13 | |
(2) | On August 10, 2020, we utilized proceeds from our 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes, together with cash on hand, to purchase approximately $255 million and $1,045 million in aggregate principal amount of our 2024 Senior Unsecured Notes and 2025 Senior Unsecured Notes, respectively. On August 12, 2020, we redeemed the remaining amounts outstanding under our 2024 Senior Unsecured Notes and 2025 Senior Unsecured Notes. |
On August 10, 2020, we issued $650 million in aggregate principal amount of 4.625% senior unsecured notes due 2029 and $850 million in aggregate principal amount of 5.000% senior unsecured notes due 2031 in private placements. The 2029 Senior Unsecured Notes bear interest at 4.625% per annum and the 2031 Senior Unsecured Notes bear interest at 5.000% per
annum with interest payable on both series of notes semi-annually on February 1 and August 1 of each year, beginning on February 1, 2021. The 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes mature on February 1, 2029 and February 1, 2031, respectively. We used the net proceeds from the 2029 Senior Unsecured Notes and 2031 Senior Unsecured Notes, together with cash on hand, to pay the consideration in connection with the tender offers and redeem any of the 2024 Senior Unsecured Notes and 2025 Senior Unsecured Notes not tendered in connection with the tender offers.
First Lien Notes
The amounts outstanding under our First Lien Notes are summarized in the table below (in millions):
|
| | | | | | | |
| June 30, 2020 | | December 31, 2019 |
2022 First Lien Notes(1) | $ | — |
| | $ | 245 |
|
2024 First Lien Notes(2) | — |
| | 184 |
|
2026 First Lien Notes | 1,173 |
| | 1,172 |
|
2028 First Lien Notes | 1,235 |
| | 1,234 |
|
Total First Lien Notes | $ | 2,408 |
| | $ | 2,835 |
|
____________
| |
(1) | On January 21, 2020, we redeemed the outstanding $245 million in aggregate principal amount of our 2022 First Lien Notes, which was included in debt, current portion on our Consolidated Condensed 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 Condensed Balance Sheet at December 31, 2019. |
| |
(2) | On January 21, 2020, we redeemed the outstanding $184 million in aggregate principal amount of our 2024 First Lien Notes, which was included in debt, current portion on our Consolidated Condensed 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 Condensed Balance Sheet at December 31, 2019. |
Project Financing, Notes Payable and Other
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11GPC Term Loan
On June 9, 2020, GPC and the guarantors party thereto entered into a seven-year $900 million first lien senior secured term loan facility and three senior secured revolving letter of credit facilities totaling $200 million. The GPC Term Loan is certified under the Climate Bonds Standard. Any letters of credit issued under the GPC Term Loan letter of credit facilities must be at the request of and for the account of GPC. The GPC Term Loan bears interest, at GPC’s option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Rate plus 0.50% per annum, (b) the prime rate published in the Wall Street Journal, or (c) 1.0% plus an applicable margin of 1.0%, increasing by 0.125% every three years, or (ii) LIBOR plus an applicable margin of 2.0% per annum, increasing by 0.125% every three years. The GPC Term Loan matures on June 9, 2027, but may be prepaid at any time upon irrevocable notice to the Administrative Agent. We used a portion of the proceeds from the GPC Term Loan to repay project debt associated with Steamboat as further discussed below.
The GPC Term Loan is secured by certain real and personal property of GPC consisting primarily of the Geysers Assets. The GPC Term Loan is not guaranteed by Calpine Corporation and is without recourse to Calpine Corporation or any of our non-GPC subsidiaries or assets; however, GPC generates a portion 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.
Project Financing, Notes Payable and Other
On June 12, 2020, we used a portion of the proceeds from the GPC Term Loan to repay approximately $342 million in carrying value of project debt associated with Steamboat and recorded approximately $8 million in loss on extinguishment of debt during the second quarter of 2020.
On July 1, 2020, PG&E and PG&E Corporation emerged from bankruptcy. Our power plants thatRussell City Energy Center and Los Esteros Critical Energy Facility sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since. Subsequent to the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. As a result of PG&E’s bankruptcy, we are currentlywere temporarily 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 executedUnder PG&E's plan of reorganization, our PPAs were assumed and any restrictions on distributing cash from our Russell City and Los Esteros projects were cured. Additionally, the forbearance agreements associated with theour 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’swere terminated in accordance
with the terms of the agreements. Accordingly, following removal of 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 $276 million of Russell City and Los Esteros long-term project debt outstanding at restrictions, our Russell City and Los Esteros projects will distribute funds in the amount of March 31, 2020$88 million to a current liabilityCalpine Corporation in a future period. We continue to monitor the bankruptcy proceedings and are assessing our optionsAugust 2020.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at MarchJune 3130, 2020 and December 31, 2019 (in millions):
|
| | | | | | | |
| June 30, 2020 | | December 31, 2019 |
Corporate Revolving Facility(1) | $ | 462 |
| | $ | 604 |
|
CDHI | 3 |
| | 3 |
|
Various project financing facilities(2) | 336 |
| | 184 |
|
Other corporate facilities(3) | 275 |
| | 294 |
|
Total | $ | 1,076 |
| | $ | 1,085 |
|
____________
| |
(1) | The Corporate Revolving Facility represents our primary revolving facility and matures on March 8, 2023. |
| |
(2) | On June 9, 2020, we entered into the GPC Term Loan which provides for $200 million in letter of credit facilities. |
| |
(3) | On April 9, 2020, we amended one of our unsecured letter of credit facilities to partially extend the maturity of $100 million in commitments from June 20, 2020 to June 20, 2022. |
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 MarchJune 3130, 2020 and December 31, 2019 (in millions):
|
| | | | | | | | | | | | | | | |
| June 30, 2020 | | December 31, 2019 |
| Fair Value | | Carrying Value | | Fair Value | | Carrying Value |
First Lien Term Loans | $ | 3,081 |
| | $ | 3,155 |
| | $ | 3,238 |
| | $ | 3,167 |
|
Senior Unsecured Notes | 3,027 |
| | 3,042 |
| | 3,764 |
| | 3,663 |
|
First Lien Notes | 2,404 |
| | 2,408 |
| | 2,929 |
| | 2,835 |
|
CCFC Term Loan | 941 |
| | 962 |
| | 982 |
| | 967 |
|
GPC Term Loan | 900 |
| | 867 |
| | — |
| | — |
|
Project financing, notes payable and other(1) | 426 |
| | 419 |
| | 822 |
| | 817 |
|
Revolving facilities | 122 |
| | 122 |
| | 122 |
| | 122 |
|
Total | $ | 10,901 |
| | $ | 10,975 |
| | $ | 11,857 |
| | $ | 11,571 |
|
____________
| |
(1) | Excludes an agreement that is accounted for as a failed sale-leaseback transaction under U.S. GAAP. |
Our First Lien Term Loans, Senior Unsecured Notes, First Lien Notes and CCFC Term Loan are categorized as level 2 within the fair value hierarchy. Our GPC Term Loan, 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.
| |
5. | 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 Condensed 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 assets and liabilities that were accounted for at fair value on a recurring basis as of MarchJune 3130, 2020 and December 31, 2019, by level within the fair value hierarchy:
|
| | | | | | | | | | | | | | | |
| Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2020 |
| Level 1 | | Level 2 | | Level 3 | | Total |
| (in millions) |
Assets: | | | | | | | |
Cash equivalents(1) | $ | 417 |
| | $ | — |
| | $ | — |
| | $ | 417 |
|
Commodity instruments: | | | | | | | |
Commodity exchange traded derivatives contracts | 991 |
| | — |
| | — |
| | 991 |
|
Commodity forward contracts(2) | — |
| | 424 |
| | 364 |
| | 788 |
|
Interest rate hedging instruments | — |
| | — |
| | — |
| | — |
|
Effect of netting and allocation of collateral(3)(4) | (991 | ) | | (299 | ) | | (40 | ) | | (1,330 | ) |
Total assets | $ | 417 |
| | $ | 125 |
| | $ | 324 |
| | $ | 866 |
|
Liabilities: | | | | | | | |
Commodity instruments: | | | | | | | |
Commodity exchange traded derivatives contracts | $ | 1,001 |
| | $ | — |
| | $ | — |
| | $ | 1,001 |
|
Commodity forward contracts(2) | — |
| | 421 |
| | 118 |
| | 539 |
|
Interest rate hedging instruments | — |
| | 161 |
| | — |
| | 161 |
|
Effect of netting and allocation of collateral(3)(4) | (1,001 | ) | | (296 | ) | | (40 | ) | | (1,337 | ) |
Total liabilities | $ | — |
| | $ | 286 |
| | $ | 78 |
| | $ | 364 |
|
|
| | | | | | | | | | | | | | | |
| 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 |
|
___________
| |
(1) | At MarchJune 3130, 2020 and December 31, 2019, we had cash equivalents of $222190 million and $573 million included in cash and cash equivalents and $222227 million and $211 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 6 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 $3510 million, $8(3) million and nil, respectively, at MarchJune 3130, 2020. 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. |
At MarchJune 3130, 2020 and December 31, 2019, the derivative instruments classified as level 3 primarily included commodity contracts. 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 MarchJune 3130, 2020 and December 31, 2019:
|
| | | | | | | | | | | | | | | | | | | |
| | Quantitative Information about Level 3 Fair Value Measurements |
| | June 30, 2020 |
| | Fair Value, Net Asset | | | | Significant Unobservable | | | | | | | |
| | (Liability) | | Valuation Technique | | Input | | Range | | Average(2) |
| | (in millions) | | | | | | | | | | | |
Power Contracts(1) | | $ | 206 |
| | Discounted cash flow | | Market price (per MWh) | | $ | 3.18 |
| — | $175.51 | /MWh | | $ | 28.97 |
|
Power Congestion Products | | $ | 6 |
| | Discounted cash flow | | Market price (per MWh) | | $ | (6.48 | ) | — | $11.88 | /MWh | | $ | 1.20 |
|
Natural Gas Contracts | | $ | 9 |
| | Discounted cash flow | | Market price (per MMBtu) | | $ | 1.33 |
| — | $4.62 | /MMBtu | | $ | 2.82 |
|
| | | | | | | | | | | | | |
| | 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 | /MWh | | |
Natural Gas Contracts | | $ | (20 | ) | | Discounted cash flow | | Market price (per MMBtu) | | $ | 1.73 |
| — | $6.45 | /MMBtu | | |
___________
| |
(1) | Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy. |
| |
(2) | Amount represents the arithmetic average of the significant unobservable input based on the range disclosed. |
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 periods indicated (in millions):
|
| | | | | | | | | | | | | | | | |
| | Three Months Ended June 30, | | Six Months Ended June 30, |
| | 2020 | | 2019 | | 2020 | | 2019 |
Balance, beginning of period | | $ | 249 |
| | $ | 105 |
| | $ | 171 |
| | $ | (8 | ) |
Realized and mark-to-market gains (losses): | | | | | | | | |
Included in net income: | | | | | | | | |
Included in operating revenues(1) | | 37 |
| | 152 |
| | 106 |
| | 197 |
|
Included in fuel and purchased energy expense(2) | | 3 |
| | 1 |
| | (1 | ) | | 2 |
|
Change in collateral | | — |
| | (1 | ) | | — |
| | 1 |
|
Purchases, Issuances and settlements: | | | | | | | | |
Purchases | | 1 |
| | 1 |
| | 1 |
| | 3 |
|
Issuances | | — |
| | (1 | ) | | — |
| | (1 | ) |
Settlements | | (49 | ) | | (35 | ) | | (36 | ) | | 28 |
|
Transfers in and/or out of level 3: | | | | | | | | |
Transfers into level 3(3) | | 10 |
| | 6 |
| | 11 |
| | 7 |
|
Transfers out of level 3(4) | | (5 | ) | | (1 | ) | | (6 | ) | | (2 | ) |
Balance, end of period | | $ | 246 |
| | $ | 227 |
| | $ | 246 |
| | $ | 227 |
|
Change in unrealized gains (losses) included in net income relating to instruments still held at end of period | | $ | 40 |
| | $ | 153 |
| | $ | 105 |
| | $ | 199 |
|
___________
| |
(1) | For power contracts and other power-related products, included on our Consolidated Condensed Statements of Operations. |
| |
(2) | For natural gas and power contracts, swaps and options, included on our Consolidated Condensed Statements of Operations. |
| |
(3) | We had $310 million and $6 million in gains and $(1) million in losses transferred out of level 2 into level 3 for the three months ended March 31June 30, 2020 and 2019, respectively, and $11 million and $7 million in gains transferred out of level 2 into level 3 for the six months ended June 30, 2020 and 2019, respectively, due to changes in market liquidity in various power markets. |
| |
(4) | We had $25 million and $1 million in gains and nil transferred out of level 3 into level 2 for the three months ended March 31June 30, 2020 and 2019, respectively, and $6 million and $2 million in gains transferred out of level 3 into level 2 for the six months ended June 30, 2020 and 2019, respectively, due to changes in market liquidity in various power markets. |
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 each of the three and six months ended MarchJune 3130, 2020 and 2019.
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 MarchJune 3130, 2020, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 67 years.
As of MarchJune 3130, 2020 and December 31, 2019, 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:
|
| | | | | | | | | | |
Derivative Instruments | | Notional Amounts | | |
| June 30, 2020 | | December 31, 2019 | | Unit of Measure |
Power | | (242 | ) | | (184 | ) | | Million MWh |
Natural gas | | 1,165 |
| | 1,063 |
| | Million MMBtu |
Environmental credits | | 36 |
| | 26 |
| | Million Tonnes |
Interest rate hedging instruments(1) | | $ | 7.0 |
| | $ | 4.8 |
| | Billion U.S. dollars |
___________
| |
(1) | During the first quarterhalf of 2020, we entered into interest rate hedging instruments to hedge approximately $12.64 billion of variable rate debt. |
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 MarchJune 3130, 2020, was $153120 million for which we have posted collateral of $10437 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 $16 million of additional collateral 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 Condensed 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 Condensed 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 a portion of our interest rate hedging instruments with the change in fair value of all other hedging instruments recorded through earnings. 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. 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 Condensed 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 Condensed Balance Sheets
We offset fair value amounts associated with our derivative instruments and related cash collateral and margin deposits on our Consolidated Condensed 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 Condensed Balance Sheets by location and hedge type at MarchJune 3130, 2020 and December 31, 2019 (in millions):
|
| | | | | | | | | | | | |
| | June 30, 2020 |
| | Gross Amounts of Assets and (Liabilities) | | Gross Amounts Offset on the Consolidated Condensed Balance Sheets | | Net Amount Presented on the Consolidated Condensed Balance Sheets(1) |
Derivative assets: | | | | | | |
Commodity exchange traded derivatives contracts | | $ | 758 |
| | $ | (758 | ) | | $ | — |
|
Commodity forward contracts | | 440 |
| | (241 | ) | | 199 |
|
Interest rate hedging instruments | | — |
| | — |
| | — |
|
Total current derivative assets(2) | | $ | 1,198 |
| | $ | (999 | ) | | $ | 199 |
|
Commodity exchange traded derivatives contracts | | 233 |
| | (233 | ) | | — |
|
Commodity forward contracts | | 348 |
| | (98 | ) | | 250 |
|
Interest rate hedging instruments | | — |
| | — |
| | — |
|
Total long-term derivative assets(2) | | $ | 581 |
| | $ | (331 | ) | | $ | 250 |
|
Total derivative assets | | $ | 1,779 |
| | $ | (1,330 | ) | | $ | 449 |
|
| | | | | | |
Derivative (liabilities): | | | | | | |
Commodity exchange traded derivatives contracts | | $ | (733 | ) | | $ | 733 |
| | $ | — |
|
Commodity forward contracts | | (357 | ) | | 238 |
| | (119 | ) |
Interest rate hedging instruments | | (49 | ) | | — |
| | (49 | ) |
Total current derivative (liabilities)(2) | | $ | (1,139 | ) | | $ | 971 |
| | $ | (168 | ) |
Commodity exchange traded derivatives contracts | | (268 | ) | | 268 |
| | — |
|
Commodity forward contracts | | (182 | ) | | 98 |
| | (84 | ) |
Interest rate hedging instruments | | (112 | ) | | — |
| | (112 | ) |
Total long-term derivative (liabilities)(2) | | $ | (562 | ) | | $ | 366 |
| | $ | (196 | ) |
Total derivative liabilities | | $ | (1,701 | ) | | $ | 1,337 |
| | $ | (364 | ) |
Net derivative assets (liabilities) | | $ | 78 |
| | $ | 7 |
| | $ | 85 |
|
|
| | | | | | | | | | | | |
| | December 31, 2019 |
| | Gross Amounts of Assets and (Liabilities) | | Gross Amounts Offset on the Consolidated Condensed Balance Sheets | | Net Amount Presented on the Consolidated Condensed 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(3) | | $ | 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(3) | | $ | 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)(3) | | $ | (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)(3) | | $ | (259 | ) | | $ | 196 |
| | $ | (63 | ) |
Total derivative liabilities | | $ | (1,423 | ) | | $ | 1,135 |
| | $ | (288 | ) |
Net derivative assets (liabilities) | | $ | — |
| | $ | 114 |
| | $ | 114 |
|
____________
| |
(1) | At MarchJune 3130, 2020 and December 31, 2019, we had $191260 million and $191 million, respectively, of collateral under master netting arrangements that were not offset against our derivative instruments on the Consolidated Condensed Balance Sheets primarily related to initial margin requirements. |
| |
(2) | At MarchJune 3130, 2020, current and long-term derivative assets are shown net of collateral of $(1428) million and $(139) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $221 million and $4843 million, respectively. |
| |
(3) | 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. |
|
| | | | | | | | | | | | | | | |
| June 30, 2020 | | December 31, 2019 |
| 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 | $ | — |
| | $ | 119 |
| | $ | 12 |
| | $ | 29 |
|
Total derivatives designated as cash flow hedging instruments | $ | — |
| | $ | 119 |
| | $ | 12 |
| | $ | 29 |
|
| | | | | | | |
Derivatives not designated as hedging instruments: | | | | | | | |
Commodity instruments | $ | 449 |
| | $ | 203 |
| | $ | 390 |
| | $ | 257 |
|
Interest rate hedging instruments | — |
| | 42 |
| | — |
| | 2 |
|
Total derivatives not designated as hedging instruments | $ | 449 |
| | $ | 245 |
| | $ | 390 |
| | $ | 259 |
|
Total derivatives | $ | 449 |
| | $ | 364 |
| | $ | 402 |
| | $ | 288 |
|
Derivatives Included on Our Consolidated Condensed 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 Condensed 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 Condensed Statements of Operations for the periods indicated (in millions):
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Realized gain (loss)(1)(2) | | | | | | | |
Commodity derivative instruments | $ | 36 |
| | $ | 58 |
| | $ | 33 |
| | $ | 169 |
|
Interest rate hedging instruments(3) | (18 | ) | | — |
| | (18 | ) | | — |
|
Total realized gain (loss) | $ | 18 |
|
| $ | 58 |
|
| $ | 15 |
| | $ | 169 |
|
| | | | | | | |
Mark-to-market gain (loss)(4) | | | | | | | |
Commodity derivative instruments | $ | 35 |
| | $ | 187 |
| | $ | 236 |
| | $ | 233 |
|
Interest rate hedging instruments | (14 | ) | | (1 | ) | | (38 | ) | | (2 | ) |
Total mark-to-market gain (loss) | $ | 21 |
|
| $ | 186 |
|
| $ | 198 |
| | $ | 231 |
|
Total activity, net | $ | 39 |
|
| $ | 244 |
|
| $ | 213 |
| | $ | 400 |
|
___________
| |
(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) | Includes costs associated with the termination of de-designated interest rate hedging instruments recorded to interest expense related to our Steamboat project debt that was repaid in June 2020. |
| |
(4) | 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. |
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Realized and mark-to-market gain (loss)(1) | | | | | | | |
Derivatives contracts included in operating revenues(2)(3) | $ | 34 |
| | $ | 541 |
| | $ | 541 |
| | $ | 578 |
|
Derivatives contracts included in fuel and purchased energy expense(2)(3) | 37 |
| | (296 | ) | | (272 | ) | | (176 | ) |
Interest rate hedging instruments included in interest expense(4) | (32 | ) | | (1 | ) | | (56 | ) | | (2 | ) |
Total activity, net | $ | 39 |
|
| $ | 244 |
|
| $ | 213 |
| | $ | 400 |
|
___________
| |
(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. |
| |
(4) | Includes costs associated with the termination of de-designated interest rate hedging instruments recorded to interest expense related to our Steamboat project debt that was repaid in June 2020. |
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 periods indicated (in millions):
|
| | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Three Months Ended June 30, |
| Gain (Loss) Recognized in OCI | | Gain (Loss) Reclassified from AOCI into Income(2)(3) |
| 2020 | | 2019 | | 2020 | | 2019 | | Affected Line Item on the Consolidated Condensed Statements of Operations |
Interest rate hedging instruments(1) | $ | 3 |
| | $ | (32 | ) | | $ | (25 | ) | | $ | 3 |
| | Interest expense |
|
| | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, | | Six Months Ended June 30, |
| Gain (Loss) Recognized in OCI | | Gain (Loss) Reclassified from AOCI into Income(2)(3) |
| 2020 | | 2019 | | 2020 | | 2019 | | Affected Line Item on the Consolidated Condensed Statements of Operations |
Interest rate hedging instruments(1) | $ | (101 | ) | | $ | (57 | ) | | $ | (31 | ) | | $ | 5 |
| | Interest expense |
____________
| |
(1) | We recorded an income tax benefitexpense of $31 million and an income tax (benefit) of nil$(1) million for the three months ended March 31June 30, 2020 and 2019, respectively, and income tax (benefit) of $(2) million and $(1) million for the six months ended June 30, 2020 and 2019, respectively, in AOCI related to our cash flow hedging activities. |
| |
(2) | Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $176174 million and $72 million at MarchJune 3130, 2020 and December 31, 2019, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were nil and $3 million at MarchJune 3130, 2020 and December 31, 2019, respectively. |
| |
(3) | Includes losses of nil$16 million and nil that were reclassified from AOCI to interest expense for the three months ended June 30, 2020 and 2019, respectively, and losses of $16 million and $1 million that were reclassified from AOCI to interest expense for the threesix months ended MarchJune 3130, 2020 and 2019, respectively, where the hedged transactions became probable of not occurring. |
We estimate that pre-tax net losses of $5557 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 MarchJune 3130, 2020 and December 31, 2019 (in millions):
|
| | | | | | | |
| June 30, 2020 | | December 31, 2019 |
Margin deposits(1) | $ | 290 |
| | $ | 432 |
|
Natural gas and power prepayments | 31 |
| | 29 |
|
Total margin deposits and natural gas and power prepayments with our counterparties(2) | $ | 321 |
| | $ | 461 |
|
| | | |
Letters of credit issued | $ | 877 |
| | $ | 906 |
|
First priority liens under power and natural gas agreements | 20 |
| | 42 |
|
First priority liens under interest rate hedging instruments | 168 |
| | 31 |
|
Total letters of credit and first priority liens with our counterparties | $ | 1,065 |
| | $ | 979 |
|
| | | |
Margin deposits posted with us by our counterparties(1)(3) | $ | 23 |
| | $ | 127 |
|
Letters of credit posted with us by our counterparties | 212 |
| | 25 |
|
Total margin deposits and letters of credit posted with us by our counterparties | $ | 235 |
| | $ | 152 |
|
___________
| |
(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 6 for further discussion of our derivative instruments subject to master netting arrangements. |
| |
(2) | At MarchJune 3130, 2020 and December 31, 2019, $5919 million and $117 million, respectively, were included in current and long-term derivative assets and liabilities, $292294 million and $336 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $8 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets. |
| |
(3) | At MarchJune 3130, 2020 and December 31, 2019, $1612 million and $3 million, respectively, were included in current and long-term derivative assets and liabilities, $4611 million and $93 million, respectively, were included in other current liabilities and $31 millionnil and $31 million, respectively, were included in other long-term liabilities on our Consolidated Condensed 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.
Income Tax Expense (Benefit)
The table below shows our consolidated income tax expense (benefit) and our effective tax rates for the periods indicated (in millions):
|
| | | | | | | | | | | | | | | |
| Three Months Ended June 30, | | Six Months Ended June 30, |
| 2020 | | 2019 | | 2020 | | 2019 |
Income tax expense (benefit) | $ | (31 | ) | | $ | 9 |
| | $ | 15 |
| | $ | 19 |
|
Effective tax rate | (23 | )% | | 3 | % | | 5 | % | | 4 | % |
Our income tax rates do not bear a customary relationship to statutory income tax rates primarily as a result of the effect of our NOLs and changes in unrecognized tax benefits and valuation allowances. For the three and six months ended MarchJune 3130, 2020 and 2019, ourthe income tax expense is largely comprised of state and foreign income taxes in jurisdictions where we do not have NOLs, the effect of applying the intraperiod tax allocation rules to our results of operations and related tax expense andrecognized resulted from timing differences between the recognition of federal income tax expense and corresponding NOL valuation allowance.
changes in NOLs and the valuation allowance.
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, future earnings 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. We have federal NOLs available to offset future income tax obligations recognized as deferred tax assets in the amount of $1.5 billion at June 30, 2020. During the second quarter of 2020, we recorded a partial valuation allowance release to the federal valuation allowance in the amount of $77 million. We recognize a valuation allowance against a subset of these NOLs given uncertainty in our ability to utilize all such NOLs. 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. For purposes of this evaluation, due to historical volatility inwe consider both the existence of future taxable earnings, weas are unable to assume future earnings; however, we are able to considerwell as available tax planning strategies.
Unrecognized Tax Benefits — At March 31, 2020, we had unrecognized tax benefits of $29 million. If recognized, $17 million of our unrecognized tax benefits could affect To the extent that future expected sources of earnings materially changes, this could result in 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 on our effective tax rate. We had accrued interest and penalties of $3 million for income tax matters at March 31, 2020. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Condensed Statements of Operations. reduction or increase in our valuation allowance.
| |
9. | Commitments and Contingencies |
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.
Guarantees and Indemnifications
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 MarchJune 3130, 2020, 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. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 16 of our 2019 Form 10-K.
| |
10. | 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:
Calpine Receivables — Under the Accounts Receivable Sales Program, at MarchJune 3130, 2020 and December 31, 2019, we had $210195 million and $222 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $4241 million and $38 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the threesix months ended MarchJune 3130, 2020 and 2019, we sold an aggregate of $525 million1.0 billion and $597 million1.1 billion, respectively, in trade accounts receivable and recorded $521 million1.0 billion and $579 million1.1 billion, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 7 and 17 in our 2019 Form 10-K.
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 has a material ownership interest in Calpine also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. We recorded $1314 million and $2017 million in operating revenues during the three months ended MarchJune 3130, 2020 and 2019, respectively and, and $27 million and $37 million in operating revenues during the six months ended June 30, 2020 and 2019, respectively. We recorded $3 million and $34 million in operating expenses during the three months ended March 31June 30, 2020 and 2019, respectively, and $6 million and $7 million in operating expenses during the six months ended June 30, 2020 and 2019, respectively, associated with the Lyondell contract. At MarchJune 3130, 2020 and December 31, 2019, the related party receivable and payable associated with the Lyondell contract were immaterial.
Other — 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 MarchJune 3130, 2020 and December 31, 2019, the related party revenues, expenses, receivables and payables associated with these transactions were immaterial.
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 MarchJune 3130, 2020, 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 financial data for our segments (including a reconciliation of Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2020 |
| Wholesale | | | | Consolidation | | |
| West | | Texas | | East | | Retail | | Elimination | | Total |
Total operating revenues(1) | $ | 470 |
| | $ | 620 |
| | $ | 244 |
| | $ | 720 |
| | $ | (310 | ) | | $ | 1,744 |
|
| | | | | | | | | | | |
Commodity Margin | $ | 269 |
| | $ | 172 |
| | $ | 193 |
| | $ | 89 |
| | $ | — |
| | $ | 723 |
|
Add: Mark-to-market commodity activity, net and other(2) | 67 |
| | (17 | ) | | (38 | ) | | 56 |
| | (9 | ) | | 59 |
|
Less: | | | | | | | | | | |
|
|
Operating and maintenance expense | 96 |
| | 73 |
| | 71 |
| | 35 |
| | (9 | ) | | 266 |
|
Depreciation and amortization expense | 56 |
| | 50 |
| | 45 |
| | 12 |
| | — |
| | 163 |
|
General and other administrative expense | 6 |
| | 13 |
| | 8 |
| | 4 |
| | — |
| | 31 |
|
Other operating expenses | 7 |
| | 1 |
| | 6 |
| | — |
| | — |
| | 14 |
|
(Income) from unconsolidated subsidiaries | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
Income from operations | 171 |
| | 18 |
| | 29 |
| | 94 |
| | — |
| | 312 |
|
Interest expense | | | | | | | | | | | 167 |
|
Gain (loss) on extinguishment of debt and other (income) expense, net | | | | | | | | | | | 13 |
|
Income before income taxes | | | | | | | | | | | $ | 132 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, 2019 |
| Wholesale | | | | Consolidation | | |
| West | | Texas | | East | | Retail | | Elimination | | Total |
Total operating revenues(1) | $ | 649 |
| | $ | 899 |
| | $ | 646 |
| | $ | 1,082 |
| | $ | (677 | ) | | $ | 2,599 |
|
| | | | | | | | | | | |
Commodity Margin | $ | 251 |
| | $ | 173 |
| | $ | 235 |
| | $ | 93 |
| | $ | — |
| | $ | 752 |
|
Add: Mark-to-market commodity activity, net and other(2) | 58 |
| | 240 |
| | 94 |
| | (182 | ) | | (10 | ) | | 200 |
|
Less: | | | | | | | | | | | |
Operating and maintenance expense | 84 |
| | 66 |
| | 72 |
| | 33 |
| | (10 | ) | | 245 |
|
Depreciation and amortization expense | 60 |
| | 54 |
| | 48 |
| | 13 |
| | — |
| | 175 |
|
General and other administrative expense | 5 |
| | 15 |
| | 10 |
| | 4 |
| | — |
| | 34 |
|
Other operating expenses | 7 |
| | 1 |
| | 11 |
| | — |
| | — |
| | 19 |
|
Impairment losses | — |
| | — |
| | 40 |
| | — |
| | — |
| | 40 |
|
(Income) from unconsolidated subsidiaries | — |
| | — |
| | (6 | ) | | 1 |
| | — |
| | (5 | ) |
Income (loss) from operations | 153 |
|
| 277 |
| | 154 |
| | (140 | ) | | — |
| | 444 |
|
Interest expense | | | | | | | | | | | 157 |
|
Gain (loss) on extinguishment of debt and other (income) expense, net | | | | | | | | | | | 8 |
|
Income before income taxes | | | | | | | | | | | $ | 279 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2020 |
| Wholesale | | | | Consolidation | | |
| West | | Texas | | East | | Retail | | Elimination | | Total |
Total operating revenues(3) | $ | 1,175 |
| | $ | 1,270 |
| | $ | 786 |
| | $ | 1,628 |
| | $ | (823 | ) | | $ | 4,036 |
|
| | | | | | | | | | | |
Commodity Margin | $ | 503 |
| | $ | 285 |
| | $ | 343 |
| | $ | 180 |
| | $ | — |
| | $ | 1,311 |
|
Add: Mark-to-market commodity activity, net and other(4) | 121 |
| | 84 |
| | 44 |
| | 40 |
| | (17 | ) | | 272 |
|
Less: | | | | | | | | | | | |
Operating and maintenance expense | 182 |
| | 139 |
| | 134 |
| | 68 |
| | (17 | ) | | 506 |
|
Depreciation and amortization expense | 112 |
| | 100 |
| | 91 |
| | 24 |
| | — |
| | 327 |
|
General and other administrative expense | 14 |
| | 24 |
| | 16 |
| | 8 |
| | — |
| | 62 |
|
Other operating expenses | 15 |
| | 3 |
| | 13 |
| | — |
| | — |
| | 31 |
|
(Income) from unconsolidated subsidiaries | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
Income from operations | 301 |
| | 103 |
| | 137 |
| | 120 |
| | — |
| | 661 |
|
Interest expense | | | | | | | | | | | 336 |
|
Gain (loss) on extinguishment of debt and other (income) expense, net | | | | | | | | | | | 17 |
|
Income before income taxes | | | | | | | | | | | $ | 308 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, 2019 |
| Wholesale | | | | Consolidation | | |
| West | | Texas | | East | | Retail | | Elimination | | Total |
Total operating revenues(3) | $ | 1,331 |
| | $ | 1,642 |
| | $ | 1,335 |
| | $ | 2,080 |
| | $ | (1,190 | ) | | $ | 5,198 |
|
| | | | | | | | | | | |
Commodity Margin | $ | 515 |
| | $ | 335 |
| | $ | 500 |
| | $ | 181 |
| | $ | — |
| | $ | 1,531 |
|
Add: Mark-to-market commodity activity, net and other(4) | 114 |
| | 284 |
| | 107 |
| | (235 | ) | | (18 | ) | | 252 |
|
Less: | | | | | | | | | | | |
Operating and maintenance expense | 165 |
| | 131 |
| | 139 |
| | 67 |
| | (18 | ) | | 484 |
|
Depreciation and amortization expense | 133 |
| | 99 |
| | 91 |
| | 26 |
| | — |
| | 349 |
|
General and other administrative expense | 12 |
| | 27 |
| | 19 |
| | 8 |
| | — |
| | 66 |
|
Other operating expenses | 16 |
| | 3 |
| | 19 |
| | — |
| | — |
| | 38 |
|
Impairment losses | — |
| | — |
| | 55 |
| | — |
| | — |
| | 55 |
|
(Income) from unconsolidated subsidiaries | — |
| | — |
| | (12 | ) | | 1 |
| | — |
| | (11 | ) |
Income (loss) from operations | 303 |
| | 359 |
| | 296 |
| | (156 | ) | | — |
| | 802 |
|
Interest expense | | | | | | | | | | | 306 |
|
Gain (loss) on extinguishment of debt and other (income) expense, net | | | | | | | | | | | 27 |
|
Income before income taxes | | | | | | | | | | | $ | 469 |
|
_________
| |
(1) | Includes intersegment revenues of $11970 million and $162100 million in the West, $218214 million and $211348 million in Texas, $17524 million and $137228 million in the East and $12 million and $31 million in Retail for the three months ended March 31June 30, 2020 and 2019, respectively. |
| |
(2) | Includes $(22) million and $(19) million of lease levelization and $9 million and $18 million of amortization expense for the three months ended June 30, 2020 and 2019, respectively. |
| |
(23) | Includes intersegment revenues of $189 million and $262 million in the West, $432 million and $559 million in Texas, $199 million and $365 million in the East and $3 million and $4 million in Retail for the six months ended June 30, 2020 and 2019, respectively. |
| |
(4) | Includes $(1840) million and $(1635) million of lease levelization and $1625 million and $2139 million of amortization expense for the threesix months ended MarchJune 3130, 2020 and 2019, respectively. |
| |
Item 2. | Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Forward-Looking Information
This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our accompanying Consolidated Condensed Financial Statements and related Notes. See the cautionary statement regarding forward-looking statements at the beginning of this Report for a description of important factors that could cause actual results to differ from expected results.
Introduction and Overview
We are one of the largest power generators in the U.S. 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. We sell power, steam, capacity, renewable energy credits and ancillary services to our wholesale customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities, CCAs and other governmental entities and power marketers. Additionally, through our retail brands, we market retail energy and related products to 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.
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 7778 power plants, including onetwo under construction, with an aggregate current generation capacity of 26,035103 MW and 361381 MW under construction. 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 and one battery storage plant. Our wholesale geographic segments have an aggregate generation capacity of 7,590 MW with an additional 20 MW under construction in the West, 9,115183 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 retail business consists of multiple brands with a focus on reaching key retail energy markets. Our primary brands are Calpine Solutions (which focuses on commercial and industrial customers) and Champion Energy (which focuses on residential, mass market and commercial and industrial customers). In total, our retail business delivered approximately 60 million MWh of power in 2019. Our retail activities are primarily located in the power markets where our generation fleet maintains a presence. Products sold include standard electricity service as well as customized solutions to aid customers in their business goals (including sustainability goals).
Uncertainty Related to the COVID-19 Pandemic
In March 2020, the World Health Organization categorized the novel coronavirus disease 2019 (COVID-19) as a pandemic, and the President declared the COVID-19 outbreak a national emergency. COVID-19 continues to spread throughout the United States and other countries across the world and has negatively affectedaffecting the global economy, disrupteddisrupting global supply chains and workforce participation and resultedresulting in significant volatility and disruption of financial markets. We are closely monitoringWhile we have noted recovery in certain key geographic areas where we own generation facilities, we continue to closely monitor the impact of the COVID-19 outbreak on all aspects of our business, including how it has affected and continues to affect our employees, customers, suppliers and the communities in which we operate.
Our first priority with regard to the COVID-19 outbreak is to ensure the safety, health and hygienesafety of our employees and contractors. As one of the largest independent power producers in the U.S., we are designated as an “essential business” and have an obligation to operate our fleet of power plants to sustain the bulk electric system and manage retail customer power delivery obligations. To ensure the continued reliable operations of our generation fleet and delivery of power to our retail customers, we have putcontinue to inabide placeby a set of new safety and health measures, which include restricted as a means to ensure we are able to provide reliable energy to the markets we serve. These measures include restricting access at our power plants to only mission-critical individuals and adherence to social distancing
protocols wherever possible. Additionally, our commercial and retail
operations, including all support staff such as legal, accounting, finance, information technology and human resources, continue to work remotely consistent with directives from local and state governments.
Although there have been logistical and other challenges, to dateTo date, the COVID-19 outbreak has not had a material adverse effect on our operations, financial condition, or cash flows. While the ultimate determination depends on the length and severity of the crisis, as of the filing of this Report, we anticipate our cash flows from operations and our available sources of liquidity will be sufficient to meet our current cash requirements during this volatile period. As a precautionary measure and to preserve financial flexibility in light of current uncertainty resulting from the COVID-19 outbreak, we borrowed an additional $350 million on our Corporate Revolving Facility during March 2020, of which $200 million was repaid as of the filing of this Reportperiod. As the impact of the COVID-19 outbreak on the economy and our operations evolves, we will continue to assess and manage our liquidity needs.
The ultimate extent to which the COVID-19 pandemic may impact the Company’sour business, operating results, financial condition, or liquidity will depend on future developments, including the duration of the outbreak, continued business and workforce disruptions, the effectiveness of actions taken to contain and treat the disease and the ultimate lasting effect on the economy, especially in the geographic areas where we own and operate power generating facilities and serve retail customers. Given the uncertainty concerning the overall impact of the COVID-19 outbreak, while we do not anticipate the effect of the outbreak to have a material adverse effect on our financial condition, results of operations or cash flows for the year ended December 31, 2020, we are unable to predict the ultimate impact of the outbreak on our future results. For further discussion, see “Item 1A. Risk Factors” in Part II of this Report.
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 rules within the ISO and RTO markets in which we participate. Federal and state legislative and regulatory actions, including those by ISO/RTOs, continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO/RTO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “— Governmental and Regulatory Matters” in Part I, Item 1 of our 2019 Form 10-K.
CAISO
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 itreliability. A recent CPUC decision implemented Central Procurement Entities (“CPEs”) to meet local RA requirements. CPEs, initially Southern California Edison and PG&E in is needed. To the extent LSE’stheir respective service territories, will meet local RA requirements on behalf of all LSEs and recover the cost through distribution rates. To the extent LSEs or CPEs have not procured sufficient capacity through the CPUC administered processprocesses, the CAISO will implement a backstop procurement process calledcan procure additional capacity using the Capacity Procurement Mechanism (“CPM”) toas meetwell 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. For example, the CPUC is considering Central Procurement Entities (“CPEs”) for local RA. Under this construct, CPEs rather than individual LSEs would be responsible for meeting local RA requirements, while the current LSE contracting structure would remain in place for other RA requirementsas Reliability Must-Run (“RMR”) contracts. We do not know at this point whether these changes will be impactful to our business.
ERCOT
On March 26, 2020, the Public Utility Commission of Texas (“PUCT”) adopted the COVID-19 Electricity Relief Program (“ERP”) to mitigate the impact of COVID-19 on Texas utility customers who are experiencing economic hardship as a result of the pandemic. The ERP creates a temporary exemption from disconnections for eligible residential customers who cannot pay their electricity bills. To pay for the ERP, the PUCT has authorized the utility companies to implement a new rider which is set at $0.33/MWh for all customer classes. The funds collected will be utilized to cover the unpaid bills for these eligible residential customers experiencing unemployment due to the impacts of COVID-19 and to ensure these customers continue receiving electric service. The ERP is set to end on August 31, 2020, but the PUCT has the discretion to extend the program if necessary. Although we anticipate our losses resulting from the ERP will not be material to us, we are unable to predict whether the funds we expect to recover from the PUCT will be sufficient to recover our loss exposure.
PJM
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 (the “December 2019 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 was directed to submit a compliance filing by March 18, 2020 and to propose dates for when the postponed May 2019 auction will be held. PJM submitted its compliance filing on March 18, 2020 which generally complies with the December 2019 Order. PJM informed the FERC that it intends to hold the first auction within six and a half months after the date of the FERC’s acceptance of PJM’s compliance filing, and every six months thereafter until the delayed auctions catch up to the original auction schedule. PJM anticipates these adjustments to apply to the next three auctions.
Multiple parties sought rehearing of the FERC’s June 29, 2018 order and the December 2019 Order. The FERC issued an order on rehearing on April 16, 2020 largely affirming its December 2019 Order, although the FERC did provide further clarification of certain key issues and granted rehearing on a few issues, none of which significantly impacts the outcome of the December 2019 Order. Several notices of appeal have been filed and more are expected. The Seventh Circuit Court of Appeals will hearhas been assigned the appealscase. A briefing schedule has not been established.
In addition, subsequent to the December 2019 Order, several states in the PJM region have expressed interest in considering the possible use of the “Fixed Resource Requirement” (“FRR”) provisions of the PJM tariff to bilaterally contract for capacity instead of participating in PJM’s market. The New Jersey Board of Public Utilities issued an order on March 27, 2020 initiating a proceeding to examine whether New Jersey can achieve its clean energy goals under the current PJM capacity market program and if not, how New Jersey can best meet its resource adequacy needs while meeting its clean energy goals. There are also discussions in the Illinois Legislature on FRR, and several FRR proposals have been made by Illinois stakeholders. Maryland is also considering its FRR options. No other states have taken specific action to examine the FRR option and it is unknown at this time whether or not states will pursue this approach, and what the resulting impact on our business would be.
On May 21, 2020, the FERC issued an order generally approving PJM’s proposal to revise the rules relating to its reserve market and the Operating Reserve Demand Curves’ (“ORDC”) shapes. However, the FERC determined that the approved reserve market and ORDC changes render PJM’s current backward-looking method for calculating the energy and ancillary services offset (“E&AS Offset”) in PJM’s capacity market unjust and unreasonable, and directed PJM to amend the E&AS Offset methodology to be forward-looking. The FERC directed PJM to submit a compliance filing implementing this directive by August 5, 2020. PJM submitted its proposal on August 5, 2020 but intends to provide additional information providing illustrative E&AS Offset and net Cost of New Entry values based on a forward-looking market simulation model. We cannot predict at this time whether PJM’s proposal will satisfy the FERC’s requirements or when the FERC will issue a final order in this proceeding.
ISO-NE
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 requests for rehearing remain pending before the FERC. 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 has initiated a temporary program to provide compensation to other generators that provide fuel security to the power system and, on April 15, 2020, proposed a long-term, market-based solution to incent and retain energy secure resources. ISO-NE has requested that the FERC approve the long-term proposal by November 1, 2020, with an implementation date of June 1, 2024.
Exelon, the owner of the Mystic Units, filed a complaint with the FERC on June 10, 2020, arguing that once the Mystic Units are no longer needed for fuel security (June 1, 2024), ISO-NE will need to retain the units for transmission reliability through a transmission RMR contract. ISO-NE and stakeholders filed comments opposing Exelon’s complaint, arguing that ISO-NE has an alternative solution to address transmission reliability and the Mystic Units are not needed. The complaint is pending before the FERC.
RESULTS OF OPERATIONS FOR THE THREE MONTHS ENDED MARCHJUNE 3130, 2020 AND 2019
Below are our results of operations for the three months ended MarchJune 3130, 2020 as compared to the same period in 2019 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
|
| | | | | | | | | | | | | | |
| 2020 | | 2019 | | Change | | % Change |
Operating revenues: | | | | | | | |
Commodity revenue | $ | 1,852 |
| | $ | 2,128 |
| | $ | (276 | ) | | (13 | ) |
Mark-to-market gain (loss) | (113 | ) | | 467 |
| | (580 | ) | | # |
|
Other revenue | 5 |
| | 4 |
| | 1 |
| | 25 |
|
Operating revenues | 1,744 |
| | 2,599 |
| | (855 | ) | | (33 | ) |
Operating expenses: | | | | | | | |
Fuel and purchased energy expense: | | | | | | | |
Commodity expense | 1,110 |
| | 1,367 |
| | 257 |
| | 19 |
|
Mark-to-market (gain) loss | (148 | ) | | 280 |
| | 428 |
| | # |
|
Fuel and purchased energy expense | 962 |
| | 1,647 |
| | 685 |
| | 42 |
|
Operating and maintenance expense | 266 |
| | 245 |
| | (21 | ) | | (9 | ) |
Depreciation and amortization expense | 163 |
| | 175 |
| | 12 |
| | 7 |
|
General and other administrative expense | 31 |
| | 34 |
| | 3 |
| | 9 |
|
Other operating expenses | 14 |
| | 19 |
| | 5 |
| | 26 |
|
Total operating expenses | 1,436 |
| | 2,120 |
| | 684 |
| | 32 |
|
Impairment losses | — |
| | 40 |
| | 40 |
| | # |
|
(Income) from unconsolidated subsidiaries | (4 | ) | | (5 | ) | | (1 | ) | | (20 | ) |
Income from operations | 312 |
| | 444 |
| | (132 | ) | | (30 | ) |
Interest expense | 167 |
| | 157 |
| | (10 | ) | | (6 | ) |
Loss on extinguishment of debt | 8 |
| | 3 |
| | (5 | ) | | # |
|
Other (income) expense, net | 5 |
| | 5 |
| | — |
| | — |
|
Income before income taxes | 132 |
| | 279 |
| | (147 | ) | | (53 | ) |
Income tax expense (benefit) | (31 | ) | | 9 |
| | 40 |
| | # |
|
Net income | 163 |
| | 270 |
| | (107 | ) | | (40 | ) |
Net income attributable to the noncontrolling interest | — |
| | (4 | ) | | 4 |
| | # |
|
Net income attributable to Calpine | $ | 163 |
| | $ | 266 |
| | $ | (103 | ) | | (39 | ) |
|
| | | | | | | | | | | |
| 2020 | | 2019 | | Change | | % Change |
Operating Performance Metrics: | | | | | | | |
MWh generated (in thousands)(1)(2) | 22,493 |
| | 21,156 |
| | 1,337 |
| | 6 |
|
Average availability(2) | 81.5 | % | | 81.5 | % | | — | % | | — |
|
Average total MW in operation(1) | 25,314 |
| | 25,908 |
| | (594 | ) | | (2 | ) |
Average capacity factor, excluding peakers | 44.6 | % | | 41.6 | % | | 3.0 | % | | 7 |
|
Steam Adjusted Heat Rate(2) | 7,329 |
| | 7,338 |
| | 9 |
| | — |
|
__________
| |
# | Variance of 100% or greater |
| |
(1) | Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby (through the sale date of November 20, 2019), Freeport Energy Center, 21.5% of Hidalgo Energy Center and, 25% of Freestone Energy Center. |
and 25% of Russell City Energy Center through January 28, 2020. Subsequent to that date, 100% of Russell City Energy Center is included.
| |
(2) | Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive. |
We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal
generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment.”
Commodity revenue, net of Commodity expense, decreased $18419 million for the three months ended MarchJune 31, 2020, compared to the same period in 2019, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):
30, 2020, compared to the same period in 2019, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):
|
| | | | |
(in millions) | | |
$ | 3 |
| | Higher margins primarily driven by higher resource adequacy revenue in the West, partially offset by the sale of our Garrison and RockGen Energy Centers in July 2019 |
(32 | ) | | Lower PJM and ISO-NE regulatory capacity revenue in our East segment |
10 |
| | Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other(1) |
$ | (19 | ) | | |
__________
| |
(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 items or non-recurring items. |
Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had an unfavorable variance of $152 million primarily driven by mark-to-market gains on commodity hedges recognized during the second quarter 2019 as forward commodity prices declined.
Our normal, recurring operating and maintenance expense, after excluding the effect of power plant portfolio changes and other one-time items such as COVID-19 pandemic costs as well as major maintenance expense associated with planned outages, was relatively unchanged for the three months ended June 30, 2020 compared to the same period in 2019.
Depreciation and amortization expense decreased by $12 million for the three months ended June 30, 2020 compared to the same period in 2019 primarily due to various assets being fully depreciated in 2019.
Other operating expenses decreased by $5 million for the three months ended June 30, 2020 compared to the same period in 2019 primarily due to lower project development expense following the sale of development projects.
During the three months ended June 30, 2019, we recorded impairment losses of approximately $40 million related to the sale of our Garrison and RockGen Energy Centers.
Interest expense increased by $10 million for the three months ended June 30, 2020 compared to the same period in 2019 primarily due to mark-to-market losses on interest rate derivative instruments executed in the first quarter of 2020 which are accounted for as economic hedges of forward interest rate exposure.
Loss on extinguishment of debt had an unfavorable variance of $5 million for the three months ended June 30, 2020 compared to the same period in 2019 primarily due to debt modification and extinguishment costs associated with our GPC Term Loan and the payoff of the Steamboat project debt facility in June 2020.
During the three months ended June 30, 2020, we recorded an income tax benefit of $31 million compared to an income tax expense of $9 million for the three months ended June 30, 2019. The favorable period-over-period change primarily resulted from the partial release of our valuation allowance associated with our NOLs during the second quarter of 2020.
Net income attributable to the noncontrolling interest decreased by $4 million for the three months ended June 30, 2020 compared to the same period in 2019 due to our acquisition of the 25% noncontrolling interest of Russell City Energy Company, LLC on January 28, 2020.
RESULTS OF OPERATIONS FOR THE SIX MONTHS ENDED JUNE 30, 2020 AND 2019
Below are our results of operations for the six months ended June 30, 2020 as compared to the same period in 2019 (in millions, except for percentages and operating performance metrics). In the comparative tables below, increases in revenue/income or decreases in expense (favorable variances) are shown without brackets while decreases in revenue/income or increases in expense (unfavorable variances) are shown with brackets.
|
| | | | | | | | | | | | | | |
| 2020 | | 2019 | | Change | | % Change |
Operating revenues: | | | | | | | |
Commodity revenue | $ | 3,795 |
| | $ | 4,666 |
| | $ | (871 | ) | | (19 | ) |
Mark-to-market gain | 232 |
| | 523 |
| | (291 | ) | | (56 | ) |
Other revenue | 9 |
| | 9 |
| | — |
| | — |
|
Operating revenues | 4,036 |
| | 5,198 |
| | (1,162 | ) | | (22 | ) |
Operating expenses: | | | | | | | |
Fuel and purchased energy expense: | | | | | | | |
Commodity expense | 2,457 |
| | 3,125 |
| | 668 |
| | 21 |
|
Mark-to-market (gain) loss | (4 | ) | | 290 |
| | 294 |
| | # |
|
Fuel and purchased energy expense | 2,453 |
| | 3,415 |
| | 962 |
| | 28 |
|
Operating and maintenance expense | 506 |
| | 484 |
| | (22 | ) | | (5 | ) |
Depreciation and amortization expense | 327 |
| | 349 |
| | 22 |
| | 6 |
|
General and other administrative expense | 62 |
| | 66 |
| | 4 |
| | 6 |
|
Other operating expenses | 31 |
| | 38 |
| | 7 |
| | 18 |
|
Total operating expenses | 3,379 |
| | 4,352 |
| | 973 |
| | 22 |
|
Impairment losses | — |
| | 55 |
| | 55 |
| | # |
|
(Income) from unconsolidated subsidiaries | (4 | ) | | (11 | ) | | (7 | ) | | (64 | ) |
Income from operations | 661 |
| | 802 |
| | (141 | ) | | (18 | ) |
Interest expense | 336 |
| | 306 |
| | (30 | ) | | (10 | ) |
(Gain) loss on extinguishment of debt | 8 |
| | (1 | ) | | (9 | ) | | # |
|
Other (income) expense, net | 9 |
| | 28 |
| | 19 |
| | 68 |
|
Income before income taxes | 308 |
| | 469 |
| | (161 | ) | | (34 | ) |
Income tax expense | 15 |
| | 19 |
| | 4 |
| | 21 |
|
Net income | 293 |
| | 450 |
| | (157 | ) | | (35 | ) |
Net income attributable to the noncontrolling interest | (2 | ) | | (9 | ) | | 7 |
| | 78 |
|
Net income attributable to Calpine | $ | 291 |
| | $ | 441 |
| | $ | (150 | ) | | (34 | ) |
|
| | | | | | | | | | | |
| 2020 | | 2019 | | Change | | % Change |
Operating Performance Metrics: | | | | | | | |
MWh generated (in thousands)(1)(2) | 47,405 |
| | 43,257 |
| | 4,148 |
| | 10 |
|
Average availability(2) | 84.0 | % | | 84.2 | % | | (0.2 | )% | | — |
|
Average total MW in operation(1) | 25,273 |
| | 25,558 |
| | (285 | ) | | (1 | ) |
Average capacity factor, excluding peakers | 47.1 | % | | 43.9 | % | | 3.2 | % | | 7 |
|
Steam Adjusted Heat Rate(2) | 7,311 |
| | 7,305 |
| | (6 | ) | | — |
|
__________
| |
# | Variance of 100% or greater |
| |
(1) | Represents generation and capacity from power plants that we both consolidate and operate and excludes Greenfield LP, Whitby (through the sale date of November 20, 2019), Freeport Energy Center, 21.5% of Hidalgo Energy Center, 25% of Freestone Energy Center and 25% of Russell City Energy Center through January 28, 2020. Subsequent to that date, 100% of Russell City Energy Center is included. |
| |
(2) | Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive. |
We evaluate our Commodity revenue and Commodity expense on a collective basis because the price of power and natural gas tend to move together as the price for power is generally determined by the variable operating cost of the next marginal generator to be dispatched to meet demand. The spread between our Commodity revenue and Commodity expense represents a significant portion of our Commodity Margin. Our financial performance is correlated to how we maximize our Commodity Margin through management of our portfolio of power plants, as well as our hedging and optimization activities. See additional segment discussion in “Commodity Margin by Segment.”
Commodity revenue, net of Commodity expense, decreased $203 million for the six months ended June 30, 2020, compared to the same period in 2019, primarily due to (favorable variances are shown without brackets while unfavorable variances are shown with brackets):
|
| | | | |
(in millions) | | |
$ | (130 | ) | | Lower margins primarily driven by lower contribution from wholesale hedging activity resulting from milder weather in the first quarter of 2020, lower market Spark Spreads in the West and the sale of our Garrison and RockGen Energy Centers in July 2019. The decrease was partially offset by the commencement of commercial operations at our 828 MW York 2 Energy Center in March 2019 and higher resource adequacy revenue in the West |
(90 | ) | | Lower PJM and ISO-NE regulatory capacity revenue in our East segment |
17 |
| | Period-over-period change in contract amortization, lease levelization relating to tolling contracts and other(1) |
$ | (203 | ) | | |
__________
| |
(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 items or non-recurring items. |
Mark-to-market gain/loss, net from hedging our future generation, fuel supply requirements and retail activities had a favorable variance of $1553 million primarily driven by mark-to-market losses recognized on settled positionsthe settlement of hedges during the six months ended June 30, 2019 that exceeded mark-to-market settlement roll off losses recognized during the first quarter of 2019 compared tosame period in 2020. This positive variance is partially offset by mark-to-market gains on settled positionsrecognized on forward commodity hedge positions as market prices declined during the six months ended June 30, 2019, which were in excess of the mark-to-market gains recognized during the first quarter ofsame period in 2020.
Operating and maintenance expenseOur normal, recurring operating and maintenance expense, after excluding the effect of power plant portfolio changes and other one-time items such as COVID-19 pandemic costs as well as major maintenance expense associated with planned outages, was relatively unchanged for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019. Excluding a $4 million decrease in major maintenance expense resulting from our plant outage schedule, our normal, recurring operating and maintenance expense increased approximately $5 million attributable to an increase in insurance premium costs and health insurance and benefits costs.
Depreciation and amortization expense decreased by $1022 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 primarily due to adjustments related to our asset retirement obligations during the first quarter of 2019 and various assets being fully depreciated in 2019.
Other operating expenses decreased by $177 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 primarily due to an adjustment recordedlower project development expense following the sale of development projects.
During the six months ended June 30, 2019, we recorded impairment losses of approximately $55 million related to the carrying valuesale of our Garrison and RockGen Energy Centers. We executed an agreement to sell our Garrison and RockGen Energy Centers in April 2019 and completed the sale in July 2019.
(Income) from unconsolidated subsidiaries decreased by $67 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 primarily due to the sale of Whitby in November 2019.
Interest expense increased by $2030 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 primarily due to mark-to-market losses on interest rate derivative instruments executed in the first quarter of 2020 which are accounted for as economic hedges of forward interest rate exposure.
Gain (loss) on extinguishment of debt had an unfavorable variance of $49 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 primarily due to the repurchasedebt modification and extinguishment costs associated with our GPC Term Loan and the payoff of a portion of our Senior Unsecured Notesthe Steamboat project debt facility in the first quarter of 2019.June 2020.
Other (income) expense, net decreased by $19 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 primarily due to the net effect of a settlement agreement with General Electric International, Inc. executed in February 2019 related to the Inland Empire Energy Center.
During the threesix months ended MarchJune 3130, 2020, we recorded an income tax expense of $4615 million compared to $1019 million for the threesix months ended MarchJune 3130, 2019. The increasefavorable period-over-period change primarily resulted from a higher federal deferred tax accrual for the three months ended March 31, 2020 as a result of the effectthe partial release of our NOLs and valuation allowance and applyingassociated with our NOLs during the intraperiod tax allocation rules to our results of operations and related tax expense.
second quarter of 2020.
Net income attributable to the noncontrolling interest decreased by $37 million for the threesix months ended MarchJune 3130, 2020 compared to the same period in 2019 due to our acquisition of the 25% 25% noncontrolling interest of Russell City Energy Company, LLC on January 28, 2020.
COMMODITY MARGIN BY SEGMENT
We use Commodity Margin to assess reportable segment performance. Commodity Margin includes revenues recognized on our wholesale and retail power sales activity, electric capacity sales, REC sales, steam sales, realized settlements associated with our marketing, hedging, optimization and trading activity less costs from our fuel and purchased energy expenses, commodity transmission and transportation expenses, environmental compliance expenses and ancillary retail expense. We believe that Commodity Margin is a useful tool for assessing the performance of our core operations and is a key operational measure of profit reviewed by our chief operating decision maker. See Note 11 of the Notes to Consolidated Condensed Financial Statements for a reconciliation of Commodity Margin to income (loss) from operations by segment.
Commodity Margin by Segment for the Three Months Ended MarchJune 3130, 2020 and 2019
The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the three months ended MarchJune 3130, 2020 and 2019 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by regional segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
West — Commodity Margin in our West segment decreased by $30 |
| | | | | | | | | | | | | | |
West: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 269 |
| | $ | 251 |
| | $ | 18 |
| | 7 |
|
Commodity Margin per MWh generated | $ | 48.78 |
| | $ | 62.52 |
| | $ | (13.74 | ) | | (22 | ) |
| | | | | | | |
MWh generated (in thousands) | 5,515 |
| | 4,015 |
| | 1,500 |
| | 37 |
|
Average availability | 84.4 | % | | 79.7 | % | | 4.7 | % | | 6 |
|
Average total MW in operation | 7,590 |
| | 7,430 |
| | 160 |
| | 2 |
|
Average capacity factor, excluding peakers | 35.4 | % | | 26.6 | % | | 8.8 | % | | 33 |
|
Steam Adjusted Heat Rate | 7,552 |
| | 7,526 |
| | (26 | ) | | — |
|
West — Commodity Margin in our West segment increased by $18 million, or 7%, for the three months ended June 30, 2020 compared to the three months ended June 30, 2019, primarily due to higher resource adequacy revenue, increased contribution from higher generation driven in part by the restart of our South Point Energy Center during the second half of 2019, and the acquisition on January 28, 2020 of the 25% noncontrolling interest of Russell City Energy Company, LLC, which was previously owned by a third party.
|
| | | | | | | | | | | | | | |
Texas: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 172 |
| | $ | 173 |
| | $ | (1 | ) | | (1 | ) |
Commodity Margin per MWh generated | $ | 15.12 |
| | $ | 16.48 |
| | $ | (1.36 | ) | | (8 | ) |
| | | | | | | |
MWh generated (in thousands) | 11,377 |
| | 10,497 |
| | 880 |
| | 8 |
|
Average availability | 80.9 | % | | 80.9 | % | | — | % | | — |
|
Average total MW in operation | 8,913 |
| | 8,855 |
| | 58 |
| | 1 |
|
Average capacity factor, excluding peakers | 58.4 | % | | 54.3 | % | | 4.1 | % | | 8 |
|
Steam Adjusted Heat Rate | 7,088 |
| | 7,149 |
| | 61 |
| | 1 |
|
Texas — Commodity Margin in our Texas segment was relatively unchanged for the three months ended June 30, 2020 compared to the three months ended June 30, 2019. Lower contribution from hedging activity was largely offset by modestly higher market Spark Spreads during the second quarter of 2020 compared to the same period in 2019.
|
| | | | | | | | | | | | | | |
East: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 193 |
| | $ | 235 |
| | $ | (42 | ) | | (18 | ) |
Commodity Margin per MWh generated | $ | 34.46 |
| | $ | 35.37 |
| | $ | (0.91 | ) | | (3 | ) |
| | | | | | | |
MWh generated (in thousands) | 5,601 |
| | 6,644 |
| | (1,043 | ) | | (16 | ) |
Average availability | 79.6 | % | | 83.5 | % | | (3.9 | )% | | (5 | ) |
Average total MW in operation | 8,811 |
| | 9,623 |
| | (812 | ) | | (8 | ) |
Average capacity factor, excluding peakers | 36.0 | % | | 41.8 | % | | (5.8 | )% | | (14 | ) |
Steam Adjusted Heat Rate | 7,665 |
| | 7,571 |
| | (94 | ) | | (1 | ) |
East — Commodity Margin in our East segment decreased by $42 million, or 18%, for the three months ended June 30, 2020 compared to the three months ended June 30, 2019, primarily due to lower regulatory capacity revenue in ISO-NE and PJM and the period-over-period effect of the sale of our Garrison and RockGen Energy Centers in July 2019. Generation decreased 16% due to the sale of Garrison Energy Center and planned outages during the second quarter of 2020 compared to the same period in 2019.
|
| | | | | | | | | | | | | | |
Retail: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 89 |
| | $ | 93 |
| | $ | (4 | ) | | (4 | ) |
Retail — Commodity Margin in our retail segment was relatively unchanged for the three months ended June 30, 2020 compared to the three months ended June 30, 2019.
Commodity Margin by Segment for the Six Months Ended June 30, 2020 and 2019
The following tables show our Commodity Margin by segment and related operating performance metrics by regional segment for our wholesale business for the six months ended June 30, 2020 and 2019 (exclusive of the noncontrolling interest). In the comparative tables below, favorable variances are shown without brackets while unfavorable variances are shown with brackets. The MWh generated by regional segment below represent generation from power plants that we both consolidate and operate. Generation, average availability and Steam Adjusted Heat Rate exclude power plants and units that are inactive.
|
| | | | | | | | | | | | | | |
West: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 503 |
| | $ | 515 |
| | $ | (12 | ) | | (2 | ) |
Commodity Margin per MWh generated | $ | 40.22 |
| | $ | 47.76 |
| | $ | (7.54 | ) | | (16 | ) |
| | | | | | | |
MWh generated (in thousands) | 12,505 |
| | 10,784 |
| | 1,721 |
| | 16 |
|
Average availability | 86.7 | % | | 83.3 | % | | 3.4 | % | | 4 |
|
Average total MW in operation | 7,566 |
| | 7,428 |
| | 138 |
| | 2 |
|
Average capacity factor, excluding peakers | 40.4 | % | | 35.9 | % | | 4.5 | % | | 13 |
|
Steam Adjusted Heat Rate | 7,457 |
| | 7,391 |
| | (66 | ) | | (1 | ) |
West — Commodity Margin in our West segment decreased by $12 million, or 112%, for the threesix months ended MarchJune 3130, 2020 compared to the threesix months ended MarchJune 3130, 2019, primarily due to lower market Spark Spreads in January and February 2020 resulting largely from lower natural gas prices in Southern California and lower contribution from hedging activity. The period-over-period decrease in Commodity Margin was partially offset by anhigher resource adequacy revenue and increased contribution from hedging activityhigher generation driven in part by the restart of our South Point Energy Center during the first quarter of 2020 compared to the same period in second half of 2019.
|
| | | | | | | | | | | | | | |
Texas: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 285 |
| | $ | 335 |
| | $ | (50 | ) | | (15 | ) |
Commodity Margin per MWh generated | $ | 12.78 |
| | $ | 16.17 |
| | $ | (3.39 | ) | | (21 | ) |
| | | | | | | |
MWh generated (in thousands) | 22,295 |
| | 20,713 |
| | 1,582 |
| | 8 |
|
Average availability | 80.8 | % | | 81.8 | % | | (1.0 | )% | | (1 | ) |
Average total MW in operation | 8,896 |
| | 8,852 |
| | 44 |
| | — |
|
Average capacity factor, excluding peakers | 57.4 | % | | 53.9 | % | | 3.5 | % | | 6 |
|
Steam Adjusted Heat Rate | 7,080 |
| | 7,110 |
| | 30 |
| | — |
|
Texas — Commodity Margin in our Texas segment decreased by $4950 million, or 3015%, for the threesix months ended MarchJune 3130, 2020 compared to the threesix months ended MarchJune 3130, 2019, primarily due to lower contribution from hedging activity resulting from milder weather inprimarily during the first quarter of 2020 compared to the same period in 2019. The decrease in Commodity Margin was partially offset by higher market Spark Spreads during the three months ended March 31, 2020when compared to the same period induring 2019.
|
| | | | | | | | | | | | | | |
East: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 343 |
| | $ | 500 |
| | $ | (157 | ) | | (31 | ) |
Commodity Margin per MWh generated | $ | 27.21 |
| | $ | 42.52 |
| | $ | (15.31 | ) | | (36 | ) |
| | | | | | | |
MWh generated (in thousands) | 12,605 |
| | 11,760 |
| | 845 |
| | 7 |
|
Average availability | 85.0 | % | | 87.3 | % | | (2.3 | )% | | (3 | ) |
Average total MW in operation | 8,811 |
| | 9,278 |
| | (467 | ) | | (5 | ) |
Average capacity factor, excluding peakers | 40.6 | % | | 39.1 | % | | 1.5 | % | | 4 |
|
Steam Adjusted Heat Rate | 7,613 |
| | 7,596 |
| | (17 | ) | | — |
|
East — Commodity Margin in our East segment decreased by $115157 million, or 4331%, for the threesix months ended MarchJune 3130, 2020 compared to the threesix months ended MarchJune 3130, 2019, primarily due to lower regulatory capacity revenue in ISO-NE and PJM, the sale of our Garrison and RockGen Energy Centers in July 2019 and lower contribution from hedging activity resulting from milder weather during the first quarter of 2020 compared to the same period in 2019. The decrease in Commodity Margin was partially offset by the commencement of commercial operations at our 828 MW York 2 Energy Center in March 2019, which was also the primary contributor to the 377% increase in generation.
|
| | | | | | | | | | | | | | |
Retail: | 2020 | | 2019 | | Change | | % Change |
Commodity Margin (in millions) | $ | 180 |
| | $ | 181 |
| | $ | (1 | ) | | (1 | ) |
Retail — Commodity Margin in our retail segment was relatively unchanged for the threesix months ended MarchJune 3130, 2020 compared to the threesix months ended MarchJune 3130, 2019.
LIQUIDITY AND CAPITAL RESOURCES
We maintain a strong focus on liquidity. We manage our liquidity to help provide access to sufficient funding to meet our business needs and financial obligations throughout business cycles.
Our business is capital intensive. Our ability to successfully implement our strategy is dependent on the continued availability of capital on attractive terms. In addition, our ability to successfully operate our business is dependent on maintaining sufficient liquidity. We believe that we have adequate resources from a combination of cash and cash equivalents on hand and cash expected to be generated from future operations to continue to meet our obligations as they become due.
Liquidity
The following table provides a summary of our liquidity position at MarchJune 3130, 2020 and December 31, 2019 (in millions):
|
| | | | | | | |
| June 30, 2020 | | December 31, 2019 |
Cash and cash equivalents, corporate(1) | $ | 574 |
| | $ | 1,072 |
|
Cash and cash equivalents, non-corporate(2) | 103 |
| | 59 |
|
Total cash and cash equivalents | 677 |
| | 1,131 |
|
Restricted cash(2) | 241 |
| | 345 |
|
Corporate Revolving Facility availability(3) | 1,534 |
| | 1,392 |
|
CDHI revolving facility availability(4) | 1 |
| | 1 |
|
Other facilities availability(5) | 37 |
| | 3 |
|
Total current liquidity availability(6) | $ | 2,490 |
| | $ | 2,872 |
|
____________
| |
(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 outstanding approximately $1,052 million aggregate principal amount of our 2022 and 2024 First Lien Notes and 2023 Senior Unsecured Notes. See Note 4 of the Notes to Consolidated Condensed 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 1 of the Notes to Consolidated Condensed 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. At MarchJune 3130, 2020, the approximately $2.0 billion in total capacity under our Corporate Revolving Facility is comprised of $450$462 million in borrowings outstanding, $636 million in letters of credit outstanding and $910, no borrowings outstanding and $1,534 million in remaining available capacity. In April 2020, we repaid $200 million in borrowings on our Corporate Revolving Facility. See “Letter of Credit Facilities” below for amounts issued under letters of credit at March 31, 2020 associated with our Corporate Revolving Facility. in remaining available capacity. |
| |
(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. |
| |
(5) | On April 9, 2020, we amended one of our unsecured letter of credit facilities to partially extend the maturity of $100 million in commitments from June 20, 2020 to June 20, 2022. On June 9, 2020, we entered into the GPC Term Loan which provides for $200 million in letter of credit facilities. |
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(6) | Includes $9323 million and $127 million of margin deposits posted with us by our counterparties at MarchJune 3130, 2020 and December 31, 2019, respectively. See Note 7 of the Notes to Consolidated Condensed Financial Statements for further information related to our collateral. |
Our principal source for future liquidity is cash flows generated from our operations. We believe that cash on hand and expected future cash flows from operations will be sufficient to meet our liquidity needs for our operations, both in the near and longer term. See “Cash Flow Activities” below for a further discussion of our change in cash, cash equivalents and restricted cash.
Our principal uses of liquidity and capital resources, outside of those required for our operations, include, but are not limited to, collateral requirements to support our commercial hedging and optimization activities, debt service obligations including principal and interest payments, capital expenditures for construction, project development and other growth initiatives and opportunistically repaying debt to manage our balance sheet.
Cash Management — We manage our cash in accordance with our cash management system subject to the requirements of our Corporate Revolving Facility and requirements under certain of our project debt and lease agreements or by regulatory
agencies. Our cash and cash equivalents, as well as our restricted cash balances, are invested in money market funds that are not FDIC insured. We place our cash, cash equivalents and restricted cash in what we believe to be creditworthy financial institutions.
Future cash dividends, if any, may be authorized at the discretion of our Board of Directors and will depend upon, among other things, our future operations and earnings, capital requirements, asset sales, general financial condition, contractual and financing restrictions and such other factors as our Board of Directors may deem relevant.
Liquidity Sensitivity
Significant changes in commodity prices and Market Heat Rates can affect our liquidity as we use margin deposits, cash prepayments and letters of credit as credit support (collateral) with and from our counterparties for commodity procurement and risk management activities. We estimate that as of MarchJune 3130, 2020, a three standard deviation shift in collateral exposure based on commodity market price changes for the previous 12 months applied to our current portfolio of margined transactions would result in an increase in collateral posted of approximately $348336 million. This amount is not necessarily indicative of the actual amounts that could be required, which may be higher or lower than the amounts estimated above, and also exclude any correlation between the changes in natural gas prices and Market Heat Rates that may occur concurrently. These sensitivities will change as new contracts or hedging activities are executed.
In order to effectively manage our future Commodity Margin, we have economically hedged a portion of our 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. In addition to the price of natural gas, our Commodity Margin is highly dependent on other factors such as:
| |
• | the level of Market Heat Rates; |
| |
• | our continued ability to successfully hedge our Commodity Margin; |
| |
• | changes in U.S. macroeconomic conditions; |
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• | maintaining acceptable availability levels for our fleet; |
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• | the effect of current and pending environmental regulations in the markets in which we participate; |
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• | improving the efficiency and profitability of our operations; |
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• | increasing future contractual cash flows; and |
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• | our significant counterparties performing under their contracts with us. |
Additionally, scheduled outages related to the life cycle of our power plant fleet in addition to unscheduled outages may result in maintenance expenditures that are disproportionate in differing periods. In order to manage such liquidity requirements, we maintain additional liquidity availability in the form of our Corporate Revolving Facility (noted in the table above), letters of credit and the ability to issue first priority liens for collateral support. It is difficult to predict future developments and the amount of credit support that we may need to provide should such conditions occur, we experience an economic recession or energy commodity prices increase significantly.
Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at MarchJune 3130, 2020 and December 31, 2019 (in millions):
|
| | | | | | | |
| June 30, 2020 | | December 31, 2019 |
Corporate Revolving Facility(1) | $ | 462 |
| | $ | 604 |
|
CDHI | 3 |
| | 3 |
|
Various project financing facilities(2) | 336 |
| | 184 |
|
Other corporate facilities(3) | 275 |
| | 294 |
|
Total | $ | 1,076 |
| | $ | 1,085 |
|
____________
| |
(1) | The Corporate Revolving Facility represents our primary revolving facility and matures on March 8, 2023. |
| |
(2) | On June 9, 2020, we entered into the GPC Term Loan which provides for $200 million in letter of credit facilities. |
| |
(3) | On April 9, 2020, we amended one of our unsecured letter of credit facilities to partially extend the maturity of $100 million in commitments from June 20, 2020 to June 20, 2022. |
California Wildfire
A wildfire known as the Kincade Fire began on October 23, 2019 in Sonoma County, California where our Geysers Assets are located and burned on parts of the 45 square miles that make up our Geysers Assets properties and leasehold. Operating equipment at our Geysers Assets sustained limited damage which has been repaired. The fire caused extensive damage to third-party property in the region. Transmission service owned and operated by PG&E was cut due to the fire and high wind conditions, forcing us to suspend operations. In March 2020, transmission was restored and we resumed full operations of our Geysers Assets.
Prior to the fire, in response to forecasted severe wind conditions and PG&E’s Public Safety Power Shutoff (“PSPS”), personnel at our Geysers Assets followed fire prevention protocols, including de-energizing the local power system that supports our Geysers Assets operations. We do not believe our facilities caused or contributed to the start of the fire, nor do we believe we have any liability for damages caused by the fire. Notably, PG&E hason July filed a notice with the CPUC that it was notified by16, 2020, the California Department of Forestry and Fire Protection (“CALFIRE”) issued a press release stating that equipment on one of its transmission towers was observed to be broken at the location thattransmission lines owned and operated by PG&E were the cause of the Kincade Fire, however, CALFIRE is investigating as the fire’s potential point of origin. The ultimate liability for the fire cannot presently be determined, nor can the liability for any parties that could potentially result from a negative outcome be reasonably estimatedhas not yet released its investigation report.
Our Geysers Assets remain a critical part of the California plan to achieve a low-carbon future. In our view, our investments and processes at our Geysers Assets assure the facilities are as fire resistant and resilient as possible, and we expect our Geysers Assets will remain ready to help California meet that challenge.
NOLs
We have significant NOLs that will provide future tax deductions whenas we generate sufficientan offset to taxable income during the applicable carryover periods. At December 31, 2019, our consolidated federal NOLs totaled approximately $7.1 billion. Additionally, we had a federal valuation allowance in the amount of $873 million at December 31, 2019 due to the uncertainty in our ability to utilize NOLs prior to expiration.
Cash Flow Activities
The following table summarizes our cash flow activities for the threesix months ended MarchJune 3130, 2020 and 2019 (in millions):
|
| | | | | | | |
| 2020 | | 2019 |
Beginning cash, cash equivalents and restricted cash | $ | 1,476 |
| | $ | 406 |
|
Net cash provided by (used in): | | | |
Operating activities | 434 |
| | 519 |
|
Investing activities | (304 | ) | | (315 | ) |
Financing activities | (688 | ) | | (51 | ) |
Net increase (decrease) in cash, cash equivalents and restricted cash | (558 | ) | | 153 |
|
Ending cash, cash equivalents and restricted cash | $ | 918 |
| | $ | 559 |
|
Net Cash Provided By Operating Activities
Cash provided by operating activities for the threesix months ended MarchJune 3130, 2020, was $213434 million compared to $241519 million for the threesix months ended MarchJune 3130, 2019. The decrease was primarily due to:
| |
• | Income from operations — Income from operations, adjusted for non-cash items primarily including depreciation and amortization, impairment losses, and mark- to- market activitygains decreased by $189228 million for the threesix months ended March 31June 30, 2020, compared to 2019. The decrease in income from operations, adjusted for non-cash items, was primarily driven by a $184203 million decrease in Commodity revenue, net of Commodity expense. See “Results of Operations forwhich is driven by a decrease in regulatory capacity revenues in PJM and ISO-NE as well as a lower contribution from hedging activity on milder weather during the first quarter of 2020 when compared to the Three Months Ended March 31, 2020 andsame period during 2019” above for further discussion of these changes.. |
| |
• | Working capital employed — Working capital employed decreased by $148123 million for the threesix months ended March 31June 30, 2020, compared to the same period in 2019. ThisThe decrease wasis primarily duedriven toby a reduction in cash margin postings onassociated with our commodity hedging activities. |
forward hedging positions, a reduction in environmental products inventory procurement, and change in timing of interest payable accruals as a result of the refinancing efforts undertaken during the fourth quarter of 2019.
Net Cash Used In Investing Activities
Cash used in investing activities for the threesix months ended MarchJune 3130, 2020, was $126304 million compared to $152315 million for the threesix months ended MarchJune 3130, 2019. The decrease was primarily due to:
| |
• | Capital expenditures — During the threesix months ended March 31June 30, 2020, we incurred lower capital expenditures on construction and growth projects as compared to the same period in 2019 due to the completion of construction of our York 2 Energy Center in March 2019 as well as normal timing differences in capital expenditures associated with planned maintenance projects. . |
Net Cash Provided by (Used In) Financing Activities
Cash used in financing activities for the threesix months ended MarchJune 3130, 2020, was $726688 million compared to cash provided by financing activities of $2351 million for the threesix months ended MarchJune 3130, 2019. The change was primarily due to:
| |
• | Debt transactions — During the threesix months ended March 31June 30, 2020, we redeemed the aggregate principal outstanding in the amount of $1,052 million consisting of $623 million of the 2023 Senior Unsecured Notes, $245 million of the 2022 First Lien Notes and $184 million of the 2024 First Lien Notes utilizing proceeds received from the issuance of our 2028 First Lien Notes and 2028 Senior Unsecured Notes during December of 2019. This variance was partially reduced by the repurchase of $48 million in aggregate principal of Senior Unsecured Notes for $44 million during the threesix months ended March 31June 30, 2019, where no similar repurchases were noted during the same period in 2020.time period during 2020. |
| |
• | GPC Term Loan — During the six months ended June 30, 2020, GPC entered into a new seven-year $900 million first lien senior secured term loan facility and three senior secured revolving letter of credit facilities totaling $200 million. We incurred lender fees and third party costs associated with the GPC Term Loan of $28 million. The proceeds from the Geysers financing transaction were utilized in part to repay the Steamboat project debt principal amount of $348 million. |
| |
• | Corporate Revolving Facility — During the threesix months ended March 31, 2020, out of an abundance of caution to ensure sufficient liquidity in response to the COVID-19 pandemic, we borrowed aJune 30, 2019, we had net $450borrowings of $45 million under our Corporate Revolving Facility, compared to no net borrowings of $120 million during the same period in 20192020. |
| |
• | Acquisition — During the threesix months ended March 31June 30, 2020, we completed our acquisition of the 25% noncontrolling interest of Russell City Energy Company, LLC for $35 million plus working capital adjustments of approximately $14 million for a total purchase price of approximately $49 million. |
Off Balance Sheet Arrangements
There have been no material changes to our off balance sheet arrangements from those disclosed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2019 Form 10-K.
Special Purpose Subsidiaries
Pursuant to applicable transaction agreements, we have established certain of our entities separate from Calpine Corporation and our other subsidiaries. In accordance with applicable accounting standards, we consolidate these entities with the exception of Calpine Receivables (see Notes 7 and 17 of the Notes to Consolidated Financial Statements in our 2019 Form 10-K for further information related to Calpine Receivables). As of the date of filing of this Report, these entities included: Russell City Energy Company, LLC, GPC, Calistoga Holdings, LLC, Wildhorse Geothermal, LLC, Geysers Intermediate Holdings, LLC, Geysers Company, LLC and Calpine Receivables.
Russell City Energy Company, LLC — On January 28, 2020, we completed the acquisition of the 25% of Russell City Energy Company, LLC, thatwhich was previously owned by a third party for, for $35 million plus working capital adjustments of approximately $14 million for a total purchase price of approximately $49 million.
RISK MANAGEMENT AND COMMODITY ACCOUNTING
Our commercial hedging and optimization strategies are designed to maximize our risk-adjusted Commodity Margin by leveraging our knowledge, experience and fundamental views on natural gas and power. We actively manage our risk exposures with a variety of physical and financial instruments with varying time horizons. These instruments include PPAs, tolling arrangements, Heat Rate swaps and options, 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. 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.
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. Changes in fair value of commodity positions that do not qualify for or for which we do not elect either hedge accounting or the normal purchase normal sale exemption are recognized currently in earnings and are separately stated on our Consolidated Condensed 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). Our future hedged status and marketing and optimization activities are subject to change as determined by our commercial operations group, Chief Risk Officer, senior management and Board of Directors.
At any point in time, the relative quantity of our products hedged or sold under longer-term contracts is determined by the availability of forward product sales opportunities and our view of the attractiveness of the pricing available for forward sales. We have economically hedged a portion of our expected generation and natural gas portfolio 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 have historically used interest rate hedging instruments to adjust the mix between our fixed and variable rate debt. A portion of 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. See Note 6 of the Notes to Consolidated Condensed Financial Statements for further discussion of our derivative instruments.
The primary factors affecting our market risk and the fair value of our derivatives at any point in time are the volume of open derivative positions (MMBtu, MWh and $ notional amounts); changing commodity market prices, primarily for power and natural gas; our credit standing and that of our counterparties for energy commodity derivatives; and prevailing interest rates for our interest rate hedging instruments. Since prices for power and natural gas and interest rates are volatile, there may be material changes in the fair value of our derivatives over time, driven both by price volatility and the changes in volume of open derivative transactions. Our derivative assets have increased to approximately $489449 million at MarchJune 3130, 2020, compared to approximately $402 million at December 31, 2019, and our derivative liabilities have increased to approximately $378364 million at MarchJune 3130, 2020, compared to approximately $288 million at December 31, 2019. The fair value of our level 3 derivative assets and liabilities at MarchJune 3130, 2020 represents approximately 37% and 2421% of our total assets and liabilities measured at fair value, respectively. See Note 5 of the Notes to Consolidated Condensed Financial Statements for further information related to our level 3 derivative assets and liabilities.
The change in fair value of our outstanding commodity and interest rate hedging instruments from January 1, 2020, through MarchJune 3130, 2020, is summarized in the table below (in millions):
|
| | | | | | | | | | | |
| Commodity Instruments | | Interest Rate Hedging Instruments | | Total |
Fair value of contracts outstanding at January 1, 2020 | $ | 133 |
| | $ | (19 | ) | | $ | 114 |
|
Items recognized or otherwise settled during the period(1)(2) | (52 | ) | | 21 |
| | (31 | ) |
Fair value attributable to new contracts(3) | 88 |
| | (86 | ) | | 2 |
|
Changes in fair value attributable to price movements | 77 |
| | (77 | ) | | — |
|
Fair value of contracts outstanding at June 30, 2020(4) | $ | 246 |
| | $ | (161 | ) | | $ | 85 |
|
__________
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(1) | Commodity contract settlements consist of the realization of previously recognized lossesgains on contracts not designated as hedging instruments of $(32)44 million (represents a portion of Commodity revenue and Commodity expense as reported on our Consolidated Condensed Statements of Operations) and $(28) million related to current period losses from other changes in derivative assets and liabilities not reflected in OCI or earnings. |
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(2) | Interest rate settlements consist of $25 million related to realized losses from settlements of designated cash flow hedges and nil$16 million related to realized losses roll-off from settlements of undesignated interest rate hedging instruments (represents a portion of interest expense as reported on our Consolidated Condensed Statements of Operations). |
| |
(3) | Fair value attributable to new contracts includes $(8) million and nil of fair value related to commodity contracts and interest rate hedging instruments, respectively, which are not reflected in OCI or earnings. |
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(4) | We netted all amounts allowed under the derivative accounting guidance on our Consolidated Condensed 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 5 and 6 of the Notes to Consolidated Condensed Financial Statements are shown net of collateral paid to and received from counterparties under legally enforceable master netting arrangements. |
Commodity Price Risk — Commodity price risks result from exposure to changes in spot prices, forward prices, price volatilities and correlations between the price of power, steam and natural gas. We manage the commodity price risk and the variability in future cash flows from forecasted sales of power and purchases of natural gas of our entire portfolio of generating assets and contractual positions by entering into various derivative and non-derivative instruments.
The net fair value of outstanding derivative commodity instruments, net of allocated collateral, at MarchJune 3130, 2020, based on price source and the period during which the instruments will mature, are summarized in the table below (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
Fair Value Source | | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
Prices actively quoted | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Prices provided by other external sources | | (65 | ) | | 61 |
| | 3 |
| | 1 |
| | — |
|
Prices based on models and other valuation methods | | 28 |
| | 95 |
| | 74 |
| | 49 |
| | 246 |
|
Total fair value | | $ | (37 | ) | | $ | 156 |
| | $ | 77 |
| | $ | 50 |
| | $ | 246 |
|
We measure the energy commodity price risk in our portfolio on a daily basis using a VAR model to estimate the potential one-day risk of loss based upon historical experience resulting from potential market movements. Our VAR is calculated for our entire portfolio comprising energy commodity derivatives, expected generation and natural gas consumption from our power plants, PPAs, and other physical and financial transactions. We measure VAR using a variance/covariance approach based on a confidence level of 95%, a one-day holding period and actual observed historical correlation. While we believe that our VAR assumptions and approximations are reasonable, different assumptions and/or approximations could produce materially different estimates.
The table below presents the high, low and average of our daily VAR for the three and six months ended MarchJune 3130, 2020 and 2019 (in millions):
|
| | | | | | | |
| 2020 | | 2019 |
Three months ended June 30: | | | |
High | $ | 27 |
| | $ | 39 |
|
Low | $ | 13 |
| | $ | 22 |
|
Average | $ | 20 |
| | $ | 28 |
|
| | | |
Six months ended June 30: | | | |
High | $ | 29 |
| | $ | 50 |
|
Low | $ | 13 |
| | $ | 22 |
|
Average | $ | 20 |
| | $ | 32 |
|
As of June 30 | $ | 15 |
| | $ | 37 |
|
Due to the inherent limitations of statistical measures such as VAR, the VAR calculation may not capture the full extent of our commodity price exposure. As a result, actual changes in the value of our energy commodity portfolio could be different from the calculated VAR, and could have a material effect on our financial results. In order to evaluate the risks of our portfolio on a comprehensive basis and augment our VAR analysis, we also measure the risk of the energy commodity portfolio using several analytical methods including sensitivity analysis, non-statistical scenario analysis, including stress testing, and daily position report analysis.
We utilize the forward commodity markets to hedge price risk associated with our power plant portfolio. Our ability to hedge relies in part on market liquidity and the number of counterparties with which to transact. If the number of counterparties in these markets were to decrease, it could decrease our ability to hedge our forward commodity price risk and create incremental volatility in our earnings. The effects of declining liquidity in the forward commodity markets is also mitigated by our retail subsidiaries which provides us with an additional outlet to transact hedging activities related to our wholesale power plant portfolio.
Liquidity Risk — Liquidity risk arises from the general funding requirements needed to manage our activities and assets and liabilities. Fluctuating natural gas prices or Market Heat Rates can cause our collateral requirements for our wholesale and retail activities to increase or decrease. Our liquidity management framework is intended to maximize liquidity access and minimize funding costs during times of rising prices. See further discussion regarding our uses of collateral as they relate to our commodity procurement and risk management activities in Note 7 of the Notes to Consolidated Condensed Financial Statements.
Credit Risk — Credit risk relates to the risk of loss resulting from nonperformance or non-payment by our counterparties or customers related to their contractual obligations with us. Risks surrounding counterparty and customer performance and credit could ultimately affect the amount and timing of expected cash flows. We also have credit risk if counterparties or customers are unable to provide collateral or post margin. We monitor and manage our credit risk through credit policies that include:
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• | routine monitoring of counterparties’ and customer’s credit limits and their overall credit ratings; |
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• | limiting our marketing, hedging and optimization activities with high risk counterparties; |
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• | margin, collateral, or prepayment arrangements; and |
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• | payment netting arrangements, or master netting arrangements that allow for the netting of positive and negative exposures of various contracts associated with a single counterparty. |
We have concentrations of credit risk with a few of our 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
On July 1, 20192020, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11emerged from bankruptcy. 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. SinceSubsequent to 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. See Note 4 of the Notes to Consolidated Condensed Financial Statements for further information related to the event of default associated with our Russell City and Los Esteros project debt agreements in connection with the PG&E bankruptcy.
California, under which PG&E continued to provide service subsequent to its bankruptcy filing. Under PG&E's plan of reorganization, our PPAs were assumed and any restrictions on our projects arising from the bankruptcy were cured.
We believe that our credit policies and portfolio of transactions adequately monitor and diversify our credit risk, and currently our counterparties and customers are performing and financially settling timely according to their respective agreements. We monitor and manage our total comprehensive credit risk associated with all of our contracts irrespective of whether they are accounted for as an executory contract, a normal purchase normal sale or whether they are marked-to-market and included in our derivative assets and liabilities on our Consolidated Condensed Balance Sheets. Our counterparty and customer credit quality associated with the net fair value of outstanding derivative commodity instruments is included in our derivative assets and (liabilities), net of allocated collateral, at MarchJune 3130, 2020, and the period during which the instruments will mature are summarized in the table below (in millions):
|
| | | | | | | | | | | | | | | | | | | | |
Credit Quality
(Based on Credit Ratings
as of June 30, 2020) | | 2020 | | 2021-2022 | | 2023-2024 | | After 2024 | | Total |
Investment grade | | $ | (70 | ) | | $ | 60 |
| | $ | 23 |
| | $ | 8 |
| | $ | 21 |
|
Non-investment grade | | (6 | ) | | 18 |
| | 11 |
| | 19 |
| | 42 |
|
No external ratings(1) | | 39 |
| | 78 |
| | 43 |
| | 23 |
| | 183 |
|
Total fair value | | $ | (37 | ) | | $ | 156 |
| | $ | 77 |
| | $ | 50 |
| | $ | 246 |
|
__________
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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. |
Interest Rate Risk — We are exposed to interest rate risk related to our variable rate debt. Interest rate risk represents the potential loss in earnings arising from adverse changes in market interest rates. Our variable rate financings are indexed to base rates, generally LIBOR. Our interest rate hedging instruments are with counterparties we believe are primarily high quality institutions, and we do not believe that our interest rate instruments expose us to any significant credit risk. Holding all other factors constant, we estimate that a 10% decrease in interest rates would result in a change in the fair value of our interest rate instruments of approximately $(58) million at MarchJune 3130, 2020.
New Accounting Standards and Disclosure Requirements
See Note 1 of the Notes to Consolidated Condensed Financial Statements for a discussion of new accounting standards and disclosure requirements.
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Item 3. | Quantitative and Qualitative Disclosures About Market Risk |
The information required to be disclosed under this Item 3 is set forth under Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Risk Management and Commodity Accounting.” This information should be read in conjunction with the information disclosed in our 2019 Form 10-K.
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Item 4. | Controls and Procedures |
Disclosure Controls and Procedures
As of the end of the period covered by this Report, we carried out an evaluation, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures as defined in Rule 13a-15(e) and Rule 15d-15(e) of the Exchange Act. Based upon, and as of the date of, this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective such that the information required to be disclosed in our SEC reports is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.
Changes in Internal Control Over Financial Reporting
During the firstsecond quarter of 2020, there were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II — OTHER INFORMATION
See Note 9 of the Notes to Consolidated Condensed Financial Statements for a description of our legal proceedings.
Except as set forth below, there were no changes to the description of the risk factors previously disclosed in Part I, Item 1A “Risk Factors” of our 2019 Form 10-K.
The ongoing COVID-19 pandemic could have a material adverse effect on our business operations, results of operations, cash flows and financial position.
In December 2019, a novel strain of coronavirus, COVID-19, was identified. This virus continues to spread globally, including in the United States. The COVID-19 outbreak is a widespread health crisis that has negatively affected large segments of the global economy, disrupted financial markets and international trade, resulting in increased unemployment levels and significantly impacted global supply chains, all of which may have a material adverse impact on our industry. In addition, federal, state and local governments have implementedin the past and may in the future implement various restrictions, including travel restrictions, border closings, restrictions on public gatherings, shelter-in-place restrictions and limitations on business. Although we are considered an essential business, any of these actions could adversely impact the ability of our employees, contractors, suppliers, customers and other business partners to conduct business activities for an indefinite period of time, which could have a material adverse effect on our results of operations, financial condition and liquidity. In particular, the continuedongoing spread of COVID-19 and efforts to contain the virus could:
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• | reduce the availability and productivity and impact the health and well-being of our employees, customers and business partners; |
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• | impact our liquidity position and cost of and ability to access funds from financial institutions and capital markets; |
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• | reduce electricity and steam demand in some or all of the regions in which we operate for a prolonged period, impacting our revenue; |
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• | cause delays and disruptions in the availability of and timely delivery of materials and components used in our operations and development activities; and |
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• | cause other unpredictable events. |
We have instituted measures to ensure our supply chain remains open to us; however, there could beif prolonged global shortages thatwere to occur, this could have a material adverse impact on our maintenance and capital programs that we currently cannot anticipate. Although we continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers, our systems and operations remain vulnerable to cyber-attacks and other disruptions due in part to the fact that a portion of our employees continue to work remotely as a result of the ongoing COVID-19 outbreak. Despite our efforts to manage various impacts, the situation surrounding the COVID-19 outbreak remains fluid and the potential for a material impact on our results of operations, financial condition and liquidity increases the longer the virus impacts activity levels in the U.S. and globally. The ultimate impact of the COVID-19 outbreak depends on factors beyond our knowledge or control, including the duration and severity of the COVID-19 outbreak on the economy as well as third-party actions taken to contain its spread and mitigate its public health effects. Therefore, we currently cannot estimate with any degree of certainty the potential impact to our financial position, results of operations and cash flows.
| |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
None.
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Item 3. | Defaults Upon Senior Securities |
None.
| |
Item 4. | Mine Safety Disclosures |
Not applicable.
None.
EXHIBIT INDEX
|
| | |
Exhibit Number | | Description |
| | |
| | Credit Agreement, dated as of June 9, 2020, among Geysers Power Company, LLC, the guarantors party thereto and MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as First Lien Collateral Agent, and the lenders and issuing banks parties thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed with the SEC on June 12, 2020).* |
| | |
| | Certification of the Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
| | Certification of the Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | |
| | Certification of the Chief Executive Officer and the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.** |
| | |
101.INS | | XBRL Instance Document. |
| | |
101.SCH | | XBRL Taxonomy Extension Schema. |
| |
101.CAL | | XBRL Taxonomy Extension Calculation Linkbase. |
| |
101.DEF | | XBRL Taxonomy Extension Definition Linkbase. |
| |
101.LAB | | XBRL Taxonomy Extension Label Linkbase. |
| |
101.PRE | | XBRL Taxonomy Extension Presentation Linkbase. |
_______________
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* | Schedules and certain similar attachments to this exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish supplementally to the SEC a copy of any omitted attachment upon request. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized.
|
| | |
CALPINE CORPORATION |
(Registrant) |
| |
By: | | /s/ ZAMIR RAUF |
| | Zamir Rauf Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
Date: MayAugust 12, 2020
