NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
September 30, 2019
(Unaudited)
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1.
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Basis of Presentation and Summary of Significant Accounting Policies
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We are a power generation company engaged in the ownership and operation of primarily natural gas-fired and geothermal power plants in North America. We have a significant presence in major competitive wholesale and retail power markets in California, Texas and the Northeast and Mid-Atlantic regions of the U.S. We sell power, steam, capacity, renewable energy credits and ancillary services to our customers, which include utilities, independent electric system operators and industrial companies, retail power providers, municipalities and other governmental entities, power marketers as well as retail commercial, industrial, governmental and residential customers. We continue to focus on providing products and services that are beneficial to our wholesale and retail customers. We purchase primarily natural gas and some fuel oil as fuel for our power plants and engage in related natural gas transportation and storage transactions. We also purchase power and related products for sale to our customers and purchase electric transmission rights to deliver power to our customers. Additionally, consistent with our Risk Management Policy, we enter into natural gas, power, environmental product, fuel oil and other physical and financial commodity contracts to hedge certain business risks and optimize our portfolio of power plants.
Basis of Interim Presentation — The accompanying unaudited, interim Consolidated Condensed Financial Statements of Calpine Corporation, a Delaware corporation, and consolidated subsidiaries have been prepared pursuant to the rules and regulations of the SEC. In the opinion of management, the Consolidated Condensed Financial Statements include the normal, recurring adjustments necessary for a fair statement of the information required to be set forth therein. Certain information and note disclosures, normally included in financial statements prepared in accordance with U.S. GAAP, have been condensed or omitted from these statements pursuant to such rules and regulations and, accordingly, these financial statements should be read in conjunction with our audited Consolidated Financial Statements for the year ended December 31, 2018, included in our 2018 Form 10-K. The results for interim periods are not indicative of the results for the entire year primarily due to acquisitions and disposals of assets, seasonal fluctuations in our revenues and expenses, timing of major maintenance expense, variations resulting from the application of the method to calculate the provision for income tax for interim periods, volatility of commodity prices and mark-to-market gains and losses from commodity and interest rate derivative contracts.
Use of Estimates in Preparation of Financial Statements — The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and related disclosures included in our Consolidated Condensed Financial Statements. Actual results could differ from those estimates.
Reclassifications — We have reclassified certain prior period amounts for comparative purposes. These reclassifications did not have a material effect on our financial condition, results of operations or cash flows.
Cash and Cash Equivalents — We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents. We have cash and cash equivalents held in non-corporate accounts relating to certain project finance facilities and lease agreements that require us to establish and maintain segregated cash accounts. These accounts have been pledged as security in favor of the lenders under such project finance facilities, and the use of certain cash balances on deposit in such accounts is limited, at least temporarily, to the operations of the respective projects.
Restricted Cash — Certain of our debt agreements, lease agreements or other operating agreements require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use. These amounts are held by depository banks in order to comply with the contractual provisions requiring reserves for payments such as for debt service, rent and major maintenance or with applicable regulatory requirements. Funds that can be used to satisfy obligations due during the next 12 months are classified as current restricted cash, with the remainder classified as non-current restricted cash. Restricted cash is generally invested in accounts earning market rates; therefore, the carrying value approximates fair value. Such cash is excluded from cash and cash equivalents on our Consolidated Condensed Balance Sheets.
The table below represents the components of our restricted cash as of September 30, 2019 and December 31, 2018 (in millions):
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September 30, 2019
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December 31, 2018
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Current
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Non-Current
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Total
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Current
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Non-Current
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Total
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Debt service
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$
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84
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$
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7
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$
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91
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$
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13
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$
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8
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$
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21
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Construction/major maintenance
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12
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22
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34
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23
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24
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47
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Security/project/insurance
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245
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31
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276
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120
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—
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120
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Other
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4
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2
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6
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11
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2
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13
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Total
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$
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345
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$
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62
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$
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407
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$
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167
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$
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34
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$
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201
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Business Interruption Proceeds — We record business interruption insurance proceeds in operating revenues when they are realizable. We recorded approximately nil and $14 million of business interruption proceeds for the three and nine months ended September 30, 2018. We have not recorded any business interruption insurance proceeds during the three and nine months ended September 30, 2019.
Property, Plant and Equipment, Net — At September 30, 2019 and December 31, 2018, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
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September 30, 2019
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December 31, 2018
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Depreciable Lives
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Buildings, machinery and equipment
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$
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16,565
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$
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16,400
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1.5
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–
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50
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Years
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Geothermal properties
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1,510
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1,501
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13
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–
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58
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Years
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Other
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272
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286
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3
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–
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50
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Years
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18,347
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18,187
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Less: Accumulated depreciation
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6,855
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6,832
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11,492
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11,355
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Land
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128
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121
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Construction in progress
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382
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966
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Property, plant and equipment, net
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$
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12,002
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$
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12,442
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Capitalized Interest — The total amount of interest capitalized was $2 million and $7 million during the three months ended September 30, 2019 and 2018, respectively, and $10 million and $21 million during the nine months ended September 30, 2019 and 2018, respectively.
Goodwill — We have not recorded any impairment losses or changes in the carrying amount of our goodwill during the three and nine months ended September 30, 2019 and 2018.
New Accounting Standards and Disclosure Requirements
Leases — On January 1, 2019, we adopted Accounting Standards Update 2016-02, “Leases” (“Topic 842”). The comprehensive new lease standard superseded all existing lease guidance. The standard requires that a lessee should recognize a right-of-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. For lessors, the accounting for leases under Topic 842 remained substantially unchanged. The standard also requires expanded disclosures surrounding leases. We adopted the standards under Topic 842 using the modified retrospective method and elected a number of the practical expedients in our implementation of Topic 842. The key change that affected us relates to our accounting for operating leases for which we are the lessee that were historically off-balance sheet. The impact of adopting the standards resulted in the recognition of a right-of-use asset and lease obligation liability of $191 million on our Consolidated Condensed Balance Sheet on January 1, 2019, exclusive of previously recognized lease balances. The implementation of Topic 842 did not have a material effect on our Consolidated Condensed Statement of Operations or Consolidated Condensed Statement of Cash Flows for the nine months ended September 30, 2019. See Note 3 for a discussion of the practical expedients we elected and additional disclosures required by Topic 842.
Derivatives and Hedging — In August 2017, the FASB issued Accounting Standards Update 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” The standard better aligns an entity’s hedging activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging
relationships and the presentation of hedge results in the financial statements. The standard will prospectively make hedge accounting easier to apply to hedging activities and also enhances disclosure requirements for how hedge transactions are reflected in the financial statements when hedge accounting is elected. We adopted Accounting Standards Update 2017-12 in the first quarter of 2019 which did not have a material effect on our financial condition, results of operations or cash flows.
Fair Value Measurements — In August 2018, the FASB issued Accounting Standards Update 2018-13, “Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement.” The standard removes, modifies and adds disclosures about fair value measurements and is effective for fiscal years beginning after December 15, 2019. The changes required by this standard to remove or modify disclosures may be early adopted with adoption of the additional disclosures required by this standard delayed until their effective date. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
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2.
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Revenue from Contracts with Customers
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Disaggregation of Revenues with Customers
The following tables represent a disaggregation of our revenue for the three and nine months ended September 30, 2019 and 2018 by reportable segment (in millions). See Note 13 for a description of our segments.
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Three Months Ended September 30, 2019
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Wholesale
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West
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Texas
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East
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Retail
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Elimination
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Total
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Third Party:
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Energy & other products
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$
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238
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$
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490
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$
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169
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$
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491
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$
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—
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$
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1,388
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Capacity
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52
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31
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115
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—
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—
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198
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Revenues relating to physical or executory contracts – third party
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$
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290
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$
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521
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$
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284
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$
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491
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$
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—
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$
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1,586
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Affiliate(1):
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$
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11
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$
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14
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$
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21
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$
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2
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$
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(48
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)
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$
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—
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Revenues relating to leases and derivative instruments(2)
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$
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1,206
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Total operating revenues
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$
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2,792
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Three Months Ended September 30, 2018
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Wholesale
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West
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Texas
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East
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Retail
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Elimination
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Total
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Third Party:
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Energy & other products
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$
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369
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$
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470
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$
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221
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$
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543
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$
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—
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$
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1,603
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Capacity
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51
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|
23
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|
|
190
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|
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—
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—
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|
264
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Revenues relating to physical or executory contracts – third party
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$
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420
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$
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493
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$
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411
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$
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543
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$
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—
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$
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1,867
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Affiliate(1):
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$
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9
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$
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11
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$
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20
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$
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—
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$
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(40
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)
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$
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—
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Revenues relating to leases and derivative instruments(2)
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$
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1,023
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Total operating revenues
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$
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2,890
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Nine Months Ended September 30, 2019
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Wholesale
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West
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Texas
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East
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Retail
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Elimination
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Total
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Third Party:
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Energy & other products
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$
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675
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$
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1,110
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$
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496
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$
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1,316
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$
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—
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|
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$
|
3,597
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Capacity
|
123
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|
|
96
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|
|
446
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|
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—
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—
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|
|
665
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Revenues relating to physical or executory contracts – third party
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$
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798
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|
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$
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1,206
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|
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$
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942
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|
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$
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1,316
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|
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$
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—
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|
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$
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4,262
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|
|
|
|
|
|
|
|
|
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Affiliate(1):
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$
|
28
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$
|
42
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$
|
78
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$
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6
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$
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(154
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)
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|
$
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—
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|
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|
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|
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Revenues relating to leases and derivative instruments(2)
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|
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|
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$
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3,728
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Total operating revenues
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$
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7,990
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|
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|
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Nine Months Ended September 30, 2018
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Wholesale
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West
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Texas
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East
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Retail
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Elimination
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Total
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Third Party:
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Energy & other products
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$
|
744
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|
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$
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1,100
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|
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$
|
473
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|
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$
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1,437
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$
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—
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|
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$
|
3,754
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Capacity
|
105
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|
|
72
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|
|
479
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|
|
—
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|
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—
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|
|
656
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Revenues relating to physical or executory contracts – third party
|
$
|
849
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|
|
$
|
1,172
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|
|
$
|
952
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|
|
$
|
1,437
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|
|
$
|
—
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|
|
$
|
4,410
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|
|
|
|
|
|
|
|
|
|
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Affiliate(1):
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$
|
22
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|
|
$
|
24
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|
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$
|
62
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|
|
$
|
2
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|
|
$
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(110
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)
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|
$
|
—
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|
|
|
|
|
|
|
|
|
|
|
|
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Revenues relating to leases and derivative instruments(2)
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|
|
|
|
|
|
|
|
|
|
$
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2,748
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Total operating revenues
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|
|
|
|
|
|
|
|
|
|
$
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7,158
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___________
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(1)
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Affiliate energy, other and capacity revenues reflect revenues on transactions between wholesale and retail affiliates excluding affiliate activity related to leases and derivative instruments. All such activity supports retail supply needs from the wholesale business and/or allows for collateral margin netting efficiencies at Calpine.
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(2)
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Revenues relating to contracts accounted for as leases and derivatives include energy and capacity revenues relating to PPAs that we are required to account for as operating leases and physical and financial commodity derivative contracts, primarily relating to power, natural gas and environmental products. Revenue related to derivative instruments includes revenue recorded in Commodity revenue and mark-to-market gain (loss) within our operating revenues on our Consolidated Condensed Statements of Operations.
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Performance Obligations and Contract Balances
At September 30, 2019 and December 31, 2018, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Condensed Balance Sheets and primarily relate to sales of environmental products and capacity. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balance outstanding at September 30, 2019 and December 31, 2018 was $10 million and $14 million, respectively. Revenue recognized during the three months ended September 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $19 million and $18 million, respectively. Revenue recognized during the nine months ended September 30, 2019 and 2018, relating to the deferred revenue balance at the beginning of each period was $14 million and $17 million, respectively. Revenue recognized each period relating to deferred revenue balances resulted from our performance under the customer contracts. The change in the deferred revenue balance during the three and nine months ended September 30, 2019
and 2018 was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.
Performance Obligations not yet Satisfied
As of September 30, 2019, we have entered into certain contracts for fixed and determinable amounts with customers under which we have not yet completed our performance obligations which primarily includes agreements for which we are providing capacity from our generating facilities. We have revenues related to the sale of capacity through participation in various ISO capacity auctions estimated based upon cleared volumes and the sale of capacity to our customers of $136 million that will be recognized during the remainder of 2019, and $611 million, $603 million, $371 million and $125 million that will be recognized during the years ending December 31, 2020, 2021, 2022 and 2023, respectively, and $112 million thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.
Accounting for Leases – Lessee
We evaluate contracts for lease accounting at contract inception and assess lease classification at the lease commencement date. For our leases, we recognize a right-of-use asset and corresponding lease obligation liability at the lease commencement date where the lease obligation liability is measured at the present value of the minimum lease payments. For our operating leases, the amortization of the right-of-use asset and the accretion of our lease obligation liability result in a single straight-line expense recognized over the lease term.
We determine the discount rate associated with our operating and finance leases using our incremental borrowing rate at lease commencement. For our operating leases, we use an interest rate commensurate with the interest rate to borrow on a collateralized basis over a similar term with an amount equal to the lease payments. Factors management considers in the calculation of the discount rate include the amount of the borrowing, the lease term including options that are reasonably certain of exercise, the current interest rate environment and the credit rating of the entity. For our finance leases, we use the interest rate commensurate with the interest rate for a project finance borrowing arrangement with a similar collateral package, repayment terms, restrictive covenants and guarantees.
Our operating leases are primarily related to office space for our corporate and regional offices as well as land and operating related leases for our power plants. Additionally, one of our power plants is accounted for as an operating lease. Payments made by Calpine on this lease are recognized on a straight-line basis with capital improvements associated with our leased power plant deemed leasehold improvements that are amortized over the shorter of the term of the lease or the economic life of the capital improvement. Several of our leases contain renewal options held by us to extend the lease term. The inclusion of these renewal periods in the lease term and in the minimum lease payments included in our lease liabilities is dependent on specific facts and circumstances for each lease and whether it is determined to be reasonably certain that we will exercise our option to extend the term. Our office, land and other operating leases do not contain any material restrictive covenants or residual value guarantees.
We have entered into finance leases for certain power plants and related equipment with terms that range up to 30 years (including lease renewal options). The finance leases generally provide for the lessee to pay taxes, maintenance, insurance, and certain other operating costs of the leased property.
In connection with our adoption of Topic 842 on January 1, 2019, we elected certain practical expedients that were available under the new lease standards including:
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•
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we elected not to separate lease and nonlease components for our current classes of underlying leased assets as the lessee;
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|
|
•
|
we did not evaluate existing and expired land easements that were not previously accounted for as leases prior to January 1, 2019; and
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•
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we did not reassess the classification of leases, the accounting for initial direct costs or whether contractual arrangements contained a lease for all contracts that expired or commenced prior to January 1, 2019.
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Further, upon the adoption of Topic 842, we made an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. We do not have any material subleases associated with our operating and finance leases.
The components of our operating and finance lease expense are as follows for the three and nine months ended September 30, 2019 (in millions):
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|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2019
|
Operating Leases
|
|
|
|
Operating lease expense
|
$
|
11
|
|
|
$
|
34
|
|
|
|
|
|
Finance Leases
|
|
|
|
Amortization of the right-of-use assets
|
$
|
2
|
|
|
$
|
6
|
|
Interest expense
|
2
|
|
|
6
|
|
Finance lease expense
|
$
|
4
|
|
|
$
|
12
|
|
|
|
|
|
Variable lease expense
|
$
|
3
|
|
|
$
|
8
|
|
|
|
|
|
Total lease expense
|
$
|
18
|
|
|
$
|
54
|
|
The following is a schedule by year of future minimum lease payments associated with our operating and finance leases together with the present value of the net minimum lease payments as of September 30, 2019 (in millions):
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|
|
|
|
|
|
|
|
|
Operating Leases(1)
|
|
Finance Leases(2)
|
2019
|
$
|
34
|
|
|
$
|
7
|
|
2020
|
20
|
|
|
16
|
|
2021
|
21
|
|
|
16
|
|
2022
|
19
|
|
|
16
|
|
2023
|
18
|
|
|
19
|
|
Thereafter
|
201
|
|
|
33
|
|
Total minimum lease payments
|
313
|
|
|
107
|
|
Less: Amount representing interest
|
105
|
|
|
29
|
|
Total lease obligation
|
208
|
|
|
78
|
|
Less: current lease obligation
|
39
|
|
|
10
|
|
Long-term lease obligation
|
$
|
169
|
|
|
$
|
68
|
|
____________
|
|
(1)
|
The lease liabilities associated with our operating leases as of September 30, 2019 are included in other current liabilities and other long-term liabilities on our Consolidated Condensed Balance Sheet.
|
|
|
(2)
|
The lease liabilities associated with our finance leases as of September 30, 2019 are included in debt, current portion and debt, net of current portion on our Consolidated Condensed Balance Sheet.
|
Supplemental balance sheet information related to our operating and finance leases is as follows as of September 30, 2019 (in millions, except lease term and discount rate):
|
|
|
|
|
|
|
|
September 30, 2019
|
Operating leases(1)
|
|
|
Right-of-use assets associated with operating leases
|
|
$
|
175
|
|
|
|
|
Finance leases(2)
|
|
|
Property, plant and equipment, gross
|
|
$
|
212
|
|
Accumulated amortization
|
|
(104
|
)
|
Property, plant and equipment, net
|
|
$
|
108
|
|
|
|
|
Weighted average remaining lease term (in years)
|
|
|
Operating leases
|
|
15.6
|
|
Finance leases
|
|
7.2
|
|
|
|
|
Weighted average discount rate
|
|
|
Operating leases
|
|
5.3
|
%
|
Finance leases
|
|
8.0
|
%
|
____________
|
|
(1)
|
The right-of-use assets associated with our operating leases as of September 30, 2019 are included in other assets on our Consolidated Condensed Balance Sheet.
|
|
|
(2)
|
The right-of-use assets associated with our finance leases as of September 30, 2019 are included in property, plant and equipment, net on our Consolidated Condensed Balance Sheet.
|
Supplemental cash flow information related to our operating and finance leases is as follows for the period presented (in millions):
|
|
|
|
|
|
|
|
Nine Months Ended
|
|
|
September 30, 2019
|
Cash paid for amounts included in the measurement of lease liabilities
|
|
|
Operating cash flows from operating leases
|
|
$
|
19
|
|
Operating cash flows from finance leases
|
|
$
|
5
|
|
Financing cash flows from finance leases
|
|
$
|
6
|
|
|
|
|
Right-of-use assets obtained in exchange for lease obligations:
|
|
|
Operating leases
|
|
$
|
9
|
|
Finance leases
|
|
$
|
—
|
|
As of September 30, 2019, we have executed agreements that contain a lease with a future lease commencement date and future lease commitments of $5 million primarily related to office leases scheduled to commence in the fourth quarter of 2019.
Accounting for Leases – Lessor
We apply lease accounting to PPAs that meet the definition of a lease and determine lease classification treatment at commencement of the agreement. We currently do not have any contracts which are accounted for as sales-type leases or direct financing leases and all of our leases as the lessor are classified as operating leases. As part of the implementation of Topic 842, we elected the practical expedient to not reassess leases that have commenced prior to January 1, 2019.
Revenue from contracts accounted for as operating leases, such as certain tolling agreements, with minimum lease rentals (capacity payments) which vary over time must be levelized. Generally, we levelize these contract revenues on a straight-line basis over the term of the contract. Our operating leases that have commenced contain terms extending through December 2034. These contracts also generally contain variable payment components based on generation volumes or operating efficiency over a
period of time. Revenues associated with the variable payments are recognized over time as the goods or services are provided to the lessee. Our operating leases generally do not contain renewal or purchase options or residual value guarantees. We have elected to not separate our lease and non-lease components as the lease components reflect the predominant characteristics of these agreements.
Revenue recognized related to fixed lease payments on our operating leases for the periods presented is as follows (in millions):
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2019
|
Operating Leases(1)
|
|
|
|
Fixed lease payments
|
$
|
130
|
|
|
$
|
269
|
|
____________
|
|
(1)
|
Revenues associated with our operating leases are included in Commodity revenue and other revenue on our Consolidated Condensed Statement of Operations.
|
The total contractual future minimum lease rentals for our contracts that have commenced and are accounted for as operating leases at September 30, 2019, are as follows (in millions):
|
|
|
|
|
2019
|
$
|
74
|
|
2020
|
286
|
|
2021
|
261
|
|
2022
|
226
|
|
2023
|
144
|
|
Thereafter
|
277
|
|
Total
|
$
|
1,268
|
|
We do not recognize lease receivables associated with our operating leases as the long-lived assets subject to the lease contracts are recorded on our Consolidated Condensed Balance Sheet and are being depreciated over their estimated useful lives. Amounts recorded on our Consolidated Condensed Balance Sheet associated with the long-lived assets subject to our operating leases as of September 30, 2019 are as follows (in millions):
|
|
|
|
|
|
September 30, 2019
|
Assets subject to contracts accounted for as operating leases
|
|
Property, plant and equipment, gross
|
$
|
3,085
|
|
Accumulated depreciation
|
(911
|
)
|
Property, plant and equipment, net(1)
|
$
|
2,174
|
|
____________
|
|
(1)
|
Our assets subject to contracts that are accounted for as operating leases primarily consist of our power plants subject to tolling contracts.
|
We also record lease levelization assets and liabilities for any difference between the timing of the contractual payments made related to our operating lease contracts and revenue recognized on a straight-line basis. These balances are included in current and long-term assets and liabilities on our Consolidated Condensed Balance Sheet.
Disclosures for periods prior to the adoption of Topic 842
Lessee
The following is a schedule by year of future minimum lease payments under operating and capital leases as of December 31, 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
Operating Leases
|
|
Capital Leases(1)
|
2019
|
$
|
50
|
|
|
$
|
40
|
|
2020
|
19
|
|
|
40
|
|
2021
|
20
|
|
|
38
|
|
2022
|
18
|
|
|
33
|
|
2023
|
17
|
|
|
27
|
|
Thereafter
|
192
|
|
|
92
|
|
Total minimum lease payments
|
$
|
316
|
|
|
270
|
|
Less: Amount representing interest
|
|
|
89
|
|
Present value of net minimum lease payments
|
|
|
$
|
181
|
|
____________
|
|
(1)
|
Includes a failed sale-leaseback transaction related to our Pasadena Power Plant.
|
At December 31, 2018, the asset balance for our assets under capital leases totaled approximately $715 million with accumulated amortization of $353 million.
Lessor
The total contractual future minimum lease rentals for our contracts accounted for as operating leases at December 31, 2018, are as follows (in millions):
|
|
|
|
|
2019
|
$
|
342
|
|
2020
|
261
|
|
2021
|
257
|
|
2022
|
224
|
|
2023
|
141
|
|
Thereafter
|
239
|
|
Total
|
$
|
1,464
|
|
4. Divestitures
Sale of Garrison Energy Center and RockGen Energy Center
On July 10, 2019, we, through our indirect, wholly owned subsidiaries Calpine Holdings, LLC and Calpine Northbrook Project Holdings, LLC, completed the sale of 100% of our ownership interests in Garrison Energy Center LLC (“Garrison”) and RockGen Energy LLC (“RockGen”) to Cobalt Power, L.L.C. for approximately $360 million, subject to certain immaterial working capital adjustments and the execution of financial commodity contracts. Upon closing, we recognized a liability of $52 million for the fair value of the financial commodity contracts on our Consolidated Condensed Balance Sheet, and the related proceeds are reflected within the financing section on our Consolidated Condensed Statement of Cash Flows. Garrison owns the Garrison Energy Center, a 309 MW natural gas-fired, combined-cycle power plant located in Dover, Delaware, and RockGen owns the RockGen Energy Center, a 503 MW natural gas-fired, simple-cycle power plant located in Christiana, Wisconsin. We used the sale proceeds, together with cash on hand, to fund a dividend of $400 million to our parent, CPN Management.
We recorded an immaterial gain on the sale during the third quarter of 2019 and an impairment loss of $55 million during the nine months ended September 30, 2019, to adjust the carrying value of the assets to reflect fair value less cost to sell.
|
|
5.
|
Variable Interest Entities and Unconsolidated Investments
|
We consolidate all of our VIEs where we have determined that we are the primary beneficiary. There were no changes to our determination of whether we are the primary beneficiary of our VIEs for the nine months ended September 30, 2019. See Note 7 in our 2018 Form 10-K for further information regarding our VIEs.
VIE Disclosures
Our consolidated VIEs include natural gas-fired power plants with an aggregate capacity of 6,769 MW and 7,880 MW at September 30, 2019 and December 31, 2018, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. On August 14, 2019, we repaid the OMEC project debt outstanding balance utilizing proceeds from our New 2026 First Lien Term Loan and cash on hand. See below for further discussion of OMEC. Other than amounts contractually required, we provided no additional material support to our VIEs in the form of cash and other contributions during each of the three and nine months ended September 30, 2019 and 2018.
OMEC — OMEC had a ten-year tolling agreement with SDG&E, which commenced on October 3, 2009 and expired on October 2, 2019. Under a ground lease agreement, OMEC held a put option to sell the Otay Mesa Energy Center for $280 million to SDG&E, pursuant to the terms and conditions of the agreement, which was exercisable until April 1, 2019 and SDG&E held a call option to purchase the Otay Mesa Energy Center for $377 million, which was exercisable through October 3, 2018. The call option held by SDG&E expired unexercised.
OMEC has executed a new 59-month Resource Adequacy (“RA”) contract with SDG&E. The RA contract received initial regulatory approval by the CPUC on February 21, 2019. This approval was subject to a 30 day appeal period from the date of the issuance of the CPUC decision. On March 27, 2019, an appeal of the CPUC decision was filed with the CPUC. Accordingly, on March 28, 2019, we provided notice of our exercise of the put option, which we subsequently rescinded by agreement following the CPUC’s denial of all appeals of the new RA contract on August 1, 2019. On October 3, 2019, the RA contract with SDG&E commenced. As a result, we will retain the 608 MW Otay Mesa Energy Center, which plays an integral role in electric reliability in Southern California.
As the call and put options have terminated and the project debt has been fully repaid, we determined that OMEC no longer meets the definition of a VIE as of September 30, 2019.
Unconsolidated VIEs and Investments in Unconsolidated Subsidiaries
We have a 50% partnership interest in Greenfield LP and in Whitby. Greenfield LP and Whitby are VIEs; however, we do not have the power to direct the most significant activities of these entities and therefore do not consolidate them. Greenfield LP is a limited partnership between certain subsidiaries of ours and of Mitsui & Co., Ltd., which operates the Greenfield Energy Centre, a 1,038 MW natural gas-fired, combined-cycle power plant located in Ontario, Canada. We and Mitsui & Co., Ltd. each hold a 50% interest in Greenfield LP. Whitby is a limited partnership between certain of our subsidiaries and Atlantic Packaging Ltd., which operates the Whitby facility, a 50 MW natural gas-fired, simple-cycle cogeneration power plant located in Ontario, Canada. We and Atlantic Packaging Ltd. each hold a 50% partnership interest in Whitby.
Calpine Receivables is a VIE and a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. We have determined that we do not have the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance nor the obligation to absorb losses or receive benefits from the VIE. Accordingly, we have determined that we are not the primary beneficiary of Calpine Receivables because we do not have the power to affect its financial performance as the unaffiliated financial institutions that purchase the receivables from Calpine Receivables control the selection criteria of the receivables sold and appoint the servicer of the receivables which controls management of default. Thus, we do not consolidate Calpine Receivables in our Consolidated Condensed Financial Statements and use the equity method of accounting to record our net interest in Calpine Receivables.
We account for these entities under the equity method of accounting and include our net equity interest in investments in unconsolidated subsidiaries on our Consolidated Condensed Balance Sheets. At September 30, 2019 and December 31, 2018, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
Ownership Interest as of
September 30, 2019
|
|
September 30, 2019
|
|
December 31, 2018
|
Greenfield LP(1)
|
50%
|
|
$
|
59
|
|
|
$
|
55
|
|
Whitby
|
50%
|
|
9
|
|
|
15
|
|
Calpine Receivables
|
100%
|
|
5
|
|
|
6
|
|
Total investments in unconsolidated subsidiaries
|
|
|
$
|
73
|
|
|
$
|
76
|
|
____________
|
|
(1)
|
Includes our share of accumulated other comprehensive income/loss related to interest rate hedging instruments associated with our unconsolidated subsidiary Greenfield LP’s debt.
|
Our risk of loss related to our investments in Greenfield LP and Whitby is limited to our investment balance. Our risk of loss related to our investment in Calpine Receivables is $63 million which consists of our notes receivable from Calpine Receivables at September 30, 2019 and our initial investment associated with Calpine Receivables. See Note 12 for further information associated with our related party activity with Calpine Receivables.
Holders of the debt of our unconsolidated investments do not have recourse to Calpine Corporation and its other subsidiaries; therefore, the debt of our unconsolidated investments is not reflected on our Consolidated Condensed Balance Sheets. At September 30, 2019 and December 31, 2018, Greenfield LP’s debt was approximately $297 million and $301 million, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately $149 million and $151 million at September 30, 2019 and December 31, 2018, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three and nine months ended September 30, 2019 and 2018, is recorded in (income) from unconsolidated subsidiaries. The following table sets forth details of our (income) from unconsolidated subsidiaries for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Greenfield LP
|
$
|
(4
|
)
|
|
$
|
(2
|
)
|
|
$
|
(10
|
)
|
|
$
|
(6
|
)
|
Whitby
|
1
|
|
|
(3
|
)
|
|
(5
|
)
|
|
(11
|
)
|
Calpine Receivables
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
Total
|
$
|
(3
|
)
|
|
$
|
(5
|
)
|
|
$
|
(14
|
)
|
|
$
|
(16
|
)
|
Distributions from Greenfield LP were nil during each of the three and nine months ended September 30, 2019 and 2018. Distributions from Whitby were nil and $11 million during the three and nine months ended September 30, 2019, respectively, and nil and $5 million during the three and nine months ended September 30, 2018, respectively. We did not have material distributions from our investment in Calpine Receivables for the three and nine months ended September 30, 2019 and 2018.
Inland Empire Energy Center Put and Call Options — We held a call option to purchase the Inland Empire Energy Center (a 775 MW natural gas-fired power plant located in California) at predetermined prices from GE that could be exercised between years 2017 and 2024. GE held a put option whereby they could require us to purchase the power plant, if certain plant performance criteria were met by 2025. On February 1, 2019, we entered into an agreement with GE, which among other things, terminated our call option and GE’s put option related to the Inland Empire Energy Center. As per this agreement, we will take ownership of the facility site and certain remaining site infrastructure and equipment after closure and decommissioning of the facility at a future date, until such time GE continues to own, operate and maintain the power plant, including directing any closure activities. As GE continues to direct all such significant activities of the power plant, we have determined that we no longer hold any variable interests in the Inland Empire Energy Center and it is not a VIE to Calpine.
Our debt at September 30, 2019 and December 31, 2018, was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
First Lien Term Loans
|
$
|
3,175
|
|
|
$
|
2,976
|
|
Senior Unsecured Notes
|
2,991
|
|
|
3,036
|
|
First Lien Notes
|
2,404
|
|
|
2,400
|
|
Project financing, notes payable and other
|
965
|
|
|
1,264
|
|
CCFC Term Loan
|
969
|
|
|
974
|
|
Finance lease obligations
|
78
|
|
|
105
|
|
Revolving facilities
|
60
|
|
|
30
|
|
Subtotal
|
10,642
|
|
|
10,785
|
|
Less: Current maturities
|
229
|
|
|
637
|
|
Total long-term debt
|
$
|
10,413
|
|
|
$
|
10,148
|
|
Our effective interest rate on our consolidated debt, excluding the effects of capitalized interest and mark-to-market gains (losses) on interest rate hedging instruments, increased to 5.9% for the nine months ended September 30, 2019, from 5.7% for the same period in 2018. Since the fourth quarter of 2018, we have cumulatively repurchased $438 million in aggregate principal amount of our Senior Unsecured Notes for $399 million.
First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
2019 First Lien Term Loan
|
$
|
—
|
|
|
$
|
389
|
|
2023 First Lien Term Loans
|
—
|
|
|
1,059
|
|
2024 First Lien Term Loan
|
1,519
|
|
|
1,528
|
|
2026 First Lien Term Loans
|
1,656
|
|
|
—
|
|
Total First Lien Term Loans
|
$
|
3,175
|
|
|
$
|
2,976
|
|
On August 12, 2019, we entered into a $750 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.50%, or (ii) LIBOR plus 2.50% per annum (with a 0% LIBOR floor) and matures on August 12, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount of the New 2026 First Lien Term Loans is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 0.50% of the aggregate principal amount of the New 2026 First Lien Term Loan, which is structured as original issue discount and recorded approximately $11 million in debt issuance costs during the third quarter of 2019 related to the issuance of our New 2026 First Lien Term Loan. The New 2026 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds, together with cash on hand, to repay the remaining 2023 First Lien Term Loans with a maturity date in May 2023 and to repay project debt associated with OMEC. We recorded approximately $12 million in loss on extinguishment of debt during the third quarter of 2019 associated with the repayment.
On April 5, 2019, we entered into a $950 million first lien senior secured term loan which bears interest, at our option, at either (i) the Base Rate, equal to the highest of (a) the Federal Funds Effective Rate plus 0.50% per annum, (b) the Prime Rate or (c) the Eurodollar Rate for a one month interest period plus 1.0% (in each case, as such terms are defined in the credit agreement), plus an applicable margin of 1.75%, or (ii) LIBOR plus 2.75% per annum (with a 0% LIBOR floor) and matures on April 5, 2026. An aggregate amount equal to 0.25% of the aggregate principal amount of the 2026 First Lien Term Loan is payable at the end of each quarter with the remaining balance payable on the maturity date. We paid an upfront fee of an amount equal to 1.0% of the aggregate principal amount of the 2026 First Lien Term Loan, which is structured as original issue discount and recorded approximately $7 million in debt issuance costs during the second quarter of 2019 related to the issuance of our 2026 First Lien Term Loan. The 2026 First Lien Term Loan contains substantially similar covenants, qualifications, exceptions and limitations as our First Lien Term Loans and First Lien Notes. We used the proceeds from our 2026 First Lien Term Loan to repay our 2019
First Lien Term Loan and a portion of our 2023 First Lien Term Loans with a maturity date in January 2023 and recorded approximately $3 million in loss on extinguishment of debt during the second quarter of 2019 associated with the repayment.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
2023 Senior Unsecured Notes(1)
|
$
|
1,229
|
|
|
$
|
1,227
|
|
2024 Senior Unsecured Notes
|
589
|
|
|
599
|
|
2025 Senior Unsecured Notes
|
1,173
|
|
|
1,210
|
|
Total Senior Unsecured Notes
|
$
|
2,991
|
|
|
$
|
3,036
|
|
____________
|
|
(1)
|
On October 23, 2019, we announced the commencement of a cash tender offer (the “2023 Offer”) for any and all of our outstanding 2023 Senior Unsecured Notes. The 2023 Offer is being made exclusively pursuant to an offer to purchase dated October 23, 2019 (the “Offer to Purchase”), which sets forth the terms and conditions of the 2023 Offer. Consummation of the 2023 Offer is subject to, and conditioned upon, the satisfaction or waiver of certain conditions described in the Offer to Purchase, and is expected to be completed in the fourth quarter of 2019. We may, in our sole discretion, terminate, extend or amend the 2023 Offer at any time as described in the Offer to Purchase.
|
During the nine months ended September 30, 2019, we repurchased $48 million in aggregate principal amount of our Senior Unsecured Notes for $44 million. In connection with the repurchases, we recorded approximately $4 million in gain on extinguishment of debt.
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
2022 First Lien Notes(1)
|
$
|
745
|
|
|
$
|
743
|
|
2024 First Lien Notes(1)
|
487
|
|
|
486
|
|
2026 First Lien Notes
|
1,172
|
|
|
1,171
|
|
Total First Lien Notes
|
$
|
2,404
|
|
|
$
|
2,400
|
|
____________
|
|
(1)
|
On October 23, 2019, we announced the commencement of cash tender offers (the “Offers”) for any and all of our outstanding 2022 First Lien Notes and 2024 First Lien Notes. The Offers are being made exclusively pursuant to the Offer to Purchase, which sets forth the terms and conditions of the Offers. Consummation of the Offers is subject to, and conditioned upon, the satisfaction or waiver of certain conditions described in the Offer to Purchase, and is expected to be completed in the fourth quarter of 2019. We may, in our sole discretion, terminate, extend or amend the Offers at any time as described in the Offer to Purchase.
|
Project Financing, Notes Payable and Other
On January 29, 2019, PG&E and PG&E Corporation each filed voluntary petitions for relief under Chapter 11. Our power plants that sell energy and energy-related products to PG&E through PPAs, include Russell City Energy Center and Los Esteros Critical Energy Facility. Since the bankruptcy filing, we have received all material payments under the PPAs, either directly or through the application of collateral. As a result of PG&E’s bankruptcy, we are currently unable to make distributions from our Russell City and Los Esteros projects in accordance with the terms of the project debt agreements associated with each related project. In July 2019, we executed forbearance agreements associated with the Russell City and Los Esteros project debt agreements, under which the lenders have agreed to forbear enforcement of their rights and remedies, including the ability to accelerate the repayment of borrowings outstanding, otherwise arising because PG&E did not assume our PPAs during the first 180 days of PG&E’s bankruptcy proceeding. The forbearance agreements are effective for rolling 90-day periods, so long as we continue to meet certain conditions, including that the PPAs have not been rejected and there are no other defaults under the project debt agreements or the forbearance agreements. We may be required to reclassify $354 million of Russell City and Los Esteros long-term project debt outstanding at September 30, 2019 to a current liability in a future period. We continue to monitor the bankruptcy proceedings and are assessing our options.
On August 14, 2019, we repaid the project debt associated with OMEC totaling $198 million from the proceeds received from the issuance of our New 2026 First Lien Term Loan (as discussed above), together with cash on hand.
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at September 30, 2019 and December 31, 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
Corporate Revolving Facility(1)
|
$
|
602
|
|
|
$
|
693
|
|
CDHI(2)
|
20
|
|
|
251
|
|
Various project financing facilities
|
199
|
|
|
228
|
|
Other corporate facilities(3)
|
294
|
|
|
193
|
|
Total
|
$
|
1,115
|
|
|
$
|
1,365
|
|
____________
|
|
(1)
|
The Corporate Revolving Facility represents our primary revolving facility. On April 5, 2019, we amended our Corporate Revolving Facility to increase the capacity by approximately $330 million from $1.69 billion to approximately $2.02 billion. On August 12, 2019, we amended our Corporate Revolving Facility to extend the maturity of $150 million in revolving commitments from June 27, 2020 to March 8, 2023, and to reduce the commitments outstanding by $20 million to approximately $2.0 billion. The entire Corporate Revolving Facility now matures on March 8, 2023.
|
|
|
(2)
|
Pursuant to the terms and conditions of the CDHI credit agreement, the capacity under the CDHI revolving facility was reduced to $125 million on June 28, 2019. The decrease in capacity did not have a material effect on our liquidity as alternative sources of liquidity are available.
|
|
|
(3)
|
We have three unsecured letter of credit facilities with two third-party financial institutions totaling approximately $300 million at September 30, 2019.
|
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 September 30, 2019 and December 31, 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
First Lien Term Loans
|
$
|
3,232
|
|
|
$
|
3,175
|
|
|
$
|
2,877
|
|
|
$
|
2,976
|
|
Senior Unsecured Notes
|
3,062
|
|
|
2,991
|
|
|
2,803
|
|
|
3,036
|
|
First Lien Notes
|
2,477
|
|
|
2,404
|
|
|
2,299
|
|
|
2,400
|
|
Project financing, notes payable and other(1)
|
895
|
|
|
889
|
|
|
1,209
|
|
|
1,188
|
|
CCFC Term Loan
|
983
|
|
|
969
|
|
|
938
|
|
|
974
|
|
Revolving facilities
|
60
|
|
|
60
|
|
|
30
|
|
|
30
|
|
Total
|
$
|
10,709
|
|
|
$
|
10,488
|
|
|
$
|
10,156
|
|
|
$
|
10,604
|
|
____________
|
|
(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, CCFC Term Loan and revolving facilities are categorized as level 2 within the fair value hierarchy. Our 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.
|
|
7.
|
Assets and Liabilities with Recurring Fair Value Measurements
|
Cash Equivalents — Highly liquid investments which meet the definition of cash equivalents, primarily investments in money market accounts 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 September 30, 2019 and December 31, 2018, by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of September 30, 2019
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(in millions)
|
Assets:
|
|
|
|
|
|
|
|
Cash equivalents(1)
|
$
|
359
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
359
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
679
|
|
|
—
|
|
|
—
|
|
|
679
|
|
Commodity forward contracts(2)
|
—
|
|
|
343
|
|
|
318
|
|
|
661
|
|
Interest rate hedging instruments
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
Effect of netting and allocation of collateral(3)(4)
|
(679
|
)
|
|
(257
|
)
|
|
(23
|
)
|
|
(959
|
)
|
Total assets
|
$
|
359
|
|
|
$
|
92
|
|
|
$
|
295
|
|
|
$
|
746
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
$
|
767
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
767
|
|
Commodity forward contracts(2)
|
—
|
|
|
415
|
|
|
111
|
|
|
526
|
|
Interest rate hedging instruments
|
—
|
|
|
38
|
|
|
—
|
|
|
38
|
|
Effect of netting and allocation of collateral(3)(4)
|
(767
|
)
|
|
(259
|
)
|
|
(23
|
)
|
|
(1,049
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
194
|
|
|
$
|
88
|
|
|
$
|
282
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(in millions)
|
Assets:
|
|
|
|
|
|
|
|
Cash equivalents(1)
|
$
|
168
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
168
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
933
|
|
|
—
|
|
|
—
|
|
|
933
|
|
Commodity forward contracts(2)
|
—
|
|
|
338
|
|
|
212
|
|
|
550
|
|
Interest rate hedging instruments
|
—
|
|
|
40
|
|
|
—
|
|
|
40
|
|
Effect of netting and allocation of collateral(3)(4)
|
(933
|
)
|
|
(262
|
)
|
|
(26
|
)
|
|
(1,221
|
)
|
Total assets
|
$
|
168
|
|
|
$
|
116
|
|
|
$
|
186
|
|
|
$
|
470
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
$
|
932
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
932
|
|
Commodity forward contracts(2)
|
—
|
|
|
549
|
|
|
220
|
|
|
769
|
|
Interest rate hedging instruments
|
—
|
|
|
10
|
|
|
—
|
|
|
10
|
|
Effect of netting and allocation of collateral(3)(4)
|
(932
|
)
|
|
(310
|
)
|
|
(26
|
)
|
|
(1,268
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
249
|
|
|
$
|
194
|
|
|
$
|
443
|
|
___________
|
|
(1)
|
At September 30, 2019 and December 31, 2018, we had cash equivalents of $187 million and $23 million included in cash and cash equivalents and $172 million and $145 million included in restricted cash, respectively.
|
|
|
(2)
|
Includes OTC swaps and options.
|
|
|
(3)
|
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 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 $88 million, $2 million and nil, respectively, at September 30, 2019. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled $(1) million, $48 million and nil, respectively, at December 31, 2018.
|
At September 30, 2019 and December 31, 2018, the derivative instruments classified as level 3 primarily included commodity contracts, which are classified as level 3 because the contract terms relate to a delivery location or tenor for which observable market rate information is not available. The fair value of the net derivative position classified as level 3 is predominantly driven by market commodity prices. The following table presents quantitative information for the unobservable inputs used in our most significant level 3 fair value measurements at September 30, 2019 and December 31, 2018:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
|
|
|
September 30, 2019
|
|
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
|
|
|
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
Power Contracts(1)
|
|
$
|
165
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
3.68
|
|
—
|
$182.70
|
/MWh
|
Power Congestion Products
|
|
$
|
13
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
(13.19
|
)
|
—
|
$12.51
|
/MWh
|
Natural Gas Contracts
|
|
$
|
10
|
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$
|
1.72
|
|
—
|
$6.34
|
/MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
|
|
|
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
Power Contracts(1)
|
|
$
|
36
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
2.12
|
|
—
|
$227.98
|
/MWh
|
Power Congestion Products
|
|
$
|
26
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
(11.71
|
)
|
—
|
$11.88
|
/MWh
|
Natural Gas Contracts
|
|
$
|
(73
|
)
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$
|
0.75
|
|
—
|
$8.87
|
/MMBtu
|
___________
|
|
(1)
|
Power contracts include power and heat rate instruments classified as level 3 in the fair value hierarchy.
|
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Balance, beginning of period
|
|
$
|
227
|
|
|
$
|
131
|
|
|
$
|
(8
|
)
|
|
$
|
197
|
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
|
|
|
Included in net income:
|
|
|
|
|
|
|
|
|
Included in operating revenues(1)
|
|
20
|
|
|
(99
|
)
|
|
151
|
|
|
(84
|
)
|
Included in fuel and purchased energy expense(2)
|
|
—
|
|
|
18
|
|
|
2
|
|
|
27
|
|
Change in collateral
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Purchases, Issuances and settlements:
|
|
|
|
|
|
|
|
|
Purchases
|
|
—
|
|
|
4
|
|
|
3
|
|
|
12
|
|
Issuances
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
Settlements
|
|
(23
|
)
|
|
37
|
|
|
68
|
|
|
(56
|
)
|
Transfers in and/or out of level 3(3):
|
|
|
|
|
|
|
|
|
Transfers into level 3(4)
|
|
7
|
|
|
(1
|
)
|
|
10
|
|
|
—
|
|
Transfers out of level 3(5)
|
|
(23
|
)
|
|
(2
|
)
|
|
(18
|
)
|
|
(8
|
)
|
Balance, end of period
|
|
$
|
207
|
|
|
$
|
88
|
|
|
$
|
207
|
|
|
$
|
88
|
|
Change in unrealized gains (losses) relating to instruments still held at end of period
|
|
$
|
20
|
|
|
$
|
(81
|
)
|
|
$
|
153
|
|
|
$
|
(57
|
)
|
___________
|
|
(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 transfer amounts among levels of the fair value hierarchy as of the end of each period. There were no transfers into or out of level 1 for each of the three and nine months ended September 30, 2019 and 2018.
|
|
|
(4)
|
We had $7 million in gains and $(1) million in losses transferred out of level 2 into level 3 for the three months ended September 30, 2019 and 2018, respectively, and $10 million in gains and nil transferred out of level 2 into level 3 for the nine months ended September 30, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
|
|
|
(5)
|
We had $23 million and $2 million in gains transferred out of level 3 into level 2 for the three months ended September 30, 2019 and 2018, respectively, and $18 million and $8 million in gains transferred out of level 3 into level 2 for the nine months ended September 30, 2019 and 2018, respectively, due to changes in market liquidity in various power markets.
|
|
|
8.
|
Derivative Instruments
|
Types of Derivative Instruments and Volumetric Information
Commodity Instruments — We are exposed to changes in prices for the purchase and sale of power, natural gas, 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 nine months ended September 30, 2019 and 2018.
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 September 30, 2019, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was 6 years.
As of September 30, 2019 and December 31, 2018, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments
|
|
Notional Amounts
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
Unit of Measure
|
Power
|
|
(161
|
)
|
|
(161
|
)
|
|
Million MWh
|
Natural gas
|
|
1,030
|
|
|
1,045
|
|
|
Million MMBtu
|
Environmental credits
|
|
20
|
|
|
13
|
|
|
Million Tonnes
|
Interest rate hedging instruments
|
|
$
|
4.9
|
|
|
$
|
4.5
|
|
|
Billion U.S. dollars
|
Certain of our derivative instruments contain credit risk-related contingent provisions that require us to maintain collateral balances consistent with our credit ratings. If our credit rating were to be downgraded, it could require us to post additional collateral or could potentially allow our counterparty to request immediate, full settlement on certain derivative instruments in liability positions. The aggregate fair value of our derivative liabilities with credit risk-related contingent provisions as of September 30, 2019, was $136 million for which we have posted collateral of $89 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 an immaterial amount of 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 our interest rate hedging instruments. We report the mark-to-market gain or loss on our interest rate hedging instruments designated and qualifying as a cash flow hedging instrument as a component of OCI and reclassify such gains and losses into earnings in the same period during which the hedged forecasted transaction affects earnings. Prior to January 1, 2019, gains and losses due to ineffectiveness on interest rate hedging instruments were recognized in earnings as a component of interest expense. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value will be recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction affects earnings or until it is determined that the forecasted transaction is probable of not occurring.
Derivatives Not Designated as Hedging Instruments — We enter into power, natural gas, interest rate, environmental product and fuel oil transactions that primarily act as economic hedges to our asset and interest rate portfolio, but either do not qualify as hedges under the hedge accounting guidelines or qualify under the hedge accounting guidelines and the hedge accounting designation has not been elected. Changes in fair value of commodity derivatives not designated as hedging instruments are recognized currently in earnings and are separately stated on our Consolidated 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 September 30, 2019 and December 31, 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 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
|
|
$
|
492
|
|
|
$
|
(492
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
333
|
|
|
(190
|
)
|
|
143
|
|
Interest rate hedging instruments
|
|
3
|
|
|
(2
|
)
|
|
1
|
|
Total current derivative assets(2)
|
|
$
|
828
|
|
|
$
|
(684
|
)
|
|
$
|
144
|
|
Commodity exchange traded derivatives contracts
|
|
187
|
|
|
(187
|
)
|
|
—
|
|
Commodity forward contracts
|
|
328
|
|
|
(88
|
)
|
|
240
|
|
Interest rate hedging instruments
|
|
3
|
|
|
—
|
|
|
3
|
|
Total long-term derivative assets(2)
|
|
$
|
518
|
|
|
$
|
(275
|
)
|
|
$
|
243
|
|
Total derivative assets
|
|
$
|
1,346
|
|
|
$
|
(959
|
)
|
|
$
|
387
|
|
|
|
|
|
|
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
(571
|
)
|
|
$
|
571
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(383
|
)
|
|
195
|
|
|
(188
|
)
|
Interest rate hedging instruments
|
|
(12
|
)
|
|
2
|
|
|
(10
|
)
|
Total current derivative (liabilities)(2)
|
|
$
|
(966
|
)
|
|
$
|
768
|
|
|
$
|
(198
|
)
|
Commodity exchange traded derivatives contracts
|
|
(196
|
)
|
|
196
|
|
|
—
|
|
Commodity forward contracts
|
|
(143
|
)
|
|
85
|
|
|
(58
|
)
|
Interest rate hedging instruments
|
|
(26
|
)
|
|
—
|
|
|
(26
|
)
|
Total long-term derivative (liabilities)(2)
|
|
$
|
(365
|
)
|
|
$
|
281
|
|
|
$
|
(84
|
)
|
Total derivative liabilities
|
|
$
|
(1,331
|
)
|
|
$
|
1,049
|
|
|
$
|
(282
|
)
|
Net derivative assets (liabilities)
|
|
$
|
15
|
|
|
$
|
90
|
|
|
$
|
105
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2018
|
|
|
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
|
|
$
|
820
|
|
|
$
|
(820
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
341
|
|
|
(229
|
)
|
|
112
|
|
Interest rate hedging instruments
|
|
30
|
|
|
—
|
|
|
30
|
|
Total current derivative assets(3)
|
|
$
|
1,191
|
|
|
$
|
(1,049
|
)
|
|
$
|
142
|
|
Commodity exchange traded derivatives contracts
|
|
113
|
|
|
(113
|
)
|
|
—
|
|
Commodity forward contracts
|
|
209
|
|
|
(59
|
)
|
|
150
|
|
Interest rate hedging instruments
|
|
10
|
|
|
—
|
|
|
10
|
|
Total long-term derivative assets(3)
|
|
$
|
332
|
|
|
$
|
(172
|
)
|
|
$
|
160
|
|
Total derivative assets
|
|
$
|
1,523
|
|
|
$
|
(1,221
|
)
|
|
$
|
302
|
|
|
|
|
|
|
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
(764
|
)
|
|
$
|
764
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(576
|
)
|
|
277
|
|
|
(299
|
)
|
Interest rate hedging instruments
|
|
(4
|
)
|
|
—
|
|
|
(4
|
)
|
Total current derivative (liabilities)(3)
|
|
$
|
(1,344
|
)
|
|
$
|
1,041
|
|
|
$
|
(303
|
)
|
Commodity exchange traded derivatives contracts
|
|
(168
|
)
|
|
168
|
|
|
—
|
|
Commodity forward contracts
|
|
(193
|
)
|
|
59
|
|
|
(134
|
)
|
Interest rate hedging instruments
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
Total long-term derivative (liabilities)(3)
|
|
$
|
(367
|
)
|
|
$
|
227
|
|
|
$
|
(140
|
)
|
Total derivative liabilities
|
|
$
|
(1,711
|
)
|
|
$
|
1,268
|
|
|
$
|
(443
|
)
|
Net derivative assets (liabilities)
|
|
$
|
(188
|
)
|
|
$
|
47
|
|
|
$
|
(141
|
)
|
____________
|
|
(1)
|
At September 30, 2019 and December 31, 2018, we had $116 million and $244 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 September 30, 2019, current and long-term derivative assets are shown net of collateral of $(7) million and $(6) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $92 million and $11 million, respectively.
|
|
|
(3)
|
At December 31, 2018, current and long-term derivative assets are shown net of collateral of $(58) million and $(8) million, respectively, and current and long-term derivative liabilities are shown net of collateral of $49 million and $64 million, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
|
Fair Value
of Derivative
Assets
|
|
Fair Value
of Derivative
Liabilities
|
|
Fair Value
of Derivative
Assets
|
|
Fair Value
of Derivative
Liabilities
|
Derivatives designated as cash flow hedging instruments:
|
|
|
|
|
|
|
|
Interest rate hedging instruments
|
$
|
4
|
|
|
$
|
34
|
|
|
$
|
40
|
|
|
$
|
10
|
|
Total derivatives designated as cash flow hedging instruments
|
$
|
4
|
|
|
$
|
34
|
|
|
$
|
40
|
|
|
$
|
10
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
Commodity instruments
|
$
|
383
|
|
|
$
|
246
|
|
|
$
|
262
|
|
|
$
|
433
|
|
Interest rate hedging instruments
|
—
|
|
|
2
|
|
|
—
|
|
|
—
|
|
Total derivatives not designated as hedging instruments
|
$
|
383
|
|
|
$
|
248
|
|
|
$
|
262
|
|
|
$
|
433
|
|
Total derivatives
|
$
|
387
|
|
|
$
|
282
|
|
|
$
|
302
|
|
|
$
|
443
|
|
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 September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Realized gain (loss)(1)(2)
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
92
|
|
|
$
|
45
|
|
|
$
|
261
|
|
|
$
|
111
|
|
Total realized gain (loss)
|
$
|
92
|
|
|
$
|
45
|
|
|
$
|
261
|
|
|
$
|
111
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss)(3)
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
67
|
|
|
$
|
106
|
|
|
$
|
300
|
|
|
$
|
(77
|
)
|
Interest rate hedging instruments
|
(1
|
)
|
|
1
|
|
|
(3
|
)
|
|
4
|
|
Total mark-to-market gain (loss)
|
$
|
66
|
|
|
$
|
107
|
|
|
$
|
297
|
|
|
$
|
(73
|
)
|
Total activity, net
|
$
|
158
|
|
|
$
|
152
|
|
|
$
|
558
|
|
|
$
|
38
|
|
___________
|
|
(1)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
|
|
(2)
|
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions.
|
|
|
(3)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Realized and mark-to-market gain (loss)(1)
|
|
|
|
|
|
|
|
Derivatives contracts included in operating revenues(2)(3)
|
$
|
213
|
|
|
$
|
34
|
|
|
$
|
791
|
|
|
$
|
(142
|
)
|
Derivatives contracts included in fuel and purchased energy expense(2)(3)
|
(54
|
)
|
|
117
|
|
|
(230
|
)
|
|
176
|
|
Interest rate hedging instruments included in interest expense
|
(1
|
)
|
|
1
|
|
|
(3
|
)
|
|
4
|
|
Total activity, net
|
$
|
158
|
|
|
$
|
152
|
|
|
$
|
558
|
|
|
$
|
38
|
|
___________
|
|
(1)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes adjustments to reflect changes in credit default risk exposure.
|
|
|
(2)
|
Does not include the realized value associated with derivative instruments that settle through physical delivery.
|
|
|
(3)
|
Includes amortization of acquisition date fair value of financial derivative activity related to the acquisition of Champion Energy and Calpine Solutions.
|
Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Three Months Ended September 30,
|
|
Gain (Loss) Recognized in OCI
|
|
Gain (Loss) Reclassified from AOCI into Income(3)(4)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Affected Line Item on the Consolidated Condensed Statements of Operations
|
Interest rate hedging instruments(1)(2)
|
$
|
(3
|
)
|
|
$
|
13
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
Interest expense
|
Interest rate hedging instruments(1)(2)
|
1
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
Depreciation and amortization expense
|
Total
|
$
|
(2
|
)
|
|
$
|
13
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
Gain (Loss) Recognized in OCI
|
|
Gain (Loss) Reclassified from AOCI into Income(3)(4)
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
|
Affected Line Item on the Consolidated Condensed Statements of Operations
|
Interest rate hedging instruments(1)(2)
|
$
|
(60
|
)
|
|
$
|
82
|
|
|
$
|
3
|
|
|
$
|
(6
|
)
|
|
Interest expense
|
Interest rate hedging instruments(1)(2)
|
1
|
|
|
1
|
|
|
(1
|
)
|
|
(1
|
)
|
|
Depreciation and amortization expense
|
Total
|
$
|
(59
|
)
|
|
$
|
83
|
|
|
$
|
2
|
|
|
$
|
(7
|
)
|
|
|
____________
|
|
(1)
|
We recorded nil and $1 million in gains on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and nine months ended September 30, 2018. Upon the adoption of Accounting Standards Update 2017-12 on January 1, 2019, hedge ineffectiveness is no longer separately measured and recorded in earnings.
|
|
|
(2)
|
We recorded an income tax benefit of $1 million for each of the three months ended September 30, 2019 and 2018, respectively, and income tax benefit of $2 million and income tax expense of $3 million for the nine months ended September 30, 2019 and 2018, respectively, in AOCI related to our cash flow hedging activities.
|
|
|
(3)
|
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were $90 million and $34 million at September 30, 2019 and December 31, 2018, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were $4 million and $3 million at September 30, 2019 and December 31, 2018, respectively.
|
|
|
(4)
|
Includes losses (gains) of nil that were reclassified from AOCI to interest expense for the three months ended September 30, 2019 and 2018, and losses of $2 million and nil that were reclassified from AOCI to interest expense for the nine months ended September 30, 2019 and 2018, respectively, where the hedged transactions became probable of not occurring.
|
We estimate that pre-tax net losses of $25 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 September 30, 2019 and December 31, 2018 (in millions):
|
|
|
|
|
|
|
|
|
|
September 30, 2019
|
|
December 31, 2018
|
Margin deposits(1)
|
$
|
331
|
|
|
$
|
343
|
|
Natural gas and power prepayments
|
38
|
|
|
31
|
|
Total margin deposits and natural gas and power prepayments with our counterparties(2)
|
$
|
369
|
|
|
$
|
374
|
|
|
|
|
|
Letters of credit issued
|
$
|
902
|
|
|
$
|
1,166
|
|
First priority liens under power and natural gas agreements
|
46
|
|
|
92
|
|
First priority liens under interest rate hedging instruments
|
38
|
|
|
10
|
|
Total letters of credit and first priority liens with our counterparties
|
$
|
986
|
|
|
$
|
1,268
|
|
|
|
|
|
Margin deposits posted with us by our counterparties(1)(3)
|
$
|
125
|
|
|
$
|
52
|
|
Letters of credit posted with us by our counterparties
|
35
|
|
|
27
|
|
Total margin deposits and letters of credit posted with us by our counterparties
|
$
|
160
|
|
|
$
|
79
|
|
___________
|
|
(1)
|
We offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement for financial statement presentation; therefore, amounts recognized for the right to reclaim, or the obligation to return, cash collateral are presented net with the corresponding derivative instrument fair values. See Note 8 for further discussion of our derivative instruments subject to master netting arrangements.
|
|
|
(2)
|
At September 30, 2019 and December 31, 2018, $92 million and $79 million, respectively, were included in current and long-term derivative assets and liabilities, $269 million and $286 million, respectively, were included in margin deposits and other prepaid expense and $8 million and $9 million, respectively, were included in other assets on our Consolidated Condensed Balance Sheets.
|
|
|
(3)
|
At September 30, 2019 and December 31, 2018, $2 million and $32 million, respectively, were included in current and long-term derivative assets and liabilities, $92 million and $20 million, respectively, were included in other current liabilities and $31 million and nil, respectively, were included in other long-term liabilities on our Consolidated 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
The table below shows our consolidated income tax expense and our effective tax rates for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30,
|
|
Nine Months Ended September 30,
|
|
2019
|
|
2018
|
|
2019
|
|
2018
|
Income tax expense
|
$
|
21
|
|
|
$
|
128
|
|
|
$
|
40
|
|
|
$
|
78
|
|
Effective tax rate
|
4
|
%
|
|
32
|
%
|
|
4
|
%
|
|
75
|
%
|
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, changes in unrecognized tax benefits and valuation allowances. For the three and nine months ended September 30, 2019 and 2018, our income tax expense is largely comprised of discrete tax items and estimated state and foreign income taxes in jurisdictions where we do not have NOLs or valuation allowances.
Income Tax Audits — We remain subject to periodic audits and reviews by taxing authorities; however, we do not expect these audits will have a material effect on our tax provision. Any NOLs we claim in future years to reduce taxable income could be subject to IRS examination regardless of when the NOLs were generated. Any adjustment of state or federal returns could result in a reduction of deferred tax assets rather than a cash payment of income taxes in tax jurisdictions where we have NOLs. We are currently under various state income tax audits for various periods.
Valuation Allowance — U.S. GAAP requires that we consider all available evidence, both positive and negative, and tax planning strategies to determine whether, based on the weight of that evidence, a valuation allowance is needed to reduce the value of deferred tax assets. Future realization of the tax benefit of an existing deductible temporary difference or carryforward ultimately depends on the existence of sufficient taxable income of the appropriate character within the carryback or carryforward periods available under the tax law. Due to our history of losses, we were unable to assume future profits; however, we are able to consider available tax planning strategies.
Limitation on Deduction of Net Business Interest Expense — On November 26, 2018, the U.S. Treasury Department released proposed regulations which would limit the current deductibility of net business interest expense. The proposed regulations would be applicable for taxable years ending after the date on which the regulations become final. Companies have the discretion to apply the proposed regulations, but must apply all such provisions of the proposed regulations on a consistent basis. As of September 30, 2019, we have not elected to apply the proposed regulations for the 2018 or 2019 tax years and we do not expect the application of the final regulations will have a material effect on our Consolidated Condensed Financial Statements.
Unrecognized Tax Benefits — At September 30, 2019, we had unrecognized tax benefits of $29 million. If recognized, $17 million of our unrecognized tax benefits could affect the annual effective tax rate and $12 million, related to deferred tax assets, could be offset against the recorded valuation allowance resulting in no effect on our effective tax rate. We had accrued interest and penalties of $3 million for income tax matters at September 30, 2019. We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of nil and $8 million in unrecognized tax benefits could occur within the next twelve months primarily related to state tax issues.
|
|
11.
|
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 September 30, 2019, there are no material outstanding claims related to our guarantee and indemnification obligations and we do not anticipate that we will be required to make any material payments under our guarantee and indemnification obligations. There have been no material changes to our guarantees and indemnifications from those disclosed in Note 16 of our 2018 Form 10-K.
|
|
12.
|
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 September 30, 2019 and December 31, 2018, we had $269 million and $238 million, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and $53 million and $34 million, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the nine months ended September 30, 2019 and 2018, we sold an aggregate of $1.8 billion and $1.8 billion, respectively, in trade accounts receivable and recorded $1.8 billion and $1.8 billion, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 7 and 17 in our 2018 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 obtained an ownership interest in Calpine through the Merger also has an ownership interest in Lyondell whereby they may significantly influence the management and operating policies of Lyondell. The terms of the PPA with Lyondell were negotiated prior to the Merger closing. We recorded $16 million and $17 million in Commodity revenue during the three months ended September 30, 2019 and 2018, respectively, and $53 million and $55 million in Commodity revenue during the nine months ended September 30, 2019 and 2018, associated with this contract with Lyondell. We recorded $4 million and $5 million in Commodity expense during the three months ended September 30, 2019 and 2018, respectively, and $11 million and $11 million in Commodity expense during the nine months ended September 30, 2019 and 2018, associated with this contract with Lyondell. At September 30, 2019 and December 31, 2018, the related party receivable and payable associated with this contract with Lyondell were immaterial.
Other — Following the Merger, we have identified other related party contracts for the sale of power, capacity, steam and RECs which are entered into in the ordinary course of our business. Most of these contracts relate to the sale of commodities and capacity for varying tenors. We have also entered into a long-term land lease agreement with a related party. As of September 30, 2019 and December 31, 2018, 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 September 30, 2019, our geographic reportable segments for our wholesale business are West (including geothermal), Texas and East (including Canada) and we have a separate reportable segment for our retail business. We continue to evaluate the optimal
manner in which we assess our performance including our segments and future changes may result in changes to the composition of our geographic segments.
Commodity Margin is a key operational measure of profit reviewed by our chief operating decision maker to assess the performance of our segments. The tables below show financial data for our segments (including a reconciliation of our Commodity Margin to income (loss) from operations by segment) for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2019
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues(1)
|
$
|
856
|
|
|
$
|
867
|
|
|
$
|
348
|
|
|
$
|
1,096
|
|
|
$
|
(375
|
)
|
|
$
|
2,792
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
393
|
|
|
$
|
369
|
|
|
$
|
265
|
|
|
$
|
100
|
|
|
$
|
—
|
|
|
$
|
1,127
|
|
Add: Mark-to-market commodity activity, net and other(2)
|
110
|
|
|
(107
|
)
|
|
(69
|
)
|
|
108
|
|
|
(8
|
)
|
|
34
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
82
|
|
|
71
|
|
|
69
|
|
|
41
|
|
|
(8
|
)
|
|
255
|
|
Depreciation and amortization expense
|
61
|
|
|
47
|
|
|
51
|
|
|
14
|
|
|
—
|
|
|
173
|
|
General and other administrative expense
|
10
|
|
|
13
|
|
|
12
|
|
|
4
|
|
|
—
|
|
|
39
|
|
Other operating expenses
|
9
|
|
|
2
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
15
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
Income from operations
|
341
|
|
|
129
|
|
|
63
|
|
|
149
|
|
|
—
|
|
|
682
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
153
|
|
Loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
17
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
512
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended September 30, 2018
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues(1)
|
$
|
701
|
|
|
$
|
1,022
|
|
|
$
|
460
|
|
|
$
|
1,125
|
|
|
$
|
(418
|
)
|
|
$
|
2,890
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
356
|
|
|
$
|
187
|
|
|
$
|
320
|
|
|
$
|
111
|
|
|
$
|
—
|
|
|
$
|
974
|
|
Add: Mark-to-market commodity activity, net and other(2)
|
(13
|
)
|
|
137
|
|
|
(26
|
)
|
|
(20
|
)
|
|
(8
|
)
|
|
70
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
85
|
|
|
63
|
|
|
72
|
|
|
36
|
|
|
(8
|
)
|
|
248
|
|
Depreciation and amortization expense
|
70
|
|
|
57
|
|
|
39
|
|
|
13
|
|
|
—
|
|
|
179
|
|
General and other administrative expense
|
7
|
|
|
12
|
|
|
7
|
|
|
5
|
|
|
—
|
|
|
31
|
|
Other operating expenses
|
11
|
|
|
3
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
23
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(5
|
)
|
|
—
|
|
|
—
|
|
|
(5
|
)
|
Income from operations
|
170
|
|
|
189
|
|
|
172
|
|
|
37
|
|
|
—
|
|
|
568
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
158
|
|
Loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
4
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
406
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2019
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues(3)
|
$
|
2,187
|
|
|
$
|
2,509
|
|
|
$
|
1,683
|
|
|
$
|
3,176
|
|
|
$
|
(1,565
|
)
|
|
$
|
7,990
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
908
|
|
|
$
|
704
|
|
|
$
|
765
|
|
|
$
|
281
|
|
|
$
|
—
|
|
|
$
|
2,658
|
|
Add: Mark-to-market commodity activity, net and other(4)
|
224
|
|
|
177
|
|
|
38
|
|
|
(127
|
)
|
|
(26
|
)
|
|
286
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
247
|
|
|
202
|
|
|
208
|
|
|
108
|
|
|
(26
|
)
|
|
739
|
|
Depreciation and amortization expense
|
194
|
|
|
146
|
|
|
142
|
|
|
40
|
|
|
—
|
|
|
522
|
|
General and other administrative expense
|
22
|
|
|
40
|
|
|
31
|
|
|
12
|
|
|
—
|
|
|
105
|
|
Other operating expenses
|
25
|
|
|
5
|
|
|
23
|
|
|
—
|
|
|
—
|
|
|
53
|
|
Impairment losses
|
—
|
|
|
—
|
|
|
55
|
|
|
—
|
|
|
—
|
|
|
55
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(15
|
)
|
|
1
|
|
|
—
|
|
|
(14
|
)
|
Income (loss) from operations
|
644
|
|
|
488
|
|
|
359
|
|
|
(7
|
)
|
|
—
|
|
|
1,484
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
459
|
|
Loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
44
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nine Months Ended September 30, 2018
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues(3)
|
$
|
1,536
|
|
|
$
|
2,155
|
|
|
$
|
1,415
|
|
|
$
|
2,998
|
|
|
$
|
(946
|
)
|
|
$
|
7,158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
782
|
|
|
$
|
504
|
|
|
$
|
729
|
|
|
$
|
265
|
|
|
$
|
—
|
|
|
$
|
2,280
|
|
Add: Mark-to-market commodity activity, net and other(4)
|
(23
|
)
|
|
(109
|
)
|
|
7
|
|
|
41
|
|
|
(23
|
)
|
|
(107
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
255
|
|
|
208
|
|
|
208
|
|
|
117
|
|
|
(23
|
)
|
|
765
|
|
Depreciation and amortization expense
|
204
|
|
|
190
|
|
|
133
|
|
|
39
|
|
|
—
|
|
|
566
|
|
General and other administrative expense
|
28
|
|
|
50
|
|
|
30
|
|
|
14
|
|
|
—
|
|
|
122
|
|
Other operating expenses
|
33
|
|
|
22
|
|
|
24
|
|
|
—
|
|
|
—
|
|
|
79
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(17
|
)
|
|
1
|
|
|
—
|
|
|
(16
|
)
|
Income (loss) from operations
|
239
|
|
|
(75
|
)
|
|
358
|
|
|
135
|
|
|
—
|
|
|
657
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
466
|
|
Loss on extinguishment of debt and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
73
|
|
Income before income taxes
|
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$
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118
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_________
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(1)
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Includes intersegment revenues of $133 million and $160 million in the West, $225 million and $238 million in Texas, $13 million and $19 million in the East and $4 million and $1 million in Retail for the three months ended September 30, 2019 and 2018, respectively.
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(2)
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Includes $31 million and $30 million of lease levelization and $20 million and $26 million of amortization expense for the three months ended September 30, 2019 and 2018, respectively.
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(3)
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Includes intersegment revenues of $395 million and $344 million in the West, $784 million and $447 million in Texas, $378 million and $152 million in the East and $8 million and $3 million in Retail for the nine months ended September 30, 2019 and 2018, respectively.
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(4)
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Includes $(4) million and $(5) million of lease levelization and $59 million and $79 million of amortization expense for the nine months ended September 30, 2019 and 2018, respectively.
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