NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
June 30, 2018
(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, industrial and agricultural 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 getting closer to customers through the expansion of our retail platform which began with the acquisition of Champion Energy in 2015 and was followed by the acquisitions of Calpine Solutions in late 2016 and North American Power in early 2017. 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 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, 2017
, included in our
2017
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
June 30, 2018
and
December 31, 2017
(in millions):
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June 30, 2018
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December 31, 2017
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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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18
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$
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8
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$
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26
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$
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11
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$
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8
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$
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19
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Construction/major maintenance
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15
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20
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35
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28
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16
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44
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Security/project/insurance
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67
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—
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67
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92
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—
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92
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Other
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3
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2
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5
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3
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1
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4
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Total
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$
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103
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$
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30
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$
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133
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$
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134
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$
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25
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$
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159
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Business Interruption Proceeds
— We record business interruption insurance proceeds in operating revenues when they are realizable and recorded approximately
$14 million
and
nil
of business interruption proceeds during the three months ended
June 30, 2018
and
2017
, respectively, and
$14 million
and
$1 million
during the six months ended
June 30, 2018
and
2017
, respectively.
Property, Plant and Equipment, Net
— At
June 30, 2018
and
December 31, 2017
, the components of property, plant and equipment are stated at cost less accumulated depreciation as follows (in millions):
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June 30, 2018
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December 31, 2017
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Depreciable Lives
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Buildings, machinery and equipment
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$
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16,440
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$
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16,506
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1.5
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–
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46
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Years
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Geothermal properties
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1,500
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1,494
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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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261
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236
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3
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–
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46
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Years
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18,201
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18,236
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Less: Accumulated depreciation
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6,590
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6,383
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11,611
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11,853
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Land
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118
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117
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Construction in progress
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857
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754
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Property, plant and equipment, net
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$
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12,586
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$
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12,724
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Depreciable Lives
— During the first quarter of 2018, we reviewed our accounting policies related to depreciation associated with our estimates of useful lives related to our componentized balance of plant parts. As a result, the useful lives of our rotable parts are now generally estimated to range from
1.5
to
12
years. Our change in the method of depreciation for rotable parts is considered a change in accounting estimate and will result in changes to our depreciation expense prospectively. The change in estimate resulted in a decrease to our net income (loss) attributable to Calpine of $
(4) million
and $
(43) million
for the three and six months ended
June 30, 2018
, respectively.
Capitalized Interest
— The total amount of interest capitalized was $
7 million
and $
6 million
during the three months ended
June 30, 2018
and
2017
, respectively, and $
14 million
and
$13 million
during the six months ended
June 30, 2018
and
2017
, respectively.
Goodwill
— We have not recorded any impairment losses associated with our goodwill. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, 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. As our goodwill resulted from the acquisition of our retail business over the last several years, our goodwill balance of $
242 million
was allocated to our Retail segment in connection with the change in segment presentation.
New Accounting Standards and Disclosure Requirements
Revenue Recognition
— On January 1, 2018, we adopted Accounting Standards Update 2014-09, “Revenue from Contracts with Customers”
(“Topic 606”)
.
The comprehensive new revenue recognition standard supersedes all pre-existing revenue recognition guidance. The core principle of Topic 606 is that a company will recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange
for those goods or services. The standard also requires expanded disclosures surrounding the recognition of revenue from contracts with customers. We adopted the new revenue recognition standards under Topic 606 using the modified retrospective method and applied Topic 606 to those contracts which were not completed as of January 1, 2018. Results for reporting periods beginning after December 31, 2017 are presented under Topic 606, while prior period amounts continue to be reported in accordance with historical accounting standards. The adoption of Topic 606 resulted in no adjustment to our opening retained earnings as of January 1, 2018. There was no material effect to our revenues, results of operations or cash flows for the six months ending June 30, 2018 from the adoption of Topic 606 and we do not expect the new revenue standard to have a material effect on our results of operations in future periods. See Note 3 for additional disclosures required by Topic 606.
Leases —
In February 2016, the FASB issued Accounting Standards Update 2016-02, “Leases.” The comprehensive new lease standard will supersede all existing lease guidance. The standard requires that a lessee should recognize a right-to-use asset and a lease liability for substantially all operating leases based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets and liabilities for leases with a term of 12 months or less. For lessors, the accounting for leases remains substantially unchanged. The standard also requires expanded disclosures surrounding leases. The standard is effective for fiscal periods beginning after December 15, 2018, including interim periods within that reporting period and requires modified retrospective adoption with early adoption permitted. In January 2018, the FASB issued Accounting Standards Update 2018-01, “Land Easement Practical Expedient for Transition to Topic 842” that allows an entity to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Accounting Standards Update 2016-02. Any land easements entered into prospectively or modified after adoption should be evaluated to assess whether they meet the definition of a lease. In July 2018, the FASB issued Accounting Standards Update 2018-10 “Codification Improvements to Topic 842, Leases” which clarifies, corrects or consolidates authoritative guidance issued in Accounting Standards Update 2016-02 and is effective upon adoption of Accounting Standards Update 2016-02. Also in July 2018, the FASB issued Accounting Standards Update 2018-11 “Leases (Topic 842): Targeted Improvements” which provides a new transitional method to adopt the new leases standard and a practical expedient for lessors in applying the provisions of the new leases standard, which is effective upon adoption of Accounting Standards Update 2016-02. We expect to adopt the standards in the first quarter of 2019. We have completed our initial evaluation of the standards and believe that the key changes that will affect us relate to our accounting for operating leases that are currently off-balance sheet and tolling contracts which we currently account for as operating leases. Additionally, we are evaluating the potential effects of the removal of the real estate guidance currently applicable to lessors. We are considering electing certain practical expedients in our implementation of the standard; however, this may change as we complete our assessment of the standard.
Statement of Cash Flows
— In August 2016, the FASB issued Accounting Standards Update 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” The standard addresses several matters of diversity in practice in how certain cash receipts and cash payments are presented and classified in the statement of cash flows including the presentation of debt extinguishment costs and distributions received from equity method investments. The standard is effective for fiscal years beginning after December 15, 2017, and requires retrospective adoption. We adopted Accounting Standards Update 2016-15 in the first quarter of 2018 which resulted in the reclassification of cash payments for debt extinguishment costs from a cash outflow for operating activities to a cash outflow for financing activities. The adoption of this standard did not have a material effect on our financial condition, results of operations or cash flows.
Income Taxes
— In October 2016, the FASB issued Accounting Standards Update 2016-16, “Intra-Entity Transfers of Assets Other than Inventory.” The standard requires an entity to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs which differs from the current requirement that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period and requires modified retrospective adoption. We adopted Accounting Standards Update 2016-16 in the first quarter of 2018 which did not have a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Restricted Cash
— In November 2016, the FASB issued Accounting Standards Update 2016-18, “Restricted Cash.” The standard requires restricted cash to be included with cash and cash equivalents when reconciling the beginning and ending amounts in the statement of cash flows and also requires disclosures regarding the nature of restrictions on cash, cash equivalents and restricted cash. The standard is effective for fiscal years beginning after December 15, 2017, including interim periods and requires retrospective adoption with early adoption permitted. We adopted Accounting Standards Update 2016-18 in the first quarter of 2018 which did not have a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
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. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We are currently assessing the future effect this standard may have on our financial condition, results of operations or cash flows.
Merger
— On August 17, 2017, we entered into the Merger Agreement with Volt Parent, LP (“Volt Parent”) and Volt Merger Sub, Inc. (“Merger Sub”), a wholly-owned subsidiary of Volt Parent, pursuant to which Merger Sub merged with and into Calpine, with Calpine surviving the Merger as a subsidiary of Volt Parent. On March 8, 2018, we completed the Merger contemplated in the Merger Agreement.
At the effective time of the Merger, each share of Calpine common stock outstanding as of immediately prior to the effective time of the Merger (excluding certain shares as described in the Merger Agreement) ceased to be outstanding and was converted into the right to receive
$15.25
per share in cash or approximately
$5.6 billion
in total. See Note 10 for a discussion of the treatment of the outstanding share-based awards to employees at the effective time of the Merger.
We recorded approximately
$1 million
and
nil
for the three months ended
June 30, 2018
and
2017
, respectively, and
$32 million
and
nil
for the six months ended
June 30, 2018
and
2017
, respectively, in Merger-related costs which was recorded in other operating expenses on our Consolidated Condensed Statements of Operations and primarily related to legal, investment banking and other professional fees associated with the Merger. We elected not to apply pushdown accounting in connection with the consummation of the Merger.
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3.
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Revenue from Contracts with Customers
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Disaggregation of Revenues with Customers
The following tables represent a disaggregation of our revenue for the three and six months ended
June 30, 2018
by reportable segment (in millions). See Note 13 for a description of our segments.
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Three Months Ended June 30, 2018
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Wholesale
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West
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Texas
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East
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Retail
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Elimination
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Total
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Third Party:
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Energy & other products
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$
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176
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$
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326
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$
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120
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$
|
451
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$
|
—
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$
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1,073
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Capacity
|
35
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|
23
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|
140
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|
—
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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
|
$
|
211
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$
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349
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$
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260
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|
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$
|
451
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|
$
|
—
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$
|
1,271
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Affiliate
(1)
:
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$
|
5
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$
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9
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$
|
21
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$
|
1
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|
$
|
(36
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)
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$
|
—
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Revenues relating to leases and derivative instruments
(2)
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$
|
988
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Total operating revenues
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$
|
2,259
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Six Months Ended June 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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$
|
375
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$
|
630
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|
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$
|
252
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$
|
894
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$
|
—
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$
|
2,151
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Capacity
|
54
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|
49
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|
|
289
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|
|
—
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|
|
—
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|
392
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|
Revenues relating to physical or executory contracts – third party
|
$
|
429
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$
|
679
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|
|
$
|
541
|
|
|
$
|
894
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|
|
$
|
—
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|
$
|
2,543
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|
|
|
|
|
|
|
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Affiliate
(1)
:
|
$
|
13
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|
$
|
13
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|
|
$
|
42
|
|
|
$
|
2
|
|
|
$
|
(70
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)
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|
$
|
—
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Revenues relating to leases and derivative instruments
(2)
|
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$
|
1,725
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Total operating revenues
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|
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|
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$
|
4,268
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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 Corporation.
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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 Statement of Operations.
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For contracts that do not meet the requirements of a lease and either do not meet the definition of a derivative instrument or are exempt from derivative accounting, we have applied the new revenue recognition guidance beginning in the first quarter of 2018. Under the new guidance, the majority of our operating revenue continues to be recognized as the underlying commodity or service is delivered to our customers.
Energy and Other Products
Variable payments for power and steam that are based on generation, including retail sales of power, are recognized over time as the underlying commodity is generated and control is transferred to our customer upon transmission and delivery. Ancillary service revenues are also included within energy-related revenues and are recognized over time as the service is provided.
For our power, steam and ancillary service contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time based on the quantity of the commodity delivered to the customer for power and steam sales and over time as the service is provided for our ancillary service sales.
Energy and other revenues also includes revenues generated from the sale of natural gas and environmental products, including RECs and are recognized at either a point in time or over time when control of the commodity has transferred. Revenues from the sale of RECs are primarily related to credits that are generated upon generation of renewable power from our Geysers Assets and are recognized over a period of time similar to the timing of the related energy sale. Revenues from sales of RECs or other environmental products that are not generated from our assets are recognized once all certifications have been completed and the credits are delivered to the customer at a point in time. Revenues from our natural gas sales are recognized at a point in time when delivery of the natural gas is provided. Revenues from natural gas and emission product sales are generally at the contracted transaction price, which may be fixed or index-based.
Capacity
Capacity revenues include fixed and variable capacity payments, which are based on generation volumes and include capacity payments received from RTO and ISO capacity auctions. For these contracts, we have elected the practical expedient that allows us to recognize revenue in the amount to which we have the right to invoice to the extent we determine that we have a right to consideration in an amount that corresponds directly with the value provided to date. To the extent this practical expedient cannot be utilized, we will recognize revenue over time as the service is being provided to the customer.
Performance Obligations and Contract Balances
Certain of our contracts have multiple performance obligations. The revenues associated with each individual performance obligation is based on the relative stand-alone sales price of each good or service or, when not available, is based on a cost incurred plus margin approach. For a significant portion of our contracts with multiple performance obligations, management has applied the practical expedient that results in recognition of revenue commensurate with the invoiced amount and no allocation is required as all performance obligations are transferred over the same period of time.
Certain of our contracts include volumetric optionality based on the customer’s needs. The transaction price within these contracts are based on a stand-alone sale price of the good or service being provided and revenue is recognized based on the customer’s usage. On a monthly basis, revenue is recognized based on estimated or actual usage by the customer at the transaction price. To the extent estimated usage is used in the recognition of revenue, revenues are adjusted for actual usage once known; however, this adjustment is not material to the revenues recognized. Generally, we have applied the practical expedient that allows us to recognize revenue based on the invoiced amount for these contracts.
Changes in estimates for our contracts are not material and revisions to estimates are recognized when the amounts can be reasonably estimated. Unbilled retail sales are based upon estimates of customer usage since the date of the last meter reading provided by the ISOs or electric distribution companies by applying the estimated revenue per KWh by customer class to the estimated number of KWhs delivered but not yet billed. Estimated amounts are adjusted when actual usage is known and billed. During the three and six months ended
June 30, 2018
, there were no significant changes to revenue amounts recognized in prior periods as a result of a change in estimates. Sales and other taxes we collect concurrent with revenue-producing activities are excluded from our operating revenues.
Billing requirements for our wholesale customers generally result in billing customers on a monthly basis in the month following the delivery of the good or service. Once billed, payment is generally required within 20 days resulting in payment for the delivery of the good or service in the month following delivery of the good or service. Billing requirements for our retail customers are generally once every 30 days and may result in billed amounts relating to our retail customers extending up to 60 days. Based on the terms of our agreements, payment is generally received at or shortly after delivery of the good or service.
Changes in accounts receivable relating to our customers is primarily due to the timing difference between payment and when the good or service is provided. During the three and six months ended
June 30, 2018
, there were no significant changes in accounts receivable other than normal billing and collection transactions and there were no material credit or impairment losses recognized relating to accounts receivable balances associated with contracts with customers.
When we receive consideration from a customer prior to transferring goods or services to the customer under the terms of a contract, we record deferred revenue, which represents a contract liability. Such deferred revenue typically results from consideration received prior to the transfer of goods and services relating to our capacity contracts and the sale of RECs that are not generated from our power plants. Based on the nature of these contracts and the timing between when consideration is received and delivery of the good or service is provided, these contracts do not contain any material financing elements.
At
June 30, 2018
and
December 31, 2017
, deferred revenue balances relating to contracts with our customers were included in other current liabilities on our Consolidated Condensed Balance Sheets. We classify deferred revenue as current or long-term based on the timing of when we expect to recognize revenue. The balances outstanding at both
June 30, 2018
and
December 31, 2017
were not material. The revenue recognized during the three and six months ended
June 30, 2018
, relating to the deferred revenue balance at the beginning of the period was immaterial and resulted from our performance under the customer contracts. The change in deferred revenues during the three and six months ended
June 30, 2018
was primarily due to the timing difference of when consideration was received and when the related good or service was transferred.
Contract Costs
For certain retail contracts, we incur third party incremental broker costs that are capitalized on our Consolidated Condensed Balance Sheets. Capitalized contract costs are amortized on a straight line basis over the term of the underlying sales
contract to the extent the term extends beyond one year. Contract costs associated with sales contracts that are less than one year are expensed as incurred under a practical expedient.
At both
June 30, 2018
and
December 31, 2017
, the capitalized contract cost balance was not material. There were no impairment losses or changes in amortization during the three and six months ended
June 30, 2018
and amortization of contract costs during the three and six months ended
June 30, 2018
was immaterial.
Performance Obligations not yet Satisfied
As of
June 30, 2018
, we have entered into certain contracts with customers under which we have not yet completed our performance obligations which includes agreements for which we are providing power and capacity from our generating facilities for an aggregate transaction price of approximately
$79 million
that we expect to recognize as revenue through
2029
. We also 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
$374 million
,
$558 million
,
$494 million
,
$467 million
and
$200 million
that will be recognized during the years ending December 31, 2018, 2019, 2020, 2021 and 2022, respectively, and
$42 million
thereafter. Revenues under these contracts will be recognized as we transfer control of the commodities to our customers.
|
|
4.
|
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 six months ended
June 30, 2018
. See Note 6 in our
2017
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
7,880
MW and
7,880
MW at
June 30, 2018
and
December 31, 2017
, respectively. For these VIEs, we may provide other operational and administrative support through various affiliate contractual arrangements among the VIEs, Calpine Corporation and its other wholly-owned subsidiaries whereby we support the VIE through the reimbursement of costs and/or the purchase and sale of energy. Other than amounts contractually required, we provided support to these VIEs in the form of cash and other contributions of
nil
during each of the three and six months ended
June 30, 2018
and
2017
.
OMEC —
OMEC has a ten-year tolling agreement with SDG&E which commenced on October 3, 2009. Under a ground lease agreement, OMEC holds a put option to sell the Otay Mesa Energy Center for
$280 million
to SDG&E, which is exercisable through April 2019 and SDG&E holds a call option to purchase the Otay Mesa Energy Center for
$377 million
, which is exercisable through October 2018. If either option is exercised, the sale would occur upon the conclusion of the tolling agreement in October 2019. We have concluded that we are the primary beneficiary of OMEC as we believe the activity that has the most effect on the financial performance of OMEC is operations and maintenance which is controlled by us. As a result, we consolidate OMEC.
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.
In December 2016, we acquired Calpine Receivables, a bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Solutions under the Accounts Receivable Sales Program. Calpine Receivables is a VIE. 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
June 30, 2018
and
December 31, 2017
, our equity method investments included on our Consolidated Condensed Balance Sheets were comprised of the following (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
Ownership Interest as of
June 30, 2018
|
|
June 30, 2018
|
|
December 31, 2017
|
Greenfield LP
|
50%
|
|
$
|
96
|
|
|
$
|
92
|
|
Whitby
|
50%
|
|
8
|
|
|
6
|
|
Calpine Receivables
|
100%
|
|
7
|
|
|
8
|
|
Total investments in unconsolidated subsidiaries
|
|
|
$
|
111
|
|
|
$
|
106
|
|
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
$56 million
which consists of our notes receivable from Calpine Receivables at
June 30, 2018
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
June 30, 2018
and
December 31, 2017
, Greenfield LP’s debt was approximately
$244 million
and $
256 million
, respectively, and based on our pro rata share of our investment in Greenfield LP, our share of such debt would be approximately
$122 million
and $
128 million
at
June 30, 2018
and
December 31, 2017
, respectively.
Our equity interest in the net income from our investments in unconsolidated subsidiaries for the three and six months ended
June 30, 2018
and
2017
, 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 June 30,
|
|
Six Months Ended June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Greenfield LP
|
$
|
(2
|
)
|
|
$
|
(4
|
)
|
|
$
|
(4
|
)
|
|
$
|
(6
|
)
|
Whitby
|
(4
|
)
|
|
(2
|
)
|
|
(8
|
)
|
|
(4
|
)
|
Calpine Receivables
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
Total
|
$
|
(5
|
)
|
|
$
|
(6
|
)
|
|
$
|
(11
|
)
|
|
$
|
(10
|
)
|
Distributions from Greenfield LP were
nil
during each of the three and six months ended
June 30, 2018
and
2017
. Distributions from Whitby were
$2 million
and
$5 million
during the three and six months ended
June 30, 2018
, respectively, and
$3 million
and
$16 million
during the three and six months ended
June 30, 2017
, respectively. We did not have material distributions from our investment in Calpine Receivables for the three and six months ended
June 30, 2018
and
2017
.
Our debt at
June 30, 2018
and
December 31, 2017
, was as follows (in millions):
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Senior Unsecured Notes
|
$
|
3,420
|
|
|
$
|
3,417
|
|
First Lien Term Loans
|
2,986
|
|
|
2,995
|
|
First Lien Notes
|
2,397
|
|
|
2,396
|
|
Project financing, notes payable and other
|
1,440
|
|
|
1,498
|
|
CCFC Term Loan
|
978
|
|
|
984
|
|
Capital lease obligations
|
111
|
|
|
115
|
|
Corporate Revolving Facility
|
275
|
|
|
—
|
|
Subtotal
|
11,607
|
|
|
11,405
|
|
Less: Current maturities
|
512
|
|
|
225
|
|
Total long-term debt
|
$
|
11,095
|
|
|
$
|
11,180
|
|
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
5.7%
for the six months ended
June 30, 2018
, from
5.4%
for the same period in 2017.
Senior Unsecured Notes
The amounts outstanding under our Senior Unsecured Notes are summarized in the table below (in millions):
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
2023 Senior Unsecured Notes
|
$
|
1,240
|
|
|
$
|
1,239
|
|
2024 Senior Unsecured Notes
|
644
|
|
|
644
|
|
2025 Senior Unsecured Notes
|
1,536
|
|
|
1,534
|
|
Total Senior Unsecured Notes
|
$
|
3,420
|
|
|
$
|
3,417
|
|
First Lien Term Loans
The amounts outstanding under our senior secured First Lien Term Loans are summarized in the table below (in millions):
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
2019 First Lien Term Loan
|
$
|
389
|
|
|
$
|
389
|
|
2023 First Lien Term Loans
|
1,062
|
|
|
1,064
|
|
2024 First Lien Term Loan
|
1,535
|
|
|
1,542
|
|
Total First Lien Term Loans
|
$
|
2,986
|
|
|
$
|
2,995
|
|
First Lien Notes
The amounts outstanding under our senior secured First Lien Notes are summarized in the table below (in millions):
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
2022 First Lien Notes
|
$
|
742
|
|
|
$
|
741
|
|
2024 First Lien Notes
|
486
|
|
|
485
|
|
2026 First Lien Notes
|
1,169
|
|
|
1,170
|
|
Total First Lien Notes
|
$
|
2,397
|
|
|
$
|
2,396
|
|
Corporate Revolving Facility and Other Letter of Credit Facilities
The table below represents amounts issued under our letter of credit facilities at
June 30, 2018
and
December 31, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Corporate Revolving Facility
(1)
|
$
|
800
|
|
|
$
|
629
|
|
CDHI
|
267
|
|
|
244
|
|
Various project financing facilities
|
217
|
|
|
196
|
|
Other corporate facilities
(2)
|
96
|
|
|
—
|
|
Total
|
$
|
1,380
|
|
|
$
|
1,069
|
|
____________
|
|
(1)
|
The Corporate Revolving Facility represents our primary revolving facility.
|
|
|
(2)
|
During the second quarter of 2018, we executed two unsecured
$50 million
letter of credit facilities with third party financial institutions, each maturing on June 20, 2020. On July 26, 2018, we upsized one of the letter of credit facilities to
$100 million
.
|
On May 18, 2018, we amended our Corporate Revolving Facility to increase the capacity by approximately
$220 million
from
$1.47 billion
to approximately
$1.69 billion
. On March 8, 2018, we amended our Corporate Revolving Facility to increase the letter of credit facility from
$1.15 billion
to
$1.3 billion
and increased the Incremental Revolving Facilities (as defined in the credit agreement) amount to
$500 million
.
On September 15, 2017, we amended our Corporate Revolving Facility to, among other things, provide that the Merger does not constitute a “Change of Control” thereunder, effective upon consummation of the Merger. On October 20, 2017, we further amended our Corporate Revolving Facility to extend the maturity of most revolving commitments (totaling
$1.3 billion
in the aggregate) to March 8, 2023. Both amendments to the Corporate Revolving Facility became effective upon consummation of the Merger on March 8, 2018. See Note 2 for further information related to the Merger.
Short Term Credit Facility —
On April 11, 2018, we entered into a credit agreement which allows us access to
$300 million
in aggregate available borrowings until August 31, 2018. Any cash draws from the Short Term Credit Facility are unsecured but will be converted to first lien senior secured term loans if not repaid within
21
days of the initial draw date. Any borrowings converted into first lien senior secured loans have a
364
-day maturity from the initial draw date and will contain substantially similar interest rates, covenants, qualifications, exceptions and limitations as our 2019 First Lien Term Loan.
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
June 30, 2018
and
December 31, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
Senior Unsecured Notes
|
$
|
3,193
|
|
|
$
|
3,420
|
|
|
$
|
3,294
|
|
|
$
|
3,417
|
|
First Lien Term Loans
|
3,026
|
|
|
2,986
|
|
|
3,043
|
|
|
2,995
|
|
First Lien Notes
|
2,368
|
|
|
2,397
|
|
|
2,437
|
|
|
2,396
|
|
Project financing, notes payable and other
(1)
|
1,374
|
|
|
1,351
|
|
|
1,439
|
|
|
1,409
|
|
CCFC Term Loan
|
994
|
|
|
978
|
|
|
1,000
|
|
|
984
|
|
Corporate Revolving Facility
|
275
|
|
|
275
|
|
|
—
|
|
|
—
|
|
Total
|
$
|
11,230
|
|
|
$
|
11,407
|
|
|
$
|
11,213
|
|
|
$
|
11,201
|
|
____________
|
|
(1)
|
Excludes a lease that is accounted for as a failed sale-leaseback transaction under U.S. GAAP.
|
Our Senior Unsecured Notes, First Lien Term Loans, First Lien Notes, CCFC Term Loan and Corporate Revolving Facility 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.
|
|
6.
|
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 an exchange.
Our level 2 fair value derivative instruments primarily consist of interest rate hedging instruments and OTC power and natural gas forwards for which market-based pricing inputs in the principal or most advantageous market are representative of executable prices for market participants. These inputs are observable at commonly quoted intervals for substantially the full term of the instruments. In certain instances, our level 2 derivative instruments may utilize models to measure fair value. These models are industry-standard models, including the Black-Scholes option-pricing model, that incorporate various assumptions, including quoted interest rates, correlation, volatility, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.
Our level 3 fair value derivative instruments may consist of OTC power and natural gas forwards and options where pricing inputs are unobservable, as well as other complex and structured transactions primarily for the sale and purchase of power and natural gas to both wholesale counterparties and retail customers. Complex or structured transactions are tailored to our customers’ needs and can introduce the need for internally-developed model inputs which might not be observable in or corroborated by the market. When such inputs have a significant effect on the measurement of fair value, the instrument is categorized in level 3. Our valuation models may incorporate historical correlation information and extrapolate available broker and other information to future periods.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement at period end. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect our estimate of the fair value of our assets and liabilities and their placement within the fair value hierarchy levels. The following tables present our financial assets and liabilities that were accounted for at fair value on a recurring basis as of
June 30, 2018
and
December 31, 2017
, by level within the fair value hierarchy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of June 30, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(in millions)
|
Assets:
|
|
|
|
|
|
|
|
Cash equivalents
(1)
|
$
|
126
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
126
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
569
|
|
|
—
|
|
|
—
|
|
|
569
|
|
Commodity forward contracts
(2)
|
—
|
|
|
642
|
|
|
244
|
|
|
886
|
|
Interest rate hedging instruments
|
—
|
|
|
76
|
|
|
—
|
|
|
76
|
|
Effect of netting and allocation of collateral
(3)(4)
|
(569
|
)
|
|
(466
|
)
|
|
(24
|
)
|
|
(1,059
|
)
|
Total assets
|
$
|
126
|
|
|
$
|
252
|
|
|
$
|
220
|
|
|
$
|
598
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
$
|
687
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
687
|
|
Commodity forward contracts
(2)
|
—
|
|
|
821
|
|
|
112
|
|
|
933
|
|
Interest rate hedging instruments
|
—
|
|
|
16
|
|
|
—
|
|
|
16
|
|
Effect of netting and allocation of collateral
(3)(4)
|
(687
|
)
|
|
(488
|
)
|
|
(23
|
)
|
|
(1,198
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
349
|
|
|
$
|
89
|
|
|
$
|
438
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets and Liabilities with Recurring Fair Value Measures as of December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
|
(in millions)
|
Assets:
|
|
|
|
|
|
|
|
Cash equivalents
(1)
|
$
|
131
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
131
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
746
|
|
|
—
|
|
|
—
|
|
|
746
|
|
Commodity forward contracts
(2)
|
—
|
|
|
327
|
|
|
265
|
|
|
592
|
|
Interest rate hedging instruments
|
—
|
|
|
29
|
|
|
—
|
|
|
29
|
|
Effect of netting and allocation of collateral
(3)(4)
|
(746
|
)
|
|
(206
|
)
|
|
(23
|
)
|
|
(975
|
)
|
Total assets
|
$
|
131
|
|
|
$
|
150
|
|
|
$
|
242
|
|
|
$
|
523
|
|
Liabilities:
|
|
|
|
|
|
|
|
Commodity instruments:
|
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
$
|
790
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
790
|
|
Commodity forward contracts
(2)
|
—
|
|
|
461
|
|
|
68
|
|
|
529
|
|
Interest rate hedging instruments
|
—
|
|
|
34
|
|
|
—
|
|
|
34
|
|
Effect of netting and allocation of collateral
(3)(4)
|
(790
|
)
|
|
(224
|
)
|
|
(23
|
)
|
|
(1,037
|
)
|
Total liabilities
|
$
|
—
|
|
|
$
|
271
|
|
|
$
|
45
|
|
|
$
|
316
|
|
___________
|
|
(1)
|
At
June 30, 2018
and
December 31, 2017
, we had cash equivalents of
$27 million
and
$21 million
included in cash and cash equivalents and
$99 million
and
$110 million
included in restricted cash, respectively.
|
|
|
(2)
|
Includes OTC swaps and options and retail contracts.
|
|
|
(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 7 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
$118 million
,
$22 million
and
$(1) million
, respectively, at
June 30, 2018
. Cash collateral posted with (received from) counterparties allocated to level 1, level 2 and level 3 derivative instruments totaled
$44 million
,
$18 million
and
nil
, respectively, at
December 31, 2017
.
|
At
June 30, 2018
and
December 31, 2017
, 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
June 30, 2018
and
December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantitative Information about Level 3 Fair Value Measurements
|
|
|
|
June 30, 2018
|
|
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
|
|
|
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
Power Contracts
|
|
$
|
89
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
1.42
|
|
—
|
$158.04
|
/MWh
|
Power Congestion Products
|
|
$
|
7
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
(7.52
|
)
|
—
|
$15.57
|
/MWh
|
Natural Gas Contracts
|
|
$
|
7
|
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$
|
1.10
|
|
—
|
$5.82
|
/MMBtu
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
|
Fair Value, Net Asset
|
|
|
|
Significant Unobservable
|
|
|
|
|
|
|
|
(Liability)
|
|
Valuation Technique
|
|
Input
|
|
Range
|
|
|
(in millions)
|
|
|
|
|
|
|
|
|
|
Power Contracts
|
|
$
|
149
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
4.13
|
|
—
|
$119.20
|
/MWh
|
Power Congestion Products
|
|
$
|
11
|
|
|
Discounted cash flow
|
|
Market price (per MWh)
|
|
$
|
(10.54
|
)
|
—
|
$9.13
|
/MWh
|
Natural Gas Contracts
|
|
$
|
34
|
|
|
Discounted cash flow
|
|
Market price (per MMBtu)
|
|
$
|
1.62
|
|
—
|
$13.67
|
/MMBtu
|
The following table sets forth a reconciliation of changes in the fair value of our net derivative assets (liabilities) classified as level 3 in the fair value hierarchy for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Balance, beginning of period
|
|
$
|
129
|
|
|
$
|
350
|
|
|
$
|
197
|
|
|
$
|
416
|
|
Realized and mark-to-market gains (losses):
|
|
|
|
|
|
|
|
|
Included in net income (loss):
|
|
|
|
|
|
|
|
|
Included in operating revenues
(1)
|
|
31
|
|
|
28
|
|
|
(28
|
)
|
|
104
|
|
Included in fuel and purchased energy expense
(2)
|
|
18
|
|
|
(14
|
)
|
|
15
|
|
|
1
|
|
Change in collateral
|
|
1
|
|
|
1
|
|
|
(1
|
)
|
|
(8
|
)
|
Purchases and settlements:
|
|
|
|
|
|
|
|
|
Purchases
|
|
5
|
|
|
3
|
|
|
9
|
|
|
3
|
|
Settlements
|
|
(42
|
)
|
|
(67
|
)
|
|
(53
|
)
|
|
(97
|
)
|
Transfers in and/or out of level 3
(3)
:
|
|
|
|
|
|
|
|
|
Transfers into level 3
(4)
|
|
(1
|
)
|
|
2
|
|
|
(1
|
)
|
|
(3
|
)
|
Transfers out of level 3
(5)
|
|
(10
|
)
|
|
—
|
|
|
(7
|
)
|
|
(113
|
)
|
Balance, end of period
|
|
$
|
131
|
|
|
$
|
303
|
|
|
$
|
131
|
|
|
$
|
303
|
|
Change in unrealized gains (losses) relating to instruments still held at end of period
|
|
$
|
49
|
|
|
$
|
14
|
|
|
$
|
(13
|
)
|
|
$
|
105
|
|
___________
|
|
(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 six months ended
June 30, 2018
and
2017
.
|
|
|
(4)
|
We had
$(1) million
in losses and
$2 million
in gains transferred out of level 2 into level 3 for the three months ended
June 30, 2018
and
2017
, respectively, and
$(1) million
and
$(3) million
in losses transferred out of level 2 into level 3 for the six months ended
June 30, 2018
and
2017
, respectively, due to changes in market liquidity in various power markets.
|
|
|
(5)
|
We had
$10 million
and
nil
in gains transferred out of level 3 into level 2 for the three months ended
June 30, 2018
and
2017
, respectively, and
$7 million
and
$113 million
in gains transferred out of level 3 into level 2 for the six months ended
June 30, 2018
and
2017
, respectively, due to changes in market liquidity in various power markets.
|
|
|
7.
|
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 six months ended
June 30, 2018
and
2017
.
Interest Rate Hedging Instruments
— A portion of our debt is indexed to base rates, primarily LIBOR. We have historically used interest rate hedging instruments to adjust the mix between fixed and variable rate debt to hedge our interest rate risk for potential adverse changes in interest rates. As of
June 30, 2018
, the maximum length of time over which we were hedging using interest rate hedging instruments designated as cash flow hedges was
8
years.
As of
June 30, 2018
and
December 31, 2017
, the net forward notional buy (sell) position of our outstanding commodity derivative instruments that did not qualify or were not designated under the normal purchase normal sale exemption and our interest rate hedging instruments were as follows (in millions):
|
|
|
|
|
|
|
|
|
|
|
Derivative Instruments
|
|
Notional Amounts
|
|
|
June 30, 2018
|
|
December 31, 2017
|
|
Power (MWh)
|
|
(155
|
)
|
|
(119
|
)
|
|
Natural gas (MMBtu)
|
|
997
|
|
|
405
|
|
|
Environmental credits (Tonnes)
|
|
16
|
|
|
12
|
|
|
Interest rate hedging instruments
|
|
$
|
4,600
|
|
|
$
|
4,600
|
|
|
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
June 30, 2018
, was
$393 million
for which we have posted collateral of
$347 million
by posting margin deposits, letters of credit or granting additional first priority liens on the assets currently subject to first priority liens under our First Lien Notes, First Lien Term Loans and Corporate Revolving Facility. However, if our credit rating were downgraded by one notch from its current level, we estimate that additional collateral of
$4 million
related to our derivative liabilities would be required and that no counterparty could request immediate, full settlement.
Accounting for Derivative Instruments
We recognize all derivative instruments that qualify for derivative accounting treatment as either assets or liabilities and measure those instruments at fair value unless they qualify for, and we elect, the normal purchase normal sale exemption. For transactions in which we elect the normal purchase normal sale exemption, gains and losses are not reflected on our Consolidated 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 most of our interest rate hedging instruments. We report the effective portion of 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. Gains and losses due to ineffectiveness on interest rate hedging instruments are recognized currently in earnings as a component of interest expense. If it is determined that the forecasted transaction is no longer probable of occurring, then hedge accounting will be discontinued prospectively and future changes in fair value are recorded in earnings. If the hedging instrument is terminated or de-designated prior to the occurrence of the hedged forecasted transaction, the net accumulated gain or loss associated with the changes in fair value of the hedge instrument remains deferred in AOCI until such time as the forecasted transaction 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
During the third quarter of 2017, we elected to begin offsetting 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
June 30, 2018
and
December 31, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 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
|
|
$
|
456
|
|
|
$
|
(456
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
631
|
|
|
(421
|
)
|
|
210
|
|
Interest rate hedging instruments
|
|
28
|
|
|
—
|
|
|
28
|
|
Total current derivative assets
(2)
|
|
$
|
1,115
|
|
|
$
|
(877
|
)
|
|
$
|
238
|
|
Commodity exchange traded derivatives contracts
|
|
113
|
|
|
(113
|
)
|
|
—
|
|
Commodity forward contracts
|
|
255
|
|
|
(69
|
)
|
|
186
|
|
Interest rate hedging instruments
|
|
48
|
|
|
—
|
|
|
48
|
|
Total long-term derivative assets
(2)
|
|
$
|
416
|
|
|
$
|
(182
|
)
|
|
$
|
234
|
|
Total derivative assets
|
|
$
|
1,531
|
|
|
$
|
(1,059
|
)
|
|
$
|
472
|
|
|
|
|
|
|
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
(514
|
)
|
|
$
|
514
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(649
|
)
|
|
410
|
|
|
(239
|
)
|
Interest rate hedging instruments
|
|
(11
|
)
|
|
—
|
|
|
(11
|
)
|
Total current derivative (liabilities)
(2)
|
|
$
|
(1,174
|
)
|
|
$
|
924
|
|
|
$
|
(250
|
)
|
Commodity exchange traded derivatives contracts
|
|
(173
|
)
|
|
173
|
|
|
—
|
|
Commodity forward contracts
|
|
(284
|
)
|
|
101
|
|
|
(183
|
)
|
Interest rate hedging instruments
|
|
(5
|
)
|
|
—
|
|
|
(5
|
)
|
Total long-term derivative (liabilities)
(2)
|
|
$
|
(462
|
)
|
|
$
|
274
|
|
|
$
|
(188
|
)
|
Total derivative liabilities
|
|
$
|
(1,636
|
)
|
|
$
|
1,198
|
|
|
$
|
(438
|
)
|
Net derivative assets (liabilities)
|
|
$
|
(105
|
)
|
|
$
|
139
|
|
|
$
|
34
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
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
|
|
$
|
672
|
|
|
$
|
(672
|
)
|
|
$
|
—
|
|
Commodity forward contracts
|
|
361
|
|
|
(194
|
)
|
|
167
|
|
Interest rate hedging instruments
|
|
7
|
|
|
—
|
|
|
7
|
|
Total current derivative assets
(3)
|
|
$
|
1,040
|
|
|
$
|
(866
|
)
|
|
$
|
174
|
|
Commodity exchange traded derivatives contracts
|
|
74
|
|
|
(74
|
)
|
|
—
|
|
Commodity forward contracts
|
|
231
|
|
|
(32
|
)
|
|
199
|
|
Interest rate hedging instruments
|
|
22
|
|
|
(3
|
)
|
|
19
|
|
Total long-term derivative assets
(3)
|
|
$
|
327
|
|
|
$
|
(109
|
)
|
|
$
|
218
|
|
Total derivative assets
|
|
$
|
1,367
|
|
|
$
|
(975
|
)
|
|
$
|
392
|
|
|
|
|
|
|
|
|
Derivative (liabilities):
|
|
|
|
|
|
|
Commodity exchange traded derivatives contracts
|
|
$
|
(702
|
)
|
|
$
|
702
|
|
|
$
|
—
|
|
Commodity forward contracts
|
|
(389
|
)
|
|
209
|
|
|
(180
|
)
|
Interest rate hedging instruments
|
|
(17
|
)
|
|
—
|
|
|
(17
|
)
|
Total current derivative (liabilities)
(3)
|
|
$
|
(1,108
|
)
|
|
$
|
911
|
|
|
$
|
(197
|
)
|
Commodity exchange traded derivatives contracts
|
|
(88
|
)
|
|
88
|
|
|
—
|
|
Commodity forward contracts
|
|
(140
|
)
|
|
35
|
|
|
(105
|
)
|
Interest rate hedging instruments
|
|
(17
|
)
|
|
3
|
|
|
(14
|
)
|
Total long-term derivative (liabilities)
(3)
|
|
$
|
(245
|
)
|
|
$
|
126
|
|
|
$
|
(119
|
)
|
Total derivative liabilities
|
|
$
|
(1,353
|
)
|
|
$
|
1,037
|
|
|
$
|
(316
|
)
|
Net derivative assets (liabilities)
|
|
$
|
14
|
|
|
$
|
62
|
|
|
$
|
76
|
|
____________
|
|
(1)
|
At
June 30, 2018
and
December 31, 2017
, we had
$227 million
and
$155 million
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
June 30, 2018
, current and long-term derivative assets are shown net of collateral of
$(49) million
and
$(3) million
, respectively, and current and long-term derivative liabilities are shown net of collateral of
$96 million
and
$95 million
, respectively.
|
|
|
(3)
|
At
December 31, 2017
, current and long-term derivative assets are shown net of collateral of
$(8) million
and
$(2) million
, respectively, and current and long-term derivative liabilities are shown net of collateral of
$52 million
and
$20 million
, respectively.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
|
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
|
$
|
75
|
|
|
$
|
16
|
|
|
$
|
26
|
|
|
$
|
31
|
|
Total derivatives designated as cash flow hedging instruments
|
$
|
75
|
|
|
$
|
16
|
|
|
$
|
26
|
|
|
$
|
31
|
|
|
|
|
|
|
|
|
|
Derivatives not designated as hedging instruments:
|
|
|
|
|
|
|
|
Commodity instruments
|
$
|
396
|
|
|
$
|
422
|
|
|
$
|
366
|
|
|
$
|
285
|
|
Interest rate hedging instruments
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total derivatives not designated as hedging instruments
|
$
|
397
|
|
|
$
|
422
|
|
|
$
|
366
|
|
|
$
|
285
|
|
Total derivatives
|
$
|
472
|
|
|
$
|
438
|
|
|
$
|
392
|
|
|
$
|
316
|
|
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 the effective portion of derivative instruments which qualify for and we have elected cash flow hedge accounting treatment, or on our Consolidated Condensed Statements of Operations as a component of mark-to-market activity within our earnings.
The following tables detail the components of our total activity for both the net realized gain (loss) and the net mark-to-market gain (loss) recognized from our derivative instruments in earnings and where these components were recorded on our Consolidated Condensed Statements of Operations for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Realized gain (loss)
(1)(2)
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
69
|
|
|
$
|
44
|
|
|
$
|
66
|
|
|
$
|
73
|
|
Total realized gain (loss)
|
$
|
69
|
|
|
$
|
44
|
|
|
$
|
66
|
|
|
$
|
73
|
|
|
|
|
|
|
|
|
|
Mark-to-market gain (loss)
(3)
|
|
|
|
|
|
|
|
Commodity derivative instruments
|
$
|
188
|
|
|
$
|
(82
|
)
|
|
$
|
(183
|
)
|
|
$
|
(27
|
)
|
Interest rate hedging instruments
|
1
|
|
|
1
|
|
|
3
|
|
|
1
|
|
Total mark-to-market gain (loss)
|
$
|
189
|
|
|
$
|
(81
|
)
|
|
$
|
(180
|
)
|
|
$
|
(26
|
)
|
Total activity, net
|
$
|
258
|
|
|
$
|
(37
|
)
|
|
$
|
(114
|
)
|
|
$
|
47
|
|
___________
|
|
(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, Calpine Solutions and North American Power.
|
|
|
(3)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and adjustments to reflect changes in credit default risk exposure.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Realized and mark-to-market gain (loss)
(1)
|
|
|
|
|
|
|
|
Derivatives contracts included in operating revenues
(2)(3)
|
$
|
183
|
|
|
$
|
(31
|
)
|
|
$
|
(176
|
)
|
|
$
|
192
|
|
Derivatives contracts included in fuel and purchased energy expense
(2)(3)
|
74
|
|
|
(7
|
)
|
|
59
|
|
|
(146
|
)
|
Interest rate hedging instruments included in interest expense
|
1
|
|
|
1
|
|
|
3
|
|
|
1
|
|
Total activity, net
|
$
|
258
|
|
|
$
|
(37
|
)
|
|
$
|
(114
|
)
|
|
$
|
47
|
|
___________
|
|
(1)
|
In addition to changes in market value on derivatives not designated as hedges, changes in mark-to-market gain (loss) also includes hedge ineffectiveness and 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, Calpine Solutions and North American Power.
|
Derivatives Included in OCI and AOCI
The following table details the effect of our net derivative instruments that qualified for hedge accounting treatment and are included in OCI and AOCI for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Three Months Ended June 30,
|
|
Gain (Loss) Recognized in
OCI (Effective Portion)
|
|
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)
(3)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
Affected Line Item on the Consolidated Condensed Statements of Operations
|
Interest rate hedging instruments
(1)(2)
|
$
|
15
|
|
|
$
|
(15
|
)
|
|
$
|
—
|
|
|
$
|
(11
|
)
|
|
Interest expense
|
Interest rate hedging instruments
(1)(2)
|
—
|
|
|
4
|
|
|
—
|
|
|
(4
|
)
|
|
Depreciation expense
|
Total
|
$
|
15
|
|
|
$
|
(11
|
)
|
|
$
|
—
|
|
|
$
|
(15
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
Gain (Loss) Recognized in
OCI (Effective Portion)
|
|
Gain (Loss) Reclassified from
AOCI into Income (Effective Portion)
(3)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
|
Affected Line Item on the Consolidated Condensed Statements of Operations
|
Interest rate hedging instruments
(1)(2)
|
$
|
69
|
|
|
$
|
(19
|
)
|
|
$
|
(6
|
)
|
|
$
|
(22
|
)
|
|
Interest expense
|
Interest rate hedging instruments
(1)(2)
|
1
|
|
|
4
|
|
|
(1
|
)
|
|
(4
|
)
|
|
Depreciation expense
|
Total
|
$
|
70
|
|
|
$
|
(15
|
)
|
|
$
|
(7
|
)
|
|
$
|
(26
|
)
|
|
|
____________
|
|
(1)
|
We recorded
$1 million
in gains on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during each of the three and six months ended
June 30, 2018
. We did not record any material gain (loss) on hedge ineffectiveness related to our interest rate hedging instruments designated as cash flow hedges during the three and six months ended
June 30, 2017
.
|
|
|
(2)
|
We recorded an income tax benefit of
$7 million
and income tax expense of
$2 million
for the three months ended
June 30, 2018
and
2017
, respectively, and income tax expense of
$4 million
and
$2 million
for the six months ended
June 30, 2018
and
2017
, respectively, in AOCI related to our cash flow hedging activities.
|
|
|
(3)
|
Cumulative cash flow hedge losses attributable to Calpine, net of tax, remaining in AOCI were
$8 million
and
$72 million
at
June 30, 2018
and
December 31, 2017
, respectively. Cumulative cash flow hedge losses attributable to the noncontrolling interest, net of tax, remaining in AOCI were
$4 million
and
$6 million
at
June 30, 2018
and
December 31, 2017
, respectively.
|
We estimate that pre-tax net gains of
$7 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
June 30, 2018
and
December 31, 2017
(in millions):
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
December 31, 2017
|
Margin deposits
(1)
|
$
|
407
|
|
|
$
|
221
|
|
Natural gas and power prepayments
|
32
|
|
|
23
|
|
Total margin deposits and natural gas and power prepayments with our counterparties
(2)
|
$
|
439
|
|
|
$
|
244
|
|
|
|
|
|
Letters of credit issued
|
$
|
1,192
|
|
|
$
|
885
|
|
First priority liens under power and natural gas agreements
|
34
|
|
|
102
|
|
First priority liens under interest rate hedging instruments
|
17
|
|
|
31
|
|
Total letters of credit and first priority liens with our counterparties
|
$
|
1,243
|
|
|
$
|
1,018
|
|
|
|
|
|
Margin deposits posted with us by our counterparties
(1)(3)
|
$
|
41
|
|
|
$
|
4
|
|
Letters of credit posted with us by our counterparties
|
18
|
|
|
30
|
|
Total margin deposits and letters of credit posted with us by our counterparties
|
$
|
59
|
|
|
$
|
34
|
|
___________
|
|
(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 7 for further discussion of our derivative instruments subject to master netting arrangements.
|
|
|
(2)
|
At
June 30, 2018
and
December 31, 2017
,
$177 million
and
$64 million
, respectively, were included in current and long-term derivative assets and liabilities,
$254 million
and
$171 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
June 30, 2018
and
December 31, 2017
,
$38 million
and
$2 million
, respectively, were included in current and long-term derivative assets and liabilities and
$3 million
and
$2 million
, respectively, were included in other current 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.
Tax Cuts and Jobs Act (the “Act”)
On December 22, 2017, the Act was signed into law resulting in significant changes from previous tax law. Some of the more meaningful provisions which will affect us are:
|
|
•
|
a reduction in the U.S. federal corporate tax rate from
35%
to
21%
;
|
|
|
•
|
limitation on the deduction of certain interest expense;
|
|
|
•
|
full expense deduction for certain business capital expenditures;
|
|
|
•
|
limitation on the utilization of NOLs arising after December 31, 2017; and
|
|
|
•
|
a system of taxing foreign-sourced income from multinational corporations.
|
Because of the complexity of the new Global Intangible Low Taxed Income (“GILTI”) rules in the Act, we are continuing to evaluate this provision and its application under U.S. GAAP and have recorded a reasonable estimate of the effect of this
provision of the Act in our Consolidated Condensed Financial Statements. We have not made a policy decision regarding whether to record deferred taxes on GILTI.
In December 2017, the SEC issued Staff Accounting Bulletin No. 118 “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”) which allows a company up to one year to finalize and record the tax effects of the Act. We are currently in the process of finalizing and quantifying the tax effects of the Act, but have recorded provisional amounts based on reasonable estimates for the measurement and accounting of certain effects of the Act in our Consolidated Condensed Financial Statements for the six months ended
June 30, 2018
. Under SAB 118, we will complete the required analyses and accounting during the year ended December 31, 2018.
Comprehensive Income
— In February 2018, the FASB issued Accounting Standards Update 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” The standard allows an entity to reclassify the income tax effects of the Act on items within AOCI to retained earnings and also requires additional disclosures. The standard is effective for fiscal years beginning after December 15, 2018, with early adoption permitted. We do not anticipate a material effect on our financial condition, results of operations or cash flows as a result of adopting this standard.
Income Tax Expense (Benefit)
The table below shows our consolidated income tax expense (benefit) and our effective tax rates for the periods indicated (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30,
|
|
Six Months Ended June 30,
|
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
Income tax expense (benefit)
|
|
$
|
(158
|
)
|
|
$
|
63
|
|
|
$
|
(50
|
)
|
|
$
|
2
|
|
Effective tax rate
|
|
(81
|
)%
|
|
(41
|
)%
|
|
17
|
%
|
|
(1
|
)%
|
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 six months ended
June 30, 2018
and
2017
, our income tax expense (benefit) 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. As a result of the Merger, an increase of approximately
$57 million
in the valuation allowance and a related charge to deferred tax expense was recorded during the six months ended
June 30, 2018
, due to our Canadian NOLs being substantially limited and not available to offset future income.
NOL Carryforwards
— As of December 31, 2017, our NOL carryforwards consisted primarily of federal NOL carryforwards of approximately
$6.6 billion
, which expire between
2024
and
2037
, and NOL carryforwards in
27
states and the District of Columbia totaling approximately
$3.5 billion
, which expire between
2018
and
2037
. Substantially all of the federal and state NOLs are offset with a full valuation allowance. Certain of the state NOL carryforwards may be subject to limitations on their annual usage. As a result of the ownership change, our ability to utilize the NOL carryforwards will be limited. The reduction in our federal NOLs will be offset by an adjustment to the existing valuation allowance for an equal and offsetting amount. Additionally, our state NOLs available to offset future state income could materially decrease which would also be offset by an equal and offsetting adjustment to the existing valuation allowance. Given the offsetting adjustments to the existing valuation allowance, the ownership change is not expected to have a material adverse effect on our Consolidated Condensed Financial Statements.
As of December 31, 2017, we had approximately
$659 million
in foreign NOLs, which expire between
2026
and
2037
, and the associated deferred tax asset of approximately
$165 million
is partially offset by a valuation allowance of
$106 million
. As a result of the Merger, an increase of approximately
$57 million
in the valuation allowance and a related charge to deferred tax expense occurred, which resulted in our Canadian NOLs being substantially limited and not available to offset future income.
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 have concluded our U.S. federal income tax examination for the year ended December 31, 2015 with no adjustments. We are currently under various state income tax audits for various periods. Our Canadian subsidiaries are currently under examination by the Canada Revenue Agency for the years ended December 31, 2013 through 2016.
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.
Unrecognized Tax Benefits
— At
June 30, 2018
, we had unrecognized tax benefits of
$34 million
. If recognized,
$14 million
of our unrecognized tax benefits could affect the annual effective tax rate and
$20 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
$2 million
for income tax matters at
June 30, 2018
. We recognize interest and penalties related to unrecognized tax benefits in income tax expense (benefit) on our Consolidated Condensed Statements of Operations. We believe that it is reasonably possible that a decrease within the range of
nil
and
$9 million
in unrecognized tax benefits could occur within the next twelve months primarily related to federal tax issues.
|
|
10.
|
Stock-Based Compensation
|
Calpine Equity Incentive Plans
Prior to the effective date of the Merger on March 8, 2018, the Calpine Equity Incentive Plans provided for the issuance of equity awards to all non-union employees as well as the non-employee members of our Board of Directors. As a result of the Merger, the outstanding share-awards were treated as follows during the first quarter of
2018
:
|
|
•
|
all restricted stock and restricted stock units were vested and canceled and the holders received a cash payment equal to a share price of
$15.25
per share less any applicable withholding taxes;
|
|
|
•
|
all vested and unvested stock options were vested (in the case of unvested stock options) and canceled and the holders of the stock options received a cash payment equal to the intrinsic value based on a share price of
$15.25
per share less any applicable withholding taxes; and
|
|
|
•
|
all Performance Share Units (“PSUs”), including the PSUs awarded in 2015 for the measurement period of January 1, 2015 through December 31, 2017, were vested and canceled in exchange for a cash payment with the payout value based on the greater of target value or actual performance over the truncated period using a share price of
$15.25
per share less any applicable withholding taxes.
|
The amount of cash transferred to repurchase the share-based awards associated with our equity classified share-based awards totaled
$79 million
and was recorded to additional paid-in capital on our Consolidated Condensed Balance Sheet during the six months ended
June 30, 2018
. The amount of unrecognized compensation related to our equity classified share-based awards that we recognized in connection with the shortened service period associated with the completion of the Merger was
$35 million
for the six months ended
June 30, 2018
, which did not include any incremental compensation cost as the amount paid did not exceed the fair value of the equity classified share-based awards at the effective time of the Merger. The total stock-based compensation expense for our equity classified share-based awards was
nil
and
$9 million
for the three months ended
June 30, 2018
and
2017
, respectively, and
$41 million
and
$17 million
for the six months ended
June 30, 2018
and
2017
, respectively.
The amount of cash transferred to repurchase the share-based awards associated with our liability classified share-based awards totaled
$25 million
and was recorded to the associated liability in other long-term liabilities on our Consolidated Condensed Balance Sheet during the six months ended
June 30, 2018
. The amount of unrecognized compensation related to our liability classified share-based awards that we recognized in connection with the shortened implied service period associated with the completion of the Merger was
$16 million
for the six months ended
June 30, 2018
. The total stock-based compensation expense for our liability classified share-based awards was
nil
and
$3 million
for the three months ended
June 30, 2018
and
2017
, respectively, and
$16 million
and
$3 million
for the six months ended
June 30, 2018
and
2017
, respectively.
The total intrinsic value of our employee stock options exercised was
nil
for each of the three months ended
June 30, 2018
and
2017
and
$11 million
and
nil
for the six months ended
June 30, 2018
and
2017
, respectively. We did not receive any material cash proceeds from the exercise of our employee stock options for the three and six months ended
June 30, 2018
and
2017
, respectively.
The total fair value of our restricted stock and restricted stock units that vested during the six months ended
June 30, 2018
and
2017
was approximately $
88 million
and $
19 million
, respectively.
|
|
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 an adverse effect on our financial condition, results of operations or cash flows.
Former Stockholder Appraisal Rights —
After the Merger, we received demands for appraisal pursuant to Section 262 of the Delaware General Corporate Law from certain dissenting stockholders. In May and July 2018, we entered into settlement agreements which resolved the appraisal claims with the stockholders that demanded a statutory right to appraisal of their shares. In July 2018, one such dissenting stockholder filed a petition for appraisal in the Delaware Chancery Court, captioned
Marble Holdings LLC v. Calpine Corporation
, C.A. No. 2018-0492. The case was subsequently dismissed pursuant to settlement. As a result of the settlement agreements, we recorded a charge of approximately
$52 million
to other (income) expense, net on our Consolidated Condensed Statement of Operation during the three months ended
June 30, 2018
.
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
June 30, 2018
, 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 2017 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 (see Note 2 for a description of the Merger):
Calpine Receivables —
Under the Accounts Receivable Sales Program, at
June 30, 2018
and
December 31, 2017
, we had
$228 million
and
$196 million
, respectively, in trade accounts receivable outstanding that were sold to Calpine Receivables and
$46 million
and
$26 million
, respectively, in notes receivable from Calpine Receivables which were recorded on our Consolidated Condensed Balance Sheets. During the six months ended
June 30, 2018
and
2017
, we sold an aggregate of
$1.1 billion
and
$1.1 billion
, respectively, in trade accounts receivable and recorded
$1.1 billion
and
$1.1 billion
, respectively, in proceeds. For a further discussion of the Accounts Receivable Sales Program and Calpine Receivables, see Notes 3 and 6 in our
2017
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 which closed on March 8, 2018, 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
$19 million
and
$38 million
in Commodity revenue during the three and six months ended
June 30, 2018
, respectively, and
$4 million
and
$6 million
in Commodity expense during the three and six months ended
June 30, 2018
, respectively, associated with Lyondell. At
June 30, 2018
, the related party receivable and payable associated with Lyondell were immaterial.
Other —
Following the Merger, we have identified other related party contracts for the sale of power, capacity 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. The terms of most of these contracts were negotiated prior to the Merger. As of
June 30, 2018
, the related party receivables and payables associated with these transactions were immaterial.
At June 30, 2018, we have a payable totaling
$11 million
due to CPN Management, LP, our direct parent which holds 100% of our common stock, associated with a payment for a legal settlement made by CPN Management, LP on our behalf in May 2018. In July 2018, we repaid the related party payable.
We assess our wholesale business on a regional basis due to the effect on our financial performance of the differing characteristics of these regions, particularly with respect to competition, regulation and other factors affecting supply and demand. During the first quarter of 2018, we altered the composition of our segments to report the results associated with our retail business as a separate segment. This change reflects the manner in which our segment information is presented internally to our chief operating decision maker associated with the strategic utilization of our retail business subsequent to the consummation of the Merger. Thus, beginning in the first quarter of 2018, 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. The tables below have been updated to present our segments on this revised basis for all periods. 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 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 June 30, 2018
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues
(1)
|
$
|
355
|
|
|
$
|
993
|
|
|
$
|
341
|
|
|
$
|
935
|
|
|
$
|
(365
|
)
|
|
$
|
2,259
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
241
|
|
|
$
|
151
|
|
|
$
|
225
|
|
|
$
|
77
|
|
|
$
|
—
|
|
|
$
|
694
|
|
Add: Mark-to-market commodity activity, net and other
(2)
|
(23
|
)
|
|
301
|
|
|
(7
|
)
|
|
(67
|
)
|
|
(8
|
)
|
|
196
|
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
80
|
|
|
65
|
|
|
65
|
|
|
41
|
|
|
(9
|
)
|
|
242
|
|
Depreciation and amortization expense
|
67
|
|
|
57
|
|
|
49
|
|
|
13
|
|
|
—
|
|
|
186
|
|
General and other administrative expense
|
5
|
|
|
13
|
|
|
8
|
|
|
5
|
|
|
—
|
|
|
31
|
|
Other operating expenses
|
8
|
|
|
3
|
|
|
8
|
|
|
—
|
|
|
—
|
|
|
19
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
1
|
|
|
—
|
|
|
(5
|
)
|
Income (loss) from operations
|
58
|
|
|
314
|
|
|
94
|
|
|
(50
|
)
|
|
1
|
|
|
417
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
157
|
|
Other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
62
|
|
Income before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
198
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2017
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues
(1)
|
$
|
352
|
|
|
$
|
548
|
|
|
$
|
457
|
|
|
$
|
910
|
|
|
$
|
(183
|
)
|
|
$
|
2,084
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
214
|
|
|
$
|
136
|
|
|
$
|
190
|
|
|
$
|
107
|
|
|
$
|
—
|
|
|
$
|
647
|
|
Add: Mark-to-market commodity activity, net and other
(2)
|
(26
|
)
|
|
(73
|
)
|
|
7
|
|
|
6
|
|
|
(6
|
)
|
|
(92
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
106
|
|
|
94
|
|
|
73
|
|
|
36
|
|
|
(7
|
)
|
|
302
|
|
Depreciation and amortization expense
|
60
|
|
|
55
|
|
|
49
|
|
|
22
|
|
|
—
|
|
|
186
|
|
General and other administrative expense
|
8
|
|
|
20
|
|
|
8
|
|
|
4
|
|
|
—
|
|
|
40
|
|
Other operating expenses
|
8
|
|
|
3
|
|
|
8
|
|
|
—
|
|
|
1
|
|
|
20
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
Income (loss) from operations
|
6
|
|
|
(109
|
)
|
|
65
|
|
|
51
|
|
|
—
|
|
|
13
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
154
|
|
Debt extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
8
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
(149
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2018
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues
(3)
|
$
|
835
|
|
|
$
|
1,133
|
|
|
$
|
955
|
|
|
$
|
1,873
|
|
|
$
|
(528
|
)
|
|
$
|
4,268
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
426
|
|
|
$
|
317
|
|
|
$
|
409
|
|
|
$
|
154
|
|
|
$
|
—
|
|
|
$
|
1,306
|
|
Add: Mark-to-market commodity activity, net and other
(4)
|
(10
|
)
|
|
(246
|
)
|
|
33
|
|
|
61
|
|
|
(15
|
)
|
|
(177
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
170
|
|
|
145
|
|
|
136
|
|
|
81
|
|
|
(15
|
)
|
|
517
|
|
Depreciation and amortization expense
|
134
|
|
|
133
|
|
|
94
|
|
|
26
|
|
|
—
|
|
|
387
|
|
General and other administrative expense
|
21
|
|
|
38
|
|
|
23
|
|
|
9
|
|
|
—
|
|
|
91
|
|
Other operating expenses
|
22
|
|
|
19
|
|
|
15
|
|
|
—
|
|
|
—
|
|
|
56
|
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(12
|
)
|
|
1
|
|
|
—
|
|
|
(11
|
)
|
Income (loss) from operations
|
69
|
|
|
(264
|
)
|
|
186
|
|
|
98
|
|
|
—
|
|
|
89
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
308
|
|
Other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
69
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
(288
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30, 2017
|
|
Wholesale
|
|
|
|
Consolidation
|
|
|
|
West
|
|
Texas
|
|
East
|
|
Retail
|
|
Elimination
|
|
Total
|
Total operating revenues
(3)
|
$
|
871
|
|
|
$
|
1,156
|
|
|
$
|
873
|
|
|
$
|
1,870
|
|
|
$
|
(405
|
)
|
|
$
|
4,365
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Margin
|
$
|
417
|
|
|
$
|
261
|
|
|
$
|
332
|
|
|
$
|
195
|
|
|
$
|
—
|
|
|
$
|
1,205
|
|
Add: Mark-to-market commodity activity, net and other
(4)
|
54
|
|
|
(30
|
)
|
|
21
|
|
|
(92
|
)
|
|
(14
|
)
|
|
(61
|
)
|
Less:
|
|
|
|
|
|
|
|
|
|
|
|
Operating and maintenance expense
|
197
|
|
|
175
|
|
|
154
|
|
|
72
|
|
|
(14
|
)
|
|
584
|
|
Depreciation and amortization expense
|
147
|
|
|
109
|
|
|
97
|
|
|
39
|
|
|
—
|
|
|
392
|
|
General and other administrative expense
|
20
|
|
|
36
|
|
|
15
|
|
|
9
|
|
|
—
|
|
|
80
|
|
Other operating expenses
|
17
|
|
|
6
|
|
|
17
|
|
|
—
|
|
|
—
|
|
|
40
|
|
(Gain) on sale of assets, net
|
—
|
|
|
—
|
|
|
(27
|
)
|
|
—
|
|
|
—
|
|
|
(27
|
)
|
(Income) from unconsolidated subsidiaries
|
—
|
|
|
—
|
|
|
(10
|
)
|
|
—
|
|
|
—
|
|
|
(10
|
)
|
Income (loss) from operations
|
90
|
|
|
(95
|
)
|
|
107
|
|
|
(17
|
)
|
|
—
|
|
|
85
|
|
Interest expense
|
|
|
|
|
|
|
|
|
|
|
313
|
|
Debt extinguishment costs and other (income) expense, net
|
|
|
|
|
|
|
|
|
|
|
34
|
|
Loss before income taxes
|
|
|
|
|
|
|
|
|
|
|
$
|
(262
|
)
|
_________
|
|
(1)
|
Includes intersegment revenues of
$70 million
and
$47 million
in the West,
$276 million
and
$54 million
in Texas,
$18 million
and
$81 million
in the East and
$1 million
and
$1 million
in Retail for the three months ended
June 30, 2018
and
2017
, respectively. Intersegment revenues for sales between wholesale and retail operations are executed to manage supply needs for our retail operations from our wholesale fleet or to facilitate margin collateral netting at Calpine Corporation.
|
|
|
(2)
|
Includes
$(19) million
and
$(24) million
of lease levelization and
$25 million
and
$44 million
of amortization expense for the three months ended
June 30, 2018
and
2017
, respectively.
|
|
|
(3)
|
Includes intersegment revenues of
$184 million
and
$108 million
in the West,
$209 million
and
$126 million
in Texas,
$133 million
and
$169 million
in the East and
$2 million
and
$2 million
in Retail for the six months ended June 30, 2018 and 2017, respectively. Intersegment revenues for sales between wholesale and retail operations are executed to manage supply needs for our retail operations from our wholesale fleet or to facilitate margin collateral netting at Calpine Corporation.
|
|
|
(4)
|
Includes
$(35) million
and
$(46) million
of lease levelization and
$53 million
and
$104 million
of amortization expense for the six months ended June 30, 2018 and 2017, respectively.
|