depreciation expense, including amortization of finance lease assets, recorded for the years ended December 31, 2019, 2018 and 2017, was $627 million, $684 million and $638 million, respectively.
We have various debt instruments that are collateralized by our property, plant and equipment. See Note 8 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 finance leases. See Note 4 for further information regarding these assets under finance leases.
Geothermal Properties
This component primarily includes power plants and related equipment associated with our Geysers Assets.
Other
This component primarily includes software and hardware as well as emission reduction credits that are power plant specific and not available to be sold.
Capitalized Interest
The total amount of interest capitalized was $12 million, $29 million and $26 million for the years ended December 31, 2019, 2018 and 2017, respectively.
|
|
7.
|
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, 2019. 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. See Note 8 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 had a ten-year tolling agreement with SDG&E which commenced on October 3, 2009 and expired on October 2, 2019. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E. The RA contract received initial regulatory approval by the CPUC on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC. Accordingly, on March 28, 2019, we provided notice of our exercise of the put option, which we subsequently rescinded by agreement following the CPUC’s denial of all appeals of the new RA contract on August 1, 2019. On October 3, 2019, the RA contract with SDG&E commenced. As a result, we retained the 608 MW Otay Mesa Energy Center, which plays an integral role in electric reliability in Southern California.
As the call and put options have terminated and the project debt has been fully repaid, we determined that OMEC no longer meets the definition of a VIE during the third quarter of 2019.
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 affect 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 almost 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 effect 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 for most of 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 as contractual changes where 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 affect the VIE’s economic performance or when there are other changes in the powers held by individual variable interest holders.
|
Noncontrolling Interest — At December 31, 2019, we owned a 75% interest in Russell City Energy Company, LLC, one of our VIEs, which was also 25% owned by a third party. On January 28, 2020, we completed the acquisition of the 25% noncontrolling interest of Russell City Energy Company, LLC for approximately $49 million. For the year ended December 31, 2019, we fully consolidated this entity in our Consolidated Financial Statements and accounted 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 6,669 MW and 7,880 MW, at December 31, 2019 and 2018, 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. On August 14, 2019, we repaid the OMEC project debt outstanding balance utilizing a portion of the proceeds from our 2026 First Lien Term Loans and cash on hand. See above for further discussion of OMEC. Other than amounts contractually required, we provided no additional material support to our VIEs in the form of cash and other contributions during each of the years ended December 31, 2019, 2018 and 2017.
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 (including cash and cash equivalents, restricted cash and property, plant and equipment), and where our VIEs have 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.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP which is also a VIE; however, we do not have the power to direct the most significant activities of this entity and therefore do not consolidate it. 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. On November 20, 2019, we sold our 50% interest in Whitby, a limited partnership, which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada.
Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. We have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables because we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Balance Sheets. At December 31, 2019 and 2018, our equity method investments included on our Consolidated Balance Sheets were comprised of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
Ownership Interest as of December 31, 2019
|
|
2019
|
|
2018
|
Greenfield LP(1)
|
50%
|
|
$
|
66
|
|
|
$
|
55
|
|
Whitby(2)
|
—%
|
|
—
|
|
|
15
|
|
Calpine Receivables
|
100%
|
|
4
|
|
|
6
|
|
Total investments in unconsolidated subsidiaries
|
|
|
$
|
70
|
|
|
$
|
76
|
|
____________
|
|
(1)
|
Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt.
|
|
|
(2)
|
On November 20, 2019, we sold our 50% interest in Whitby to a third party and recorded a gain on sale of assets, net of approximately $5 million.
|
Our risk of loss related to our investment in Greenfield LP is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $48 million which consists of our notes receivable from Calpine Receivables at December 31, 2019, and our initial investment associated with Calpine Receivables. See Note 17 for further information associated with our related party activity with Calpine Receivables.
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, 2019 and 2018, Greenfield LP’s debt was approximately $299 million and $301 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $150 million and $151 million at December 31, 2019 and 2018, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the years ended December 31, 2019, 2018 and 2017, is recorded in (income) loss from unconsolidated subsidiaries. The following table sets forth details of our (income) loss from unconsolidated subsidiaries and distributions for the years indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Income) loss from
Unconsolidated Subsidiaries
|
|
Distributions
|
|
2019
|
|
2018
|
|
2017
|
|
2019
|
|
2018
|
|
2017
|
Greenfield LP
|
$
|
(13
|
)
|
|
$
|
(11
|
)
|
|
$
|
(14
|
)
|
|
$
|
—
|
|
|
$
|
48
|
|
|
$
|
8
|
|
Whitby(1)
|
(11
|
)
|
|
(15
|
)
|
|
(10
|
)
|
|
26
|
|
|
5
|
|
|
20
|
|
Calpine Receivables
|
2
|
|
|
2
|
|
|
2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
(22
|
)
|
|
$
|
(24
|
)
|
|
$
|
(22
|
)
|
|
$
|
26
|
|
|
$
|
53
|
|
|
$
|
28
|
|
____________
|
|
(1)
|
On November 20, 2019, we sold our 50% interest in Whitby to a third party.
|
Inland Empire Energy Center Put and Call Options — We held a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that could be exercised between years 2017 and 2024. GE held a put option whereby they could require us to purchase the power plant, if certain plant performance criteria were met by 2025. On February 1, 2019, we entered into an agreement with GE, which among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. As per this agreement, we will take ownership of the facility site and certain remaining site infrastructure and equipment after closure and decommissioning of the facility at a future date, until such time GE continues to own, operate and maintain the power plant, including directing any closure activities. As GE continues to direct all such significant activities of the power plant, we have determined that we no longer hold any variable interests in the Inland Empire Energy Center and it is not a VIE to Calpine.
Our debt at December 31, 2019 and 2018, was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
Senior Unsecured Notes
|
$
|
3,663
|
|
|
$
|
3,036
|
|
First Lien Term Loans
|
3,167
|
|
|
2,976
|
|
First Lien Notes
|
2,835
|
|
|
2,400
|
|
Project financing, notes payable and other
|
879
|
|
|
1,264
|
|
CCFC Term Loan
|
967
|
|
|
974
|
|
Finance lease obligations
|
73
|
|
|
105
|
|
Revolving facilities
|
122
|
|
|
30
|
|
Subtotal
|
11,706
|
|
|
10,785
|
|
Less: Current maturities
|
1,268
|
|
|
637
|
|
Total long-term debt
|
$
|
10,438
|
|
|
$
|
10,148
|
|
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, 2019. Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, increased to 5.8% for the year ended December 31, 2019 from 5.7% for the year ended December 31, 2018.
Annual Debt Maturities
Contractual annual principal repayments or maturities of debt instruments as of December 31, 2019, are as follows (in millions):
|
|
|
|
|
2020
|
$
|
1,269
|
|
2021
|
347
|
|
2022
|
230
|
|
2023
|
198
|
|
2024
|
2,030
|
|
Thereafter
|
7,771
|
|
Subtotal
|
11,845
|
|
Less: Debt issuance costs
|
114
|
|
Less: Discount
|
25
|
|
Total debt
|
$
|
11,706
|
|
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)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
2023 Senior Unsecured Notes(2)
|
$
|
623
|
|
|
$
|
1,227
|
|
|
5.7
|
%
|
|
5.6
|
%
|
2024 Senior Unsecured Notes
|
479
|
|
|
599
|
|
|
5.7
|
|
|
5.7
|
|
2025 Senior Unsecured Notes
|
1,174
|
|
|
1,210
|
|
|
5.8
|
|
|
6.0
|
|
2028 Senior Unsecured Notes(2)
|
1,387
|
|
|
—
|
|
|
5.3
|
|
|
—
|
|
Total Senior Unsecured Notes
|
$
|
3,663
|
|
|
$
|
3,036
|
|
|
|
|
|
____________
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs.
|
|
|
(2)
|
On December 27, 2019, we used the proceeds from the issuance of our 2028 Senior Unsecured Notes (discussed below) to redeem approximately $613 million in aggregate principal amount of our 2023 Senior Unsecured Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $623 million in aggregate principal amount of our 2023 Senior Unsecured Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 Senior Unsecured Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019. We recorded approximately $24 million in loss on extinguishment of debt which is comprised of approximately $18 million of prepayment premiums and approximately $6 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption.
|
During the year ended December 31, 2019, we repurchased $160 million in aggregate principal amount of our Senior Unsecured Notes for $158 million. In connection with the repurchases, we recorded approximately $2 million in gain on extinguishment of debt and recorded an immaterial amount in loss on extinguishment of debt associated with the write-off of debt issuance costs.
During the year ended December 31, 2018, we repurchased $390 million in aggregate principal of our Senior Unsecured Notes for $355 million. In connection with the repurchases, we recorded approximately $35 million in gain on extinguishment of debt and recorded approximately $3 million in loss on extinguishment of debt associated with the write-off of debt issuance costs.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2019
|
|
Year Ended December 31, 2018
|
|
|
Principal Repurchased
|
|
Cash Paid
|
|
Gain (loss) on Extinguishment of Debt
|
|
Principal Repurchased
|
|
Cash Paid
|
|
Gain on Extinguishment of Debt
|
|
|
(in million)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2023 Senior Unsecured Notes
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
14
|
|
|
$
|
13
|
|
|
$
|
1
|
|
2024 Senior Unsecured Notes
|
|
122
|
|
|
123
|
|
|
(1
|
)
|
|
46
|
|
|
42
|
|
|
4
|
|
2025 Senior Unsecured Notes
|
|
38
|
|
|
35
|
|
|
3
|
|
|
330
|
|
|
300
|
|
|
30
|
|
Total
|
|
$
|
160
|
|
|
$
|
158
|
|
|
$
|
2
|
|
|
$
|
390
|
|
|
$
|
355
|
|
|
$
|
35
|
|
On December 27, 2019, we issued $1.4 billion in aggregate principal amount of 5.125% senior unsecured notes due 2028 in a private placement. The 2028 Senior Unsecured Notes bear interest at 5.125% per annum with interest payable semi-annually on March 15 and September 15 of each year, beginning on September 15, 2020. The 2028 Senior Unsecured Notes mature on March 15, 2028. We recorded approximately $13 million in debt issuance costs during the fourth quarter of 2019 in connection with the issuance of our 2028 Senior Unsecured 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.
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.
|
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)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
2019 First Lien Term Loan
|
$
|
—
|
|
|
$
|
389
|
|
|
—
|
%
|
|
4.9
|
%
|
2023 First Lien Term Loans
|
—
|
|
|
1,059
|
|
|
—
|
|
|
5.4
|
|
2024 First Lien Term Loan(2)
|
1,514
|
|
|
1,528
|
|
|
5.3
|
|
|
5.0
|
|
2026 First Lien Term Loans
|
1,653
|
|
|
—
|
|
|
5.4
|
|
|
—
|
|
Total First Lien Term Loans
|
$
|
3,167
|
|
|
$
|
2,976
|
|
|
|
|
|
____________
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
|
|
(2)
|
Our 2024 First Lien Term Loan, which matures on January 15, 2024, carries substantially similar terms as our $950 million first lien senior secured term loan as discussed below.
|
On August 12, 2019, we entered into a $750 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.0%, or (ii) LIBOR plus 2.00% per annum, which reflects the lower rate resulting from the repricing on February 12, 2020, (with a 0% LIBOR floor) and matures on August 12, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 0.50% of the aggregate principal amount, which is structured as original issue discount and recorded approximately $11 million in debt issuance costs during the third quarter of 2019 related to the issuance of our $750 million first lien senior secured term loan. The $750 million first lien senior secured term contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds, together with cash on hand, to repay the remaining 2023 First Lien Term Loans with a maturity date in May 2023 and to repay project debt associated with OMEC. We recorded approximately $12 million in loss on extinguishment of debt during the third quarter of 2019 associated with the repayment.
On April 5, 2019, we entered into a $950 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.25%, or (ii) LIBOR plus 2.25% per annum, which reflects the lower rate resulting from the repricing on December 20, 2019, (with a 0% LIBOR floor) and matures on April 5, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount, which is structured as original issue discount and recorded approximately $7 million in debt issuance costs during the second quarter of 2019 related to the issuance of our $950 million first lien senior secured term loan. The $950 million first lien senior secured term loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds to repay our 2019 First Lien Term Loan and a portion of our 2023 First Lien Term Loans with a maturity date in January 2023 and recorded approximately $3 million in loss on extinguishment of debt during the second quarter of 2019 associated with the repayment.
First Lien Notes
Our First Lien Notes are summarized in the table below (in millions, except for interest rates):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates(1)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
2022 First Lien Notes(2)
|
$
|
245
|
|
|
$
|
743
|
|
|
6.4
|
%
|
|
6.4
|
%
|
2024 First Lien Notes(3)
|
184
|
|
|
486
|
|
|
6.1
|
|
|
6.1
|
|
2026 First Lien Notes
|
1,172
|
|
|
1,171
|
|
|
5.5
|
|
|
5.5
|
|
2028 First Lien Notes(2)(3)
|
1,234
|
|
|
—
|
|
|
4.7
|
|
|
—
|
|
Total First Lien Notes
|
$
|
2,835
|
|
|
$
|
2,400
|
|
|
|
|
|
____________
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
|
|
(2)
|
On December 20, 2019, we used the proceeds from the issuance of our 2028 First Lien Notes (discussed below) to redeem approximately $505 million in aggregate principal amount of our 2022 First Lien Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $245 million in aggregate principal amount of our 2022 First Lien Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 First Lien Notes, which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019. We recorded approximately $6 million in loss on extinguishment of debt which is comprised of approximately $1 million of prepayment premiums and approximately $5 million associated with the write-off of unamortized discount and debt issuance costs during the fourth quarter of 2019 associated with the redemption.
|
|
|
(3)
|
On December 20, 2019, we used the proceeds from the issuance of our 2028 First Lien Notes (discussed below) to redeem approximately $306 million of the total aggregate debt amount of 2024 First Lien Notes, plus accrued and unpaid interest. On January 21, 2020, we redeemed the remaining $184 million in aggregate principal amount of our 2024 First Lien Notes, which was included in debt, current portion on our Consolidated Balance Sheet at December 31, 2019, with the proceeds from the 2028 First Lien Notes which was included in cash and cash equivalents on our Consolidated Balance Sheet at December 31, 2019. We recorded approximately $14 million in loss on extinguishment of debt which is comprised of approximately $11 million of prepayment premiums and approximately $3 million associated with the write-off of unamortized debt issuance costs during the fourth quarter of 2019 associated with the redemption.
|
On December 20, 2019, we issued $1.25 billion in aggregate principal amount of 4.50% senior secured notes due 2028 in a private placement. Our 2028 First Lien Notes bear interest at 4.50% payable semi-annually on February 15 and August 15 of each year, beginning on August 15, 2020. Our 2028 First Lien Notes mature on February 15, 2028 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $16 million in debt issuance costs during the fourth quarter of 2019 related to the issuance of our 2028 First Lien Notes.
On December 15, 2017, we issued $560 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Additionally, on May 31, 2016, we issued $625 million in aggregate principal amount of 5.25% senior secured notes due 2026 in a private placement. Our 2026 First Lien Notes bear interest at 5.25% payable semi-annually on June 1 and December 1 of each year. Our 2026 First Lien Notes mature on June 1, 2026 and contain substantially similar covenants, qualifications, exceptions and limitations as our First Lien Notes. We recorded approximately $8 million in debt issuance costs during the fourth quarter of 2017 related to the issuance of a portion of our 2026 First Lien Notes and approximately $9 million in debt issuance costs during the second quarter of 2016 related to the issuance of a portion of our 2026 First Lien Notes.
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.
|
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)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Russell City due 2023
|
$
|
272
|
|
|
$
|
341
|
|
|
6.6
|
%
|
|
6.5
|
%
|
Steamboat due 2025
|
351
|
|
|
384
|
|
|
4.6
|
|
|
4.5
|
|
OMEC due 2024(2)
|
—
|
|
|
218
|
|
|
—
|
|
|
7.1
|
|
Los Esteros due 2023
|
135
|
|
|
163
|
|
|
5.2
|
|
|
4.7
|
|
Pasadena(3)
|
62
|
|
|
76
|
|
|
8.9
|
|
|
8.9
|
|
Bethpage Energy Center 3 due 2020-2025(4)
|
45
|
|
|
53
|
|
|
7.0
|
|
|
7.1
|
|
Other
|
14
|
|
|
29
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
879
|
|
|
$
|
1,264
|
|
|
|
|
|
_____________
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
|
|
(2)
|
On August 14, 2019, we repaid the project debt associated with OMEC from a portion of the proceeds received from the issuance of our 2026 First Lien Term Loans (as discussed above), together with cash on hand.
|
|
|
(3)
|
Represents a failed sale-leaseback transaction that is accounted for as financing transaction under U.S. GAAP.
|
|
|
(4)
|
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.
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through application of collateral. As a result of PG&E’s bankruptcy, we are currently unable to make distributions from our Russell City and Los Esteros projects in accordance with the terms of the project debt agreements associated with each related project. In July 2019, we executed forbearance agreements associated with the Russell City and Los Esteros project debt agreements, under which the lenders have agreed to forbear enforcement of their rights and remedies, including the ability to accelerate the repayment of borrowings outstanding, otherwise arising because PG&E did not assume our PPAs during the first 180 days of PG&E’s bankruptcy proceeding. The forbearance agreements are effective for rolling 90-day periods, so long as we continue to meet certain conditions, including that the PPAs have not been rejected and there are no other defaults under the project debt agreements or the forbearance agreements. We may be required to reclassify $304 million of Russell City and Los Esteros long-term project debt outstanding at December 31, 2019 to a current liability in a future period. We continue to monitor the bankruptcy proceedings and are assessing our options.
CCFC Term Loan
Our CCFC Term Loan is summarized in the table below (in millions, except for interest rates):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at December 31,
|
|
Weighted Average
Effective Interest Rates(1)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
CCFC Term Loan
|
$
|
967
|
|
|
$
|
974
|
|
|
5.2
|
%
|
|
4.9
|
%
|
____________
|
|
(1)
|
Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.
|
On December 15, 2017, CCFC entered into a credit agreement providing for a first lien senior secured term loan facility for $1.0 billion. The CCFC Term Loan bears interest, at CCFC’s option, at either (i) the Base Rate, equal to the higher of (a) the Federal Funds Effective Rate plus 0.5% per annum, (b) the Prime Rate or (c) the Eurodollar Rate (as such terms are defined in the Credit Agreement) plus 1.0% per annum, plus an applicable margin of 1.0% per annum, or (ii) LIBOR plus 2.0% per annum, which reflects the lower rate resulting from the repricing on January 29, 2020. The CCFC Term Loan was offered to investors at an issue price equal to 99.875% of face value.
An aggregate amount equal to 0.25% of the aggregate principal amount of the CCFC Term Loan will be payable at the end of each quarter commencing in March 2018, with the remaining balance payable on the maturity date (January 15, 2025). CCFC may elect from time to time to convert all or a portion of the CCFC Term Loan from LIBOR rate loans to Base Rate loans or vice versa. In addition, CCFC may at any time, and from time to time, prepay the CCFC Term Loan, in whole or in part, without premium or penalty, upon irrevocable notice to the Administrative Agent. Partial prepayments shall be in an aggregate minimum principal amount of $1 million, provided that any prepayment shall be first applied to any portion of the CCFC Term Loan that is designated as Base Rate loans and then LIBOR rate loans.
CCFC may also reprice the CCFC Term Loan, subject to approval from the Lenders (as defined in the Credit Agreement). CCFC may elect to extend the maturity of any CCFC Term Loan, in whole or in part, subject to approval from those lenders (as defined in the Credit Agreement) holding such CCFC Term Loan.
Subject to certain qualifications and exceptions, the Credit Agreement will, among other things, limit CCFC’s ability and the ability of the guarantors of the CCFC Term Loan to:
|
|
•
|
incur or guarantee additional first lien indebtedness;
|
|
|
•
|
enter into sale and leaseback transactions;
|
|
|
•
|
consummate certain asset sales;
|
|
|
•
|
make certain non-cash restricted payments; and
|
|
|
•
|
consolidate, merge or transfer all or substantially all of CCFC’s assets and the assets of CCFC’s restricted subsidiaries on a combined basis.
|
We utilized the proceeds received from a portion of our 2026 First Lien Notes (discussed above) and the CCFC Term Loan, together with operating cash on hand, to fully repay the CCFC Term Loans and recorded approximately $13 million in debt issuance costs during the fourth quarter of 2017. We recorded approximately $12 million in loss on extinguishment of debt associated with the repayment of our CCFC Term Loans during the fourth quarter of 2017.
The CCFC Term Loan is secured by certain real and personal property of CCFC consisting primarily of six natural gas-fired power plants. The CCFC Term Loan is not guaranteed by Calpine Corporation and is 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.
Finance Lease Obligations
See Note 4 for disclosures related to our finance lease obligations.
Corporate Revolving Facility and Other Letters of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at December 31, 2019 and 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
Corporate Revolving Facility
|
$
|
604
|
|
|
$
|
693
|
|
CDHI
|
3
|
|
|
251
|
|
Various project financing facilities
|
184
|
|
|
228
|
|
Other corporate facilities
|
294
|
|
|
193
|
|
Total
|
$
|
1,085
|
|
|
$
|
1,365
|
|
Corporate Revolving Facility
On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion. On August 12, 2019, we amended our Corporate Revolving Facility to extend the maturity of $150 million in revolving commitments from June 27, 2020 to March 8, 2023, and to reduce the commitments outstanding by $20 million to approximately $2.0 billion. The entire Corporate Revolving Facility matures on March 8, 2023.
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 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. 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 is guaranteed and secured by certain of our current domestic subsidiaries 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 revolving facility related to CDHI which matures on October 2, 2021. Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI revolving facility was reduced to $125 million on June 28, 2019. The decrease in capacity did not have a material effect on our liquidity as alternative sources of liquidity are available to us. Our CDHI revolving facility is restricted to support certain obligations under PPAs and power transmission and natural gas transportation agreements as well as fund the construction of our Washington Parish Energy Center. Borrowings under the CDHI revolving facility were $122 million at December 31, 2019, and 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 of 1.75% and LIBOR rate borrowings shall be at the LIBOR rate, plus an applicable margin of 2.75%.
Other corporate facilities
We have three unsecured letter of credit facilities with third party financial institutions totaling approximately $300 million. One of the facilities, with commitments totaling $150 million, matures partially in June 2020 and fully by December 2020. The other two facilities, with commitments totaling $50 million and approximately $100 million, mature in December 2023 and December 2021, respectively.
Fair Value of Debt
We record our debt instruments based on contractual terms, net of any applicable premium or discount and debt issuance costs. The following table details the fair values and carrying values of our debt instruments at December 31, 2019 and 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
Fair Value
|
|
Carrying
Value
|
|
Fair Value
|
|
Carrying
Value
|
Senior Unsecured Notes
|
$
|
3,764
|
|
|
$
|
3,663
|
|
|
$
|
2,803
|
|
|
$
|
3,036
|
|
First Lien Term Loans
|
3,238
|
|
|
3,167
|
|
|
2,877
|
|
|
2,976
|
|
First Lien Notes
|
2,929
|
|
|
2,835
|
|
|
2,299
|
|
|
2,400
|
|
Project financing, notes payable and other(1)
|
822
|
|
|
817
|
|
|
1,209
|
|
|
1,188
|
|
CCFC Term Loan
|
982
|
|
|
967
|
|
|
938
|
|
|
974
|
|
Revolving facilities
|
122
|
|
|
122
|
|
|
30
|
|
|
30
|
|
Total
|
$
|
11,857
|
|
|
$
|
11,571
|
|
|
$
|
10,156
|
|
|
$
|
10,604
|
|
____________
|
|
(1)
|
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
|
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes and CCFC Term Loan are categorized as level 2 within the fair value hierarchy. Our revolving facilities and project financing, notes payable and other debt instruments are categorized as level 3 within the fair value hierarchy. We do not have any debt instruments with fair value measurements categorized as level 1 within the fair value hierarchy.
|
|
9.
|
Assets and Liabilities with Recurring Fair Value Measurements
|
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts and other interest-bearing accounts, are included in both our cash and cash equivalents and our restricted cash on our Consolidated Balance Sheets. Certain of our money market accounts invest in U.S. Treasury securities or other obligations issued or guaranteed by the U.S. Government, its agencies or instrumentalities. We do not have any cash equivalents invested in institutional prime money market funds which require use of a floating net asset value and are subject to liquidity fees and redemption restrictions. Certain of our cash equivalents are classified within level 1 of the fair value hierarchy.
Derivatives — The primary factors affecting the fair value of our derivative instruments at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties and customers for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Prices for power and natural gas and interest rates are volatile, which can result in material changes in the fair value measurements reported in our financial statements in the future.
We utilize market data, such as pricing services and broker quotes, and assumptions that we believe market participants would use in pricing our assets or liabilities including assumptions about the risks inherent to the inputs in the valuation technique. These inputs can be either readily observable, market corroborated or generally unobservable. The market data obtained from broker pricing services is evaluated to determine the nature of the quotes obtained and, where accepted as a reliable quote, used to validate our assessment of fair value. We use other qualitative assessments to determine the level of activity in any given market. We primarily apply the market approach and income approach for recurring fair value measurements and utilize what we believe to be the best available information. We utilize valuation techniques that seek to maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the observability of those inputs.
The fair value of our derivatives includes consideration of our credit standing, the credit standing of our counterparties and customers and the effect of credit enhancements, if any. We have also recorded credit reserves in the determination of fair value based on our expectation of how market participants would determine fair value. Such valuation adjustments are generally based on market evidence, if available, or our best estimate.
Our level 1 fair value derivative instruments primarily consist of power and natural gas swaps, futures and options traded on the NYMEX or Intercontinental Exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, 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 primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. 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, 2019 and 2018, by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2019
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(in millions)
|
Assets:
|
|
|
|
|
|
|
|
Cash equivalents(1)
|
$
|
784
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
784
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
872
|
|
|
—
|
|
|
—
|
|
|
872
|
|
Commodity forward contracts(2)
|
—
|
|
|
245
|
|
|
294
|
|
|
539
|
|
Interest rate hedging instruments
|
—
|
|
|
12
|
|
|
—
|
|
|
12
|
|
Effect of netting and allocation of collateral(3)(4)
|
(872
|
)
|
|
(131
|
)
|
|
(18
|
)
|
|
(1,021
|
)
|
Total assets
|
$
|
784
|
|
|
$
|
126
|
|
|
$
|
276
|
|
|
$
|
1,186
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
984
|
|
|
—
|
|
|
—
|
|
|
984
|
|
Commodity forward contracts(2)
|
—
|
|
|
285
|
|
|
123
|
|
|
408
|
|
Interest rate hedging instruments
|
—
|
|
|
31
|
|
|
—
|
|
|
31
|
|
Effect of netting and allocation of collateral(3)(4)
|
(984
|
)
|
|
(133
|
)
|
|
(18
|
)
|
|
(1,135
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
183
|
|
|
$
|
105
|
|
|
$
|
288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(in millions)
|
Assets:
|
|
|
|
|
|
|
|
Cash equivalents(1)
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
168
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
933
|
|
|
—
|
|
|
—
|
|
|
933
|
|
Commodity forward contracts(2)
|
—
|
|
|
338
|
|
|
212
|
|
|
550
|
|
Interest rate hedging instruments
|
—
|
|
|
40
|
|
|
—
|
|
|
40
|
|
Effect of netting and allocation of collateral(3)(4)
|
(933
|
)
|
|
(262
|
)
|
|
(26
|
)
|
|
(1,221
|
)
|
Total assets
|
$
|
168
|
|
|
$
|
116
|
|
|
$
|
186
|
|
|
$
|
470
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
932
|
|
|
—
|
|
|
—
|
|
|
932
|
|
Commodity forward contracts(2)
|
—
|
|
|
549
|
|
|
220
|
|
|
769
|
|
Interest rate hedging instruments
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
Effect of netting and allocation of collateral(3)(4)
|
(932
|
)
|
|
(310
|
)
|
|
(26
|
)
|
|
(1,268
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
249
|
|
|
$
|
194
|
|
|
$
|
443
|
|
___________
|
|
(1)
|
As of December 31, 2019 and 2018, we had cash equivalents of $573 million and $23 million included in cash and cash equivalents and $211 million and $145 million included in restricted cash, respectively.
|
|
|
(2)
|
Includes OTC swaps and options.
|
|
|
(3)
|
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements.
|
|
|
(4)
|
Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $112 million, $2 million and nil, respectively, at December 31, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.
|
At December 31, 2019 and 2018, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at December 31, 2019 and 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
|
|
December 31, 2019
|
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
|
|
(in millions)
|
|
|
|
|
|
|
Power Contracts(1)
|
|
$
|
158
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$4.85 — $184.15/MWh
|
Power Congestion Products
|
|
$
|
17
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$(10.32)— $20.00/MWh
|
Natural Gas Contracts
|
|
$
|
(20
|
)
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$1.73 — $6.45/MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
|
|
December 31, 2018
|
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
|
|
(in millions)
|
|
|
|
|
|
|
Power Contracts(1)
|
|
$
|
36
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$2.12 — $227.98/MWh
|
Power Congestion Products
|
|
$
|
26
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$(11.71) — $11.88/MWh
|
Natural Gas Contracts
|
|
$
|
(73
|
)
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$0.75 — $8.87/MMBtu
|
___________
|
|
(1)
|
Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.
|
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, 2019, 2018 and 2017 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Balance, beginning of period
|
$
|
(8
|
)
|
|
$
|
197
|
|
|
$
|
416
|
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
Included in net income (loss):
|
|
|
|
|
|
Included in operating revenues(1)
|
171
|
|
|
(88
|
)
|
|
32
|
|
Included in fuel and purchased energy expense(2)
|
(21
|
)
|
|
(45
|
)
|
|
50
|
|
Change in collateral
|
—
|
|
|
—
|
|
|
(17
|
)
|
Purchases, issuances and settlements:
|
|
|
|
|
|
Purchases
|
5
|
|
|
18
|
|
|
4
|
|
Issuances
|
(3
|
)
|
|
(2
|
)
|
|
(1
|
)
|
Settlements
|
56
|
|
|
(86
|
)
|
|
(179
|
)
|
Transfers in and/or out of level 3(3):
|
|
|
|
|
|
Transfers into level 3(4)
|
1
|
|
|
—
|
|
|
(2
|
)
|
Transfers out of level 3(5)
|
(30
|
)
|
|
(2
|
)
|
|
(106
|
)
|
Balance, end of period
|
$
|
171
|
|
|
$
|
(8
|
)
|
|
$
|
197
|
|
Change in unrealized gains (losses) relating to instruments still held at end of period
|
$
|
150
|
|
|
$
|
(133
|
)
|
|
$
|
82
|
|
___________
|
|
(1)
|
For power contracts and other power-related products, included on our Consolidated Statements of Operations.
|
|
|
(2)
|
For natural gas and power contracts, swaps and options, included on our Consolidated Statements of Operations.
|
|
|
(3)
|
We transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 during the years ended December 31, 2019, 2018 and 2017.
|
|
|
(4)
|
We had $1 million in gains, nil and $(2) million in losses transferred out of level 2 into level 3 for the years ended December 31, 2019, 2018 and 2017, respectively.
|
|
|
(5)
|
We had $30 million, $2 million and $104 million in gains transferred out of level 3 into level 2 during the years ended December 31, 2019, 2018 and 2017, respectively, due to changes in market liquidity in various power markets and $2 million in gains transferred out of level 3 during the years ended December 31, 2017, to other assets following the election of the normal purchase normal sales exemption and the discontinuance of derivative accounting treatment as of the date of this election for certain commodity contracts.
|
|
|
10.
|
Derivative Instruments
|
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, fuel oil, environmental products and other energy commodities. We use derivatives, which include physical commodity contracts and financial commodity instruments such as OTC and exchange traded swaps, futures, options, forward agreements and instruments that settle on the power price to natural gas price relationships (Heat Rate swaps and options) or instruments that settle on power or natural gas price relationships between delivery points for the purchase and sale of power and natural gas to attempt to maximize the risk-adjusted returns by economically hedging a portion of the commodity price risk associated with our assets. By entering into these transactions, we are able to economically hedge a portion of our Spark Spread at estimated generation and prevailing price levels.
We also engage in limited trading activities related to our commodity derivative portfolio as authorized by our Board of Directors and monitored by our Chief Risk Officer and Risk Management Committee of senior management. These transactions are executed primarily for the purpose of providing improved price and price volatility discovery, greater market access, and profiting from our market knowledge, all of which benefit our asset hedging activities. Our trading results were not material for the years ended December 31, 2019, 2018 and 2017.
Interest Rate Hedging Instruments — A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of December 31, 2019, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 6 years.
As of December 31, 2019 and 2018, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments
|
|
Notional Amounts
|
|
|
|
2019
|
|
2018
|
|
Unit of Measure
|
Power (MWh)
|
|
(184
|
)
|
|
(161
|
)
|
|
Million MWh
|
Natural gas (MMBtu)
|
|
1,063
|
|
|
1,045
|
|
|
Million MMBtu
|
Environmental credits (Tonnes)
|
|
26
|
|
|
13
|
|
|
Million Tonnes
|
Interest rate hedging instruments
|
|
$
|
4.8
|
|
|
$
|
4.5
|
|
|
Billion U.S. dollars
|
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. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of December 31, 2019, was $153 million for which we have posted collateral of $93 million by posting margin deposits, letters of credit 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 $3 million related to our derivative liabilities 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. We present the cash flows from our derivatives in the same category as the item being hedged (or economically hedged) within operating activities on our Consolidated 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 currently apply hedge accounting to our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. 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 will be recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated Statements of Operations in mark-to-market gain/loss as a component of operating revenues (for physical and financial power and Heat Rate and commodity option activity) and fuel and purchased energy expense (for physical and financial natural gas, power, environmental product and fuel oil activity). Changes in fair value of interest rate derivatives not designated as hedging instruments are recognized currently in earnings as interest expense.
Derivatives Included on Our Consolidated Balance Sheets
We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Balance Sheets that are executed with the same counterparty under master netting arrangements. 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 and/or receive cash collateral in support of our derivative instruments which may also be subject to a master netting arrangement with the same counterparty.
The following tables present the fair values of our derivative instruments and our net exposure after offsetting amounts subject to a master netting arrangement with the same counterparty to our derivative instruments recorded on our Consolidated Balance Sheets by location and hedge type at December 31, 2019 and 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
|
Gross Amounts of Assets and (Liabilities)
|
|
Gross Amounts Offset on the Consolidated Balance Sheets
|
|
Net Amount Presented on the Consolidated Balance Sheets(1)
|
Derivative assets:
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
727
|
|
|
$
|
(727
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
262
|
|
|
(108
|
)
|
|
154
|
|
Interest rate hedging instruments
|
|
2
|
|
|
—
|
|
|
2
|
|
Total current derivative assets(2)
|
|
$
|
991
|
|
|
$
|
(835
|
)
|
|
$
|
156
|
|
Commodity exchange traded derivatives contracts
|
|
145
|
|
|
(145
|
)
|
|
—
|
|
Commodity forward contracts
|
|
277
|
|
|
(41
|
)
|
|
236
|
|
Interest rate hedging instruments
|
|
10
|
|
|
—
|
|
|
10
|
|
Total long-term derivative assets(2)
|
|
$
|
432
|
|
|
$
|
(186
|
)
|
|
$
|
246
|
|
Total derivative assets
|
|
$
|
1,423
|
|
|
$
|
(1,021
|
)
|
|
$
|
402
|
|
|
|
|
|
|
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
(830
|
)
|
|
$
|
830
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(321
|
)
|
|
109
|
|
|
(212
|
)
|
Interest rate hedging instruments
|
|
(13
|
)
|
|
—
|
|
|
(13
|
)
|
Total current derivative (liabilities)(2)
|
|
$
|
(1,164
|
)
|
|
$
|
939
|
|
|
$
|
(225
|
)
|
Commodity exchange traded derivatives contracts
|
|
(154
|
)
|
|
154
|
|
|
—
|
|
Commodity forward contracts
|
|
(87
|
)
|
|
42
|
|
|
(45
|
)
|
Interest rate hedging instruments
|
|
(18
|
)
|
|
—
|
|
|
(18
|
)
|
Total long-term derivative (liabilities)(2)
|
|
$
|
(259
|
)
|
|
$
|
196
|
|
|
$
|
(63
|
)
|
Total derivative liabilities
|
|
$
|
(1,423
|
)
|
|
$
|
1,135
|
|
|
$
|
(288
|
)
|
Net derivative assets (liabilities)
|
|
$
|
—
|
|
|
$
|
114
|
|
|
$
|
114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
Gross Amounts of Assets and (Liabilities)
|
|
Gross Amounts Offset on the Consolidated Balance Sheets
|
|
Net Amount Presented on the Consolidated Balance Sheets(1)
|
Derivative assets:
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
820
|
|
|
$
|
(820
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
341
|
|
|
(229
|
)
|
|
112
|
|
Interest rate hedging instruments
|
|
30
|
|
|
—
|
|
|
30
|
|
Total current derivative assets(3)
|
|
$
|
1,191
|
|
|
$
|
(1,049
|
)
|
|
$
|
142
|
|
Commodity exchange traded derivatives contracts
|
|
113
|
|
|
(113
|
)
|
|
—
|
|
Commodity forward contracts
|
|
209
|
|
|
(59
|
)
|
|
150
|
|
Interest rate hedging instruments
|
|
10
|
|
|
—
|
|
|
10
|
|
Total long-term derivative assets(3)
|
|
$
|
332
|
|
|
$
|
(172
|
)
|
|
$
|
160
|
|
Total derivative assets
|
|
$
|
1,523
|
|
|
$
|
(1,221
|
)
|
|
$
|
302
|
|
|
|
|
|
|
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
(764
|
)
|
|
$
|
764
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(576
|
)
|
|
277
|
|
|
(299
|
)
|
Interest rate hedging instruments
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
Total current derivative (liabilities)(3)
|
|
$
|
(1,344
|
)
|
|
$
|
1,041
|
|
|
$
|
(303
|
)
|
Commodity exchange traded derivatives contracts
|
|
(168
|
)
|
|
168
|
|
|
—
|
|
Commodity forward contracts
|
|
(193
|
)
|
|
59
|
|
|
(134
|
)
|
Interest rate hedging instruments
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
Total long-term derivative (liabilities)(3)
|
|
$
|
(367
|
)
|
|
$
|
227
|
|
|
$
|
(140
|
)
|
Total derivative liabilities
|
|
$
|
(1,711
|
)
|
|
$
|
1,268
|
|
|
$
|
(443
|
)
|
Net derivative assets (liabilities)
|
|
$
|
(188
|
)
|
|
$
|
47
|
|
|
$
|
(141
|
)
|
____________
|
|
(1)
|
At December 31, 2019 and 2018, we had $191 million and $244 million of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Balance Sheets primarily related to initial margin requirements.
|
|
|
(2)
|
At December 31, 2019, current and long-term derivative assets are shown net of collateral of $(4) million and $(4) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $108 million and $14 million, respectively.
|
|
|
(3)
|
At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2019
|
|
December 31, 2018
|
|
Fair Value
of Derivative
Assets
|
|
Fair Value
of Derivative
Liabilities
|
|
Fair Value
of Derivative
Assets
|
|
Fair Value
of Derivative
Liabilities
|
Derivatives designated as cash flow hedging instruments:
|
|
|
|
|
|
|
|
Interest rate hedging instruments
|
$
|
12
|
|
|
$
|
29
|
|
|
$
|
40
|
|
|
$
|
10
|
|
Total derivatives designated as cash flow hedging instruments
|
$
|
12
|
|
|
$
|
29
|
|
|
$
|
40
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
Commodity instruments
|
$
|
390
|
|
|
$
|
257
|
|
|
$
|
262
|
|
|
$
|
433
|
|
Interest rate hedging instruments
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total derivatives not designated as hedging instruments
|
$
|
390
|
|
|
$
|
259
|
|
|
$
|
262
|
|
|
$
|
433
|
|
Total derivatives
|
$
|
402
|
|
|
$
|
288
|
|
|
$
|
302
|
|
|
$
|
443
|
|
Derivatives Included on Our Consolidated Statements of Operations
Changes in the fair values of our derivative instruments are reflected either in cash for option premiums paid or collected, in OCI, net of tax, for 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, 2019, 2018 and 2017 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Realized gain (loss)(1)(2)
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
256
|
|
|
$
|
193
|
|
|
$
|
7
|
|
Total realized gain
|
$
|
256
|
|
|
$
|
193
|
|
|
$
|
7
|
|
|
|
|
|
|
|
Mark-to-market gain (loss)(3)
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
278
|
|
|
$
|
(208
|
)
|
|
$
|
(171
|
)
|
Interest rate hedging instruments
|
(3
|
)
|
|
3
|
|
|
2
|
|
Total mark-to-market gain (loss)
|
$
|
275
|
|
|
$
|
(205
|
)
|
|
$
|
(169
|
)
|
Total activity, net
|
$
|
531
|
|
|
$
|
(12
|
)
|
|
$
|
(162
|
)
|
___________
|
|
(1)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
|
|
(2)
|
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions.
|
|
|
(3)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Realized and mark-to-market gain (loss)(1)
|
|
|
|
|
|
Derivatives contracts included in operating revenues(2)(3)
|
$
|
816
|
|
|
$
|
(369
|
)
|
|
$
|
(69
|
)
|
Derivatives contracts included in fuel and purchased energy expense(2)(3)
|
(282
|
)
|
|
354
|
|
|
(95
|
)
|
Interest rate hedging instruments included in interest expense
|
(3
|
)
|
|
3
|
|
|
2
|
|
Total activity, net
|
$
|
531
|
|
|
$
|
(12
|
)
|
|
$
|
(162
|
)
|
___________
|
|
(1)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
|
|
|
(2)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
|
|
(3)
|
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions.
|
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, 2019, 2018 and 2017 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (Loss) Recognized in
OCI (Effective Portion)
|
|
Gain (Loss) Reclassified from
AOCI into Income (Effective
Portion)(3)(4)
|
|
2019
|
|
2018
|
|
2017
|
|
2019
|
|
2018
|
|
2017
|
|
Affected Line Item on the Consolidated Statements of Operations
|
Interest rate hedging instruments(1)(2)
|
$
|
(41
|
)
|
|
$
|
45
|
|
|
$
|
21
|
|
|
$
|
(1
|
)
|
|
$
|
(5
|
)
|
|
$
|
(43
|
)
|
|
Interest expense
|
Interest rate hedging instruments(1)(2)
|
1
|
|
|
1
|
|
|
5
|
|
|
(1
|
)
|
|
(1
|
)
|
|
(5
|
)
|
|
Depreciation expense
|
Total
|
$
|
(40
|
)
|
|
$
|
46
|
|
|
$
|
26
|
|
|
$
|
(2
|
)
|
|
$
|
(6
|
)
|
|
$
|
(48
|
)
|
|
|
____________
|
|
(1)
|
We recorded a gain of $1 million on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the years ended December 31, 2018 and 2017. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.
|
|
|
(2)
|
We recorded an income tax benefit of $2 million and income tax expense of $5 million and $6 million for the years ended December 31, 2019, 2018 and 2017, respectively, in AOCI related to our cash flow hedging activities.
|
|
|
(3)
|
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $72 million, $34 million and $72 million at December 31, 2019, 2018 and 2017, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $3 million, $3 million and $6 million at December 31, 2019, 2018 and 2017, respectively.
|
|
|
(4)
|
Includes losses of $2 million, $1 million and nil that were reclassified from AOCI to interest expense for the years ended December 31, 2019, 2018 and 2017, respectively, where the hedged transactions became probable of not occurring.
|
We estimate that pre-tax net losses of $26 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.
We use margin deposits, prepayments and letters of credit as credit support with and from our counterparties for commodity procurement and risk management activities. In addition, we have granted additional first priority liens on the assets currently subject to first priority liens under various debt agreements as collateral under certain of our power and natural gas agreements and certain of our interest rate hedging instruments in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under our various debt agreements.
The table below summarizes the balances outstanding under margin deposits, natural gas and power prepayments, and exposure under letters of credit and first priority liens for commodity procurement and risk management activities as of December 31, 2019 and 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
Margin deposits(1)
|
$
|
432
|
|
|
$
|
343
|
|
Natural gas and power prepayments
|
29
|
|
|
31
|
|
Total margin deposits and natural gas and power prepayments with our counterparties(2)
|
$
|
461
|
|
|
$
|
374
|
|
|
|
|
|
Letters of credit issued
|
$
|
906
|
|
|
$
|
1,166
|
|
First priority liens under power and natural gas agreements
|
42
|
|
|
92
|
|
First priority liens under interest rate hedging instruments
|
31
|
|
|
10
|
|
Total letters of credit and first priority liens with our counterparties
|
$
|
979
|
|
|
$
|
1,268
|
|
|
|
|
|
Margin deposits posted with us by our counterparties(1)(3)
|
$
|
127
|
|
|
$
|
52
|
|
Letters of credit posted with us by our counterparties
|
25
|
|
|
27
|
|
Total margin deposits and letters of credit posted with us by our counterparties
|
$
|
152
|
|
|
$
|
79
|
|
___________
|
|
(1)
|
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 10 for further discussion of our derivative instruments subject to master netting arrangements.
|
|
|
(2)
|
At December 31, 2019 and 2018, $117 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $336 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Balance Sheets.
|
|
|
(3)
|
At December 31, 2019 and 2018, $3 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $93 million and $20 million, respectively, were included in other current liabilities and $31 million and nil, respectively, were included in other long-term 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.
Tax Cuts and Jobs Act (the “Act”)
On December 22, 2017, the Act was signed into law resulting in significant changes from previous tax law. Some of the more meaningful provisions which affected us are:
|
|
•
|
a reduction in the U.S. federal corporate tax rate from 35% to 21%;
|
|
|
•
|
limitation on the deduction of certain interest expense;
|
|
|
•
|
full expense deduction for certain business capital expenditures;
|
|
|
•
|
limitation on the utilization of NOLs arising after December 31, 2017; and
|
|
|
•
|
a system of taxing foreign-sourced income from multinational corporations.
|
In December 2017, the SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” which allows a company up to one year to finalize and record the tax effects of the Act. We finalized the tax effect of the transition tax as of December 31, 2017 which did not have a material effect on our financial condition, results of operations or cash flows. During the year ended December 31, 2018, we finalized and recorded the remaining tax effects of the Act which did not have a material effect on our financial condition, results of operations or cash flows.
Income Tax Expense (Benefit)
The jurisdictional components of income from continuing operations before income tax expense (benefit), attributable to Calpine, for the years ended December 31, 2019, 2018 and 2017, are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
U.S.
|
$
|
836
|
|
|
$
|
47
|
|
|
$
|
(358
|
)
|
International
|
32
|
|
|
27
|
|
|
27
|
|
Total
|
$
|
868
|
|
|
$
|
74
|
|
|
$
|
(331
|
)
|
The components of income tax expense from continuing operations for the years ended December 31, 2019, 2018 and 2017, consisted of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Current:
|
|
|
|
|
|
Federal
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
(10
|
)
|
State
|
2
|
|
|
20
|
|
|
18
|
|
Foreign
|
3
|
|
|
(3
|
)
|
|
(14
|
)
|
Total current
|
3
|
|
|
17
|
|
|
(6
|
)
|
Deferred:
|
|
|
|
|
|
Federal
|
66
|
|
|
(1
|
)
|
|
5
|
|
State
|
28
|
|
|
(6
|
)
|
|
6
|
|
Foreign
|
1
|
|
|
54
|
|
|
3
|
|
Total deferred
|
95
|
|
|
47
|
|
|
14
|
|
Total income tax expense
|
$
|
98
|
|
|
$
|
64
|
|
|
$
|
8
|
|
For the years ended December 31, 2019, 2018 and 2017, our income tax rates did not bear a customary relationship to statutory income tax rates, primarily as a result of the effect of our NOLs, valuation allowances and state income taxes. A reconciliation of the federal statutory rate of 21% and, prior to 2018, 35% to our effective rate from continuing operations for the years ended December 31, 2019, 2018 and 2017, is as follows:
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Federal statutory tax rate
|
21.0
|
%
|
|
21.0
|
%
|
|
35.0
|
%
|
State tax expense, net of federal benefit
|
2.8
|
|
|
17.0
|
|
|
(6.0
|
)
|
Change in tax rate of net deferred tax asset
|
—
|
|
|
—
|
|
|
(168.8
|
)
|
Valuation allowances offsetting tax rate change
|
—
|
|
|
—
|
|
|
168.8
|
|
Valuation allowances against future tax benefits
|
(11.2
|
)
|
|
(31.7
|
)
|
|
(33.0
|
)
|
Valuation allowance related to foreign taxes
|
—
|
|
|
(138.3
|
)
|
|
0.5
|
|
Decrease in foreign NOL due to change in ownership
|
—
|
|
|
202.3
|
|
|
—
|
|
Distributions from foreign affiliates and foreign taxes
|
0.2
|
|
|
6.6
|
|
|
(2.0
|
)
|
Change in unrecognized tax benefits
|
—
|
|
|
(8.0
|
)
|
|
5.1
|
|
Disallowed compensation
|
—
|
|
|
7.7
|
|
|
(0.6
|
)
|
Stock-based compensation
|
—
|
|
|
(1.5
|
)
|
|
(0.9
|
)
|
Equity earnings
|
0.1
|
|
|
1.4
|
|
|
(0.8
|
)
|
Merger Related Fees/Expenses
|
—
|
|
|
12.7
|
|
|
—
|
|
Depletion in excess of basis
|
(0.3
|
)
|
|
(4.0
|
)
|
|
—
|
|
Other differences
|
(1.3
|
)
|
|
1.3
|
|
|
0.3
|
|
Effective income tax rate
|
11.3
|
%
|
|
86.5
|
%
|
|
(2.4
|
)%
|
Deferred Tax Assets and Liabilities
The components of deferred income taxes as of December 31, 2019 and 2018, are as follows (in millions):
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
Deferred tax assets:
|
|
|
|
NOL and credit carryforwards
|
$
|
1,731
|
|
|
$
|
1,595
|
|
Taxes related to risk management activities and derivatives
|
18
|
|
|
7
|
|
Reorganization items and impairments
|
73
|
|
|
166
|
|
Other differences
|
62
|
|
|
101
|
|
Deferred tax assets before valuation allowance
|
1,884
|
|
|
1,869
|
|
Valuation allowance
|
(873
|
)
|
|
(1,000
|
)
|
Total deferred tax assets
|
1,011
|
|
|
869
|
|
Deferred tax liabilities:
|
|
|
|
Property, plant and equipment
|
(1,125
|
)
|
|
(890
|
)
|
Total deferred tax liabilities
|
(1,125
|
)
|
|
(890
|
)
|
Net deferred tax asset (liability)
|
(114
|
)
|
|
(21
|
)
|
Less: Non-current deferred tax liability
|
(116
|
)
|
|
(22
|
)
|
Deferred income tax asset, non-current
|
$
|
2
|
|
|
$
|
1
|
|
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 an offsetting amount recognized in OCI. The intraperiod tax allocation included in continuing operations is nil, $1 million and $6 million for the years ended December 31, 2019, 2018 and 2017.
NOL Carryforwards — As of December 31, 2019, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately $7.1 billion, of which the majority expire between 2024 and 2037, and NOL carryforwards in 25 states and the District of Columbia totaling approximately $3.2 billion, which expire between 2020 and 2039. A substantial portion of our federal and state NOLs are offset with a valuation allowance. Certain of the state NOL carryforwards may be subject to limitations on their annual usage. As a result of the ownership change associated with the Merger, our ability to utilize the NOL carryforwards are subject to limitations. Additionally, our state NOLs available to offset future state income could materially decrease which would be offset by an equal and offsetting adjustment to the existing valuation allowance. Given the offsetting adjustments to the existing valuation allowance, the ownership change is not expected to have a material adverse effect on our Consolidated Financial Statements.
As a result of the Merger, our Canadian NOLs, which comprised all of our foreign NOLs, are no longer available to us. This resulted in a decrease of approximately $58 million in the deferred tax asset and a related charge to deferred tax expense during the year ended December 31, 2018.
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently under various state income tax audits for various periods.
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, 2019, we have provided a valuation allowance of approximately $873 million on certain federal and state 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 $127 million for the year ended December 31, 2019.
Limitation on Deductions of Net Business Interest Expense — On November 26, 2018, the U.S. Treasury Department released proposed regulations which would limit the current deductibility of net business interest expense. The proposed regulations would be applicable for taxable years ending after the date on which the regulations become final. Companies have the discretion to apply the proposed regulations, but must apply all such provisions of the proposed regulations on a consistent basis. As of December 31, 2019, we have not elected to apply the proposed regulations for the 2018 or 2019 tax years and we do not expect the application of the final regulations will have a material effect on our Consolidated Financial Statements.
Unrecognized Tax Benefits
At December 31, 2019, we had unrecognized tax benefits of $29 million. If recognized, $17 million of our unrecognized tax benefits could affect the annual effective tax rate and $12 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect to our effective tax rate. We had accrued interest and penalties of $3 million and $2 million for income tax matters at December 31, 2019 and 2018, respectively. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Statements of Operations and recorded $1 million, $(2) million and $(8) million for the years ended December 31, 2019, 2018 and 2017, respectively.
A reconciliation of the beginning and ending amounts of our unrecognized tax benefits for the years ended December 31, 2019, 2018 and 2017, is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
2018
|
|
2017
|
Balance, beginning of period
|
$
|
(28
|
)
|
|
$
|
(38
|
)
|
|
$
|
(59
|
)
|
Increases related to prior year tax positions
|
—
|
|
|
(7
|
)
|
|
—
|
|
Decreases related to prior year tax positions
|
—
|
|
|
17
|
|
|
11
|
|
Increases related to current year tax positions
|
(1
|
)
|
|
—
|
|
|
(2
|
)
|
Decreases related to change in tax rate of net deferred tax asset
|
—
|
|
|
—
|
|
|
12
|
|
Balance, end of period
|
$
|
(29
|
)
|
|
$
|
(28
|
)
|
|
$
|
(38
|
)
|
|
|
13.
|
Stock-Based Compensation
|
Calpine Equity Incentive Plans
Prior to the effective date of the Merger on March 8, 2018, the Calpine Equity Incentive Plans provided for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. Subsequent to the merger, we do not issue share-based awards.
As a result of the Merger, the outstanding share-based awards were treated as follows during the first quarter of 2018:
|
|
•
|
all restricted stock and restricted stock units were vested and canceled and the holders received a cash payment equal to a share price of $15.25 per share less any applicable withholding taxes;
|
|
|
•
|
all vested and unvested stock options were vested (in the case of unvested stock options) and canceled and the holders of the stock options received a cash payment equal to the intrinsic value based on a share price of $15.25 per share less any applicable withholding taxes; and
|
|
|
•
|
all Performance Share Units (“PSUs”), including the PSUs awarded in 2015 for the measurement period of January 1, 2015 through December 31, 2017, were vested and canceled in exchange for a cash payment with the payout value based on the greater of target value or actual performance over the truncated period using a share price of $15.25 per share less any applicable withholding taxes.
|
The amount of cash transferred to repurchase the share-based awards associated with our equity classified share-based awards totaled $79 million and was recorded to additional paid-in capital on our Consolidated Balance Sheet for the year ended December 31, 2018. The amount of unrecognized compensation related to our equity classified share-based awards that we recognized in connection with the shortened service period associated with the completion of the Merger was $35 million for the year ended December 31, 2018, which did not include any incremental compensation cost as the amount paid did not exceed the fair value of the equity classified share-based awards at the effective time of the Merger. The total stock-based compensation expense for our equity classified share-based awards was $41 million and $36 million for the years ended December 31, 2018 and 2017, respectively.
The amount of cash transferred to repurchase the share-based awards associated with our liability classified share-based awards totaled $25 million and was recorded to the associated liability in other long-term liabilities on our Consolidated Balance Sheet for the year ended December 31, 2018. The amount of unrecognized compensation related to our liability classified share-
based awards that we recognized in connection with the shortened implied service period associated with the completion of the Merger was $16 million for the year ended December 31, 2018. The total stock-based compensation expense for our liability classified share-based awards was $16 million and $6 million for the years ended December 31, 2018 and 2017, respectively.
The total intrinsic value of our employee stock options exercised was $11 million and nil for the years ended December 31, 2018 and 2017, respectively. The total cash proceeds received from our employee stock options exercised was nil for each of the years ended December 31, 2018 and 2017, respectively.
The total fair value of our restricted stock and restricted stock units that vested during the years ended December 31, 2018 and 2017 was approximately $88 million and $23 million, respectively.
|
|
14.
|
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. In 2018, we added an enhanced feature to our defined contribution plan for non-union employees consisting of a non-elective contribution for certain eligible employees who are active employees as of December 31st. We recorded expenses for these plans of approximately $20 million, $20 million and $14 million for the years ended December 31, 2019, 2018 and 2017, 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 defined benefit pension plans whereby retirement benefits are primarily a function of age attained, years of participation, years of service, vesting and level of compensation. Only approximately 4% of our employees are eligible to participate in a defined benefit pension plan. As of December 31, 2019 and 2018, there were approximately $26 million and $19 million in plan assets and approximately $33 million and $27 million in pension liabilities, respectively. Our net pension liability recorded on our Consolidated Balance Sheets as of December 31, 2019 and 2018, was approximately $7 million and $8 million, respectively. For the years ended December 31, 2019, 2018 and 2017, we recognized net periodic benefit costs of approximately $1 million, $1 million and $1 million, respectively. Our net periodic benefit cost is included in operating and maintenance expense on our Consolidated Statements of Operations. As of December 31, 2019 and 2018, the total amount recognized in AOCI for actuarial losses related to pension obligation was approximately $6 million and $4 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 the 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 2019 and 2018, we made contributions of approximately $4 million and $1 million, respectively, and estimated contributions to the pension plan are expected to be approximately nil in 2020. Estimated future benefit payments to participants in each of the next five years are expected to be approximately $1 million in each year.
On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) ceased to be outstanding and was converted into the right to receive $15.25 per share in cash or approximately $5.6 billion in total. Also at the effective time of the Merger, the common stock of Merger Sub became the new common stock of Calpine Corporation.
Common Stock
Our authorized common stock consists of 5,000 shares of Calpine Corporation common stock as of December 31, 2019 and 2018. Common stock issued as of December 31, 2019 and 2018, was 105.2 shares, at a par value of $0.001 per share. Common stock outstanding as of December 31, 2019 and 2018, was 105.2 shares. The table below summarizes our common stock activity for the years ended December 31, 2019, 2018 and 2017.
|
|
|
|
|
|
|
|
|
|
|
Shares
Issued
|
|
Shares
Held in
Treasury
|
|
Shares
Outstanding
|
Balance, December 31, 2016
|
359,627,113
|
|
|
(565,349
|
)
|
|
359,061,764
|
|
Shares issued under Calpine Equity Incentive Plans
|
2,050,778
|
|
|
(596,451
|
)
|
|
1,454,327
|
|
Balance, December 31, 2017
|
361,677,891
|
|
|
(1,161,800
|
)
|
|
360,516,091
|
|
Shares issued under Calpine Equity Incentive Plans
|
355,805
|
|
|
(477,711
|
)
|
|
(121,906
|
)
|
Cancellation of Calpine Corporation common stock in accordance with the Merger Agreement
|
(362,033,696
|
)
|
|
1,639,511
|
|
|
(360,394,185
|
)
|
Conversion of Merger Sub common stock to Calpine Corporation common stock in accordance with the Merger Agreement
|
105.2
|
|
|
—
|
|
|
105.2
|
|
Balance, December 31, 2018
|
105.2
|
|
|
—
|
|
|
105.2
|
|
Shares issued under Calpine Equity Incentive Plans
|
—
|
|
|
—
|
|
|
—
|
|
Balance, December 31, 2019
|
105.2
|
|
|
—
|
|
|
105.2
|
|
|
|
16.
|
Commitments and Contingencies
|
Long-Term Service Agreements
As of December 31, 2019, the total estimated commitments for LTSAs associated with turbines were approximately $217 million. These commitments are payable over the remaining terms of the respective agreements, which range from 1 to 20 years. LTSA future commitment estimates are based on the stated payment terms in the contracts at the time of execution. 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.
Production Royalties
We are obligated under numerous geothermal contracts and right-of-way, easement and surface agreements. The geothermal contracts 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 contracts, 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 contract royalties. Some contracts contain clauses providing for minimum payments if production temporarily ceases or if production falls below a specified level. Production royalties for geothermal power plants for the years ended December 31, 2019, 2018 and 2017, were $24 million, $26 million and $25 million, respectively.
Commodity Purchases
We enter into commodity purchase contracts of various terms with third parties to supply fuel to our natural gas-fired power plants and power to our retail customers. 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, 2019, we had future commitments for the purchase, transportation, or storage of commodities as detailed below (in millions):
|
|
|
|
|
2020
|
$
|
402
|
|
2021
|
178
|
|
2022
|
121
|
|
2023
|
98
|
|
2024
|
41
|
|
Thereafter
|
103
|
|
Total
|
$
|
943
|
|
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, retail contracts, contracts associated with the development, construction, operation and maintenance of our fleet of power plants and our Accounts Receivable Sales Program. 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, 2019, guarantees of subsidiary debt, standby letters of credit and surety bonds to third parties and the guarantee under our Account Receivable Sales Program and their respective expiration dates were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Guarantee Commitments
|
|
2020
|
|
2021
|
|
2022
|
|
2023
|
|
2024
|
|
Thereafter
|
|
Total
|
Guarantee of subsidiary obligations(1)
|
|
$
|
30
|
|
|
$
|
29
|
|
|
$
|
24
|
|
|
$
|
14
|
|
|
$
|
13
|
|
|
$
|
39
|
|
|
$
|
149
|
|
Standby letters of credit(2)(3)(4)
|
|
1,015
|
|
|
32
|
|
|
—
|
|
|
38
|
|
|
—
|
|
|
—
|
|
|
1,085
|
|
Surety bonds(4)(5)(6)
|
|
10
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
94
|
|
|
111
|
|
Guarantee under Accounts Receivable Sales Program(7)
|
|
222
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
222
|
|
Total
|
|
$
|
1,277
|
|
|
$
|
68
|
|
|
$
|
24
|
|
|
$
|
52
|
|
|
$
|
13
|
|
|
$
|
133
|
|
|
$
|
1,567
|
|
____________
|
|
(1)
|
Represents Calpine Corporation guarantees of certain power plant leases and related interest. All guaranteed finance leases are recorded on our Consolidated Balance Sheets.
|
|
|
(2)
|
The standby letters of credit disclosed above represent those disclosed in Note 8.
|
|
|
(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)
|
These are contingent off balance sheet obligations.
|
|
|
(5)
|
The majority of surety bonds do not have expiration or cancellation dates.
|
|
|
(6)
|
As of December 31, 2019, no cash collateral is outstanding related to these bonds.
|
|
|
(7)
|
Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. The Accounts Receivable Sales Program expires on November 27, 2020.
|
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 third party, we would be responsible for reimbursing the issuing bank or surety within an agreed timeframe, typically a period of one to five 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, environmental products and fuel oil to and from third parties with respect to the operation of our power plants and our retail subsidiaries, we may be required to guarantee a portion of the obligations of certain of our subsidiaries. We may also be required to guarantee performance obligations associated with our marketing, hedging, optimization and trading activities to manage our exposure to changes in prices for energy commodities. 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, 2019, 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, individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows.
On a quarterly basis, we review our litigation activities and determine if an unfavorable outcome to us is considered “remote,” “reasonably possible” or “probable” as defined by U.S. GAAP. Where we determine an unfavorable outcome is probable and is reasonably estimable, we accrue for potential litigation losses. The liability we may ultimately incur with respect to such litigation matters, in the event of a negative outcome, may be in excess of amounts currently accrued, if any; however, we do not expect that the reasonably possible outcome of these litigation matters would, individually or in the aggregate, have a material adverse effect on our financial condition, results of operations or cash flows. Where we determine an unfavorable outcome is not probable or reasonably estimable, we do not accrue for any potential litigation loss. The ultimate outcome of these litigation matters cannot presently be determined, nor can the liability that could potentially result from a negative outcome be reasonably estimated.
As a result, we give no assurance that such litigation matters would, individually or in the aggregate, not have a material adverse effect on our financial condition, results of operations or cash flows.
Environmental Matters
We are subject to complex and stringent environmental laws and regulations related to the operation of our power plants. On occasion, we may incur environmental fees, penalties and fines associated with the operation of our power plants. At the present time, we do not have environmental violations or other matters that would have a material effect on our financial condition, results of operations or cash flows or that would significantly change our operations.
|
|
17.
|
Related Party Transactions
|
We have entered into various agreements with related parties associated with the operation of our business. A description of these related party transactions is provided below:
Accounts Receivable Sales Program
On December 1, 2016, in conjunction with our acquisition of Calpine Solutions, we entered into the Accounts Receivable Sales Program which allows us to sell, at a discount, up to $250 million in certain trade accounts receivable, arising from the sale of power and natural gas, from Calpine Solutions to Calpine Receivables which in turn sells 100% of the receivables to an unaffiliated financial institution, subject to certain contractual limitations. The Accounts Receivable Sales Program expires on November 27, 2020. Calpine Solutions services the receivables sold in exchange for a servicing fee which was not material for the years ended December 31, 2019, 2018 and 2017. We are not the primary beneficiary of Calpine Receivables and, accordingly, do not consolidate this entity in our Consolidated Financial Statements. See Note 7 for a further discussion of our unconsolidated VIEs. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a note receivable. The note receivable is recorded at fair value and does not materially differ from the carrying value of the trade accounts receivable held prior to sale due to the short-term nature of the receivables and high credit quality of the retail customers involved. Receivables sold under the Accounts Receivable Sales Program are accounted for as sales and excluded from accounts receivable on our Consolidated Balance Sheets and reflected as cash provided by operating activities on our Consolidated Statements of Cash Flows. Calpine has guaranteed the performance of Calpine Solutions under the Accounts Receivable Sales Program. See Note 16 for a further description of our guarantees.
Under the Accounts Receivable Sales Program, at December 31, 2019 and 2018, we had $222 million and $238 million, respectively, in trade accounts receivable outstanding that were sold under the Accounts Receivable Sales Program and $38 million and $34 million, respectively, in notes receivable which was recorded on our Consolidated Balance Sheets. We sold an aggregate of approximately $2.3 billion, $2.4 billion and $2.2 billion in trade accounts receivable and recorded proceeds of approximately $2.3 billion, $2.3 billion and $2.2 billion during the years ended December 31, 2019, 2018 and 2017, respectively. Any losses incurred on the sale of trade accounts receivable are recorded in other (income) expense, net on our Consolidated Statements of Operations which were not material during the years ended December 31, 2019, 2018 and 2017.
Lyondell — We have a ground lease agreement with Houston Refining LP (“Houston Refining”), a subsidiary of Lyondell, for our Channel Energy Center site from which we sell power, capacity and steam to Houston Refining under a PPA. We purchase refinery gas and raw water from Houston Refining under a facilities services agreement. One of the entities which obtained an ownership interest in Calpine through the Merger also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. During the year ended December 31, 2019 and 2018, we recorded $70 million and $76 million in operating revenues, respectively, and $14 million and $12 million in operating expenses, respectively, associated with Lyondell. At December 31, 2019 and 2018, the related party receivables and payables associated with this contract were immaterial.
Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity, steam and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. We have also entered into a long-term land lease agreement with a related party. As of December 31, 2019 and 2018, the related party revenues, expenses, receivables and payables associated with these transactions were immaterial.
|
|
18.
|
Segment and Significant Customer Information
|
We assess our business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. At December 31, 2019, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. We continue to evaluate the optimal manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments.
Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show our financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions).
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2019
|
|
Wholesale
|
|
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Consolidation
and
Elimination
|
|
Total
|
Total operating revenues(1)
|
$
|
2,743
|
|
|
$
|
3,081
|
|
|
$
|
2,164
|
|
|
$
|
4,093
|
|
|
$
|
(2,009
|
)
|
|
$
|
10,072
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
1,151
|
|
|
$
|
857
|
|
|
$
|
924
|
|
|
$
|
382
|
|
|
$
|
—
|
|
|
$
|
3,314
|
|
Add: Mark-to-market commodity activity, net and other(2)
|
219
|
|
|
154
|
|
|
46
|
|
|
(131
|
)
|
|
(34
|
)
|
|
254
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
340
|
|
|
269
|
|
|
278
|
|
|
148
|
|
|
(34
|
)
|
|
1,001
|
|
Depreciation and amortization expense
|
254
|
|
|
196
|
|
|
191
|
|
|
53
|
|
|
—
|
|
|
694
|
|
General and other administrative expense
|
35
|
|
|
53
|
|
|
45
|
|
|
17
|
|
|
—
|
|
|
150
|
|
Other operating expenses
|
31
|
|
|
6
|
|
|
42
|
|
|
—
|
|
|
—
|
|
|
79
|
|
Impairment losses
|
—
|
|
|
13
|
|
|
71
|
|
|
—
|
|
|
—
|
|
|
84
|
|
(Gain) on sale of assets, net
|
(4
|
)
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
2
|
|
|
—
|
|
|
(22
|
)
|
Income from operations
|
714
|
|
|
474
|
|
|
373
|
|
|
31
|
|
|
—
|
|
|
1,592
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
609
|
|
(Gain) loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
95
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
888
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2018
|
|
Wholesale
|
|
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Consolidation
and
Elimination
|
|
Total
|
Total operating revenues(1)
|
$
|
1,988
|
|
|
$
|
2,860
|
|
|
$
|
1,987
|
|
|
$
|
3,976
|
|
|
$
|
(1,299
|
)
|
|
$
|
9,512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
1,060
|
|
|
$
|
646
|
|
|
$
|
970
|
|
|
$
|
357
|
|
|
$
|
—
|
|
|
$
|
3,033
|
|
Add: Mark-to-market commodity activity, net and other(2)
|
(165
|
)
|
|
(197
|
)
|
|
40
|
|
|
84
|
|
|
(32
|
)
|
|
(270
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
348
|
|
|
272
|
|
|
269
|
|
|
163
|
|
|
(32
|
)
|
|
1,020
|
|
Depreciation and amortization expense
|
269
|
|
|
237
|
|
|
180
|
|
|
53
|
|
|
—
|
|
|
739
|
|
General and other administrative expense
|
40
|
|
|
61
|
|
|
38
|
|
|
19
|
|
|
—
|
|
|
158
|
|
Other operating expenses
|
42
|
|
|
24
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|
98
|
|
Impairment losses
|
—
|
|
|
—
|
|
|
10
|
|
|
—
|
|
|
—
|
|
|
10
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(26
|
)
|
|
2
|
|
|
—
|
|
|
(24
|
)
|
Income (loss) from operations
|
196
|
|
|
(145
|
)
|
|
507
|
|
|
204
|
|
|
—
|
|
|
762
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
617
|
|
(Gain) loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
53
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
92
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2017
|
|
Wholesale
|
|
|
|
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Consolidation
and
Elimination
|
|
Total
|
Total operating revenues(1)
|
$
|
1,881
|
|
|
$
|
2,342
|
|
|
$
|
1,658
|
|
|
$
|
3,797
|
|
|
$
|
(926
|
)
|
|
$
|
8,752
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
970
|
|
|
$
|
552
|
|
|
$
|
790
|
|
|
$
|
396
|
|
|
$
|
—
|
|
|
$
|
2,708
|
|
Add: Mark-to-market commodity activity, net and other(2)
|
(19
|
)
|
|
(174
|
)
|
|
(62
|
)
|
|
(10
|
)
|
|
(29
|
)
|
|
(294
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
361
|
|
|
308
|
|
|
302
|
|
|
138
|
|
|
(29
|
)
|
|
1,080
|
|
Depreciation and amortization expense
|
240
|
|
|
208
|
|
|
201
|
|
|
75
|
|
|
—
|
|
|
724
|
|
General and other administrative expense
|
45
|
|
|
66
|
|
|
27
|
|
|
17
|
|
|
—
|
|
|
155
|
|
Other operating expenses
|
38
|
|
|
14
|
|
|
33
|
|
|
—
|
|
|
—
|
|
|
85
|
|
Impairment losses
|
28
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
41
|
|
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(24
|
)
|
|
2
|
|
|
—
|
|
|
(22
|
)
|
Income (loss) from operations
|
239
|
|
|
(231
|
)
|
|
216
|
|
|
154
|
|
|
—
|
|
|
378
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
621
|
|
Debt modification and extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
70
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
(313
|
)
|
__________
|
|
(1)
|
Includes intersegment revenues of $530 million, $488 million and $324 million in the West, $946 million, $573 million and $361 million in Texas, $522 million, $234 million and $237 million in the East and $11 million, $4 million, $4 million in Retail for the years ended December 31, 2019, 2018 and 2017, respectively.
|
|
|
(2)
|
Includes $1 million, nil and $(8) million of lease levelization and $78 million, $104 million and $178 million of amortization expense for the years ended December 31, 2019, 2018 and 2017, respectively.
|
Significant Customers
For the years ended December 31, 2019, 2018 and 2017, we had no significant customer that individually accounted for more than 10% of our annual consolidated revenues.
|
|
19.
|
Quarterly Consolidated Financial Data (unaudited)
|
Our quarterly operating results have fluctuated in the past and may continue to do so in the future as a result of a number of factors, including, but not limited to, our restructuring activities (including asset sales and dispositions), 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)
|
2019
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
2,082
|
|
|
$
|
2,792
|
|
|
$
|
2,599
|
|
|
$
|
2,599
|
|
Income from operations
|
$
|
108
|
|
|
$
|
682
|
|
|
$
|
444
|
|
|
$
|
358
|
|
Net income (loss) attributable to Calpine
|
$
|
(156
|
)
|
|
$
|
485
|
|
|
$
|
266
|
|
|
$
|
175
|
|
|
|
|
|
|
|
|
|
2018
|
|
|
|
|
|
|
|
Operating revenues
|
$
|
2,354
|
|
|
$
|
2,890
|
|
|
$
|
2,259
|
|
|
$
|
2,009
|
|
Income (loss) from operations
|
$
|
105
|
|
|
$
|
568
|
|
|
$
|
417
|
|
|
$
|
(328
|
)
|
Net income (loss) attributable to Calpine
|
$
|
(16
|
)
|
|
$
|
272
|
|
|
$
|
352
|
|
|
$
|
(598
|
)
|