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•	Financial results that may be volatile and may not reflect historical trends due to, among other things, seasonality of demand, fluctuations in prices for commodities such as natural gas and power, changes in U.S. macroeconomic conditions, fluctuations in liquidity and volatility in the energy commodities markets and our ability and extent to which we hedge risks;

•	Laws, regulations and market rules in the wholesale and retail markets in which we participate and our ability to effectively respond to changes in laws, regulations or market rules or the interpretation thereof including those related to the environment, derivative transactions and market design in the regions in which we operate;

•	Our ability to manage our liquidity needs, access the capital markets when necessary and comply with covenants under our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, Corporate Revolving Facility, CCFC Term Loan and other existing financing obligations;

•	Risks associated with the operation, construction and development of power plants, including unscheduled outages or delays and plant efficiencies;

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Risks related to our geothermal resources, including the adequacy of our steam reserves, unusual or unexpected steam field well and pipeline maintenance requirements, variables associated with the injection of water to the steam reservoir and potential regulations or other requirements related to seismicity concerns that may delay or increase the cost of developing or operating geothermal resources;

•	Extensive competition in our wholesale and retail businesses, including from renewable sources of power, interference by states in competitive power markets through subsidies or similar support for new or existing power plants, lower prices and other incentives offered by retail competitors, and other risks associated with marketing and selling power in the evolving energy markets;

•	Structural changes in the supply and demand of power, resulting from the development of new fuels or technologies and demand-side management tools (such as distributed generation, power storage and other technologies);

•	The expiration or early termination of our PPAs and the related results on revenues;

•	Future capacity revenue may not occur at expected levels;

•	Natural disasters, such as hurricanes, earthquakes, droughts and floods, acts of terrorism, cyber attacks or wildfires that may affect our power plants or the markets our power plants or retail operations serve and our corporate offices;

•	Disruptions in or limitations on the transportation of natural gas or fuel oil and the transmission of power;

•	Our ability to manage our counterparty and customer exposure and credit risk, including our commodity positions or if a significant customer were to seek bankruptcy protection under Chapter 11;

•	Our ability to attract, motivate and retain key employees;

•	Present and possible future claims, litigation and enforcement actions that may arise from noncompliance with market rules promulgated by the SEC, CFTC, FERC and other regulatory bodies; and

•	Other risks identified in this Report.

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Item 1.	Business

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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.

•	Fourth, our cogeneration power plants produce steam, in addition to electricity, for sale to industrial customers for use in their manufacturing processes or heating, ventilation and air conditioning operations.

•	Fifth, we provide ancillary service products to wholesale power markets. These products include the right for the purchaser to call on our generation to provide flexibility to the market and support operation of the electric grid.

•	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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•	26% related to leases with the federal government via the Office of Natural Resources Revenue,

•	31% related to leases with the California State Lands Commission and

•	43% related to leases with private landowners/leaseholders.

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(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.

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Item 1A.	Risk Factors

•	increases and decreases in generation capacity in our markets;

•	changes in power transmission or fuel transportation capacity constraints or inefficiencies;

•	volatile weather conditions, particularly unusually hot or mild summers or unusually cold or warm winters in our market areas;

•	an economic downturn which could negatively affect demand for power;

•	changes in the supply of commodities utilized as fuel sources for power generation, including but not limited to coal, natural gas and fuel oil;

•	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;

•	federal and state power, market and environmental regulation and legislation, including mandating an RPS or creating financial incentives, each resulting in new renewable energy generation capacity creating oversupply;

•	changes in prices related to RECs and other environmental allowance products; and

•	changes in capacity prices and capacity markets.

•	rate caps, price limitations and bidding rules imposed by ISOs, RTOs and other market regulators that may impair our ability to recover our costs and limit our return on our capital investments;

•	regulations promulgated by the FERC, the CFTC and state public utility commissions;

•	sufficient liquidity in the forward commodity markets to conduct our hedging activities;

•	some of our competitors (mainly utilities) receive entitlement-guaranteed rates of return on their capital investments, with returns that exceed market returns and may affect our ability to sell our power at economical rates;

•	structure and operating characteristics of our capacity markets such as the PJM and ISO-NE capacity auctions and the NYISO and California markets; and

•	regulations and market rules related to our RECs.

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•	the cessation or abandonment of the development, construction, maintenance or operation of a power plant;

•	failure of a power plant to achieve construction milestones or commercial operation by agreed-upon deadlines;

•	failure of a power plant to achieve certain output or efficiency minimums;

•	our failure to make any of the payments owed to the counterparty or to establish, maintain, restore, extend the term of or increase any required collateral;

•	failure of a power plant to obtain material permits and regulatory approvals by agreed-upon deadlines;

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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

•	events of liquidation, dissolution, insolvency or bankruptcy.

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•	necessary power generation or storage equipment;

•	governmental permits and approvals including environmental permits and approvals;

•	fuel supply and transportation agreements;

•	sufficient equity capital and debt financing;

•	power transmission agreements;

•	water supply and wastewater discharge agreements or permits; and

•	site agreements and construction contracts.

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•	transportation may be unavailable if pipeline infrastructure is damaged or disabled;

•	pipeline tariff changes may adversely affect our ability to, or cost to, deliver natural gas and fuel oil supply;

•	new pipelines and pipeline expansions may not be permitted in a timely manner due to environmental concerns or prolonged regulatory processes;

•	third-party suppliers may default on natural gas supply obligations, and we may be unable to replace supplies currently under contract;

•	market liquidity for physical natural gas and fuel oil or availability of natural gas and fuel oil services (e.g. storage) may be insufficient or available only at prices that are not acceptable to us;

•	natural gas and fuel oil quality variation may adversely affect our power plant operations;

•	our natural gas and fuel oil operations capability may be compromised due to various events such as natural disaster, loss of key personnel or loss of critical infrastructure;

•	fuel supplies diverted to residential heating for humanitarian reasons; and

•	any other reasons.

•	the heat content of the extractable steam or fluids;

•	the geology of the reservoir;

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•	the total amount of recoverable reserves;

•	operating expenses relating to the extraction of steam or fluids;

•	price levels relating to the extraction of steam, fluids or power generated; and

•	capital expenditure requirements relating primarily to the drilling of new wells.

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•	limiting our ability to borrow additional amounts for working capital, capital expenditures, debt service requirements, potential growth or other purposes;

•	limiting our ability to use operating cash flows in other areas of our business because we must dedicate a substantial portion of these funds to service our debt;

•	increasing our vulnerability to general adverse economic and industry conditions;

•	limiting our ability to capitalize on business opportunities and to react to competitive pressures and adverse changes in governmental regulation;

•	limiting our ability or increasing the costs to refinance indebtedness; and

•	limiting our ability to enter into marketing, hedging and optimization activities by reducing the number of counterparties with whom we can transact as well as the volume and type of those transactions.

•	low credit ratings may prevent us from obtaining any material amount of additional debt financing;

•	conditions in energy commodity markets;

•	regulatory developments;

•	credit availability from banks or other lenders for us and our industry peers;

•	investor confidence in the industry and in us;

•	the continued reliable operation of our current power plants; and

•	provisions of tax, regulatory and securities laws that are conducive to raising capital.

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•	incur or guarantee additional first lien indebtedness up to certain consolidated net tangible asset ratios;

•	enter into certain types of commodity hedge agreements that can be secured by first lien collateral;

•	enter into sale and leaseback transactions;

•	make certain investments;

•	create or incur liens;

•	consolidate or merge with or transfer all or substantially all of our assets to another entity, or allow substantially all of our subsidiaries to do so;

•	lease, transfer or sell assets and use proceeds of permitted asset leases, transfers or sales;

•	engage in certain business activities; and

•	enter into certain transactions with our affiliates.

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Item 1B.	Unresolved Staff Comments

Item 2.	Properties

Item 3.	Legal Proceedings

Item 4.	Mine Safety Disclosures

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Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

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Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations

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#	Variance of 100% or greater

(1)	Represents generation and capacity from power plants that we both consolidate and operate. See “— Description of Our Power Plants – Table of Operating Power Plants and Project Under Construction” for our total equity generation and capacities.

(2)	Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.

(1)	Commodity Margin excludes amortization expense related to contracts recorded at fair value, non-cash GAAP-related adjustments to levelize revenues from tolling agreements, Commodity revenue and Commodity expense attributable to the noncontrolling interest and other unusual or non-recurring items.

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(1)

Our ability to use corporate cash and cash equivalents is unrestricted. On January 21, 2020, we used the remaining cash on hand from the issuance of our 2028 First Lien Notes and 2028 Senior Unsecured Notes to redeem the remaining approximately $1,052 million aggregate principal amount of our 2022 and 2024 First Lien Notes and 2023 Senior Unsecured Notes. See Note 8 of the Notes to Consolidated Financial Statements for further information related to the redemption of our 2022 and 2024 First Lien Notes and 2023 Senior Unsecured Notes.

(2)	See Note 2 of the Notes to Consolidated Financial Statements for a description of the restrictions on our use of non-corporate cash and cash equivalents and restricted cash.

(3)

Our ability to use availability under our Corporate Revolving Facility is unrestricted. 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. See “Letter of Credit Facilities” below for amounts issued under letters of credit at December 31, 2019 associated with our Corporate Revolving Facility.

(4)

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. 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.

(5)	We have three unsecured letter of credit facilities with two third-party financial institutions totaling approximately $300 million at December 31, 2019.

(6)	Includes $127 million and $52 million of margin deposits posted with us by our counterparties at December 31, 2019 and 2018, respectively. See Note 11 of the Notes to Consolidated Financial Statements for further information related to our collateral.

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•	the level of Market Heat Rates;

•	our continued ability to successfully hedge our Commodity Margin;

•	changes in U.S. macroeconomic conditions;

•	maintaining acceptable availability levels for our fleet;

•	the effect of current and pending environmental regulations in the markets in which we participate;

•	improving the efficiency and profitability of our operations;

•	increasing future contractual cash flows; and

•	our significant counterparties performing under their contracts with us.

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(1)

The Corporate Revolving Facility represents our primary 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.

(2)	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.

(3)

We have three unsecured letter of credit facilities with two third-party financial institutions totaling approximately $300 million at December 31, 2019. 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.

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Income from operations — Income from operations, adjusted for non-cash items, increased by $325 million for the year ended December 31, 2019, compared to 2018. Non-cash items consist primarily of depreciation and amortization, impairment losses, gain on sale of assets and mark-to-market activity. The increase in income from operations was primarily driven by a $322 million increase in Commodity revenue, net of Commodity expense. See “Results of Operations for the Year Ended December 31, 2019 and 2018” above for further discussion of these changes.

•	Working capital employed — Working capital employed decreased by $169 million for the year ended December 31, 2019, compared to the same period in 2018. This change was primarily due to margin posting activity on our commodity hedging activities as well as timing differences relating to procurement of environmental products for compliance purposes.

•	Divestitures — During the year ended December 31, 2019, we closed on the sale of the Garrison and RockGen Energy Centers for approximately $303 million.

•	Capital expenditures — We incurred higher capital expenditures on construction and growth projects during the year ended December 31, 2019, as compared to the year ended December 31, 2018.

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Debt transactions — During the year ended December 31, 2019, we refinanced $4.1 billion of our First Lien Term Loans, First Lien Notes and Senior Unsecured Notes resulting in a net borrowing of $1.3 billion for the year ended December 31, 2019. Approximately $1.1 billion of the net borrowing is attributable to a timing difference as call redemptions on our 2022 and 2024 First Lien Notes and 2023 Senior Unsecured Notes were issued during December 2019 and not funded until January 21, 2020. The remaining net borrowing is attributable to the repayment of our OMEC project debt facility with a portion of the proceeds from our 2026 First Lien Term Loans during the year ended December 31, 2019. During the year ended December 31, 2018, we repurchased $390 million in aggregate principal of our Senior Unsecured Notes for $355 million as compared to repurchases of $48 million in aggregate principal during 2019.

•	Project financing, note payable and other — During the year ended December 31, 2019, project debt, notes payable and finance leases outstanding were reduced by $404 million as a result of standard amortization payments as well as the repayment of the project debt associated with OMEC in the amount of $220 million as noted above. During

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•	Dividends Paid — During the year ended December 31, 2019, we paid dividends to our parent, CPN Management, of $1.15 billion from the proceeds of the sale of the Garrison Energy Center and RockGen Energy Center and from cash on hand. We paid a $20 million dividend to CPN Management during 2018.

•	Stock Repurchases — During the year ended December 31, 2018, we repurchased $79 million of our equity classified share-based awards on the effective date of the Merger. There was no similar activity during the year ended December 31, 2019.

•	Commodity liability — During the year ended December 31, 2019, we recognized a liability for the fair value of two financial commodity contracts that were executed at closing of the sale of the Garrison and RockGen Energy Centers. The proceeds, net of repayments, through December 31, 2019 were $50 million. There was no similar activity during the year ended December 31, 2018.

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(1)	Included in the total are future minimum payments for office, land and other operating leases. See Note 4 of the Notes to Consolidated Financial Statements for more information.

(2)	The amounts presented here include contractually obligated amounts for the purchase, transportation or storage of commodities accounted for as executory contracts and therefore not recognized on our Consolidated Balance Sheet.

(3)	The amounts presented here are based on estimated payments in accordance with the stated payment terms in the contracts at the time of execution.

(4)	The amounts presented here are based on contractually obligated amounts over the life of the contracts.

(5)	The amounts presented here include costs to complete construction projects, parts supply agreements, maintenance agreements, information technology agreements and other purchase obligations.

(6)	Amounts are projected based upon spot and forward interest rates at December 31, 2019.

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(1)

Commodity contract settlements consist of the realization of previously recognized losses on contracts not designated as hedging instruments of $(202) million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Statements of Operations) and $(23) million related to current period losses from other changes in derivative assets and liabilities not reflected in OCI or earnings.

(2)	Interest rate settlements consist of $25 million related to realized gains from settlements of designated cash flow hedges and nil related to roll-off from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Statements of Operations).

(3)	Fair value attributable to new contracts includes $(18) million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings.

(4)

We netted all amounts allowed under the derivative accounting guidance on the Consolidated Balance Sheet, which includes derivative transactions under enforceable master netting arrangements and related cash collateral. Net commodity and interest rate derivative assets and liabilities reported in Notes 9 and 10 of the Notes to Consolidated Financial Statements and are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements.

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•	credit approvals;

•	routine monitoring of counterparties’ and customer’s credit limits and their overall credit ratings;

•	limiting our marketing, hedging and optimization activities with high risk counterparties;

•	margin, collateral, or prepayment arrangements; and

•	payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty.

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(1)	Primarily comprised of the fair value of derivative instruments held with customers that are not rated by third party credit agencies due to the nature and size of the customers.

(1)	Projection based upon forward LIBOR rates inferred from spot rates at December 31, 2019.

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•	a contract that qualifies as a lease;

•	a derivative;

•	a contract that meets the definition of a derivative but is eligible for the normal purchase normal sale exemption; or

•	a contract that is a physical or executory contract.

•	power revenues consisting of fixed and variable capacity payments, including capacity payments received from PJM and ISO-NE capacity auctions which are not related to generation;

•	other revenues such as RMR Contracts, resource adequacy and certain ancillary service revenues; and

•	sales of natural gas and other service revenues.

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•	perform an ongoing reassessment each reporting period of whether we are the primary beneficiary of our VIEs; and

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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.

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•	a significant decrease in the market price of a long-lived asset;

•	a significant adverse change in the manner an asset is being used or its physical condition;

•	an adverse action by a regulator or legislature or an adverse change in the business climate;

•	an accumulation of costs significantly in excess of the amount originally expected for the construction or acquisition of an asset;

•	a current-period loss combined with a history of losses or the projection of future losses; or

•	a change in our intent about an asset from an intent to hold to a greater than 50% likelihood that an asset will be sold or disposed of before the end of its previously estimated useful life.

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Item 7A.	Quantitative and Qualitative Disclosures about Market Risk

Item 8.	Financial Statements and Supplementary Data

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

Item 9A.	Controls and Procedures

•	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

•	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

•	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

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Item 9B.	Other Information

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Item 10.	Directors, Executive Officers and Corporate Governance

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(1)	See “Directors” above for biographical information.

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Item 11.	Executive Compensation

•	Alignment with Owners’ Interests. Our long-term incentive awards align our named executive officers’ interests with the interests of our owners by rewarding increases in the value of our business, incentivizing retention and optimizing long-term financial performance.

•	Pay for Performance. A significant portion of compensation for our named executive officers is linked to the achievement of corporate operating and financial objectives that we believe drive long-term value.

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Emphasis on Performance Over Time. The compensation program for our named executive officers is designed to minimize excessive short-term decision making and imprudent risk taking. The potential value of long-term incentives could be substantially greater than the annual cash incentive bonus based upon the creation of long-term value. Additionally, our annual incentive plan limits the maximum cash incentive bonus that can be earned in a given year. The Compensation Committee also retains the discretionary power to reduce annual incentive awards below calculated values.

•	Recruitment, Retention and Motivation of Key Leadership Talent. We provide an appropriate combination of fixed and variable compensation designed not only to attract and motivate the most talented executives for Calpine,

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•	our budget for annual merit increases;

•	the appropriateness of each executive officer’s compensation, both individually and relative to the other executive officers; and

•	the individual performance of each executive officer.

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(1)	Threshold and maximum incentive levels for each Performance Measure under the CIP are displayed as 0% and 200%, respectively, of the target incentive percentage for Commodity Margin, Expenses, CAPEX/Maintenance and Average EFOF. Actual results for these Performance Measures can exceed the maximum incentive level. TRIR has a maximum incentive level of 150% and Regulatory Compliance is Pass/Fail.

(2)	Although the individual Performance Measures have no cap, the overall CIP payout (or Final Performance Score) is capped at 150%.

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Commodity Margin, as used for purposes of determining our CIP goal, is a financial measure that includes power and steam revenues, sales of purchased power and physical natural gas, capacity revenues, REC revenue, sales of surplus emission allowances, transmission revenue and expenses, fuel and purchased energy expense, fuel transportation expense, environmental compliance expenses, ancillary retail expense and realized settlements from marketing, hedging, optimization and trading activities, but excludes mark-to-market activity. Commodity Margin is a key operational measure of profit used to assess the performance of our business. This amount differs from “Commodity Margin” as reported under FASB Accounting Standards Codification 280 in this Report as it also includes other revenue, as referenced in the CIP performance score calculation, Adjusted EBITDA from Calpine’s unconsolidated operations at Greenfield and Whitby (prior to the sale of our interest in Whitby), and certain other adjustments approved by the Compensation Committee.

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Expenses, as used solely for purposes of determining our CIP pool, are comprised of Operating and Maintenance Expense (excluding major maintenance, scrap and certain other items), Royalty Expense from Calpine’s geothermal operations, General & Other Administrative Expense (excluding certain other items), and Other Operating Expense (excluding amortization and Merger-related costs), in each case, as calculated in accordance with U.S. GAAP and included in the amounts reported on our Consolidated Statement of Operations for the year ended December 31, 2019 in this Report. We believe that Expenses are a useful tool for assessing the performance of our core operations and are a key operational measure reviewed by our management.

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CAPEX/Maintenance refers to Calpine’s Capital Expenditure and Major Maintenance Expense related to the refurbishment of major turbine generator equipment and other plant-related facilities inclusive of Calpine’s unconsolidated operations at Greenfield and Whitby (prior to the sale of our interest in Whitby). CAPEX is capitalized into Property, Plant and Equipment and Maintenance is recorded as a component of Operating and Maintenance Expense. We monitor these expenditures and establish targets as useful tools to measure our operating performance. We believe that monitoring our Capital Expenditure and Major Maintenance Expense allows us to ensure that planned capital projects are not experiencing cost overruns.

•	Average EFOF refers to Equivalent Forced Outage Factor, which is a measure indicating the percent of time that our power plants are not capable of reaching full capacity due to forced outages and forced equipment limitations and is a key operating measure to assess plant availability.

•	TRIR refers to Total Recordable Incident Rate, which is a measure of operational safety. We place a high priority on the safety of our employees. TRIR is calculated as the sum of our lost time, restricted duty and other recordable cases as well as any fatality incidents during the year multiplied by 200,000 and then divided by total hours worked during the year.

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•	Regulatory Compliance refers to the Compensation Committee evaluation of overall regulatory compliance based on consultation with the Chief Compliance Officer to ensure compliance with all applicable statutes in the operation of our business.

•	Board Discretionary Increase/Decrease Factor represents the Board of Directors’ consideration of the quantitative outcomes of the Performance Measures and any additional factors taken into consideration which would result in the Board of Directors, in its discretion, adjusting the calculated outcomes.

(1)	The maximum incentive as a percentage of base salary is set forth in the employment agreement for these named executive officers.

(2)	Mr. Gates’ maximum incentive is consistent with the terms of the CIP.

(3)	Incremental Incentive Rate equals the additional percentage of eligible earnings for each percent that Overall Performance Score exceeds 100%. Rate is calculated as the ratio of the difference between maximum and target incentive percentage and maximum and target Performance Score.

(4)	From 2019 CIP performance score calculation shown above.

(5)	Incentive % equals sum of Target Incentive plus product of excess of Overall Performance Score over 100% multiplied by Incremental Incentive Rate.

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(1)	Bonus paid pursuant to the CIP and/or the named executive officer’s employment agreement or letter agreement, as applicable.

(2)	For 2019, the amounts set forth under “All Other Compensation” for Messrs. Hill, Rauf, Miller and Gates represents $14,000 in employer contributions to the Company’s 401(k) Plan and $2,500 in non-discretionary employer contribution.

(3)

The Class B Interests do not have a grant date fair value as these awards are accounted for as profit sharing arrangements under FASB Accounting Standards Codification Topic 710. For a further description of the Class B Interests, see “Compensation Discussion and Analysis — Elements of Compensation — Details of Each Element of Compensation — Long-Term Incentives.” The market value for the Class B Interests is not determinable as there is no public market for the Class B Interests. As such, the fair value of the Class B Interests is not included herein. We did not record any expense in our Consolidated Statement of Operations for the year ended December 31, 2019 associated with the Class B Interests.

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(1)

Amounts represent estimated possible payments under the CIP. Actual amounts paid under the CIP for 2019 are shown in the “Non-Equity Incentive Plan Compensation” column of the “Summary Compensation Table.” For more information on the performance metrics applicable to these awards, see “Compensation Discussion and Analysis — Details of Each Element of Compensation — Annual Incentive — Calpine Incentive Plan.”

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a lump sum payment within 60 days following termination in an amount equal to 2.99 times (in the case of a Tier 1, Tier 2 or Tier 3 participant) or 1.99 times (in the case of a Tier 4 participant) the sum of (i) the participant’s highest annual salary in the three years preceding the termination and (ii) the participant’s target bonus for the year of termination or for the year in which the change in control occurred, whichever is larger; plus

•	in the case of a Tier 1 participant only, a pro-rated annual bonus for the year of termination, to be paid at such time as we pay annual bonuses generally; plus

•	a lump sum payment for all “accrued obligations,” defined as all unused vacation time and all accrued but unpaid compensation earned by such participant as of the termination date, to be paid as soon as practicable following the termination date; and

•

continued coverage for the participant and his or her dependents under all health care, medical, dental and life insurance plans and programs (excluding disability) maintained by us under which the participant was covered immediately prior to his or her termination date, to be provided (concurrently with any health care benefit required under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended, “COBRA”), in the case of a Tier 1, Tier 2 or Tier 3 participant, for a period of 36 months following termination, at the same cost sharing between us and such participant as applies to a similarly situated active employee.

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In the case of a Tier 1 participant, (i) a lump sum payment within 60 days following termination in an amount equal to 2.0 times the sum of (a) the participant’s highest annual salary in the three years preceding termination and (b) the participant’s highest target bonus for the year of termination; plus (ii) payment of all accrued obligations as soon as practicable following the termination date; plus (iii) a pro-rated annual bonus for the year of termination, to be paid at such time as we pay annual bonuses generally;

•

In the case of a Tier 2 or Tier 3 participant, (i) a lump sum payment within 60 days following termination in an amount equal to 1.5 times the sum of (a) the participant’s highest annual salary in the three years preceding termination and (b) the participant’s highest target bonus for the year of termination; plus (ii) payment of all accrued obligations as soon as practicable following the termination date; and

•	In the case of a Tier 4 participant, (i) a lump sum payment within 60 days following termination in an amount equal to the sum of (a) the participant’s highest annual salary in the three years preceding termination and (b) the participant’s highest target bonus for the year of termination; plus (ii) payment of all accrued obligations as soon as practicable following the termination date.

•	a prorated bonus for the year in which such termination occurs;

•	a lump sum cash severance payment equal to 3.0 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his highest target bonus with respect to the year of termination or for 2018, whichever is larger;

•	a monthly payment for a period of 36 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	reimbursement for payment for outplacement services for a period of up to 24 months following such termination.

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•	a prorated bonus for the year in which such termination occurs calculated based on the Company’s actual performance;

•	a lump sum cash severance payment equal to 2.0 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his highest target bonus with respect to the year of termination;

•	a monthly payment for a period of 24 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	reimbursement for payment for outplacement services for a period of up to 24 months following such termination.

•	a full annual bonus for the year in which such termination occurs calculated based on actual Company performance; and

•	a monthly payment for a period of 18 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments.

•	a prorated bonus for the year in which such termination occurs calculated based on actual Company performance and the number of days in the year of termination that Mr. Hill was employed by the Company;

•	a monthly payment for a period of 24 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	consent rights regarding certain redemption, repurchase, and / or call rights that may be applicable to vested Class B Interests.

•	in the event of a change in control of the Company, the Class B Interests will become fully vested; and

•	if Mr. Hill’s employment terminates by reason of disability or death, the Class B Interests will become fully vested.

•	a prorated bonus for the year in which such termination would have occurred calculated based on actual Company performance;

•	a lump sum cash severance payment equal to 3.0 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his target bonus with respect to the year of termination or for 2018, if higher;

•	a monthly payment for a period of 36 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	outplacement services for a period of up to 18 months following such termination.

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•	a prorated bonus for the year in which such termination occurs calculated based on actual Company performance;

•	a lump sum cash severance payment equal to 1.5 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his target bonus with respect to the year of termination;

•	a monthly payment for a period of 18 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	reimbursement for payment for outplacement services for a period of up to 18 months following such termination.

•	a full annual bonus for the year in which such termination occurs calculated based on actual Company performance; and

•	for the remainder of the employment term, a monthly payment equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments.

•	a prorated bonus for the year in which such termination occurs calculated based on actual Company performance;

•	a monthly payment for a period of 18 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	consent rights regarding certain redemption, repurchase, and / or call rights that may be applicable to vested Class B Interests.

•	in the event of a change in control of the Company, the Class B Interests will become fully vested; and

•	if Mr. Miller’s employment terminates by reason of disability or death, the Class B Interests will become fully vested.

•	a prorated bonus for the year in which such termination would have occurred;

•	a lump sum cash severance payment equal to 3.0 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his target bonus with respect to the year of termination or for 2018, whichever is larger;

•	a monthly payment for a period of 36 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	outplacement services for a period of up to 18 months following such termination.

•	a prorated bonus for the year in which such termination occurs;

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•	a lump sum cash severance payment equal to 1.5 times the sum of (i) his highest base salary in the three years preceding termination and (ii) his target bonus with respect to the year of termination;

•	a monthly payment for a period of 18 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	reimbursement for payment for outplacement services for a period of up to 18 months following such termination.

•	a full annual bonus for the year in which such termination occurs calculated based on actual Company performance; and

•	for the remainder of the employment term, a monthly payment equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments.

•	a prorated bonus for the year in which such termination occurs calculated based on actual Company performance;

•	a monthly payment for a period of 18 months following the date of termination equal to the full monthly premium paid by other former employees for continuation coverage under the Company’s health plans, as well as a tax gross-up on such payments; and

•	consent rights regarding certain redemption, repurchase, and / or call rights that may be applicable to vested Class B Interests.

•	in the event of a change in control of the Company, the Class B Interests will become fully vested; and

•	if Mr. Rauf’s employment terminates by reason of disability or death, the Class B Interests will become fully vested.

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(1)	Amounts disclosed in the table assume that no executive received any severance or termination benefit which would decrease the amount of the above payments, where applicable. These amounts would primarily be paid as a lump sum but have been calculated without any present-value discount and assuming that base pay would continue at 2019 rates.

(2)

Using generally accepted accounting principles for purposes of the Company’s financial statements, continued health and welfare benefits were valued at the amount of $2,864 per month (for family coverage) which applied to Messrs. Hill and Rauf and $1,990 per month (for employee and spouse coverage) which applied to Messrs. Miller and Gates. Outplacement services were valued at $50,000 for 18 and 24 months of coverage.

(3)	Class B Interests only entitle the holder to future distributions from CPN Management. Distributions from CPN Management are made at the discretion of the general partner.

(4)

The gross-up payment is an additional amount that we are obligated to pay to Mr. Gates pursuant to the Gates Letter Agreement in order to make the executive whole for any federal excise tax imposed on the executive as a result of the executive’s receipt of any excess parachute payments that are contingent upon a change of control, as well as the payment of all federal and state income and excise taxes imposed on the gross-up payment.

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•	base salary,

•	compensation under the annual incentive program or equivalent (calculated assuming payouts at the target level for employees hired in 2019 who were not eligible for an incentive payment in 2019), and

•	employer contributions to the Company’s 401(k) Plan.

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Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

(1)	The principal business address of CPN Management, LP is 40 Beachwood Road, Summit, NJ 07901.

(2)

ECP ControlCo, LLC is the sole managing member of Energy Capital Partners III, LLC, which is the sole managing member of Volt Parent GP, LLC, which is the general partner of each of Volt Parent, LP and CPN Management. Douglas Kimmelman, Andrew Singer, Peter Labbat, Tyler Reeder and Rahman D’Argenio are the managing members of ECP ControlCo, LLC and share the power to vote and dispose of the securities beneficially owned by ECP ControlCo, LLC. As such, each of ECP ControlCo, LLC, Energy Capital Partners III, LLC, Volt Parent GP, LLC, and Messrs. Kimmelman, Singer, Labbat, Reeder and D’Argenio may be deemed to have or share beneficial ownership of the common stock held directly by CPN Management. Each such entity or individual disclaims any such beneficial ownership. The principal business address of each of the entities and individuals listed in this footnote is 40 Beachwood Road, Summit, NJ 07901.

Item 13.	Certain Relationships and Related Transactions, and Director Independence

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•	ECP ControlCo, LLC

•	CPPIB Calpine Canada, Inc.

•	Access Industries, Inc.

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Item 14.	Principal Accounting Fees and Services

(1)	Our Audit fees consisted of approximately $4.9 million and $4.4 million for the audits and quarterly reviews of our consolidated financial statements and other offerings for Calpine Corporation for 2019 and 2018, respectively, and fees of approximately $1.1 million and $1.0 million for 2019 and 2018, respectively, which were billed for performing audits and reviews of certain of our subsidiaries.

(2)	PwC did not provide us with any material tax consulting services for the years ended December 31, 2019 and 2018.

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Item 15.	Exhibits, Financial Statement Schedule

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*	Filed herewith.

‡	Furnished herewith.

†	Management contract or compensatory plan, contract or arrangement.

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(1)	Includes amortization included in Commodity revenue and Commodity expense associated with intangible assets and amortization recorded in interest expense associated with debt issuance costs and discounts.

(2)	Dividends paid during the years ended December 31, 2019 and 2018, includes approximately $1 million and $20 million, respectively, in certain Merger-related costs incurred by CPN Management, our parent.

(3)	Our cash and cash equivalents, restricted cash, current and restricted cash, net of current portion are stated as separate line items on our Consolidated Balance Sheets.

(4)	On April 3, 2017, we completed the purchase of the King City Cogeneration Plant lease in exchange for a three-year promissory note with a discounted value of $57 million. We recorded a net increase to property, plant and equipment, net on our Consolidated Balance Sheet of $15 million due to the increased value of the promissory note as compared to the carrying value of the lease.

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1.	Organization and Operations

2.	Summary of Significant Accounting Policies

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•	financial institutions and trading companies;

•	regulated utilities, municipalities, cooperatives, ISOs and other retail power suppliers;

•	oil, natural gas, chemical and other energy-related industrial companies; and

•	commercial, industrial and residential retail customers.

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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

•	sales of natural gas and other service revenues.

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3.	Revenue from Contracts with Customers

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(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.

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4.	Leases

•	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

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•	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.

(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.

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(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.

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(1)	Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Statement of Operations.

(1)	Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts.

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(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.

5.	Acquisitions and Divestitures

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6.	Property, Plant and Equipment, Net

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7.	Variable Interest Entities and Unconsolidated Investments

•	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.

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(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.

(1)	On November 20, 2019, we sold our 50% interest in Whitby to a third party.

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8.	Debt

(1)	Our weighted average interest rate calculation includes the amortization of debt issuance costs.

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(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.

•	general unsecured obligations of Calpine;

•	rank equally in right of payment with all of Calpine’s existing and future senior indebtedness;

•	effectively subordinated to Calpine’s secured indebtedness to the extent of the value of the collateral securing such indebtedness;

•	structurally subordinated to any existing and future indebtedness and other liabilities of Calpine’s subsidiaries; and

•	senior in right of payment to any of Calpine’s subordinated indebtedness.

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(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.

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(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.

•	incur or guarantee additional first lien indebtedness;

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•	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.

(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.

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(1)	Our weighted average interest rate calculation includes the amortization of debt issuance costs and debt discount.

•	incur or guarantee additional first lien indebtedness;

•	enter into sale and leaseback transactions;

•	create liens;

•	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.

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(1)	Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.

9.	Assets and Liabilities with Recurring Fair Value Measurements

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(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.

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(1)	Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.

(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.

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10.	Derivative Instruments

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(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.

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(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.

(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.

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(3)	Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions.

(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.

11.	Use of Collateral

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(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.

12.	Income Taxes

•	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.

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13.	Stock-Based Compensation

•	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.

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14.	Defined Contribution and Defined Benefit Plans

15.	Capital Structure

16.	Commitments and Contingencies

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(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.

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(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.

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17.	Related Party Transactions

18.	Segment and Significant Customer Information

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(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.

19.	Quarterly Consolidated Financial Data (unaudited)

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