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1. | BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES |
Description of Business
References in the September 30, 2017 Quarterly Financial Statements to “we,” “our,” “us” and “the Company” are to Vistra Energy and/or its subsidiaries in the Successor period, and to TCEH and/or its subsidiaries in the Predecessor periods, as apparent in the context. See Glossary for defined terms.
On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (collectively, the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court).
On October 3, 2016 (the Effective Date), subsidiaries of TCEH that were Debtors in the Chapter 11 Cases (the TCEH Debtors) and certain EFH Corp. subsidiaries (the Contributed EFH Debtors) completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases (Emergence) as subsidiaries of a newly-formed company, Vistra Energy (our Successor). On the Effective Date, Vistra Energy was spun-off from EFH Corp. in a tax-free transaction to the former first lien creditors of TCEH (Spin-Off). As a result, as of the Effective Date, Vistra Energy is a holding company for subsidiaries principally engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users. TCEH is the Predecessor to Vistra Energy. See Note 2 for further discussion regarding the Chapter 11 Cases.
Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users. Prior to the Effective Date, TCEH was a holding company for subsidiaries principally engaged in the same activities as Vistra Energy.
Subsequent to the Effective Date, Vistra Energy has two reportable segments: our Wholesale Generation segment, consisting largely of Luminant, and our Retail Electricity segment, consisting largely of TXU Energy. Prior to the Effective Date, there were no reportable business segments for our Predecessor. See Note 15 for further information concerning reportable business segments.
Basis of Presentation
As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852). Fresh start reporting included (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring (TCEH, or the Predecessor) from the financial statements of the entity that emerges from restructuring (Vistra Energy, or the Successor), (2) accounting for the effects of the Plan of Reorganization, (3) assigning the reorganization value of the Successor entity by measuring all assets and liabilities of the Successor entity at fair value, and (4) selecting accounting policies for the Successor entity. The financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh start reporting. The reorganization value of Vistra Energy was assigned to its assets and liabilities in conformity with the procedures specified by FASB ASC 805, Business Combinations, and the portion of the reorganization value that was not attributable to identifiable tangible or intangible assets was recognized as goodwill.
The condensed consolidated financial statements of the Predecessor reflect the application of ASC 852 as it applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. As a result, the condensed consolidated financial statements of the Predecessor have been prepared as if TCEH was a going concern and contemplated the realization of assets and liabilities in the normal course of business. During the Chapter 11 Cases, the Debtors operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. Prior to the Effective Date, the Predecessor recorded the effects of the Plan of Reorganization in accordance with ASC 852. SeeReorganization Items in Note 2 for further discussion of these accounting and reporting changes.
Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgment related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Changes in Accounting Standards
In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606), which was further amended through several updates issued by the FASB in 2016 and 2017. The guidance under Topic 606 provides the core principle and key steps in determining the recognition of revenue and expands disclosure requirements related to revenue recognition. We intend to adopt the new standard on January 1, 2018 using the modified retrospective method and expect to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date. In recent periods, we completed an assessment of substantially all of our performance obligations in our contractual relationships and continued to assess the expanded disclosure requirements. We do not anticipate that the adoption of the standard will have a material effect on our results of operations, cash flows or financial condition.
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-02 (ASU 2016-02), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We are currently evaluating the impact of this ASU on our financial statements.
In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between the change in cash and cash equivalents and the amounts presented on the balance sheet. This ASU will be effective for fiscal years beginning after December 15, 2017, and we will adopt the new standard on January 1, 2018. The ASU will modify the presentation of our statement of consolidated cash flows, but will not have a material impact on our statement of consolidated net income and consolidated balance sheet.
In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The ASU provides an updated model for determining if acquired assets and liabilities constitute a business. In a business combination, the acquired assets and liabilities are recognized at fair value and goodwill could be recognized. In an asset acquisition, the assets are allocated value based on relative fair value and no goodwill is recognized. The ASU narrows the definition of a business. We adopted this standard in the first quarter of 2017. ASU 2017-01 did not have a material impact on our financial statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). The ASU provides for the elimination of Step 2 from the goodwill impairment test. If impairment charges are recognized, the amount recorded will be the amount by which the carrying amount exceeds the reporting unit’s fair value with certain limitations. We adopted this standard in the first quarter of 2017. ASU 2017-04 did not have a material impact on our financial statements.
1. BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
Description of Business, Bankruptcy Proceedings and Emergence
References in the 2016 Annual Financial Statements to “we,” “our,” “us” and “the Company” are to Vistra Energy and/or its subsidiaries in the Successor period, and to TCEH and/or its subsidiaries in the Predecessor periods, as apparent in the context. See Glossary for defined terms.
On April 29, 2014 (the Petition Date), EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities (collectively, the Debtors), filed voluntary petitions for relief (the Bankruptcy Filing) under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the District of Delaware (the Bankruptcy Court).
On October 3, 2016 (the Effective Date), subsidiaries of TCEH that were Debtors in the Chapter 11 Cases (the TCEH Debtors) and certain EFH Corp. subsidiaries (the Contributed EFH Debtors) completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases (Emergence) as subsidiaries of a newly-formed company, Vistra Energy (our Successor). On the Effective Date, Vistra Energy was spun-off from EFH Corp. in a tax-free transaction to the former first lien creditors of TCEH (Spin-Off). As a result, as of the Effective Date, Vistra Energy is a holding company for subsidiaries principally engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users. TCEH is the Predecessor to Vistra Energy. See Note 2 for further discussion regarding the Chapter 11 Cases.
Vistra Energy is a holding company operating an integrated power business in Texas. Through our Luminant and TXU Energy subsidiaries, we are engaged in competitive electricity market activities including power generation, wholesale energy sales and purchases, commodity risk management and retail sales of electricity to end users. Prior to the Effective Date, TCEH was a holding company for subsidiaries principally engaged in the same activities as Vistra Energy.
Subsequent to the Effective Date, Vistra Energy has two reportable segments: our Wholesale Generation segment, consisting largely of Luminant, and our Retail Electricity segment, consisting largely of TXU Energy. Prior to the Effective Date, there were no reportable business segments for our Predecessor. See Note 21 for further information concerning reportable business segments.
Basis of Presentation
As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852). Fresh start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring (TCEH, or the Predecessor) from the financial statements of the entity that emerges from restructuring (Vistra Energy, or the Successor), (2) accounting for the effects of the Plan of Reorganization, (3) assigning the reorganized value of the Successor entity by measuring all assets and liabilities of the Successor entity at fair value, and (4) selecting accounting policies for the Successor entity. The financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh start reporting. The reorganization value of Vistra Energy was assigned to its assets and liabilities in conformity with the procedures specified by FASB ASC 805, Business Combinations, and the portion of the reorganization value that was not attributable to identifiable tangible or intangible assets was recognized as goodwill. See Note 3 for further discussion regarding fresh start reporting.
The consolidated financial statements of the Predecessor reflect the application of ASC 852 as it applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. As a result, the consolidated financial statements of the Predecessor have been prepared as if TCEH was a going concern and contemplated the realization of assets and liabilities in the normal course of business. During the Chapter 11 Cases, the Debtors operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. Prior to the Effective Date, the Predecessor recorded the effects of the Plan of Reorganization in accordance with ASC 852. See Notes 4 and 5 for further discussion of these accounting and reporting changes.
The consolidated financial statements have been prepared in accordance with US GAAP. All intercompany transactions and balances have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through March 30, 2017, the date these consolidated financial statements were issued.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgment related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the consolidated balance sheets. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 16 and 17 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the normal purchase and sale exemption. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. At December 31, 2016 and 2015, there were no derivative positions accounted for as cash flow or fair value hedges.
Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the statements of consolidated income (loss) in either operating revenues or fuel, purchased power costs and delivery fees in the Successor period depending on the type of derivative instrument and net gain (loss) from commodity hedging and trading activities in the Predecessor period. Further, realized and unrealized gains and losses associated with interest rate swap transactions are reported in the statements of consolidated income (loss) in interest expense for both the Predecessor and Successor.
Revenue Recognition
We record revenue from electricity sales under the accrual method of accounting. Revenues are recognized when electricity is provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).
In the statements of consolidated income (loss), we report physically delivered commodity sales and related hedging activity in operating revenues and physically delivered purchases and related hedging activity in fuel, purchased power costs and delivery fees for the Successor period, whereas hedging activity was reported as net gain (loss) from commodity hedging and trading activities in the Predecessor period. Volumes under bilateral purchase and sales contracts, including contracts intended as hedges, are not scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, such contracts are reported in operating revenues, for the Successor, and in net gain (loss) from commodity hedging and trading activities, for the Predecessor. If volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record net bilateral activity as wholesale revenues, and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record net bilateral activity as purchased costs in the Successor period. The additional wholesale revenues or purchased power costs were offset in net gain (loss) from commodity hedging and trading activities in the Predecessor period.
Advertising Expense
We expense advertising costs as incurred and include them within selling, general and administrative expenses. Advertising expenses totaled $9 million, $35 million, $44 million and $42 million for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 8 for discussion of impairments of certain long-lived assets recorded by the Predecessor.
Finite-lived intangibles identified as a result of fresh start reporting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 7 for details of intangible assets with indefinite lives, including discussion of fair value determinations.
Goodwill and Intangible Assets with Indefinite Lives
As part of fresh start reporting, reorganization value is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill (see Note 3). We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. As part of fresh start reporting, we have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. The Predecessor’s annual evaluation date was December 1. See Note 7 for details of goodwill, including discussion of fair value determinations and our Predecessor’s goodwill impairments.
Nuclear Fuel
Nuclear fuel is capitalized and reported as a component of our property, plant and equipment in our consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs and delivery fees in our statements of consolidated income (loss).
Major Maintenance Costs
Major maintenance costs incurred by the Successor during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other costs of maintenance activities are charged to expense as incurred and reported as operating costs in our statements of consolidated income (loss). The Predecessor charged major and other maintenance activities to expense as incurred.
Defined Benefit Pension Plans and OPEB Plans
On the Effective Date, EFH Corp. transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy. Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employee from the company and also offer pension benefits to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Effective January 1, 2017, the OPEB plan was amended to discontinue the life insurance benefits for active employees. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates.
Prior to the Effective Date, our Predecessor bore a portion of the costs of the EFH Corp. sponsored pension and OPEB plans and accounted for the arrangement under multiemployer plan accounting.
See Note 18 for additional information regarding pension and OPEB plans.
Stock-Based Compensation
Stock-based compensation is accounted for in accordance with ASC 718, Compensation — Stock Compensation. The fair value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model. Forfeitures are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. See Note 19 for additional information regarding stock-based compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as a “pass through” item on the consolidated balance sheets with no effect on the statements of consolidated income (loss) (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction).
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and gross receipt taxes are not a “pass through” item. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in our statements of consolidated income (loss).
Income Taxes
Subsequent to the Effective Date, Vistra Energy will file a consolidated US federal income tax return. Prior to the Effective Date, EFH Corp. filed a consolidated US federal income tax return that included the results of our Predecessor; however, our Predecessor’s income tax expense and related balance sheet amounts were recorded as if it filed separate corporate income tax returns.
Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. See Note 9.
We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 9.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 14 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. See Notes 13 and 22 for more details regarding restricted cash.
Property, Plant and Equipment
In connection with fresh start reporting, carrying amounts of property, plant and equipment were adjusted to estimated fair values as of the Effective Date (see Note 3). Significant improvements or additions to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 11.
Depreciation of our property, plant and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives. See Note 22.
Asset Retirement Obligations (ARO)
A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases to the liability and related asset as information becomes available. See Note 22.
Inventories
Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (on a weighted average basis) or market. We expect to recover the value of inventory costs in the normal course of business.
Investments
Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 22 for discussion of these and other investments.
Changes in Accounting Standards
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-02 (ASU 2016-02), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We are currently evaluating the impact of this ASU on our financial statements.
In May 2016, the FASB issued Accounting Standards Update 2016-09, Revenue from Contracts with Customers (Topic 606), which was further amended through various updates issued by the FASB thereafter. The guidance under Topic 606 provides the core principle and key steps in determining the recognition of revenue and expands disclosure requirements related to revenue recognition. We intend to adopt the new standard on January 1, 2018 using the modified retrospective method and expect to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. In 2016, we continued to assess the new standard, including the expanded disclosure requirements. We do not anticipate that the adoption of the standard will have a material effect on our results of operations, cash flows or financial condition.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (ASU 2016-13). The ASU provides for a new impairment model which requires measurement and recognition of expected credit losses for most financial assets held. The ASU is effective for public companies for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. We do not anticipate ASU 2016-13 to have a material impact on our financial statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). The ASU provides for the elimination of Step 2 from the goodwill impairment test. If impairment charges are recognized, the amount recorded will be the amount by which the carrying amount exceeds the reporting unit’s fair value with certain limitations. The ASU is effective for public companies for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017 and the adoption should be applied prospectively. We expect to early adopt this standard in 2017. We do not currently anticipate ASU 2017-04 to have a material impact on our financial statements.
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2. | EMERGENCE FROM CHAPTER 11 CASES |
On the Petition Date, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH, but excluding the Oncor Ring-Fenced Entities, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases as subsidiaries of Vistra Energy.
Separation of Vistra Energy from EFH Corp. and its Subsidiaries
Upon the Effective Date, Vistra Energy separated from EFH Corp. pursuant to a tax-free spin-off transaction that was part of a series of transactions that included a taxable component. The taxable portion of the transaction generated a taxable gain that resulted in no regular tax liability due to available net operating loss carryforwards of EFH Corp. The transaction did result in an alternative minimum tax liability of approximately $14 million payable by EFH Corp. to the IRS. Pursuant to the Tax Matters Agreement (defined below), Vistra Energy had an obligation to reimburse EFH Corp. 50% of the estimated alternative minimum tax, and approximately $7 million was reimbursed during the three months ended June 30, 2017. In October 2017, the 2016 federal tax return that included the results of EFCH, EFIH, Oncor Holdings and TCEH was filed with the IRS and resulted in a $3 million payable from EFH Corp. to Vistra Energy. The spin-off transaction resulted in Vistra Energy, including the TCEH Debtors and the Contributed EFH Debtors, no longer being an affiliate of EFH Corp. and its subsidiaries.
Separation Agreement
On the Effective Date, EFH Corp., Vistra Energy and a subsidiary of Vistra Energy entered into a separation agreement that provided for, among other things, the transfer of certain assets and liabilities by EFH Corp., EFCH and TCEH to Vistra Energy. Among other things, EFH Corp., EFCH and/or TCEH, as applicable, (a) transferred the TCEH Debtors and certain contracts and assets (and related liabilities) primarily related to the business of the TCEH Debtors to Vistra Energy, (b) transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy and (c) assigned certain employment agreements from EFH Corp. and certain of the Contributed EFH Debtors to a subsidiary of Vistra Energy.
Tax Matters Agreement
On the Effective Date, Vistra Energy and EFH Corp. entered into a tax matters agreement (the Tax Matters Agreement), which provides for the allocation of certain taxes among the parties and for certain rights and obligations related to, among other things, the filing of tax returns, resolutions of tax audits and preserving the tax-free nature of the spin-off.
Pre-Petition Claims
On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged approximately $33.8 billion in LSTC. Initial distributions related to the allowed claims asserted against the TCEH Debtors and the Contributed EFH Debtors commenced subsequent to the Effective Date. As of September 30, 2017, the TCEH Debtors have approximately $54 million in escrow to (1) distribute to holders of currently contingent and/or disputed unsecured claims that become allowed and/or (2) make further distributions to holders of previously allowed unsecured claims, if applicable. Additionally, the TCEH Debtors have approximately $7 million in escrow to pay remaining professional fees incurred in the Chapter 11 Cases. The remaining contingent and/or disputed claims against the TCEH Debtors consist primarily of unsecured legal claims, including asbestos claims. These remaining claims and the related escrow balance for the claims are recorded in Vistra Energy’s condensed consolidated balance sheet as other current liabilities and current restricted cash, respectively. A small number of other disputed, de minimis claims that are asserted as being entitled to priority and/or against the Contributed EFH Debtors, if allowed, will be paid by Vistra Energy, but all non-priority unsecured claims, including asbestos claims arising before the Petition Date, will be satisfied from the approximately $54 million in escrow.
Predecessor Reorganization Items
Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of consolidated income (loss) as reorganization items as required by ASC 852, Reorganizations. Reorganization items also included adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments were determined. The following table presents reorganization items incurred in the three and nine months ended September 30, 2016 as reported in the condensed statements of consolidated income (loss):
Predecessor | ||||||||
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2016 |
|||||||
Expenses related to legal advisory and representation services |
$ | 28 | $ | 55 | ||||
Expenses related to other professional consulting and advisory services |
19 | 39 | ||||||
Contract claims adjustments |
10 | 13 | ||||||
Other |
7 | 9 | ||||||
|
|
|
|
|||||
Total reorganization items |
$ | 64 | $ | 116 | ||||
|
|
|
|
2. EMERGENCE FROM CHAPTER 11 CASES
On the Petition Date, EFH Corp. and the substantial majority of its direct and indirect subsidiaries, including EFIH, EFCH and TCEH but excluding the Oncor Ring-Fenced Entities, filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. On the Effective Date, the TCEH Debtors and the Contributed EFH Debtors completed their reorganization under the Bankruptcy Code and emerged from the Chapter 11 Cases as subsidiaries of Vistra Energy.
Separation of Vistra Energy from EFH Corp. and its Subsidiaries
Upon the Effective Date, Vistra Energy separated from EFH Corp. pursuant to a tax-free spin-off transaction that was part of a series of transactions that included a taxable component. The taxable portion of the transaction generated a taxable gain that resulted in no regular tax liability due to available net operating loss carryforwards of EFH Corp. The transaction did result in an alternative minimum tax liability of approximately $14 million payable by EFH Corp. to the IRS. Vistra Energy has an obligation to reimburse EFH Corp. 50% of such alternative minimum tax, approximately $7 million, pursuant to the Tax Matters Agreement. The spin-off transaction resulted in Vistra Energy, including the TCEH Debtors and the Contributed EFH Debtors, no longer being an affiliate of EFH Corp. and its subsidiaries. In addition to the Plan of Reorganization, the separation was effectuated, in part, pursuant to the terms of a separation agreement, a transition services agreement and a tax matters agreement.
Separation Agreement
On the Effective Date, EFH Corp., Vistra Energy and a subsidiary of Vistra Energy entered into a separation agreement that provides for, among other things, the transfer of certain assets and liabilities by EFH Corp., EFCH and TCEH to Vistra Energy. Among other things, EFH Corp., EFCH and/or TCEH, as applicable, (a) transferred the TCEH Debtors and certain contracts and assets (and related liabilities) primarily related to the business of the TCEH Debtors to Vistra Energy, (b) transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy and (c) assigned certain employment agreements from EFH Corp. and certain of the Contributed EFH Debtors to a subsidiary of Vistra Energy.
Tax Matters Agreement
On the Effective Date, Vistra Energy and EFH Corp. entered into a tax matters agreement (the Tax Matters Agreement), which provides for the allocation of certain taxes among the parties and for certain rights and obligations related to, among other things, the filing of tax returns, resolutions of tax audits and preserving the tax-free nature of the spin-off. See Note 9 for further information about the Tax Matters Agreement.
Settlement Agreement
The Debtors, the Sponsor Group, certain settling TCEH first lien creditors, certain settling TCEH second lien creditors, certain settling TCEH unsecured creditors and the official committee of unsecured creditors of the TCEH Debtors entered into a settlement agreement (the Settlement Agreement) in August 2015 (as amended in September 2015 and approved by the Bankruptcy Court in December 2015) to settle, among other things, (a) intercompany claims among the Debtors, (b) claims and causes of actions against holders of first lien claims against TCEH and the agents under the TCEH Senior Secured Facilities, (c) claims and causes of action against holders of interests in EFH Corp. and certain related entities and (d) claims and causes of action against each of the Debtors’ current and former directors, the Sponsor Group, managers and officers and other related entities.
Tax Matters
In July 2016, EFH Corp. received a private letter ruling from the IRS in connection with our emergence from bankruptcy, which provides, among other things, for certain rulings regarding the qualification of (a) the transfer of certain assets and ordinary course operating liabilities to Vistra Energy and (b) the distribution of the equity of Vistra Energy, the cash proceeds from Vistra Energy debt, the cash proceeds from the sale of preferred stock in a newly-formed subsidiary of Vistra Energy, and the right to receive payments under a tax receivables agreement, to holders of TCEH first lien claims, as a reorganization qualifying for tax-free treatment.
Pre-Petition Claims
On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged approximately $33.8 billion in LSTC. Distributions for the settled claims related to the funded debt of the TCEH Debtors commenced subsequent to the Effective Date. With respect to remaining claims related to the TCEH Debtors, as of December 31, 2016, the TCEH Debtors have approximately $54 million in escrow to allocate among and resolve the remaining claims, which consist primarily of remaining trade payable and legal claims, including asbestos claims. The Bankruptcy code allows up to 180 days from the Effective Date to resolve these claims. These remaining claims and the related escrow balance for the claims are recorded in Vistra Energy’s consolidated balance sheet as other current liabilities and restricted cash, respectively.
4. PREDECESSOR REORGANIZATION ITEMS
Expenses and income directly associated with the Chapter 11 Cases are reported separately in the statements of consolidated loss as reorganization items as required by ASC 852, Reorganizations. Reorganization items also included adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments were determined. For the period from January 1, 2016 through October 2, 2016, reorganization items include the gain from extinguishing LSTC and the impacts of fresh start reporting. The following table presents reorganization items as reported in the statements of consolidated loss:
Predecessor | ||||||||||||
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, 2015 |
Post-Petition Period Ended December 31, 2014 |
||||||||||
Gain on reorganization adjustments (Note 3) |
$ | (24,252 | ) | $ | — | $ | — | |||||
Loss from the adoption of fresh start reporting |
2,013 | — | — | |||||||||
Expenses related to legal advisory and representation services |
55 | 141 | 65 | |||||||||
Expenses related to other professional consulting and advisory services |
39 | 69 | 67 | |||||||||
Contract claims adjustments |
13 | 54 | 19 | |||||||||
Noncash adjustment for estimated allowed claims related to debt |
— | 896 | — | |||||||||
Adjustment to affiliate claims pursuant to Settlement Agreement (Note 20) |
— | (635 | ) | — | ||||||||
Gain on settlement of debt held by affiliates (Note 20) |
— | (382 | ) | — | ||||||||
Gain on settlement of interest on debt held by affiliates |
— | (20 | ) | — | ||||||||
Sponsor management agreement settlement (Notes 2 and 20) |
— | (19 | ) | — | ||||||||
Contract assumption adjustments |
— | (14 | ) | — | ||||||||
Fees associated with extension/completion of the DIP Facility |
— | 9 | 92 | |||||||||
Noncash liability adjustment arising from termination of interest rate swaps |
— | — | 277 | |||||||||
Other |
11 | 2 | — | |||||||||
|
|
|
|
|
|
|||||||
Total reorganization items |
$ | (22,121 | ) | $ | 101 | $ | 520 | |||||
|
|
|
|
|
|
|
3. FRESH START REPORTING
As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of ASC 852. In order to apply fresh-start reporting, ASC 852 requires two criteria to be satisfied: (1) that total post-petition liabilities and allowed claims immediately before the date of confirmation of the Plan of Reorganization be in excess of reorganization value and (2) that holders of our Predecessor’s voting shares immediately before confirmation of the Plan receive less than 50% of the voting shares of the emerging entity. Vistra Energy met both criteria. Under ASC 852, application of fresh start reporting is required on the date on which a plan of reorganization is confirmed by a bankruptcy court and all material conditions to the plan of reorganization are satisfied. All material conditions to the Plan of Reorganization were satisfied on the Effective Date, including the execution of the Spin-Off.
Reorganization Value
A third-party valuation specialist submitted a report to the Bankruptcy Court in July 2016 assuming an emergence from bankruptcy as of December 31, 2016. This report provided an estimated value range for the total Vistra Energy enterprise. Management selected an enterprise value within that range of $10.5 billion. The enterprise value submitted by the valuation specialist was based upon:
• | historical financial information of our Predecessor for recent years and interim periods; |
• | certain internal financial and operating data of our Predecessor; |
• | certain financial, tax and operational forecasts of Vistra Energy; |
• | certain publicly available financial data for comparable companies to the operating business of Vistra Energy; |
• | the Plan of Reorganization and related documents; |
• | certain economic and industry information relevant to the operating business, and |
• | other studies, analyses and inquiries. |
The valuation analysis for Vistra Energy included (i) a discounted cash flow calculation and (ii) peer group company analysis. Equal weighting was assigned to the two methodologies, before adding the value of the tax basis step-up resulting from certain transactions pursuant to the Plan of Reorganization, which was valued separately. The estimated future cash flows included annual forecasts through 2021. A terminal value was included in the discounted cash flow calculation using an exit multiple approach based on the cash flows of the final year of the forecast period.
The valuation analysis used a discount rate of approximately 7%. The determination of the discount rate takes into consideration the capital structure, credit ratings and current debt yields of comparable publicly traded companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry.
Although the Company believes the assumptions and estimates used by the valuation specialist to develop the enterprise value are reasonable and appropriate, different assumption and estimates could materially impact the analysis and resulting conclusions.
Under ASC 852, reorganization value is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill. Vistra Energy estimates its reorganization value of assets at approximately $15.161 billion as of October 3, 2016, which consists of the following:
Business enterprise value |
$ | 10,500 | ||
Cash excluded from business enterprise value |
1,594 | |||
Deferred asset related to prepaid capital lease obligation |
38 | |||
Current liabilities, excluding short-term portion of debt and capital leases |
1,123 | |||
Noncurrent, non-interest bearing liabilities |
1,906 | |||
|
|
|||
Vistra Energy reorganization value of assets |
$ | 15,161 | ||
|
|
Consolidated Balance Sheet
The adjustments to TCEH’s October 3, 2016 consolidated balance sheet below include the impacts of the Plan of Reorganization and the adoption of fresh start reporting.
October 3, 2016 | ||||||||||||||||||||||||
TCEH (Predecessor) (1) |
Reorganization Adjustments (2) |
Fresh Start Adjustments |
Vistra Energy (Successor) |
|||||||||||||||||||||
ASSETS |
||||||||||||||||||||||||
Current assets: |
||||||||||||||||||||||||
Cash and cash equivalents |
$ | 1,829 | $ | (1,028 | ) | (3) | $ | — | $ | 801 | ||||||||||||||
Restricted cash |
12 | 131 | (4) | — | 143 | |||||||||||||||||||
Trade accounts receivable — net |
750 | 4 | — | 754 | ||||||||||||||||||||
Advances to parents and affiliates of Predecessor |
78 | (78 | ) | — | — | |||||||||||||||||||
Inventories |
374 | — | (86 | ) | (17) | 288 | ||||||||||||||||||
Commodity and other derivative contractual assets |
255 | — | — | 255 | ||||||||||||||||||||
Margin deposits related to commodity contracts |
42 | — | — | 42 | ||||||||||||||||||||
Other current assets |
47 | 17 | 3 | 67 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total current assets |
3,387 | (954 | ) | (83 | ) | 2,350 | ||||||||||||||||||
Restricted cash |
650 | — | — | 650 | ||||||||||||||||||||
Advance to parent and affiliates of Predecessor |
17 | (21 | ) | 4 | — | |||||||||||||||||||
Investments |
1,038 | 1 | 9 | (18) | 1,048 | |||||||||||||||||||
Property, plant and equipment — net |
10,359 | 53 | (5,970 | ) | (19) | 4,442 | ||||||||||||||||||
Goodwill |
152 | — | 1,755 | (27) | 1,907 | |||||||||||||||||||
Identifiable intangible assets — net |
1,148 | 4 | 2,256 | (20) | 3,408 | |||||||||||||||||||
Commodity and other derivative contractual assets |
73 | — | (14 | ) | 59 | |||||||||||||||||||
Deferred income taxes |
— | 320 | (5) | 730 | (21) | 1,050 | ||||||||||||||||||
Other noncurrent assets |
51 | 38 | 158 | (22) | 247 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total assets |
$ | 16,875 | $ | (559 | ) | $ | (1,155 | ) | $ | 15,161 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
LIABILITIES AND EQUITY |
||||||||||||||||||||||||
Current liabilities: |
||||||||||||||||||||||||
Long-term debt due currently |
$ | 4 | $ | 5 | $ | (1 | ) | $ | 8 | |||||||||||||||
Trade accounts payable |
402 | 145 | (6) | 3 | 550 | |||||||||||||||||||
Trade accounts and other payables to affiliates of Predecessor |
152 | (152 | ) | (6) | — | — | ||||||||||||||||||
Commodity and other derivative contractual liabilities |
125 | — | — | 125 | ||||||||||||||||||||
Margin deposits related to commodity contracts |
64 | — | — | 64 | ||||||||||||||||||||
Accrued income taxes |
12 | 12 | — | 24 | ||||||||||||||||||||
Accrued taxes other than income |
119 | 4 | — | 123 | ||||||||||||||||||||
Accrued interest |
110 | (109 | ) | (7) | — | 1 | ||||||||||||||||||
Other current liabilities |
243 | 170 | (8) | 5 | 418 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total current liabilities |
1,231 | 75 | 7 | 1,313 | ||||||||||||||||||||
Long-term debt, less amounts due currently |
— | 3,476 | (9) | 151 | (23) | 3,627 | ||||||||||||||||||
Borrowings under debtor-in-possession credit facilities |
3,387 | (3,387 | ) | (9) | — | — | ||||||||||||||||||
Liabilities subject to compromise |
33,749 | (33,749 | ) | (10) | — | — | ||||||||||||||||||
Commodity and other derivative contractual liabilities |
5 | — | 3 | 8 | ||||||||||||||||||||
Deferred income taxes |
256 | (256 | ) | (11) | — | — | ||||||||||||||||||
Tax Receivable Agreement obligation |
— | 574 | (12) | — | 574 | |||||||||||||||||||
Asset retirement obligations |
809 | — | 854 | (24) | 1,663 | |||||||||||||||||||
Other noncurrent liabilities and deferred credits |
1,018 | 117 | (13) | (900 | ) | (25) | 235 | |||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total liabilities |
40,455 | (33,150 | ) | 115 | 7,420 | |||||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Equity: |
||||||||||||||||||||||||
Common stock |
— | 4 | (14) | — | 4 | |||||||||||||||||||
Additional paid-in-capital |
— | 7,737 | (15) | — | 7,737 | |||||||||||||||||||
Accumulated other comprehensive income (loss) |
(32 | ) | 22 | 10 | (26) | — | ||||||||||||||||||
Predecessor membership interests |
(23,548 | ) | 24,828 | (16) | (1,280 | ) | (26) | — | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total equity |
(23,580 | ) | 32,591 | (1,270 | ) | 7,741 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Total liabilities and equity |
$ | 16,875 | $ | (559 | ) | $ | (1,155 | ) | $ | 15,161 | ||||||||||||||
|
|
|
|
|
|
|
|
(1) | Represents the consolidated balance sheet of TCEH as of October 3, 2016. |
Reorganization adjustments
(2) | Includes the addition of certain assets and liabilities associated with the Contributed EFH Entities. Also includes EFH Corp.‘s contribution of liabilities associated with certain employee benefit plans to Vistra Energy. |
(3) | Net adjustments to cash, which represent distributions made or funding provided to an escrow account, classified as restricted cash, under the Plan of Reorganization, as follows: |
Sources (uses): |
||||
Net proceeds from PrefCo preferred stock sale |
$ | 69 | ||
Addition of cash balances from the Contributed EFH Debtors |
22 | |||
Payments to TCEH first lien creditors, including adequate protection |
(486 | ) | ||
Payment to TCEH unsecured creditors (including $73 million to escrow) |
(502 | ) | ||
Payment of administrative claims to TCEH creditors |
(53 | ) | ||
Payment of legal fees, professional fees and other costs (including $52 million to escrow) |
(78 | ) | ||
|
|
|||
Net use of cash |
$ | (1,028 | ) | |
|
|
(4) | Increase in restricted cash primarily reflects amounts placed in escrow to satisfy certain secured claims, unsecured claims and professional fee obligations associated with the bankruptcy. |
(5) | Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and adjustment of tax-basis for certain assets of PrefCo that issued mandatorily redeemable preferred stock as part of the Spin-Off. |
(6) | Primarily reflects the reclassification of transmission and distribution service payables to Oncor from payables with affiliates to trade payables with third parties pursuant to the separation of Vistra Energy from EFH Corp. and payment of accrued professional fees and unsecured claimant obligations incurred in conjunction with Emergence. |
(7) | Primarily reflects the payment of accrued interest and adequate protection to the TCEH first lien creditors on the Effective Date. |
(8) | Primarily reflects the following: |
• | Reclassification of $82 million from LSTC related to secured and unsecured claims and $16 million in accrued professional fees from accounts payable to other current liabilities. |
• | Additional accruals for $23 million of change-in-control obligations and $26 million in success fees triggered by Emergence, $7 million in professional fees, and $28 million of accrued liabilities related to the Contributed EFH Entities. |
• | Payment of $12 million in professional fees. |
(9) | Reflects the conversion of the TCEH DIP Roll Facilities of $3.387 billion to the Vistra Operations Credit Facilities at Emergence, the issuance and sale of mandatorily redeemable preferred stock of PrefCo for $70 million, and the obligation related to a corporate office space lease contributed to Vistra Energy pursuant to the Plan of Reorganization. See Note 13 for additional details. |
(10) | Reflects the elimination of TCEH’s liabilities subject to compromise pursuant to the Plan of Reorganization (see Note 5). Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization: |
Notes, loans and other debt |
$ | 31,668 | ||
Accrued interest on notes, loans and other debt |
646 | |||
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements |
1,243 | |||
Trade accounts payable and other expected allowed claims |
192 | |||
|
|
|||
Third-party liabilities subject to compromise |
33,749 | |||
LSTC from the Contributed EFH Entities |
8 | |||
|
|
|||
Total liabilities subject to compromise |
33,757 | |||
Fair value of equity issued to TCEH first lien creditors |
(7,741 | ) | ||
TRA Rights issued to TCEH first lien creditors |
(574 | ) | ||
Cash distributed and accruals for TCEH first lien creditors |
(377 | ) | ||
Cash distributed for TCEH unsecured claims |
(502 | ) | ||
Cash distributed and accruals for TCEH administrative claims |
(60 | ) | ||
Settlement of affiliate balances |
(99 | ) | ||
Net liabilities of contributed entities and other items |
(60 | ) | ||
|
|
|||
Gain on extinguishment of LSTC |
$ | 24,344 | ||
|
|
(11) | Reflects the deferred income tax impact of the Plan of Reorganization implementation, including cancellation of debts and adjustment of tax basis of certain assets of PrefCo. |
(12) | Reflects the estimated present value of the TRA obligation. See Note 10 for further discussion of the TRA obligation valuation assumptions. |
(13) | Primarily reflects the following: |
• | Addition of $122 million in liabilities primarily related to benefit plan obligations associated with a pension plan and a health and welfare plan assumed by Vistra Energy pursuant to the Plan of Reorganization. See Note 18 for further discussion of the benefit plan obligations. |
• | Payment of $7 million in settlements related to split life insurance costs with a prior affiliate entity. |
(14) | Reflects the issuance of approximately 427,500,000 shares of Vistra Energy common stock, par value of $0.01 per share, to the TCEH first lien creditors. See Note 15. |
(15) | Reflects adjustments to present Vistra Energy equity value at approximately $7.741 billion based on a reconciliation from the $10.5 billion enterprise value described above under Reorganization Value as depicted below: |
Enterprise value |
$ | 10,500 | ||
Vistra Operations Credit Facility — Initial Term Loan B Facility |
(2,871 | ) | ||
Vistra Operations Credit Facility — Term Loan C Facility |
(655 | ) | ||
Accrual for post-Emergence claims satisfaction |
(181 | ) | ||
Tax Receivable Agreement Obligation |
(574 | ) | ||
Preferred stock of PrefCo |
(70 | ) | ||
Other items |
(2 | ) | ||
Cash and cash equivalents |
801 | |||
Restricted cash |
793 | |||
|
|
|||
Equity value at Emergence |
$ | 7,741 | ||
|
|
|||
Common stock at par value |
$ | 4 | ||
Additional paid-in capital |
7,737 | |||
|
|
|||
Equity value |
$ | 7,741 | ||
Shares outstanding at October 3, 2016 (in millions) |
427.5 | |||
Per share value |
$ | 18.11 |
(16) | Membership Interest impact of Plan of Reorganization are shown below: |
Gain on extinguishment of LSTC |
$ | 24,344 | ||
Elimination of accumulated other comprehensive income |
(22 | ) | ||
Change in Control payments |
(23 | ) | ||
Professional fees |
(33 | ) | ||
Other items |
(14 | ) | ||
|
|
|||
Pretax gain on reorganization adjustments (Note 4) |
24,252 | |||
Deferred tax impact of the Plan of Reorganization and spin-off |
576 | |||
|
|
|||
Total impact to membership interests |
$ | 24,828 | ||
|
|
Fresh start adjustments
(17) | Reflects the reduction of inventory to fair value, including (1) adjustment of fuel inventory to current market prices, and (2) an adjustment to the fair value of materials and supplies inventory primarily used in our lignite/coal fueled generation assets and related mining operations. |
(18) | Reflects the $12 million increase in the fair value of certain real property assets and $3 million reduction of the fair value for other investments. |
(19) | Reflects the change in fair value of property, plant and equipment related primarily to generation and mining assets as detailed below: |
Property, Plant and Equipment |
Adjustment | Fair Value |
||||||
Generation plants and mining assets |
$ | (6,057 | ) | $ | 3,698 | |||
Land |
140 | 490 | ||||||
Nuclear Fuel |
(23 | ) | 157 | |||||
Other equipment |
(30 | ) | 97 | |||||
|
|
|
|
|||||
Total |
$ | (5,970 | ) | $ | 4,442 | |||
|
|
|
|
We engaged a third-party valuation specialist to assist in preparing the values for our property, plant and equipment. For our generation plants and related mining assets, an income approach was utilized in valuing those assets based on discounted cash flow models that forecast the cash flows of the related assets over their respective useful lives. Significant estimates and assumptions utilized in those models include (1) long-term wholesale power price forecasts, (2) fuel cost forecasts, (3) expected generation volumes based on prevailing forecasts and expected maintenance outages, (4) operations and maintenance costs, (5) capital expenditure forecasts and (6) risk adjusted discount rates based on the cash flows produced by the specific generation asset. The fair value of the generation plants and mining assets is based upon Level 3 inputs utilized in the income approach.
The fair value estimates for land and nuclear fuel utilized the market approach, which included utilizing recent comparable sales information and current market conditions for similarly situated land. Nuclear fuel values were determined by utilizing market pricing information for uranium. The fair value of land and nuclear fuel are based upon Level 2 inputs.
(20) | Reflects the adjustment in fair value of $2.256 billion to identifiable intangible assets, including $1.636 billion increase related to retail customer relationships, $270 million increase related to the retail trade name, $190 million increase related to an electricity supply contract, $164 million increase related to retail and wholesale contracts and $4 million decrease related to other intangible assets (see Note 7). |
Also reflects the reduction of fair value of $476 million to identifiable intangible liabilities, including a reduction of $525 million related to an electricity supply contract and an increase of $49 million to wholesale contracts.
(21) | Reflects the deferred income tax impact of fresh-start adjustments to property, plant, and equipment, inventory, intangibles and debt issuance costs. |
(22) | Primarily reflects the following: |
• | Addition of $197 million regulatory asset related to the deficiency of the nuclear decommissioning trust investment as compared to the nuclear generation plant retirement obligation. Pursuant to Texas regulatory provisions, the trust fund for decommissioning our nuclear generation facility is funded by a fee surcharge billed to REPs by Oncor, as a collection agent, and remitted monthly to Vistra Energy. |
• | Adjustment to remove $26 million of unamortized debt issuance costs to reflect the Vistra Operations Credit Facilities at fair market value. |
(23) | Reflects the increase in fair value of the Vistra Operations Credit Facilities in the amount of $151 million based on the quoted market prices of the facilities. |
(24) | Increase in fair value of asset retirement obligation related to the plant retirement, mining and reclamation retirement, and coal combustion residuals. See Note 22 for further discussion of our asset retirement obligations. |
(25) | Reflects the following: |
• | Reduction in fair value of unfavorable contracts related to wholesale contracts and a portion of an electricity supply contract in the amount of $476 million. See footnote (20) above for further detail. |
• | Reduction of $465 million related to reduction in liability that represented excess amounts in the nuclear decommissioning trust above the carrying value of the asset retirement obligation related to our nuclear generation plant decommissioning. |
• | Increase in fair value of obligations related to leased property in the amount of $29 million. |
• | Increase in fair value of Pension and OPEB obligations in the amount of $12 million. |
(26) | Reflects the extinguishment of Predecessor membership interest and accumulated other comprehensive loss per the Plan of Reorganization. |
(27) | Reflects increase in goodwill balance to present final goodwill as the reorganization value in excess of the identifiable tangible assets, intangible assets, and liabilities at Emergence. |
Business enterprise value |
$ | 10,500 | ||
Add: Fair value of liabilities excluded from enterprise value |
3,030 | |||
Less: Fair value of tangible assets |
(8,215 | ) | ||
Less: Fair value of identified intangible assets |
(3,408 | ) | ||
|
|
|||
Vistra Energy goodwill |
$ | 1,907 |
|
5. PREDECESSOR LIABILITIES SUBJECT TO COMPROMISE (LSTC)
On the Effective Date, the TCEH Debtors (together with the Contributed EFH Debtors) emerged from the Chapter 11 Cases and discharged substantially all of the $33.8 billion in LSTC, which includes approximately $8 million of claims from the Contributed EFH Entities (see Note 3).
The amounts classified as LSTC reflected the Predecessor’s estimate of pre-petition liabilities and other expected allowed claims to be addressed in the Chapter 11 Cases. Amounts classified as LSTC did not include pre-petition liabilities that were fully collateralized by letters of credit, cash deposits or other credit enhancements. The following table presents LSTC as reported in the consolidated balance sheet at December 31, 2015:
Predecessor | ||||
December 31, 2015 |
||||
Notes, loans and other debt per the following table |
$ | 31,668 | ||
Accrued interest on notes, loans and other debt |
646 | |||
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 17) |
1,243 | |||
Trade accounts payable, advances and other payables to affiliates and other expected allowed claims |
177 | |||
|
|
|||
Total liabilities subject to compromise |
$ | 33,734 | ||
|
|
Pre-Petition Notes, Loans and Other Debt Reported as LSTC
Amounts presented below represent principal amounts of pre-petition notes, loans and other debt reported as LSTC at December 31, 2015.
Predecessor | ||||
December 31, 2015 |
||||
Senior Secured Facilities |
||||
TCEH Floating Rate Term Loan Facilities due October 10, 2014 |
$ | 3,809 | ||
TCEH Floating Rate Letter of Credit Facility due October 10, 2014 |
42 | |||
TCEH Floating Rate Revolving Credit Facility due October 10, 2016 |
2,054 | |||
TCEH Floating Rate Term Loan Facilities due October 10, 2017 |
15,691 | |||
TCEH Floating Rate Letter of Credit Facility due October 10, 2017 |
1,020 | |||
11.5% Fixed Senior Secured Notes due October 1, 2020 |
1,750 | |||
15% Fixed Senior Secured Second Lien Notes due April 1, 2021 |
336 | |||
15% Fixed Senior Secured Second Lien Notes due April 1, 2021, Series B |
1,235 | |||
10.25% Fixed Senior Notes due November 1, 2015 |
1,833 | |||
10.25% Fixed Senior Notes due November 1, 2015, Series B |
1,292 | |||
10.50% /11.25% Senior Toggle Notes due November 1, 2016 |
1,749 | |||
Pollution Control Revenue Bonds |
||||
Brazos River Authority: |
||||
5.40% Fixed Series 1994A due May 1, 2029 |
39 | |||
7.70% Fixed Series 1999A due April 1, 2033 |
111 | |||
7.70% Fixed Series 1999C due March 1, 2032 |
50 | |||
8.25% Fixed Series 2001A due October 1, 2030 |
71 | |||
8.25% Fixed Series 2001D-1 due May 1, 2033 |
171 | |||
6.30% Fixed Series 2003B due July 1, 2032 |
39 | |||
6.75% Fixed Series 2003C due October 1, 2038 |
52 | |||
5.40% Fixed Series 2003D due October 1, 2029 |
31 | |||
5.00% Fixed Series 2006 due March 1, 2041 |
100 | |||
Sabine River Authority of Texas: |
||||
6.45% Fixed Series 2000A due June 1, 2021 |
51 | |||
5.20% Fixed Series 2001C due May 1, 2028 |
70 | |||
5.80% Fixed Series 2003A due July 1, 2022 |
12 | |||
6.15% Fixed Series 2003B due August 1, 2022 |
45 | |||
Trinity River Authority of Texas: |
||||
6.25% Fixed Series 2000A due May 1, 2028 |
14 | |||
Other |
1 | |||
|
|
|||
Total TCEH consolidated notes, loans and other debt |
$ | 31,668 | ||
|
|
TCEH Letter of Credit Facility Activity
Borrowings under the TCEH Letter of Credit Facility had been recorded by TCEH as restricted cash that supported issuances of letters of credit. At December 31, 2015, the restricted cash related to the pre-petition TCEH Letter of Credit Facility totaled $507 million, and there were no outstanding letters of credit related to the pre-petition TCEH Letter of Credit Facility. Pursuant to the confirmation of the Plan of Reorganization in August 2016 with respect to the TCEH Debtors and the Contributed EFH Debtors, the restricted cash was released to TCEH and reclassified to cash and cash equivalents.
|
3. | ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES |
Odessa Acquisition (Successor)
In August 2017, La Frontera Holdings, LLC (La Frontera), an indirect wholly owned subsidiary of Vistra Energy, purchased a 1,054 MW CCGT natural gas fueled generation plant (and other related assets and liabilities) located in Odessa, Texas (Odessa Facility) from Odessa-Ector Power Partners, L.P., an indirect wholly owned subsidiary of Koch Ag & Energy Solutions, LLC (Koch) (altogether, the Odessa Acquisition). La Frontera paid an aggregate purchase price of approximately $355 million, plus a five-year earn-out provision, to acquire the Odessa Facility. The purchase price was funded by cash on hand.
The Odessa Acquisition was accounted for as an asset acquisition. Substantially all of the cash paid of approximately $355 million was assigned to property, plant and equipment in our consolidated balance sheet. Additionally, the initial fair value associated with an earn-out provision of approximately $16 million was included as consideration in the overall purchase price. The earn-out provision requires cash payments to be made to Koch if spark-spreads related to the pricing point of the Odessa Facility exceed certain thresholds. Subsequent to the acquisition, the earn-out provision has been accounted for as a derivative in our consolidated financial statements.
Upton Solar Development (Successor)
In May 2017, we acquired the rights to develop, construct and operate a utility scale solar photovoltaic power generation facility in Upton County, Texas (Upton). As part of this project, we entered a turnkey engineering, procurement and construction agreement to construct the approximately 180 MW facility. For the nine months ended September 30, 2017, we have spent approximately $129 million related to this project primarily for progress payments under the engineering, procurement and construction agreement and the acquisition of the development rights. We currently estimate that the facility will begin operations in the summer of 2018.
Lamar and Forney Acquisition (Predecessor)
In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC (La Frontera), the indirect owner of two combined-cycle gas turbine (CCGT) natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from a subsidiary of NextEra Energy, Inc. (the Lamar and Forney Acquisition). The aggregate purchase price was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera at closing, plus approximately $236 million for cash and net working capital.
The Lamar and Forney Acquisition was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date.
See Note 6 to the audited financial statements contained in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017 for a summary of the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed. The Lamar and Forney Acquisition did not result in the recording of goodwill since the purchase price did not exceed the fair value of the net assets acquired.
Unaudited Pro Forma Financial Information — The following unaudited pro forma financial information for the nine months ended September 30, 2016 assumes that the Lamar and Forney Acquisition occurred on January 1, 2016. The unaudited pro forma financial information is provided for information purposes only and isnot necessarily indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January 1, 2016, nor is the unaudited pro forma financial information indicative of future results of operations.
Predecessor | ||||
Nine Months Ended September 30, 2016 |
||||
Revenues |
$ | 4,116 | ||
Net loss |
$ | (672 | ) |
The unaudited pro forma financial information includes adjustments for incremental depreciation as a result of the fair value determination of the net assets acquired and interest expense on borrowings under our Predecessor’s DIP Roll Facilities in lieu of interest expense incurred prior to the acquisition.
6. LAMAR AND FORNEY ACQUISITION
In April 2016, Luminant purchased all of the membership interests in La Frontera Holdings, LLC (La Frontera), the indirect owner of two combined-cycle gas turbine (CCGT) natural gas fueled generation facilities representing nearly 3,000 MW of capacity located in ERCOT, from a subsidiary of NextEra Energy, Inc. (the Lamar and Forney Acquisition). The facility in Forney, Texas has a capacity of 1,912 MW and the facility in Paris, Texas has a capacity of 1,076 MW. The acquisition diversified our fuel mix and increased the dispatch flexibility in our generation fleet. The aggregate purchase price was approximately $1.313 billion, which included the repayment of approximately $950 million of existing project financing indebtedness of La Frontera at closing, plus approximately $236 million for cash and net working capital. The purchase price was funded by cash-on-hand and additional borrowings under our Predecessor’s DIP Facility totaling $1.1 billion. After completing the acquisition, we repaid approximately $230 million of borrowings under our Predecessor’s DIP Revolving Credit Facility primarily utilizing cash acquired in the transaction. La Frontera and its subsidiaries were subsidiary guarantors under our Predecessor’s DIP Roll Facilities and, on the Effective Date, became subsidiary guarantors under the Vistra Operations Credit Facilities (see Note 13).
Predecessor Purchase Accounting
The Lamar and Forney Acquisition was accounted for in accordance with ASC 805, Business Combinations (ASC 805), with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date.
To fair value the acquired property, plant and equipment, we used a discounted cash flow analysis, classified as Level 3 within the fair value hierarchy levels (see Note 16). This discounted cash flow model was created for each generation facility based on its remaining useful life. The discounted cash flow model included gross margin forecasts for each power generation facility determined using forward commodity market prices obtained from long-term forecasts. We also used management’s forecasts of generation output, operations and maintenance expense, SG&A and capital expenditures. The resulting cash flows, estimated based upon the age of the assets, efficiency, location and useful life, were then discounted using plant specific discount rates of approximately 9%.
The following table summarizes the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.
Cash paid to seller at close |
$ | 603 | ||
Net working capital adjustments |
(4 | ) | ||
|
|
|||
Consideration paid to seller |
599 | |||
Cash paid to repay project financing at close |
950 | |||
|
|
|||
Total cash paid related to acquisition |
$ | 1,549 | ||
|
|
|||
Cash and cash equivalents |
$ | 210 | ||
Property, plant and equipment — net |
1,316 | |||
Commodity and other derivative contractual assets |
47 | |||
Other assets |
44 | |||
|
|
|||
Total assets acquired |
1,617 | |||
|
|
|||
Commodity and other derivative contractual liabilities |
53 | |||
Trade accounts payable and other liabilities |
15 | |||
|
|
|||
Total liabilities assumed |
68 | |||
|
|
|||
Identifiable net assets acquired |
$ | 1,549 | ||
|
|
The Lamar and Forney Acquisition did not result in the recording of goodwill since the purchase price did not exceed the fair value of the net assets acquired.
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial information for the Predecessor periods indicated assumes that the Lamar and Forney Acquisition occurred on January 1, 2015. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January 1, 2015, nor are they indicative of future results of operations.
Predecessor | ||||||||
Period from January 1, 2016 through October 2, 2016 |
December 31, 2015 |
|||||||
Revenues |
$ | 4,116 | $ | 6,133 | ||||
Net income (loss) |
$ | 22,835 | $ | (4,671 | ) |
The unaudited pro forma financial information includes adjustments for incremental depreciation as a result of the fair value determination of the net assets acquired and interest expense on borrowings under our Predecessor’s DIP Roll Facilities in lieu of interest expense incurred prior to the acquisition.
|
4. | GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS |
Goodwill
The carrying value of goodwill totaled $1.907 billion at both September 30, 2017 and December 31, 2016. The goodwill arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to the Retail Electricity segment (see Note 1). Of the goodwill recorded at Emergence, $1.686 billion is deductible for tax purposes over 15 years on a straight-line basis.
Identifiable Intangible Assets
Identifiable intangible assets, including the impact of fresh start reporting (see Note 1), are comprised of the following:
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||
Identifiable Intangible Asset |
Gross Carrying Amount |
Accumulated Amortization |
Net | Gross Carrying Amount |
Accumulated Amortization |
Net | ||||||||||||||||||
Retail customer relationship |
$ | 1,648 | $ | 467 | $ | 1,181 | $ | 1,648 | $ | 152 | $ | 1,496 | ||||||||||||
Software and other technology-related assets |
178 | 36 | 142 | 147 | 9 | 138 | ||||||||||||||||||
Electricity supply contract (a) |
190 | 9 | 181 | 190 | 2 | 188 | ||||||||||||||||||
Retail and wholesale contracts |
164 | 72 | 92 | 164 | 38 | 126 | ||||||||||||||||||
Other identifiable intangible assets (b) |
33 | 9 | 24 | 30 | 2 | 28 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total identifiable intangible assets subject to amortization |
$ | 2,213 | $ | 593 | 1,620 | $ | 2,179 | $ | 203 | 1,976 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Retail trade names (not subject to amortization) |
1,225 | 1,225 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) |
4 | 4 | ||||||||||||||||||||||
|
|
|
|
|||||||||||||||||||||
Total identifiable intangible assets |
$ | 2,849 | $ | 3,205 | ||||||||||||||||||||
|
|
|
|
(a) | Contract terminated in October 2017. See Note 17. |
(b) | Includes mining development costs and environmental allowances and credits. |
Amortization expense related to finite-lived identifiable intangible assets (including the classification in the condensed statements of consolidated income (loss)) consisted of:
Successor | Predecessor | Successor | Predecessor | |||||||||||||||
Identifiable Intangible Asset |
Condensed Statements of |
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Retail customer relationship |
Depreciation and amortization |
$ | 105 | $ | 3 | $ | 315 | $ | 9 | |||||||||
Software and other technology-related assets |
Depreciation and amortization |
10 | 15 | 27 | 44 | |||||||||||||
Electricity supply contract |
Operating revenues |
2 | — | 7 | — | |||||||||||||
Retail and wholesale contracts |
Operating revenues/fuel, purchased power costs and delivery fees |
(17 | ) | — | 34 | — | ||||||||||||
Other identifiable intangible assets |
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization |
3 | 3 | 7 | 6 | |||||||||||||
|
|
|
|
|
|
|
|
|||||||||||
Total amortization expense (a) |
$ | 103 | $ | 21 | $ | 390 | $ | 59 | ||||||||||
|
|
|
|
|
|
|
|
(a) | Amounts recorded in depreciation and amortization totaled $116 million and $20 million for the three months ended September 30, 2017 and 2016, respectively, and $347 million and $58 million for the nine months ended September 30, 2017 and 2016, respectively. |
Estimated Amortization of Identifiable Intangible Assets
As of September 30, 2017, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.
Year |
Estimated Amortization Expense |
|||
2017 |
$ | 560 | ||
2018 |
$ | 374 | ||
2019 |
$ | 266 | ||
2020 |
$ | 198 | ||
2021 |
$ | 130 |
7. GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS
Goodwill
The following table provides information regarding the carrying value of goodwill. The goodwill of the Successor arose in connection with fresh start reporting that was applied at Emergence and was allocated to the Retail Electric segment (see Note 3). Of the goodwill recorded at Emergence, $1.686 billion is considered purchased goodwill and is deductible for tax purposes over 15 years on a straight-line basis. The goodwill of our Predecessor arose in connection with accounting for the Merger.
Successor | Predecessor | |||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, 2015 |
||||||||||
Balance at beginning of period |
$ | 1,907 | $ | 152 | $ | 2,352 | ||||||
Noncash impairment charges |
— | — | (2,200 | ) | ||||||||
|
|
|
|
|
|
|||||||
Balance at end of period (a) |
$ | 1,907 | $ | 152 | $ | 152 | ||||||
|
|
|
|
|
|
(a) | At December 31, 2016, all goodwill related to the Retail Electricity segment. Predecessor periods are net of accumulated impairment charges totaling $18.170 billion. |
Predecessor Goodwill Impairments
Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist.
During the fourth quarter of 2015, our Predecessor performed a goodwill impairment analysis as of its annual testing date of December 1. Further, during the fourth quarter of 2015, there were significant declines in the market values of several similarly situated peer companies with publicly traded equity, which indicated our Predecessor’s overall enterprise value should be reassessed. Our Predecessor’s testing resulted in an impairment of goodwill of $800 million at December 1, 2015.
During the first nine months of 2015, our Predecessor experienced impairment indicators related to decreases in forward wholesale electricity prices when compared to those prices reflected in its December 1, 2014 goodwill impairment testing analysis. As a result, the likelihood of goodwill impairments had increased, and our Predecessor initiated further testing of goodwill. Our Predecessor’s testing of goodwill for impairment during the first nine months of 2015 resulted in impairment charges totaling $1.4 billion.
Identifiable Intangible Assets
Identifiable intangible assets, including the impact of fresh start reporting (see Note 3), are comprised of the following:
Successor | Predecessor | |||||||||||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||||||||||
Identifiable Intangible Asset |
Gross Carrying Amount |
Accumulated Amortization |
Net | Gross Carrying Amount |
Accumulated Amortization |
Net | ||||||||||||||||||
Retail customer relationship |
$ | 1,648 | $ | 152 | $ | 1,496 | $ | 463 | $ | 442 | $ | 21 | ||||||||||||
Software and other technology-related assets |
147 | 9 | 138 | 385 | 224 | 161 | ||||||||||||||||||
Electricity supply contract |
190 | 2 | 188 | — | — | — | ||||||||||||||||||
Retail and wholesale contracts |
164 | 38 | 126 | — | — | — | ||||||||||||||||||
Other identifiable intangible assets (a) |
30 | 2 | 28 | 72 | 35 | 37 | ||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||
Total identifiable intangible assets subject to amortization (b) |
$ | 2,179 | $ | 203 | 1,976 | $ | 920 | $ | 701 | 219 | ||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||||
Retail trade names (not subject to amortization) |
1,225 | 955 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) |
4 | 5 | ||||||||||||||||||||||
|
|
|
|
|||||||||||||||||||||
Total identifiable intangible assets |
$ | 3,205 | $ | 1,179 | ||||||||||||||||||||
|
|
|
|
(a) | Includes favorable purchase and sales contracts, environmental allowances and credits and mining development costs. See discussion below regarding impairment charges recorded in the year ended December 31, 2015 related to other identifiable intangible assets. |
(b) | Amounts related to fully amortized assets that are expired, or of no economic value, have been excluded from both the gross carrying and accumulated amortization amounts. |
Amortization expense related to finite-lived identifiable intangible assets (including the classification in the statements of consolidated income (loss)) consisted of:
Identifiable Intangible Asset |
Statements of |
Successor | Predecessor | |||||||||||||||||||
Remaining useful lives at December 31, 2016 (weighted average in years) |
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
|||||||||||||||||||
2015 | 2014 | |||||||||||||||||||||
Retail customer relationship | Depreciation and amortization | 4 | $ | 152 | $ | 9 | $ | 17 | $ | 23 | ||||||||||||
Software and other technology-related assets | Depreciation and amortization | 4 | 9 | 44 | 60 | 59 | ||||||||||||||||
Electricity supply contract | Operating revenues | 22 | 2 | — | — | — | ||||||||||||||||
Retail and wholesale contracts | Operating revenues/fuel, purchased power costs and delivery fees | 2 | 38 | — | — | — | ||||||||||||||||
Other identifiable intangible assets | Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization | 5 | 2 | 6 | 30 | 88 | ||||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||||
Total amortization expense (a) | $ | 203 | $ | 59 | $ | 107 | $ | 170 | ||||||||||||||
|
|
|
|
|
|
|
|
(a) | Amounts recorded in depreciation and amortization totaled $162 million, $58 million, $85 million and $116 million for the Successor period from October 3, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. |
Following is a description of the separately identifiable intangible assets. In connection with fresh start reporting (see Note 3), the intangible assets were adjusted based on their estimated fair value as of the Effective Date, based on observable prices or estimates of fair value using valuation models.
• | Retail customer relationship – Retail customer relationship intangible asset represents the fair value of our non-contracted retail customer base, including residential and business customers, and is being amortized using an accelerated method based on historical customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life. |
• | Retail trade names – Our retail trade name intangible asset represents the fair value of the TXU EnergyTM and 4Change EnergyTM trade names, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset is evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other indefinite-lived intangible assets. Significant assumptions included within the development of the fair value estimate include TXU Energy’s and 4Change Energy’s estimated gross margins for future periods and implied royalty rates. |
• | Electricity supply contract – The electricity supply contract represents a long-term fixed-price supply contract for the sale of electricity from one of our generation facilities that was measured at fair value at Emergence. The value of this contract under our Predecessor was recorded as an unfavorable liability due to prevailing market prices of electricity when the contract was established at the Merger. Significant assumptions included in the fair value measurement for this contract include long-term wholesale electricity price forecasts and operating cost forecasts for the respective generation facility. |
• | Retail and wholesale contracts – These intangible assets represent the favorable value of various retail and wholesale contracts (both purchase and sale contracts) that were measured at fair value by utilizing prevailing market prices for commodities or services compared to the fixed prices contained in these agreements. The value of these contracts is being amortized using a method that is based on the monthly value of each contract measured at Emergence. |
Successor Estimated Amortization of Identifiable Intangible Assets
As of December 31, 2016, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.
Year |
Estimated Amortization Expense | |||
2017 |
$ | 523 | ||
2018 |
$ | 365 | ||
2019 |
$ | 267 | ||
2020 |
$ | 191 | ||
2021 |
$ | 143 |
Predecessor Intangible Impairments
The impairments of generation facilities in 2015 (see Note 8) resulted in the impairment of the SO2 allowances under the Clean Air Act’s acid rain cap-and-trade program that are associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO2 allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 16). Our Predecessor also impaired certain of its SO2 allowances under the Cross-State Air Pollution Rule (CSAPR) related to the impaired generation facilities. Accordingly, in the year ended December 31, 2015, our Predecessor recorded noncash impairment charges of $55 million (before deferred income tax benefit) in other deductions (see Note 22) related to its existing environmental allowances and credits intangible asset. SO2 emission allowances granted under the acid rain cap-and-trade program were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in 2007. Additionally, the impairments of generation and related mining facilities in September 2015 resulted in recording noncash impairment charges of $19 million (before deferred income tax benefit) in other deductions (see Note 22) related to mine development costs (included in other identifiable intangible assets in the table above) at the facilities.
During the three months ended March 31, 2015, our Predecessor determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on further declines in wholesale electricity prices in ERCOT experienced during the three months ended March 31, 2015. The fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and renewable energy credit (REC) prices in ERCOT. As a result of the analysis, our Predecessor recorded a noncash impairment charge of $8 million (before deferred income tax benefit) in other deductions (see Note 22).
During the fourth quarter of 2014, our Predecessor determined that certain intangible assets related to favorable power purchase contracts should be evaluated for impairment. That conclusion was based on the combination of (1) the review of contracts for rejection as part of the Chapter 11 Cases, which could result in termination of contracts before the end of their estimated useful life and (2) declines in wholesale electricity prices. The fair value measurement was based on a discounted cash flow analysis of the contracts that compared the contractual price and terms of the contract to forecasted wholesale electricity and REC prices in ERCOT. As a result of the analysis, TCEH recorded a noncash impairment charge of $183 million (before deferred income tax benefit) in other deductions (see Note 22).
As a result of the CSAPR, which became effective on January 1, 2015, and other new or proposed EPA rules, our Predecessor projected that as of December 31, 2014 it had excess SO2 emission allowances under the Clean Air Act’s existing acid rain cap-and-trade program. In addition, the impairments of the Monticello, Martin Lake and Sandow 5 generation facilities (see Note 8) resulted in the impairment of the SO2 allowances associated with those facilities to the extent they are not projected to be used at other sites. The fair market values of the SO2 allowances were estimated to be de minimis based on Level 3 fair value estimates (see Note 16). Accordingly, a noncash impairment charge of $80 million (before deferred income tax benefit) was recorded in other deductions related to its existing environmental allowances and credits intangible asset in 2014. SO2 emission allowances previously granted were recorded as intangible assets at fair value in connection with purchase accounting related to the Merger in 2007.
|
8. PREDECESSOR IMPAIRMENT OF LONG-LIVED ASSETS
Impairment of Lignite/Coal Fueled Generation and Mining Assets
We evaluated our generation assets for impairment during 2015 as a result of impairment indicators related to the continued decline in forecasted wholesale electricity prices in ERCOT. Our evaluations concluded that impairments existed, and the carrying values at our Big Brown, Martin Lake, Monticello, Sandow 4 and Sandow 5 generation facilities and related mining facilities were reduced in total by $2.541 billion.
Our fair value measurement for these assets was determined based on an income approach that utilized probability-weighted estimates of discounted future cash flows, which were Level 3 fair value measurements (see Note 16). Key inputs into the fair value measurement for these assets included current forecasted wholesale electricity prices in ERCOT, forecasted fuel prices, capital and operating expenditure forecasts and discount rates.
|
5. | INCOME TAXES |
Subsequent to the Effective Date, the TCEH Debtors and the Contributed EFH Debtors are no longer included in the consolidated federal income tax return of EFH Corp. and will be included in Vistra Energy’s consolidated federal income tax return.
Prior to the Effective Date, EFH Corp. was the corporate parent of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH was classified as a disregarded entity for US federal income tax purposes. For the 2016 tax year (through the period until the Effective Date) EFH Corp. filed a US federal income tax return in October 2017 that included the results of EFCH, EFIH, Oncor Holdings and TCEH. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group.
Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. Pursuant to the Plan of Reorganization, the TCEH Debtors and the Contributed EFH Debtors rejected this agreement on the Effective Date. See Note 2 for a discussion of the Tax Matters Agreement that was entered into on the Effective Date between EFH Corp. and Vistra Energy. Additionally, since the date of the Settlement Agreement, no further cash payments among the Debtors were made in respect of federal income taxes. The Settlement Agreement did not alter the allocation and payment for state income taxes, which continued to be settled prior to the Effective Date.
The calculation of our effective tax rate is as follows:
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Income (loss) before income taxes |
$ | 524 | $ | 184 | $ | 609 | $ | (653 | ) | |||||||
Income tax (expense) benefit |
$ | (251 | ) | $ | 3 | $ | (284 | ) | $ | (3 | ) | |||||
Effective tax rate |
47.9 | % | (1.6 | )% | 46.6 | % | (0.5 | )% |
Successor — For the three months ended September 30, 2017, the effective tax rate of 47.9% related to our income tax expense was higher than the US Federal statutory rate of 35% due primarily to nondeductible impacts of the TRA and Texas margin tax and a reduction in the tax basis of certain of our assets based on the finalization of tax returns related to the pre-Emergence period. For the nine months ended September 30, 2017, the effective tax rate of 46.6% related to our income tax expense was higher than the US Federal statutory rate of 35% due primarily to nondeductible impacts of the TRA and Texas margin tax and a reduction in the tax basis of certain of our assets based on the finalization of tax returns related to the pre-Emergence period.
Predecessor — For the three months ended September 30, 2016, the effective tax rate of (1.6)% related to our income tax benefit was lower than the US Federal statutory rate of 35% due primarily to a valuation allowance recorded against deferred tax assets in 2016, offset by the tax benefit recognized from the settlement agreement reached with the Texas Comptroller of Public Accounts. For the nine months ended September 30, 2016, the effective tax rate of (0.5)% related to our income tax expense was lower than the US Federal statutory rate of 35% due primarily to a valuation allowance recorded against deferred tax assets and Texas margin tax expense on pretax losses in 2016.
Liability for Uncertain Tax Positions
Successor — Vistra Energy has limited operational history and filed its first federal tax return in October 2017. We currently have no liabilities for uncertain tax positions.
Predecessor — In September 2016, EFH Corp. entered into a settlement agreement with the Texas Comptroller of Public Accounts (Comptroller) whereby the Comptroller agreed to release all claims and liabilities related to the EFH Corp. consolidated group’s state taxes, including sales tax, gross receipts utility tax, franchise tax and direct pay tax, through the agreement date, in exchange for a release of all refund claims and a one-time payment of $12 million. This settlement was entered and approved by the Bankruptcy Court in September 2016. As a result of the settlement, our Predecessor reduced the liability for uncertain tax positions by $27 million.
9. INCOME TAXES
EFH Corp. files a US federal income tax return that includes the results of EFCH, EFIH, Oncor Holdings and, prior to the Effective Date, TCEH. Prior to the Effective Date, EFH Corp. was the corporate parent of the EFH Corp. consolidated group, while each of EFIH, Oncor Holdings, EFCH and TCEH were classified as a disregarded entity for US federal income tax purposes. Pursuant to applicable US Treasury regulations and published guidance of the IRS, corporations that are members of a consolidated group have joint and several liability for the taxes of such group. Subsequent to the Effective Date, the TCEH Debtors and the Contributed EFH Debtors are no longer included in the consolidated federal income tax return of EFH Corp. and will be included in Vistra Energy’s consolidated federal income tax return.
Prior to the Effective Date, EFH Corp. and certain of its subsidiaries (including EFCH, EFIH, and TCEH, but not including Oncor Holdings and Oncor) were parties to a Federal and State Income Tax Allocation Agreement, which provided, among other things, that any corporate member or disregarded entity in the EFH Corp. group is required to make payments to EFH Corp. in an amount calculated to approximate the amount of tax liability such entity would have owed if it filed a separate corporate tax return. Pursuant to the Plan of Reorganization, the TCEH Debtors and the Contributed EFH Debtors rejected this agreement on the Effective Date. See Notes 2 and 10 for a discussion of the Tax Matters Agreement that was entered into on the Effective Date between EFH Corp. and Vistra Energy. Additionally, since the date of the Settlement Agreement, no further cash payments among the Debtors were made in respect of federal income taxes. The Settlement Agreement did not alter the allocation and payment for state income taxes, which continued to be settled prior to the Effective Date.
Income Tax Expense (Benefit)
The components of our income tax expense (benefit) are as follows:
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Current: |
||||||||||||||||
US Federal |
$ | — | $ | (6 | ) | $ | (17 | ) | $ | 30 | ||||||
State |
6 | 9 | 21 | 28 | ||||||||||||
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|
|
|
|
|
|
|
|||||||||
Total current |
6 | 3 | 4 | 58 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Deferred: |
||||||||||||||||
US Federal |
(75 | ) | (1,234 | ) | (811 | ) | (2,361 | ) | ||||||||
State |
(1 | ) | (36 | ) | (72 | ) | (17 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total deferred |
(76 | ) | (1,270 | ) | (883 | ) | (2,378 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | (70 | ) | $ | (1,267 | ) | $ | (879 | ) | $ | (2,320 | ) | ||||
|
|
|
|
|
|
|
|
Reconciliation of income taxes computed at the US federal statutory rate to income tax benefit recorded:
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Income (loss) before income taxes |
$ | (233 | ) | $ | 21,584 | $ | (5,556 | ) | $ | (8,549 | ) | |||||
|
|
|
|
|
|
|
|
|||||||||
Income taxes at the US federal statutory rate of 35% |
(82 | ) | 7,554 | (1,945 | ) | (2,992 | ) | |||||||||
Nondeductible TRA accretion |
5 | — | — | — | ||||||||||||
IRS audit and appeals settlements |
— | — | — | 53 | ||||||||||||
Nondeductible goodwill impairment |
— | — | 770 | 560 | ||||||||||||
Texas margin tax, net of federal benefit |
3 | (21 | ) | — | 10 | |||||||||||
Lignite depletion allowance |
— | — | (8 | ) | (14 | ) | ||||||||||
Interest accrued for uncertain tax positions, net of tax |
— | — | (2 | ) | — | |||||||||||
Nondeductible interest expense |
— | 12 | 21 | 21 | ||||||||||||
Nondeductible debt restructuring costs |
2 | 38 | 64 | 42 | ||||||||||||
Valuation allowance |
— | (210 | ) | 210 | — | |||||||||||
Nontaxable gain on extinguishment of LSTC |
— | (8,593 | ) | — | — | |||||||||||
Other |
2 | (47 | ) | 11 | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income tax benefit |
$ | (70 | ) | $ | (1,267 | ) | $ | (879 | ) | $ | (2,320 | ) | ||||
|
|
|
|
|
|
|
|
|||||||||
Effective tax rate |
30.0 | % | (5.9 | )% | 15.8 | % | 27.1 | % |
Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2016 and 2015 are as follows:
Successor | Predecessor | |||||||
December 31, 2016 | December 31, 2015 | |||||||
Noncurrent Deferred Income Tax Assets |
||||||||
Alternative minimum tax credit carryforwards |
$ | — | $ | 22 | ||||
Net operating loss (NOL) carryforwards |
8 | 440 | ||||||
Unfavorable purchase and sales contracts |
— | 193 | ||||||
Commodity contracts and interest rate swaps |
— | 125 | ||||||
Property, plant and equipment |
943 | — | ||||||
Intangible assets |
29 | — | ||||||
Debt extinguishment gains |
52 | 1,109 | ||||||
Employee benefit obligations |
84 | 51 | ||||||
Other |
6 | 55 | ||||||
|
|
|
|
|||||
Total deferred tax assets |
1,122 | 1,995 | ||||||
|
|
|
|
|||||
Noncurrent Deferred Income Tax Liabilities |
||||||||
Property, plant and equipment |
— | 1,541 | ||||||
Identifiable intangible assets |
— | 320 | ||||||
Accrued interest |
— | 138 | ||||||
|
|
|
|
|||||
Total deferred tax liabilities |
— | 1,999 | ||||||
|
|
|
|
|||||
Valuation allowance |
— | 209 | ||||||
|
|
|
|
|||||
Net Deferred Income Tax (Asset) Liability |
$ | (1,122 | ) | $ | 213 | |||
|
|
|
|
Successor
At December 31, 2016, we had total deferred tax assets of approximately $1.1 billion that was substantially comprised of book and tax basis differences related to our generation and mining property, plant and equipment. As of December 31, 2016, we assessed the need for a valuation allowance related to our deferred tax asset and considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. In connection with that analysis, we concluded that it is more likely than not that the deferred tax assets would be fully utilized by future taxable income, and thus, no valuation allowance was recognized.
At December 31, 2016, we had $21 million in net operating loss (NOL) carryforwards for federal income tax purposes that will expire in 2037. At December 31, 2016, we had no alternative minimum tax (AMT) credit carryforwards available.
The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax liability of $3 million at December 31, 2016.
Predecessor
At December 31, 2015 our Predecessor had $1.257 billion in net operating loss (NOL) carryforwards for federal income tax purposes that will expire between 2035 and 2036. Audit settlements reached in 2013 resulted in the elimination of substantially all NOL carryforwards generated through 2013 and available AMT credits. The NOL carryforwards can be used to offset future taxable income. Our Predecessor believed that it was more likely than not that the full tax benefit from the NOLs would not be realized. In recognition of this risk, our Predecessor recorded a valuation allowance of $209 million on the net deferred tax assets balance at December 31, 2015. In assessing the need for the valuation allowance, our Predecessor considered both positive and negative evidence related to the likelihood of realization of the deferred tax assets. As a result of our Predecessor’s assessment, it was concluded that there was uncertainty as to whether the current deferred tax assets (other than our Predecessor’s indefinite lived deferred tax assets) would be fully utilized by future reversals of existing taxable temporary differences.
During 2015, our Predecessor’s deferred tax liabilities related to property, plant and equipment were significantly reduced due to impairment charges on certain long-lived assets recorded in those periods. See Note 8 for a discussion of impairment charges. Additionally, our deferred tax liabilities related to debt fair value discounts were eliminated due to the write-off of unamortized deferred debt issuance and extension costs, premiums and discounts previously classified as LSTC.
The income tax effects of the components included in accumulated other comprehensive income totaled a net deferred tax asset of $18 million at December 31, 2015.
Liability for Uncertain Tax Positions
Accounting guidance related to uncertain tax positions requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable.
Successor
Vistra Energy and its subsidiaries file income tax returns in US federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities. Vistra Energy is not currently under audit for any period, and we have no uncertain tax positions at December 31, 2016.
Predecessor
EFH Corp. and its subsidiaries file or have filed income tax returns in US Federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of income tax returns filed by EFH Corp. and any of its subsidiaries for the years ending prior to January 1, 2015 are complete. The IRS chose not to audit the tax return filed by EFH Corp. for the 2015 tax year, and the federal income tax return for the 2016 tax year has not yet been filed. Texas franchise and margin tax return examinations have been completed.
In September 2016, EFH Corp. entered into a settlement agreement with the Texas Comptroller of Public Accounts (Comptroller) whereby the Comptroller agreed to release all claims and liabilities related to the EFH Corp. consolidated group’s state taxes, including sales tax, gross receipts utility tax, franchise tax and direct pay tax, through the agreement date, in exchange for a release of all refund claims and a one-time payment of $12 million. This settlement was entered and approved by the Bankruptcy Court in September 2016. As a result of the settlement, our Predecessor reduced the liability for uncertain tax positions by $27 million.
In July 2016, EFH Corp. executed a Revenue Agent Report (RAR) with the IRS for the 2010 through 2013 tax years. As a result of the RAR, our Predecessor reduced the liability for uncertain tax positions by $1 million, resulting in a reclassification to the accumulated deferred income tax liability. Total cash payment to be assessed by the IRS for tax years 2010 through 2013, but not expected to be paid during the pendency of the Chapter 11 Cases of the EFH Debtors, is approximately $15 million, plus any interest that may be assessed.
In March 2016, EFH Corp. signed a RAR with the IRS for the 2014 tax year. No financial statement impacts resulted from the signing of the 2014 RAR.
In June 2015, EFH Corp. signed a RAR with the IRS for the 2008 and 2009 tax years. The Bankruptcy Court approved EFH Corp.’s signing of the RAR in July 2015. As a result of EFH Corp. signing this RAR, our Predecessor reduced the liability for uncertain tax positions by $22 million, resulting in a $18 million increase in noncurrent inter-company tax payable to EFH Corp., a $2 million reclassification to the accumulated deferred income tax liability and the recording of a $2 million income tax benefit. Total cash payment to be assessed by the IRS for tax years 2008 and 2009, but not paid during the pendency of the Chapter 11 Cases of the EFH Debtors, is approximately $15 million, plus any interest that may be assessed.
In 2014, the IRS filed a claim with the Bankruptcy Court for open tax years through 2013 that was consistent with the settlement EFH Corp. reached with IRS Appeals for tax years 2003-2006. Also in 2014, EFH Corp. signed a final RAR with the IRS and associated documentation for the 2007 tax year. As a result of these events, EFH Corp. effectively settled the 2003-2007 open tax years, and our Predecessor reduced the liability for uncertain tax positions related to such years by $123 million, resulting in a $119 million reclassification to the accumulated deferred income tax liability and the recording of a $4 million income tax benefit reflecting the settlement of certain positions.
In recording the 2014 impacts, our Predecessor identified approximately $85 million of income tax expense related to 2013 which was recorded in December 2014. The impact of recording this expense was not material to the financial statements in 2013 or 2014.
Our Predecessor classified interest and penalties related to uncertain tax positions as current income tax expense. Ongoing accruals of interest after the IRS settlements were not material in 2015 and 2014.
Noncurrent liabilities of our Predecessor included a total of $4 million in accrued interest at December 31, 2015. The federal income tax benefit on the interest accrued on uncertain tax positions was recorded as accumulated deferred income taxes.
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheets, during the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively:
Predecessor | ||||||||||||
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
|||||||||||
2015 | 2014 | |||||||||||
Balance at beginning of period, excluding interest and penalties |
$ | 36 | $ | 65 | $ | 184 | ||||||
Additions based on tax positions related to prior years |
— | — | 55 | |||||||||
Reductions based on tax positions related to prior years |
(1 | ) | (11 | ) | (155 | ) | ||||||
Additions based on tax positions related to the current year |
— | — | — | |||||||||
Settlements with taxing authorities |
(35 | ) | (18 | ) | (19 | ) | ||||||
|
|
|
|
|
|
|||||||
Balance at end of period, excluding interest and penalties |
$ | — | $ | 36 | $ | 65 | ||||||
|
|
|
|
|
|
Tax Matters Agreement
On the Effective Date, we entered into a Tax Matters Agreement (the Tax Matters Agreement), with EFH Corp. whereby the parties have agreed to take certain actions and refrain from taking certain actions in order to preserve the intended tax treatment of the Spin-Off and to indemnify the other parties to the extent a breach of such agreement results in additional taxes to the other parties.
Among other things, the Tax Matters Agreement allocates the responsibility for taxes for periods prior to the Spin-Off between EFH Corp. and us. For periods prior to the Spin-Off: (a) Vistra Energy is generally required to reimburse EFH Corp. with respect to any taxes paid by EFH Corp. that are attributable to us and (b) EFH Corp. is generally required to reimburse us with respect to any taxes paid by us that are attributable to EFH Corp.
We are also required to indemnify EFH Corp. against taxes, under certain circumstance, if the IRS or another taxing authority successfully challenges the amount of gain relating to the PrefCo Preferred Stock Sale or the amount or allowance of EFH Corp.’s net operating loss deductions.
Subject to certain exceptions, the Tax Matters Agreement prohibits us from taking certain actions that could reasonably be expected to undermine the intended tax treatment of the Spin-Off or to jeopardize the conclusions of the private letter ruling we obtained from the IRS or opinions of counsel received by us or EFH Corp., in each case, in connection with the Spin-Off. Certain of these restrictions apply for two years after the Spin-Off.
Under the Tax Matters Agreement, we may engage in an otherwise restricted action if (a) we obtain written consent from EFH Corp., (b) such action or transaction is described in or otherwise consistent with the facts in the private letter ruling we obtained from the IRS in connection with the Spin-Off, (c) we obtain a supplemental private letter ruling from the IRS, or (d) we obtain an unqualified opinion of a nationally recognized law or accounting firm that is reasonably acceptable to EFH Corp. that the action will not affect the intended tax treatment of the Spin-Off.
|
6. | TAX RECEIVABLE AGREEMENT OBLIGATION |
On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first lien creditors of TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in US federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including the step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the Lamar and Forney Acquisition in April 2016 (see Note 3) and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of our Predecessor entitled to receive such TRA Rights under the Plan. Such TRA Rights are subject to various transfer restrictions described in the TRA and are entitled to certain registration rights more fully described in the Registration Rights Agreement (see Note 14).
During the three months ended September 30, 2017, we recorded a reduction to the carrying value of the TRA obligation of approximately $160 million. The reduction to the TRA obligation resulted from changes in the estimated timing of TRA payments resulting from changes in certain tax assumptions including (a) the impacts of Luminant’s plan to retire its Monticello generation plant (see Note 17), (b) investment tax credits we expect to receive related to the Upton solar development project, (c) assets acquired in the Odessa Acquisition (see Note 3) and (d) the impacts of other forecasted tax amounts.
As of September 30, 2017, the estimated carrying value of the TRA obligation totaled $500 million, which represents the discounted amount of projected payments under the TRA. The projected payments are based on certain assumptions, including but not limited to (a) the federal corporate income tax rate of 35% and (b) estimates of our taxable income in the current and future years. Our taxable income takes into consideration the current federal tax code and reflects our current estimates of future results of the business. These assumptions are subject to change, and those changes could have a material impact on the carrying value of the TRA obligation. The aggregate amount of undiscounted payments under the TRA is estimated to be approximately $2.2 billion, with approximately half of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (assuming that the TRA is not terminated earlier pursuant to its terms).
The carrying value of the obligation is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of TRA payments are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. During the three and nine months ended September 30, 2017, the Impacts of Tax Receivable Agreement on the condensed statement of consolidated income (loss) totaled $138 million and $96 million, respectively, which represents the reduction to the carrying value of the TRA obligation discussed above net of accretion expense totaling $22 million and $64 million, respectively. The balance at September 30, 2017 and December 31, 2016 totaled $500 million and $596 million, respectively. The balance at September 30, 2017 included $24 million recorded to other current liabilities in the condensed consolidated balance sheet.
Additionally, we expect to record an adjustment to the carrying value of the TRA obligation during the fourth quarter of 2017 as a result of the retirement announcements related to the Sandow 4, Sandow 5 and Big Brown generation units and the impacts of the Alcoa settlement (see Note 17).
10. TAX RECEIVABLE AGREEMENT OBLIGATION
On the Effective Date, Vistra Energy entered into a tax receivable agreement (the TRA) with a transfer agent on behalf of certain former first lien creditors of TCEH. The TRA generally provides for the payment by us to holders of TRA Rights of 85% of the amount of cash savings, if any, in United States federal and state income tax that we realize in periods after Emergence as a result of (a) certain transactions consummated pursuant to the Plan of Reorganization (including any step-up in tax basis in our assets resulting from the PrefCo Preferred Stock Sale), (b) the tax basis of all assets acquired in connection with the Lamar and Forney Acquisition in April 2016 and (c) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA, plus interest accruing from the due date of the applicable tax return.
Pursuant to the TRA, we issued the TRA Rights for the benefit of the first lien secured creditors of our Predecessor entitled to receive such TRA Rights under the Plan. Such TRA Rights are subject to various transfer restrictions described in the TRA and are entitled to certain registration rights more fully described in the Registration Rights Agreement.
The estimate of fair value of $574 million for the Tax Receivable Agreement Obligation on the Effective Date was the discounted amount of projected payments under the TRA, based on certain assumptions, including but not limited to:
• | the amount of tax basis step-up resulting from the PrefCo Preferred Stock Sale, which is expected to be approximately $5.5 billion, and the allocation of such tax basis step-up among the assets subject thereto; |
• | the depreciable lives of the assets subject to such tax basis step-up, which generally is expected to be 15 years for most of such assets; |
• | a federal corporate income tax rate of 35%; |
• | the Company will generally generate sufficient taxable income so as to be able to utilize the deductions arising out of (i) the tax basis step-up attributable to the PrefCo Preferred Stock Sale, (ii) the entire tax basis of the assets acquired as a result of the Lamar and Forney Acquisition (as defined herein), and (iii) tax benefits related to imputed interest deemed to be paid by us as a result of payments under the TRA in the tax year in which such deductions arise, and |
• | a discount rate of 15%, which represents our view of the rate that a market participant would use based on the risk associated with the uncertainty in the amount and timing of the cash flows. The aggregate amount of undiscounted payments under the TRA is estimated to be approximately $2.1 billion, with more than 90% of such amount expected to be attributable to the first 15 tax years following Emergence, and the final payment expected to be made approximately 40 years following Emergence (assuming that the TRA is not terminated earlier pursuant to its terms). |
The fair value of the obligation at the Emergence Date is being accreted to the amount of the gross expected obligation using the effective interest method. Changes in the amount of this obligation resulting from changes to either the timing or amount of cash flows are recognized in the period of change and measured using the discount rate inherent in the initial fair value of the obligation. During the period from October 3, 2016 to December 31, 2016, the Impacts of Tax Receivable Agreement on the statement of consolidated income (loss) was $22 million, which represents accretion expense for the period, and the balance at December 31, 2016 totaled $596 million.
Under the Internal Revenue Code, a corporation’s ability to utilize certain tax attributes, including depreciation, may be limited following an ownership change if the corporation’s overall asset tax basis exceeds the overall fair market value of its assets (after making certain adjustments). The Spin-Off resulted in an ownership change and it is expected that the overall tax basis of our assets may have exceeded the overall fair market value of our assets at such time. As a result, there may be a limitation on our ability to claim a portion of our depreciation deductions for a five-year period. This limitation could have a material impact on our tax liabilities and on our obligations under the TRA Rights. In addition, any future ownership change of Vistra Energy following Emergence could likewise result in additional limitations on our ability to use certain tax attributes existing at the time of any such ownership change and have an impact on our tax liabilities and on our obligations with respect to the TRA Rights under the TRA.
|
7. | INTEREST EXPENSE AND RELATED CHARGES |
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Interest paid/accrued post-Emergence |
$ | 52 | $ | — | $ | 157 | $ | — | ||||||||
Interest paid/accrued on debtor-in-possession financing |
— | 38 | — | 76 | ||||||||||||
Adequate protection amounts paid/accrued |
— | 331 | — | 977 | ||||||||||||
Unrealized mark-to-market net (gains) losses on interest rate swaps |
(3 | ) | — | 3 | — | |||||||||||
Reversal of debt extinguishment gain |
21 | — | — | — | ||||||||||||
Capitalized interest |
(1 | ) | (2 | ) | (5 | ) | (9 | ) | ||||||||
Other |
7 | 4 | 14 | 5 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total interest expense and related charges |
$ | 76 | $ | 371 | $ | 169 | $ | 1,049 | ||||||||
|
|
|
|
|
|
|
|
Successor
During the three and nine months ended September 30, 2017, interest expense and related charges totaled $76 million and $169 million, respectively. The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note 9, was 4.57% and 4.61% for the three and nine months ended September 30, 2017, respectively.
During the three months ended September 30, 2017, we identified and corrected an error that understated interest expense and related charges by $22 million for both the three months ended March 31, 2017 and the six months ended June 30, 2017. In February 2017, certain pricing terms for the Vistra Operations Credit facility were amended. This amendment was accounted for as an extinguishment of debt in the three months ended March 31, 2017. In the current period, we determined that the amendment should have been accounted for as a modification of debt. During the three months ended March 31, 2017, we recognized a noncash debt extinguishment gain totaling $21 million. The amendment should have been recorded as a net charge to interest expense totaling $1 million. Because the error and the correction of the error were not material to the previously issued condensed consolidated financial statements for the three months ended March 31, 2017 and the six months ended June 30, 2017, or to the condensed consolidated financial statements for the three months ended September 30, 2017, we have corrected the error in our condensed consolidated financial statements for the current period.
Predecessor
Interest expense for the three and nine months ended September 30, 2016 reflects interest paid and accrued on debtor-in-possession financing (see Note 9) and adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors in exchange for their consent to the senior secured, super-priority liens contained in the DIP Facility. The interest rate applicable to the adequate protection amounts paid/accrued for the nine months ended September 30, 2016 was 4.95%.
The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. Other than amounts ordered or approved by the Bankruptcy Court, effective on the Petition Date, our Predecessor discontinued recording interest expense on outstanding pre-petition debt classified as LSTC. The table below shows contractual interest amounts, which are amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense reported in our condensed statements of consolidated income (loss) does not include contractual interest on pre-petition debt classified as LSTC totaling $213 million and $640 million for the three and nine months ended September 30, 2016, respectively, which had been stayed by the Bankruptcy Court effective on the Petition Date. Adequate protection amounts paid/accrued presented below excludes interest paid/accrued on TCEH first-lien interest rate and commodity hedge claims totaling $16 million and $47 million for the three and nine months ended September 30, 2016, respectively, as such amounts are not included in contractual interest amounts below.
Predecessor | ||||||||
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2016 |
|||||||
Contractual interest on debt classified as LSTC |
$ | 528 | $ | 1,570 | ||||
Adequate protection amounts paid/accrued |
315 | 930 | ||||||
|
|
|
|
|||||
Contractual interest on debt classified as LSTC not paid/accrued |
$ | 213 | $ | 640 | ||||
|
|
|
|
11. INTEREST EXPENSE AND RELATED CHARGES
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Interest paid/accrued post-Emergence |
$ | 51 | $ | — | $ | — | $ | — | ||||||||
Interest paid/accrued on debtor-in-possession financing |
— | 76 | 63 | 37 | ||||||||||||
Adequate protection amounts paid/accrued |
— | 977 | 1,233 | 828 | ||||||||||||
Interest paid/accrued on pre-petition debt (a) |
— | 1 | 4 | 878 | ||||||||||||
Noncash realized net loss on termination of interest rate swaps (offset in unrealized net gain) (Note 17) |
— | — | — | 1,225 | ||||||||||||
Unrealized mark-to-market net (gain) loss on interest rate swaps |
11 | — | — | (1,290 | ) | |||||||||||
Amortization of debt issuance, amendment and extension costs and premiums/discounts |
(1 | ) | 4 | — | 86 | |||||||||||
Dividends on mandatorily redeemable preferred stock |
2 | — | — | — | ||||||||||||
Capitalized interest |
(3 | ) | (9 | ) | (11 | ) | (17 | ) | ||||||||
Other |
— | — | — | 2 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total interest expense and related charges |
$ | 60 | $ | 1,049 | $ | 1,289 | $ | 1,749 | ||||||||
|
|
|
|
|
|
|
|
(a) | Includes amounts related to interest rate swaps totaling $193 million for the year ended December 31, 2014. Of the $193 million, $127 million is included in the liability arising from the termination of TCEH interest swaps as discussed in Note 17. |
Predecessor
Interest expense for the Predecessor period from January 1, 2016 through October 2, 2016, the year ended December 31, 2015 and the post-petition period ended December 31, 2014 reflects interest paid and accrued on debtor-in-possession financing (see Note 13), adequate protection amounts paid and accrued, as approved by the Bankruptcy Court in June 2014 for the benefit of secured creditors of (a) $22.616 billion principal amount of outstanding borrowings from the TCEH Senior Secured Facilities, (b) $1.750 billion principal amount of outstanding TCEH Senior Secured Notes and (c) the $1.243 billion net liability related to the TCEH first lien interest rate swaps and natural gas hedging positions terminated shortly after the Bankruptcy Filing (see Note 2), in exchange for their consent to the senior secured, super-priority liens contained in the DIP Facility and any diminution in value of their interests in the pre-petition collateral from the Petition Date. The interest rates applicable to the adequate protection amounts paid/accrued was 4.95%, 4.69% and 4.65% (one-month LIBOR plus 4.50%) for the Predecessor period from January 1, 2016 through October 2, 2016, the year ended December 31, 2015 and the post-petition period ended December 31, 2014, respectively. As of the Effective Date, amounts of adequate protection payments were re-characterized as payments of principal.
The Bankruptcy Code generally restricts payment of interest on pre-petition debt, subject to certain exceptions. Other than amounts ordered or approved by the Bankruptcy Court, effective on the Petition Date, our Predecessor discontinued recording interest expense on outstanding pre-petition debt classified as LSTC. The table below shows contractual interest amounts, which were amounts due under the contractual terms of the outstanding debt, including debt subject to compromise during the Chapter 11 Cases. Interest expense reported in the statements of consolidated income (loss) does not include contractual interest on pre-petition debt classified as LSTC totaling $640 million, $897 million and $604 million for the Predecessor period from January 1, 2016 through October 2, 2016, the year ended December 31, 2015 and the post-petition period ended December 31, 2014, respectively, which had been stayed by the Bankruptcy Court effective on the Petition Date. Adequate protection paid/accrued presented below excludes interest paid/accrued on the TCEH first-lien interest rate and commodity hedge claims (see Note 17) totaling $47 million, $60 million and $40 million for the Predecessor period from January 1, 2016 through October 2, 2016, the year ended December 31, 2015 and the post-petition period ended December 31, 2014, respectively, as such amounts are not included in contractual interest amounts below. All adequate protection payments ceased as of the Emergence Date.
Predecessor | ||||||||||||
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, 2015 |
Post-Petition Period Ended December 31, 2014 |
||||||||||
Contractual interest on debt classified as LSTC |
$ | 1,570 | $ | 2,070 | $ | 1,392 | ||||||
Adequate protection amounts paid/accrued |
930 | 1,173 | 788 | |||||||||
|
|
|
|
|
|
|||||||
Contractual interest on debt classified as LSTC not paid/accrued |
$ | 640 | $ | 897 | $ | 604 | ||||||
|
|
|
|
|
|
|
9. | LONG-TERM DEBT |
Successor
Amounts in the table below represent the categories of long-term debt obligations incurred by the Successor.
September 30, 2017 |
December 31, 2016 |
|||||||
Vistra Operations Credit Facilities (a) |
$ | 4,484 | $ | 4,515 | ||||
Mandatorily redeemable subsidiary preferred stock (b) |
70 | 70 | ||||||
8.82% Building Financing due semiannually through February 11, 2022 (c) |
30 | 36 | ||||||
Capital lease obligations |
— | 2 | ||||||
|
|
|
|
|||||
Total long-term debt including amounts due currently |
4,584 | 4,623 | ||||||
Less amounts due currently |
(44 | ) | (46 | ) | ||||
|
|
|
|
|||||
Total long-term debt less amounts due currently |
$ | 4,540 | $ | 4,577 | ||||
|
|
|
|
(a) | At September 30, 2017, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $22 million, debt discounts of $2 million and debt issuance costs of $7 million. At December 31, 2016, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million. |
(b) | Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 2). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance. |
(c) | Obligation related to a corporate office space capital lease contributed to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account and reflected in other noncurrent assets in our condensed consolidated balance sheets. |
Vistra Operations Credit Facilities — The Vistra Operations Credit Facilities consist of up to $5.360 billion in senior secured, first lien financing consisting of a revolving credit facility of up to $860 million, including a $600 million letter of credit sub-facility (Revolving Credit Facility), an initial term loan facility of up to $2.850 billion (Initial Term Loan B Facility), an incremental term loan facility of up to $1.0 billion (Incremental Term Loan B Facility, and together with the Initial Term Loan B Facility, the Term Loan B Facility) and a term loan letter of credit facility of up to $650 million (Term Loan C Facility).
The Vistra Operations Credit Facilities and related available capacity at September 30, 2017 are presented below.
September 30, 2017 | ||||||||||||||||
Vistra Operations Credit Facilities |
Maturity Date | Facility Limit |
Cash Borrowings |
Available Capacity |
||||||||||||
Revolving Credit Facility (a) |
August 4, 2021 | $ | 860 | $ | — | $ | 860 | |||||||||
Initial Term Loan B Facility (b)(c) |
August 4, 2023 | 2,850 | 2,829 | — | ||||||||||||
Incremental Term Loan B Facility (c) |
December 14, 2023 | 1,000 | 992 | — | ||||||||||||
Term Loan C Facility (d) |
August 4, 2023 | 650 | 650 | 170 | ||||||||||||
|
|
|
|
|
|
|||||||||||
Total Vistra Operations Credit Facilities |
$ | 5,360 | $ | 4,471 | $ | 1,030 | ||||||||||
|
|
|
|
|
|
(a) | Facility to be used for general corporate purposes. |
(b) | Facility used to repay all amounts outstanding under our Predecessor’s DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes. |
(c) | Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed. |
(d) | Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our condensed consolidated balance sheets. At September 30, 2017, the restricted cash supported $480 million in letters of credit outstanding (see Note 16), leaving $170 million in available letter of credit capacity. |
In February and August 2017, certain pricing terms for the Vistra Operations Credit Facility were amended. We accounted for both of these transactions as modifications of debt. Amounts borrowed under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus 2.75%, and there were no outstanding borrowings at September 30, 2017. Amounts borrowed under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 2.75%. At September 30, 2017, the weighted average interest rate before taking into consideration interest rate swaps on outstanding borrowings under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility was 3.98%. The Vistra Operations Credit Facilities also provide for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available Vistra Operations Credit Facilities.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Operations’ (and its subsidiaries’) consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities provide for affirmative and negative covenants applicable to Vistra Operations (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change its lines of business, and negative covenants restricting Vistra Operations’ (and its restricted subsidiaries’) ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case except as permitted in the Vistra Operations Credit Facilities. Vistra Operations’ ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.
The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Operations. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not to exceed 4.25 to 1.00. Although we had no borrowings under the Revolving Credit Facility as of September 30, 2017, we would have been in compliance with this financial covenant if it was required to be tested at such date. Upon the existence of an event of default, the Vistra Operations Credit Facilities provide that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.
Interest Rate Swaps — In the Successor period from October 3, 2016 through December 31, 2016, we entered into $3.0 billion notional amount of interest rate swaps to hedge a portion of our exposure to our variable rate debt. The interest rate swaps, which became effective in January 2017, expire in July 2023 and effectively fix the interest rates between 4.75% and 4.88% on $3.0 billion of our variable rate debt. The interest rate swaps are secured by a first lien secured interest on a pari-passu basis with the Vistra Operations Credit Facilities.
Predecessor
DIP Roll Facilities — In August 2016, the Predecessor entered into the DIP Roll Facilities. The facilities provided for up to $4.250 billion in senior secured, super-priority financing. The DIP Roll Facilities were senior, secured, super-priority debtor-in-possession credit agreements by and among the TCEH Debtors, the lenders that were party thereto from time to time and an administrative and collateral agent. On the Effective Date, the DIP Roll Facilities converted to the Vistra Operations Credit Facilities discussed above. Net proceeds from the DIP Roll Facilities were used to repay outstanding borrowings under the former DIP Facility, fund a collateral account used to backstop issuances of letters of credit and pay issuance costs. The remaining balance was used for general corporate purposes.
DIP Facility — The DIP Facility provided for up to $3.375 billion in senior secured, super-priority financing. The DIP Facility was a senior, secured, super-priority credit agreement by and among the TCEH Debtors, the lenders that were party thereto from time to time and an administrative and collateral agent. As discussed above, in August 2016, all outstanding amounts under the DIP Facility were repaid using proceeds from the DIP Roll Facilities.
13. LONG-TERM DEBT
Successor
Amounts in the table below represent the categories of long-term debt obligation incurred by the Successor.
Successor | ||||
December 31, 2016 |
||||
Vistra Operations Credit Facilities (a) |
$ | 4,515 | ||
Mandatorily redeemable preferred stock (b) |
70 | |||
8.82% Building Financing due semiannually through February 11, 2022 (c) |
36 | |||
Capital lease obligations |
2 | |||
|
|
|||
Total long-term debt including amounts due currently |
4,623 | |||
Less amounts due currently |
(46 | ) | ||
|
|
|||
Total long-term debt less amounts due currently |
$ | 4,577 | ||
|
|
(a) | Borrowings under the Vistra Operations Credit Facilities in the consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million. |
(b) | Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 2). This subsidiary’s preferred stock is accounted for as a debt instrument under relevant accounting guidance. |
(c) | Obligation related to a corporate office space capital lease contributed to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account and reflected in other noncurrent assets on the consolidated balance sheet at December 31, 2016. |
Vistra Operations Credit Facilities — As of the Effective Date, the Vistra Operations Credit Facilities initially consisted of up to $4.250 billion in senior secured, first lien financing consisting of a revolving credit facility of up to $750 million, including a $500 million letter of credit sub-facility (Initial Revolving Credit Facility), a term loan facility of up to $2.850 billion (Initial Term Loan B Facility) and a term loan letter of credit facility of up to $650 million (Term Loan C Facility).
In December 2016, we incurred $1 billion of incremental term loans (Incremental Term Loan B Facility, and together with the Initial Term Loan B Facility, the Term Loan B Facility) and $110 million of incremental revolving credit commitments (Incremental Revolving Credit Facility, and together with the Initial Revolving Credit Facility, the Revolving Credit Facility). The letter of credit sub-facility was also increased from $500 million to $600 million. Proceeds from the Incremental Term Loan B Facility were used to fund the special cash dividend in the aggregate amount of $1 billion that was approved by Vistra Energy’s board of directors and paid in December 2016 (see Note 15).
The Vistra Operations Credit Facilities and related available capacity at December 31, 2016 are presented below.
December 31, 2016 | ||||||||||||||||
Vistra Operations Credit Facilities |
Maturity Date | Facility Limit | Cash Borrowings |
Available Credit Capacity |
||||||||||||
Revolving Credit Facility (a) |
August 4, 2021 | $ | 860 | $ | — | $ | 860 | |||||||||
Initial Term Loan B Facility (b) |
August 4, 2023 | 2,850 | 2,850 | — | ||||||||||||
Incremental Term Loan B Facility (c) |
December 14, 2023 | 1,000 | 1,000 | — | ||||||||||||
Term Loan C Facility (d) |
August 4, 2023 | 650 | 650 | 131 | ||||||||||||
|
|
|
|
|
|
|||||||||||
Total Vistra Operations Credit Facilities |
$ | 5,360 | $ | 4,500 | $ | 991 | ||||||||||
|
|
|
|
|
|
(a) | Facility to be used for general corporate purposes. |
(b) | Facility used to repay all amounts outstanding under the Predecessor’s DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes. |
(c) | Facility used to fund a special cash dividend paid in December 2016 (see Note 15). |
(d) | Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in the consolidated balance sheet. At December 31, 2016, the restricted cash supported $519 million in letters of credit outstanding (see Note 22), leaving $131 million in available letter of credit capacity. |
As of December 31, 2016, amounts borrowed under the Revolving Credit Facility would bear interest based on applicable LIBOR rates plus 3.25%, and there were no outstanding borrowings at December 31, 2016. As of December 31, 2016, amounts borrowed under the Initial Term Loan B Facility and the Term Loan C Facility bear interest based on applicable LIBOR rates, subject to a 1% floor, plus 4%, and the interest rate on outstanding borrowings was 5% at December 31, 2016. Amounts borrowed under the Incremental Term Loan B Facility bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 3.25%, and the rate outstanding on outstanding borrowings was 4% at December 31, 2016. The Vistra Operation Credit Facilities also provides for certain additional fees payable to the agents and lenders, as well as availability fees payable with respect to any unused portions of the available Vistra Operations Credit Facilities.
In February 2017, certain pricing terms for the Vistra Operations Credit Facility were amended. Any amounts borrowed under the Revolving Credit Facility will bear interest based on applicable LIBOR rates plus 2.75%. Amounts borrowed under the Initial Term Loan B Facility and the Term Loan C Facility will bear interest based on applicable LIBOR rates, subject to a 0.75% floor, plus 2.75%.
We are required to make scheduled quarterly payments on the Term Loan B Facility in annual amounts equal to 1% of the original principal amount of the Term Loan B Facility with the balance paid at maturity. The first repayment will be made on March 31, 2017.
Obligations under the Vistra Operations Credit Facilities are secured by a lien covering substantially all of Vistra Energy’s consolidated assets, rights and properties, subject to certain exceptions set forth in the Vistra Operations Credit Facilities.
The Vistra Operations Credit Facilities also permit certain hedging agreements to be secured on a pari-passu basis with the Vistra Operations Credit Facilities in the event those hedging agreements met certain criteria set forth in the Vistra Operations Credit Facilities.
The Vistra Operation Credit Facilities provide for affirmative and negative covenants applicable to Vistra Energy, including affirmative covenants requiring us to provide financial and other information to the agents under the Vistra Operations Credit Facilities and to not change our lines of business, and negative covenants restricting Vistra Energy’s ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case except as permitted in the Vistra Operation Credit Facilities. Vistra Energy’s ability to borrow under the Vistra Operations Credit Facilities is subject to the satisfaction of certain customary conditions precedent set forth therein.
The Vistra Operations Credit Facilities provide for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Vistra Operations Credit Facilities or ancillary loan documents, cross-defaults under other agreements or instruments and the entry of material judgments against Vistra Energy. Solely with respect to the Revolving Credit Facility, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving letters of credit (in excess of $100 million) exceed 30% of the revolving commitments), the agreement includes a covenant that requires the consolidated first lien net leverage ratio, which is based on the ratio of net first lien debt compared to an EBITDA calculation defined under the terms of the facilities, not exceed 4.25 to 1.00. Although we had no borrowings under the Revolving Credit Facility as of December 31, 2016, we would have been in compliance with this financial covenant if it were required to be tested. Upon the existence of an event of default, the Vistra Operations Credit Facilities provides that all principal, interest and other amounts due thereunder will become immediately due and payable, either automatically or at the election of specified lenders.
Maturities — Long-term debt maturities at December 31, 2016 are as follows:
Successor | ||||
December 31, 2016 |
||||
2017 |
$ | 46 | ||
2018 |
44 | |||
2019 |
44 | |||
2020 |
44 | |||
2021 |
45 | |||
Thereafter |
4,380 | |||
Unamortized premiums, discounts and debt issuance costs |
20 | |||
|
|
|||
Total long-term debt including amounts due currently |
$ | 4,623 | ||
|
|
Interest Rate Swaps — In the Successor period from October 3, 2016 through December 31, 2016, we entered into $3.0 billion notional amount of interest rate swaps to hedge our exposure to our variable rate debt. The interest rate swaps, which become effective in January 2017, expire in July 2023 and, when taking into consideration the amended pricing on the Vistra Operations Credit Facilities discussed above, effectively fix the interest rates between 4.67% and 4.91%.
The interest rate swaps are secured by a first lien secured interest on a pari-passu basis with the Vistra Operations Credit Facilities.
Predecessor
DIP Roll Facilities — In August 2016, the Predecessor entered into the DIP Roll Facilities. The facilities provided for up to $4.250 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $750 million (DIP Roll Revolving Credit Facility), a term loan letter of credit facility of up to $650 million (DIP Roll Letter of Credit Facility) and a term loan facility of up to $2.850 billion (DIP Roll Term Loan Facility). The DIP Roll Facilities were senior, secured, super-priority debtor-in-possession credit agreements by and among the TCEH Debtors, the lenders that were party thereto from time to time and an administrative and collateral agent. The maturity date of the DIP Roll Facilities was the earlier of (a) October 31, 2017 or (b) the Effective Date. On the Effective Date, the DIP Roll Facilities converted to the Vistra Operations Credit Facilities discussed above.
Net proceeds from the DIP Roll Facilities totaled $3.465 billion and were used to repay $2.65 billion outstanding under the former DIP Facility, fund a $650 million collateral account used to backstop the issuances of letters of credit and pay $107 million of issuance costs. The remaining balance was used for general corporate purposes. Additionally, $800 million of cash from collateral accounts under the former DIP Facility that was used to backstop letters of credit was released to the Predecessor to be used for general corporate purposes.
DIP Facility — The DIP Facility provided for up to $3.375 billion in senior secured, super-priority financing consisting of a revolving credit facility of up to $1.950 billion (DIP Revolving Credit Facility) and a term loan facility of up to $1.425 billion (DIP Term Loan Facility). The DIP Facility was a senior, secured, super-priority credit agreement by and among the TCEH Debtors, the lenders that were party thereto and an administrative and collateral agent. At December 31, 2015, all $1.425 billion of the DIP Term Loan Facility were borrowed at an interest rate of 3.75%. Of this amount, $800 million represented amounts that supported issuances of letters of credit that were funded to a collateral account. Of the collateral account at December 31, 2015, $281 million was reported as cash and cash equivalents and $519 million was reported as restricted cash, which represented the amounts of outstanding letters of credit. At December 31, 2015, no amounts were borrowed under the DIP Revolving Credit Facility. As discussed above, in August 2016 all amounts under the DIP Facility were repaid using proceeds from the DIP Roll Facilities, and the $800 million of cash that was funded to the collateral account was released to TCEH to be used for general corporate purposes.
Other Long-Term Debt — Amounts in the Predecessor period represent pre-petition liabilities of the Predecessor that were not subject to compromise due to the debt being fully collateralized or specific orders from the Bankruptcy Court approving repayment of the debt.
Predecessor | ||||
December 31, 2015 |
||||
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (a) |
$ | 13 | ||
Capital lease and other obligations |
6 | |||
|
|
|||
Total |
19 | |||
Less amounts due currently |
(16 | ) | ||
|
|
|||
Total long-term debt not subject to compromise |
$ | 3 | ||
|
|
(a) | Debt issued by trust and secured by assets held by the trust. |
|
10. | COMMITMENTS AND CONTINGENCIES |
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of September 30, 2017, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees.
Letters of Credit
At September 30, 2017, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $480 million as follows:
• | $350 million to support commodity risk management collateral requirements in the normal course of business, including over-the-counter and exchange-traded transactions and collateral postings with ERCOT; |
• | $46 million to support executory contracts and insurance agreements; |
• | $55 million to support our REP financial requirements with the PUCT, and |
• | $29 million for other credit support requirements. |
Litigation
Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to Luminant under the EPA’s authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, Luminant received an additional information request from the EPA under Section 114 related to our Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to our Sandow 4 generation facility.
In July 2012, the EPA sent Luminant a notice of violation alleging noncompliance with the CAA’s New Source Review standards and the air permits at our Martin Lake and Big Brown generation facilities. In August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the CAA, including its New Source Review standards, at our Big Brown and Martin Lake generation facilities. In August 2015, the district court granted Luminant’s motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit. In August 2016, the EPA filed an amended complaint, eliminating one of the two remaining claims and withdrawing with prejudice a request for civil penalties in the other remaining claim. The EPA also filed a motion for entry of final judgment so that it could seek to appeal the district court’s dismissal decision. In September 2016, Luminant filed a response opposing the EPA’s motion for entry of final judgment. In October 2016, the district court denied the EPA’s motion for entry of final judgment and agreed that the remaining claim must be fully adjudicated at the district court or withdrawn with prejudice before the EPA may appeal the dismissal decision.
In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in our favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the US Court of Appeals for the Fifth Circuit (Fifth Circuit Court) and Luminant filed a motion in the district court to recover its attorney fees and costs. In April 2017, the district court stayed its consideration of Luminant’s motion for attorney fees. In June 2017, the EPA and the Sierra Club filed their opening briefs in the Fifth Circuit Court. Luminant filed its response brief in August 2017. In September 2017, the EPA and the Sierra Club filed their reply briefs. The case has not yet been set for oral argument. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time or retirement of the plants at issue and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed and existing electricity generation units, referred to as the Clean Power Plan. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide CO2 emissions related to affected units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the US Supreme Court (Supreme Court) asking that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for existing plants. In February 2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the Supreme Court disposes of any subsequent petition for review. Oral argument on the merits of the legal challenges to the rule were heard in September 2016 before the entire D.C. Circuit Court.
In March 2017, President Trump issued an Executive Order entitled Promoting Energy Independence and Economic Growth (Order). The Order covers a number of matters, including the Clean Power Plan. Among other provisions, the Order directs the EPA to review the Clean Power Plan and, if appropriate, suspend, revise or rescind the rules on existing and new, modified and reconstructed generating units. In April 2017, in accordance with the Order, the EPA published its intent to review the Clean Power Plan. In addition, the Department of Justice has filed motions seeking to abate those cases until the EPA concludes its review of the rules, including any new rulemaking that results from that review. In April 2017, the D.C. Circuit Court issued orders holding the cases in abeyance for 60 days and directing the EPA to provide status reports at 30 day intervals. The D.C. Circuit Court further ordered that all parties file supplemental briefs in May 2017 on whether the cases should be remanded to the EPA rather than held in abeyance. The 60-day abeyance expired in June 2017, and the D.C. Circuit Court has yet to take further action. In October 2017, the EPA issued a proposed rule that would rescind the Clean Power Plan. The proposed repeal focuses on what the EPA believes to be the unlawful nature of the Clean Power Plan and asks for public comment on the EPA’s interpretations of its authority under the Clean Air Act. We currently plan to submit comments in response to the proposed repeal. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately implemented or upheld as they were issued, they could have a material impact on our results of operations, liquidity or financial condition.
Cross-State Air Pollution Rule (CSAPR)
In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions from our fossil fueled generation units. In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In June 2012, the EPA finalized the proposed rule (Second Revised Rule).
The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of Luminant and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states’ budgets to the EPA for prompt reconsideration. While Luminant planned to participate in the EPA’s reconsideration process to develop increased budgets for the 1997 ozone standard that do not over-control Texas, the EPA instead responded to the remand by proposing a new rulemaking that created new NOX ozone season budgets for the 2008 ozone standard without addressing the over-controlling budgets for the 1997 standard. Comments on the EPA’s proposal were submitted by Luminant in February 2016. In August 2016, the EPA disapproved Texas’s 2008 ozone State Implementation Plan (SIP) submittal and imposed a Federal Implementation Plan (FIP) in its place in October 2016. Texas filed a petition in the Fifth Circuit Court challenging the SIP disapproval and Luminant has intervened in support of Texas’s challenge. The State of Texas and Luminant have also both filed challenges in the D.C. Circuit Court challenging the EPA’s FIP and those cases are currently pending before that court. With respect to Texas’s SO2 emission budgets, in June 2016, the EPA issued a memorandum describing the EPA’s proposed approach for responding to the D.C. Circuit Court’s remand for reconsideration of the CSAPR SO2 emission budgets for Texas and three other states that had been remanded to the EPA by the D.C. Circuit Court. In the memorandum, the EPA stated that those four states could either voluntarily participate in the CSAPR by submitting a SIP revision adopting the SO2 budgets that had been previously held invalid by the D.C. Circuit Court and the current annual NOX budgets or, if the state chooses not to participate in the CSAPR, the EPA could withdraw the CSAPR FIP by the fall of 2016 for those states and address any interstate transport and regional haze obligations on a state-by-state basis. Texas has not indicated that it intends to adopt the over-controlling budgets and, in November 2016, the EPA proposed to withdraw the CSAPR FIP for Texas. In September 2017, the EPA finalized its proposal to remove Texas from the annual CSAPR programs. As a result, Texas electric generating units are no longer subject to the CSAPR annual SO2 and NOX limits, but remain subject to the CSAPR’s ozone season NOX requirements. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA’s recent actions concerning the CSAPR annual emissions budgets for affected states and participating in the CSAPR program, based upon our current operating plans we do not believe that the CSAPR itself will cause any material operational, financial or compliance issues to our business or require us to incur any material compliance costs.
Regional Haze — Reasonable Progress and Long-Term Strategies
The Regional Haze Program of the CAA establishes “as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from man-made pollution.” There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. In February 2009, the TCEQ submitted a SIP concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA’s replacement CSAPR program that the EPA proposed in July 2011. The EPA finalized the limited disapproval in June 2012. In August 2012, Luminant filed a petition for review in the Fifth Circuit Court challenging the EPA’s limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court’s decision in the CSAPR litigation. In September 2012, Luminant filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA’s limited disapproval and issuance of a FIP regarding the regional haze best available retrofit technology (BART) program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. Briefing in the D.C. Circuit Court was completed in March 2017.
In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas related to the reasonable progress program. After releasing a proposed rule in November 2014 and receiving comments from a number of parties, including Luminant and the State of Texas in April 2015, the EPA issued a final rule in January 2016 approving in part and disapproving in part Texas’ SIP for Regional Haze and issuing a FIP for Regional Haze. In the rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. The EPA’s emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generating units and upgrades to existing scrubbers at seven generation units. Specifically, for Luminant, the EPA’s FIP is based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Under the terms of the rule, subject to the legal proceedings described in the following paragraph, the scrubber upgrades would be required by February 2019, and the new scrubbers would be required by February 2021.
In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the Fifth Circuit Court challenging the FIP’s Texas requirements. Luminant and other parties also filed motions to stay the FIP while the court reviews the legality of the EPA’s action. In July 2016, the Fifth Circuit Court denied the EPA’s motion to dismiss Luminant’s challenge to the FIP and denied the EPA’s motion to transfer the challenges Luminant, the other industry petitioners and the State of Texas filed to the D.C. Circuit Court. In addition, the Fifth Circuit Court granted the motions to stay filed by Luminant, the other industry petitioners and the State of Texas pending final review of the petitions for review. The case was abated until the end of November 2016 in order to allow the parties to pursue settlement discussions. Settlement discussions were unsuccessful, and in December 2016 the EPA filed a motion seeking a voluntary remand of the rule back to the EPA for further consideration of Luminant’s pending request for administrative reconsideration. Luminant and some of the other petitioners filed a response opposing the EPA’s motion to remand and filed a cross motion for vacatur of the rule in December 2016. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration in light of the Court’s prior determination that we and the other petitioners demonstrated a substantial likelihood that the EPA exceeded its statutory authority and acted arbitrarily and capriciously, but the Court denied all of the other pending motions. The stay of the rule (and the emission control requirements) remains in effect. In addition, the Fifth Circuit Court denied the EPA’s motion to lift the stay as to parts of the rule implicated in the EPA’s subsequent BART proposal and the Court is retaining jurisdiction of the case and requiring the EPA to file status reports on its reconsideration every 60 days. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
Regional Haze — Best Available Retrofit Technology
The second part of the Regional Haze Program subjects certain electricity generation units built between 1962 and 1977, to BART standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area. BART reductions of SO2 and NOX are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR or other approved alternative program. In response to a lawsuit by environmental groups, the D.C. Circuit Court issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a FIP for any provisions that the EPA disapproves. The D.C. Circuit Court has amended the consent decree several times to extend the dates for the EPA to propose and finalize a decision on the Regional Haze SIP. The consent decree was modified in December 2015 to extend the deadline for the EPA to finalize action on the determination and adoption of requirements for BART for electricity generation. Under the amended consent decree, the EPA had until December 2016 to propose, and had until September 2017 to finalize, either approval of the state plan or a FIP for BART for Texas electricity generation sources if the EPA determines that BART requirements have not been met. The EPA issued a proposed BART FIP for Texas in January 2017. The EPA’s proposed emission limits assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at 12 electric generation units and upgrades to existing scrubbers at four electric generation units. Specifically, for Luminant, the EPA’s proposed emission limitations were based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3 and Monticello Unit 3. Luminant evaluated the requirements and potential financial and operational impacts of the proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale power prices in ERCOT, would challenge the long-term economic viability of those units. Under the terms of the proposed rule, the scrubber upgrades would have been required within three years of the effective date of the final rule and the new scrubbers will be required within five years of the effective date of the final rule. We submitted comments on the proposed FIP in May 2017.
The EPA signed the final BART FIP for Texas in September 2017. The rule is a partial approval of Texas’s 2009 SIP and a partial FIP. In response to comments on the proposed rule submitted to the EPA, for SO2, the rule creates an intrastate Texas emission allowance trading program as a “BART alternative” that operates in a similar fashion to a CSAPR trading program. The program includes 39 generating units, including our Martin Lake, Big Brown, Monticello, Sandow 4, Stryker 2 and Graham 2 plants. Of the 39 units, 30 are BART-eligible, three are co-located with a BART-eligible unit and six units are included in the program based on a visibility impacts analysis by the EPA. The 39 units represent 89% of SO2 emissions from Texas electric generating units in 2016 and 85% of all CSAPR SO2 allowance allocations for Texas existing electric generating units. The compliance obligations in the program will start on January 1, 2019. The identified units will receive an annual allowance allocation that is equal to their current annual CSAPR SO2 allocation. Luminant’s units covered by the program are allocated 91,222 allowances annually. Under the rule, a unit that is listed that does not operate for two consecutive years starting after 2018 would no longer receive allowances after the fifth year of non-operation. While we are still analyzing the rule, we believe the recent retirement announcement for our Monticello, Big Brown (if not sold) and Sandow 4 plants (see Note 17) will enhance our ability to comply with this BART rule for SO2. For NOX, the rule adopts the CSAPR’s ozone program as BART and for particulate matter, the rule approves Texas’s SIP that determines that no electric generating units are subject to particulate matter BART. While we cannot predict the outcome of the rulemaking and potential legal proceedings, we believe the rule, if ultimately implemented or upheld as issued, will not have a material impact on our results of operation, liquidity or financial condition.
Intersection of the CSAPR and Regional Haze Programs
Historically the EPA has considered compliance with a regional trading program, such as the CSAPR, as satisfying a state’s obligations under the BART portion of the Regional Haze Program. However, in the reasonable progress FIP, the EPA diverged from this approach and did not treat Texas’ compliance with the CSAPR as satisfying its obligations under the BART portion of the Regional Haze Program. The EPA concluded that it would not be appropriate to finalize that determination given the remand of the CSAPR budgets. As described above, the EPA has now removed Texas from the annual CSAPR trading programs and has issued a final BART FIP for Texas.
Affirmative Defenses During Malfunctions
In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP that was found to be lawful by the Fifth Circuit Court in 2013. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA’s proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA’s revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. In May 2015, the EPA finalized the proposal. In June 2015, Luminant filed a petition for review in the Fifth Circuit Court challenging certain aspects of the EPA’s final rule as they apply to the Texas SIP. The State of Texas and other parties have also filed similar petitions in the Fifth Circuit Court. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA’s action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court on the challenges was completed in October 2016 and oral argument was originally set for May 2017. However, in April 2017, the court granted the EPA’s motion to continue oral argument and ordered that the case be held in abeyance with the EPA to provide status reports to the court on the EPA’s review of the action at 90-day intervals. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the rule as finalized may have a material impact on our results of operations, liquidity or financial condition.
SO2 Designations for Texas
In February 2016, the EPA notified Texas of the EPA’s preliminary intention to designate nonattainment areas for counties surrounding our Big Brown, Monticello and Martin Lake generation plants based on modeling data submitted to the EPA by the Sierra Club. Such designation would potentially require the implementation of various controls or other requirements to demonstrate attainment. Luminant submitted comments challenging the use of modeling data rather than data from actual air quality monitoring equipment. In November 2016, the EPA finalized its proposed designations for Texas including finalizing the nonattainment designations for the areas referenced above. In doing so, the EPA ignored contradictory modeling that we submitted with our comments. The final designation mandates would be for Texas to begin the multi-year process to evaluate what potential emission controls or operational changes, if any, may be necessary to demonstrate attainment. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court and protective petitions in the D.C. Circuit Court. In March 2017, the EPA filed a motion to transfer or dismiss our Fifth Circuit Court petition, and the State of Texas and Luminant filed an opposition to that motion. Briefing on that motion in the Fifth Circuit Court was completed in May 2017, and the Fifth Circuit Court held oral argument on that motion in July 2017. In August 2017, the Fifth Circuit Court denied the EPA’s motion to transfer our challenge to the D.C. Circuit Court. In October 2017, the Fifth Circuit Court granted the EPA’s motion to hold the case in abeyance in light of the EPA’s representation that it was considering granting Luminant’s request that the EPA reconsider the rule. In addition, with respect to Monticello and Big Brown (if that plant is retired and not sold), the retirement of those plants should favorably impact our legal challenge to the nonattainment designations in that the nonattainment designation for Freestone County and Titus County are based solely on the Sierra Club modeling of alleged SO2 emissions from Big Brown and Monticello. We dispute the Sierra Club’s modeling. Regardless, considering these retirement announcements, the nonattainment designation for those counties are no longer supported. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
Other Matters
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
14. COMMITMENTS AND CONTINGENCIES
Contractual Commitments
At December 31, 2016, we had contractual commitments under energy-related contracts, leases and other agreements as follows.
Coal purchase and transportation agreements |
Pipeline transportation and storage reservation fees |
Nuclear Fuel Contracts |
Other Contracts |
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2017 |
$ | 338 | $ | 30 | $ | 72 | $ | 128 | ||||||||
2018 |
— | 21 | 91 | 55 | ||||||||||||
2019 |
— | 22 | 39 | 57 | ||||||||||||
2020 |
— | 22 | 43 | 54 | ||||||||||||
2021 |
— | 22 | 49 | 36 | ||||||||||||
Thereafter |
— | 161 | 222 | 350 | ||||||||||||
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Total |
$ | 338 | $ | 278 | $ | 516 | $ | 680 | ||||||||
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Amounts in other contracts include certain long-term service and maintenance contracts related to our generation assets. The table above excludes TRA and pension and OPEB plan payments due to the uncertainty in the timing of those payments.
Expenditures under our coal purchase and coal transportation agreements totaled $109 million, $139 million, $218 million and $348 million for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively.
At December 31, 2016, future minimum lease payments under both capital leases and operating leases are as follows:
Capital Leases |
Operating Leases (a) |
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2017 |
$ | 2 | $ | 25 | ||||
2018 |
— | 17 | ||||||
2019 |
— | 14 | ||||||
2020 |
— | 12 | ||||||
2021 |
— | 9 | ||||||
Thereafter |
— | 153 | ||||||
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Total future minimum lease payments |
2 | $ | 230 | |||||
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Less amounts representing interest |
— | |||||||
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Present value of future minimum lease payments |
2 | |||||||
Less current portion |
(2 | ) | ||||||
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Long-term capital lease obligation |
$ | — | ||||||
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(a) | Includes operating leases with initial or remaining noncancellable lease terms in excess of one year. |
Rent reported as operating costs, fuel costs and SG&A expenses totaled $20 million, $39 million, $55 million and $54 million for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. As of December 31, 2016, there are no material outstanding claims related to our guarantee obligations, and we do not anticipate we will be required to make any material payments under these guarantees.
Letters of Credit
At December 31, 2016, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling $519 million as follows:
• | $363 million to support commodity risk management and trading collateral requirements in the normal course of business, including over-the-counter and exchange-traded hedging transactions and collateral postings with ERCOT; |
• | $70 million to support executory contracts and insurance agreements; |
• | $55 million to support our REP financial requirements with the PUCT, and |
• | $31 million for other credit support requirements. |
Litigation
Litigation Related to EPA Reviews — In June 2008, the EPA issued an initial request for information to Luminant under the EPA’s authority under Section 114 of the Clean Air Act (CAA). The stated purpose of the request is to obtain information necessary to determine compliance with the CAA, including New Source Review standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. In April 2013, Luminant received an additional information request from the EPA under Section 114 related to our Big Brown, Martin Lake and Monticello facilities as well as an initial information request related to our Sandow 4 generation facility.
In July 2012, the EPA sent Luminant a notice of violation alleging noncompliance with the CAA’s New Source Review standards and the air permits at our Martin Lake and Big Brown generation facilities. In August 2013, the US Department of Justice, acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the CAA, including its New Source Review standards, at our Big Brown and Martin Lake generation facilities. In August 2015, the district court granted Luminant’s motion to dismiss seven of the nine claims asserted by the EPA in the lawsuit. In August 2016, the EPA filed an amended complaint, eliminating one of the two remaining claims and withdrawing with prejudice a request for civil penalties in the other remaining claim. The EPA also filed a motion for entry of final judgment so that it could seek to appeal the district court’s dismissal decision. In September 2016, Luminant filed a response opposing the EPA’s motion for entry of final judgment. In October 2016, the district court denied the EPA’s motion for entry of final judgment and agreed that the remaining claim must be fully adjudicated at the district court or withdrawn with prejudice before the EPA may appeal the dismissal decision. In January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in our favor. In March 2017, the EPA appealed the final judgment to the Fifth Circuit Court and Luminant filed a motion in the district court to recover its attorney fees and costs. We believe that we and Luminant have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests the maximum civil penalties available under the CAA to the government of up to $32,500 to $37,500 per day for each alleged violation, depending on the date of the alleged violation, and injunctive relief, including an order requiring the installation of best available control technology at the affected units. An adverse outcome could require substantial capital expenditures that cannot be determined at this time or retirement of the plants at issue and could possibly require the payment of substantial penalties. We cannot predict the outcome of these proceedings, including the financial effects, if any.
Greenhouse Gas Emissions
In August 2015, the EPA finalized rules to address greenhouse gas (GHG) emissions from new, modified and reconstructed and existing electricity generation units, referred to as the Clean Power Plan. The rule for existing facilities would establish state-specific emissions rate goals to reduce nationwide CO2 emissions related to affected units by over 30% from 2012 emission levels by 2030. A number of parties, including Luminant, filed petitions for review in the US Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) for the rule for new, modified and reconstructed plants. In addition, a number of petitions for review of the rule for existing plants were filed in the D.C. Circuit Court by various parties and groups, including challenges from twenty-seven different states opposed to the rule as well as those from, among others, certain power generating companies, various business groups and some labor unions. Luminant also filed its own petition for review. In January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the US Supreme Court (Supreme Court) asking that the Supreme Court stay the rule while the D.C. Circuit Court reviews the legality of the rule for existing plants. In February 2016, the Supreme Court stayed the rule pending the conclusion of legal challenges on the rule before the D.C. Circuit Court and until the Supreme Court disposes of any subsequent petition for review. Oral argument on the merits of the legal challenges to the rule were heard in September 2016 before the entire D.C. Circuit Court. In March 2017, President Trump issued an Executive Order entitled Promoting Energy Independence and Economic Growth (Order). The Order covers a number of matters, including the Clean Power Plan. Among other provisions, the Order directs the EPA to review the Clean Power Plan and, if appropriate, suspend, revise or rescind the rules on existing and new, modified and reconstructed generating units. In addition, the Department of Justice has filed motions seeking to abate those cases until the EPA concludes its review of the rules, including any new rulemaking that results from that review. While we cannot predict the outcome of these rulemakings and related legal proceedings, or estimate a range of reasonably probable costs, if the rules are ultimately implemented or upheld as they were issued, they could have a material impact on our results of operations, liquidity or financial condition.
In August 2015, the EPA proposed model rules and federal plan requirements for states to consider as they develop state plans to comply with the rules for GHG emissions. A federal plan would then be finalized for a state if a state fails to submit a state plan by the deadlines established in the Clean Power Plan for existing plants or if the EPA disapproves a submitted state plan. Luminant filed comments on the federal plan proposal and model rules in January 2016. The Executive Order issued in March 2017, directed the EPA to review this proposed rule for consistency with the policies in the Order and, if appropriate, to revise or withdraw the proposed rule. While we cannot predict the timing or outcome of this rulemaking and related legal proceedings, or estimate a range of reasonably possible costs, they could have a material impact on our results of operations, liquidity or financial condition.
Cross-State Air Pollution Rule (CSAPR)
In July 2011, the EPA issued the CSAPR, compliance with which would have required significant additional reductions of SO2 and NOx emissions from our fossil fueled generation units. In February 2012, the EPA released a final rule (Final Revisions) and a proposed rule revising certain aspects of the CSAPR, including increases in the emissions budgets for Texas and our generation assets as compared to the July 2011 version of the rule. In June 2012, the EPA finalized the proposed rule (Second Revised Rule).
The CSAPR became effective January 1, 2015. In July 2015, following a remand of the case from the Supreme Court to consider further legal challenges, the D.C. Circuit Court unanimously ruled in favor of Luminant and other petitioners, holding that the CSAPR emissions budgets over-controlled Texas and other states. The D.C. Circuit Court remanded those states’ budgets to the EPA for prompt reconsideration. While Luminant planned to participate in the EPA’s reconsideration process to develop increased budgets for the 1997 ozone standard that do not over-control Texas, the EPA instead responded to the remand by proposing a new rulemaking that created new NOX ozone season budgets for the 2008 ozone standard without addressing the over-controlling budgets for the 1997 standard. Comments on the EPA’s proposal were submitted by Luminant in February 2016. In August 2016, the EPA disapproved Texas’s 2008 ozone SIP submittal and imposed a FIP in its place in October 2016. Texas filed a petition in the Fifth Circuit Court challenging the SIP disapproval and Luminant has intervened in support of Texas’s challenge. The State of Texas and Luminant have also both filed challenges in the D.C. Circuit Court challenging the EPA’s FIP and those cases are currently pending before that court. With respect to Texas’s SO2 emission budgets, in June 2016, the EPA issued a memorandum describing the EPA’s proposed approach for responding to the D.C. Circuit Court’s remand for reconsideration of the CSAPR SO2 emission budgets for Texas and three other states that had been remanded to the EPA by the D.C. Circuit Court. In the memorandum, the EPA stated that those four states could either voluntarily participate in the CSAPR by submitting a State Implementation Plan (SIP) revision adopting the SO2 budgets that had been previously held invalid by the D.C. Circuit Court and the current annual NOx budgets or, if the state chooses not to participate in the CSAPR, the EPA could withdraw the CSAPR Federal Implementation Plan (FIP) by the fall of 2016 for those states and address any interstate transport and regional haze obligations on a state-by-state basis. Texas has not indicated that it intends to adopt the over-controlling budgets and, in November 2016, the EPA proposed to withdraw the CSAPR FIP for Texas. Because the EPA has not finalized its proposal to remove Texas from the annual CSAPR programs, these programs will continue to apply to Texas and Texas sources. At this time, the EPA has not populated the allowance accounts for Texas sources with 2017 annual CSAPR program allowances. While we cannot predict the outcome of future proceedings related to the CSAPR, including the EPA’s recent actions concerning the CSAPR annual emissions budgets for affected states and participating in the CSAPR program, based upon our current operating plans we do not believe that the CSAPR itself will cause any material operational, financial or compliance issues to our business or require us to incur any material compliance costs.
Regional Haze — Reasonable Progress and Long-Term Strategies
The Regional Haze Program of the CAA establishes “as a national goal the prevention of any future, and the remedying of any existing, impairment of visibility in mandatory Class I federal areas, like national parks, which impairment results from manmade pollution.” There are two components to the Regional Haze Program. First, states must establish goals for reasonable progress for Class I federal areas within the state and establish long-term strategies to reach those goals and to assist Class I federal areas in neighboring states to achieve reasonable progress set by those states towards a goal of natural visibility by 2064. In February 2009, the TCEQ submitted a SIP concerning regional haze (Regional Haze SIP) to the EPA. In December 2011, the EPA proposed a limited disapproval of the Regional Haze SIP due to its reliance on the Clean Air Interstate Rule (CAIR) instead of the EPA’s replacement CSAPR program that the EPA proposed in July 2011. In August 2012, Luminant filed a petition for review in the Fifth Circuit Court challenging the EPA’s limited disapproval of the Regional Haze SIP on the grounds that the CAIR continued in effect pending the D.C. Circuit Court’s decision in the CSAPR litigation. In September 2012, Luminant filed a petition to intervene in a case filed by industry groups and other states and private parties in the D.C. Circuit Court challenging the EPA’s limited disapproval and issuance of a FIP regarding the regional haze BART program. The Fifth Circuit Court case has since been transferred to the D.C. Circuit Court and consolidated with other pending BART program regional haze appeals. Briefing in the D.C. Circuit Court was completed in March 2017.
In June 2014, the EPA issued requests for information under Section 114 of the CAA to Luminant and other generators in Texas related to the reasonable progress program. After releasing a proposed rule in November 2014 and receiving comments from a number of parties, including Luminant and the State of Texas in April 2015, the EPA released a final rule in January 2016 approving in part and disapproving in part Texas’ SIP for Regional Haze and issuing a FIP for Regional Haze. In the rule, the EPA asserts that the Texas SIP does not show reasonable progress in improving visibility for two areas in Texas and that its long-term strategy fails to make emission reductions needed to achieve reasonable progress in improving visibility in the Wichita Mountains of Oklahoma. The EPA’s proposed emission limits in the FIP assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at seven electricity generating units and upgrades to existing scrubbers at seven electricity generating units. Specifically, for Luminant, the EPA’s FIP is based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3, Monticello Unit 3 and Sandow Unit 4. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale electricity prices in ERCOT, would likely challenge the long-term economic viability of those units. Under the terms of the rule, the scrubber upgrades will be required by February 2019, and the new scrubbers will be required by February 2021.
In March 2016, Luminant and a number of other parties, including the State of Texas, filed petitions for review in the US Fifth Circuit Court challenging the FIP’s Texas requirements. Luminant and other parties also filed motions to stay the FIP while the court reviews the legality of the EPA’s action. In July 2016, the Fifth Circuit Court denied the EPA’s motion to dismiss Luminant’s challenge to the FIP and denied the EPA’s motion to transfer the challenges Luminant, the other industry petitioners and the State of Texas filed to the D.C. Circuit Court. In addition, the Fifth Circuit Court granted the motions to stay filed by Luminant, the other industry petitioners and the State of Texas pending final review of the petitions for review. The case was abated until the end of November 2016 in order to allow the parties to pursue settlement discussions. Settlement discussions were unsuccessful, and in December 2016 the EPA filed a motion seeking a voluntary remand of the rule back to the EPA for further consideration of Luminant’s pending request for administrative reconsideration. Luminant and some of the other petitioners filed a response opposing the EPA’s motion to remand and filed a cross motion for vacatur of the rule in December 2016. In March 2017, the Fifth Circuit Court remanded the rule back to the EPA for reconsideration in light of the Court’s prior determination that we and the other petitioners demonstrated a substantial likelihood that the EPA exceeded its statutory authority and acted arbitrarily and capriciously, but the Court denied all of the other pending motions. The stay of the rule (and the emission control requirements) remains in effect. In addition, the Fifth Circuit Court denied the EPA’s motion to lift the stay as to parts of the rule implicated in the EPA’s subsequent BART proposal and the Court is retaining jurisdiction of the case and requiring the EPA to file status reports on its reconsideration every 15 days. While we cannot predict the outcome of the rulemaking and legal proceedings, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
Regional Haze — Best Available Retrofit Technology
The second part of the Regional Haze Program subjects electricity generation units built between 1962 and 1977, to best available retrofit technology (BART) standards designed to improve visibility if such units cause or contribute to impairment of visibility in a federal class I area. BART reductions of SO2 and NOX are required either on a unit-by-unit basis or are deemed satisfied by state participation in an EPA-approved regional trading program such as the CSAPR. In response to a lawsuit by environmental groups, the D.C. Circuit Court issued a consent decree in March 2012 that required the EPA to propose a decision on the Regional Haze SIP by May 2012 and finalize that decision by November 2012. The consent decree requires a FIP for any provisions that the EPA disapproves. The D.C. Circuit Court has amended the consent decree several times to extend the dates for the EPA to propose and finalize a decision on the Regional Haze SIP. The consent decree was modified in December 2015 to extend the deadline for the EPA to finalize action on the determination and adoption of requirements for BART for electricity generation. Under the amended consent decree, the EPA had until December 2016 to propose, and has until September 2017 to finalize, a FIP for BART for Texas electricity generation sources if the EPA determines that BART requirements have not been met. The EPA issued its proposed BART FIP for Texas in December 2016. The EPA’s proposed emission limits assume additional control equipment for specific lignite/coal-fueled generation units across Texas, including new flue gas desulfurization systems (scrubbers) at 12 electric generation units and upgrades to existing scrubbers at four electric generation units. Specifically, for Luminant, the EPA’s emission limitations are based on new scrubbers at Big Brown Units 1 and 2 and Monticello Units 1 and 2 and scrubber upgrades at Martin Lake Units 1, 2 and 3 and Monticello Unit 3. Luminant is continuing to evaluate the requirements and potential financial and operational impacts of the proposed rule, but new scrubbers at the Big Brown and Monticello units necessary to achieve the emission limits required by the FIP (if those limits are possible to attain), along with the existence of low wholesale power prices in ERCOT, would likely challenge the long-term economic viability of those units. Under the terms of the rule, the scrubber upgrades will be required within three years of the effective date of the final rule and the new scrubbers will be required within five years of the effective date of the final rule. We anticipate submitting comments on the proposed FIP when those are due in May 2017. While we cannot predict the outcome of the rulemaking and potential legal proceedings, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
Intersection of the CSAPR and Regional Haze Programs
Historically the EPA has considered compliance with a regional trading program, such as the CSAPR, as satisfying a state’s obligations under the BART portion of the Regional Haze Program. However, in the reasonable progress FIP, the EPA diverged from this approach and did not treat Texas’ compliance with the CSAPR as satisfying its obligations under the BART portion of the Regional Haze Program. The EPA concluded that it would not be appropriate to finalize that determination given the remand of the CSAPR budgets. As described above, the EPA has now proposed to remove Texas from the annual CSAPR trading programs. If Texas were in the CSAPR annual trading programs, the EPA would have no basis for its BART FIP because it has made a determination for Texas and all other states that participate in the CSAPR annual trading programs that such participation satisfies their BART obligations. We do not believe that EPA’s proposal to remove Texas from the CSAPR annual trading programs satisfies the D.C. Circuit Court’s mandate to the EPA to develop non-over-controlling budgets for Texas and we submitted comments on the EPA’s proposed rule to remove Texas from the CSAPR annual trading programs. While we cannot predict the outcome of these matters, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
Affirmative Defenses During Malfunctions
In February 2013, in response to a petition for rulemaking filed by the Sierra Club, the EPA proposed a rule requiring certain states to replace SIP exemptions for excess emissions during malfunctions with an affirmative defense. Texas was not included in that original proposal since it already had an EPA-approved affirmative defense provision in its SIP that was found to be lawful by the Fifth Circuit Court in 2013. In 2014, as a result of a D.C. Circuit Court decision striking down an affirmative defense in another EPA rule, the EPA revised its 2013 proposal to extend the EPA’s proposed findings of inadequacy to states that have affirmative defense provisions, including Texas. The EPA’s revised proposal would require Texas to remove or replace its EPA-approved affirmative defense provisions for excess emissions during startup, shutdown and maintenance events. In May 2015, the EPA finalized the proposal. In June 2015, Luminant filed a petition for review in the Fifth Circuit Court challenging certain aspects of the EPA’s final rule as they apply to the Texas SIP. The State of Texas and other parties have also filed similar petitions in the Fifth Circuit Court. In August 2015, the Fifth Circuit Court transferred the petitions that Luminant and other parties filed to the D.C. Circuit Court, and in October 2015 the petitions were consolidated with the pending petitions challenging the EPA’s action in the D.C. Circuit Court. Briefing in the D.C. Circuit Court on the challenges was completed in October 2016 and oral argument is set for May 2017. We cannot predict the timing or outcome of this proceeding, or estimate a range of reasonably possible costs, but implementation of the rule as finalized may have a material impact on our results of operations, liquidity or financial condition.
SO2 Designations for Texas
In February 2016, the EPA notified Texas of the EPA’s preliminary intention to designate nonattainment areas for counties surrounding our Big Brown, Monticello and Martin Lake generation plants based on modeling data submitted to the EPA by the Sierra Club. Such designation would potentially require the implementation of various controls or other requirements to demonstrate attainment. Luminant submitted comments challenging the use of modeling data rather than data from actual air quality monitoring equipment. In November 2016, the EPA finalized its proposed designations for Texas including finalizing the nonattainment designations for the areas referenced above. In doing so, the EPA ignored contradictory modeling that we submitted with our comments. The final designation mandates would be for Texas to begin the multi-year process to evaluate what potential emission controls or operational changes, if any, may be necessary to demonstrate attainment. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court and protective petitions in the D.C. Circuit Court. In March 2017, the EPA filed a motion to transfer or dismiss our Fifth Circuit Court petition. In addition, Luminant has filed a request with the EPA to reconsider the rule and immediately stay its effective date. While we cannot predict the outcome of this matter, or estimate a range of reasonably possible costs, the result may have a material impact on our results of operations, liquidity or financial condition.
Other Matters
We are involved in various legal and administrative proceedings in the normal course of business, the ultimate resolutions of which, in the opinion of management, are not anticipated to have a material effect on our results of operations, liquidity or financial condition.
Labor Contracts
We employ certain personnel who are represented by labor unions, the terms of whose employment are governed by collective bargaining agreements. During 2015, all collective bargaining agreements covering bargaining unit personnel engaged in lignite mining operations, lignite-, coal- and nuclear-fueled generation operations and some of our natural gas-fueled generation operations were extended to March 2017. While we cannot predict the outcome of labor contract negotiations, we do not expect any changes in collective bargaining agreements to have a material adverse effect on our results of operations, liquidity or financial condition.
Nuclear Insurance
Nuclear insurance includes nuclear liability coverage, property damage, decontamination and accidental premature decommissioning coverage and accidental outage and/or extra expense coverage. We maintain nuclear insurance that meets or exceeds requirements promulgated by Section 170 (Price-Anderson) of the Atomic Energy Act (the Act) and Title 10 of the Code of Federal Regulations. We intend to maintain insurance against nuclear risks as long as such insurance is available. We are self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Any such self-insured losses could have a material adverse effect on our results of operations, liquidity or financial condition.
With regard to liability coverage, the Act provides for financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $13.4 billion and requires nuclear generation plant operators to provide financial protection for this amount. However, the United States Congress could impose revenue-raising measures on the nuclear industry to pay claims that exceed the $13.4 billion limit for a single incident. As required, we insure against a possible nuclear incident at our Comanche Peak facility resulting in public nuclear-related bodily injury and property damage through a combination of private insurance and an industry-wide retrospective payment plan known as the Secondary Financial Protection (SFP).
Under the SFP, in the event of any single nuclear liability loss in excess of $375 million at any nuclear generation facility in the United States, each operating licensed reactor in the United States is subject to an annual assessment of up to $127.3 million. This approximately $127.3 million maximum assessment is subject to increases for inflation every five years, with the next expected adjustment scheduled to occur in September 2018. Assessments are currently limited to $19 million per operating licensed reactor per year per incident. As of December 31, 2016, our maximum potential assessment under the industry retrospective plan would be approximately $254.6 million per incident but no more than $37.9 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility. For losses after January 1, 2017, the potential assessment applies in excess of $450 million.
The United States Nuclear Regulatory Commission (NRC) requires that nuclear generation plant license holders maintain at least $1.06 billion of nuclear decontamination and property damage insurance, and requires that the proceeds thereof be used to place a plant in a safe and stable condition, to decontaminate a plant pursuant to a plan submitted to, and approved by, the NRC prior to using the proceeds for plant repair or restoration, or to provide for premature decommissioning. We maintain nuclear decontamination and property damage insurance for our Comanche Peak facility in the amount of $2.25 billion and non-nuclear related property damage in the amount of $1.75 billion (subject to a $5 million deductible per accident except for natural hazards which are subject to a $9.5 million deductible per accident), above which we are self-insured.
We also maintain Accidental Outage insurance to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at our Comanche Peak facility are out of service for more than 20 weeks as a result of covered direct physical damage. Such coverage provides for weekly payments per unit of up to $5.25 million for the first 52 weeks, up to $4.35 million for the next 35 weeks and up to $3.6 million for the remaining 36 weeks, after the initial waiting period. The total maximum coverage is $393 million for non-nuclear accidents and $555 million for nuclear accidents. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.
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11. | EQUITY |
Successor Shareholders’ Equity
Vistra Energy did not declare or pay any dividends during the nine months ended September 30, 2017. The agreement governing the Vistra Operations Credit Facilities (the Credit Facilities Agreement) generally restricts the ability of Vistra Operations Company LLC (Vistra Operations) to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of September 30, 2017, Vistra Operations can distribute approximately $980 million to Vistra Energy Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to Parent was reduced by approximately $67 million and $537 million due to net distributions made by Vistra Operations to Parent during the three and nine months ended September 30, 2017, respectively. Additionally, Vistra Operations may make distributions to Parent in amounts sufficient for Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of Parent’s ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses.
Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that such distribution exceeds the value of our “surplus,” which is defined as the excess of our net assets above our capital (the aggregate par value of all outstanding shares of our stock).
The following table presents the changes to shareholder’s equity for the nine months ended September 30, 2017:
Vistra Energy Shareholders’ Equity | ||||||||||||||||||||
Common Stock (a) |
Additional Paid-in Capital |
Retained Earnings (Deficit) |
Accumulated Other Comprehensive Income |
Total Shareholders’ Equity |
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Balance at December 31, 2016 |
$ | 4 | $ | 7,742 | $ | (1,155 | ) | $ | 6 | $ | 6,597 | |||||||||
Net income |
— | — | 325 | — | 325 | |||||||||||||||
Effects of stock-based incentive compensation plans |
— | 13 | — | — | 13 | |||||||||||||||
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Balance at September 30, 2017 |
$ | 4 | $ | 7,755 | $ | (830 | ) | $ | 6 | $ | 6,935 | |||||||||
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(a) | Authorized shares totaled 1,800,000,000 at September 30, 2017. Outstanding shares totaled 427,597,368 and 427,580,232 at September 30, 2017 and December 31, 2016, respectively. |
Predecessor Membership Interests
The following table presents the changes to membership interests for the nine months ended September 30, 2016:
TCEH Membership Interests | ||||||||||||
Capital Account |
Accumulated Other Comprehensive Loss |
Total Membership Interests |
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Balance at December 31, 2015 |
$ | (22,851 | ) | $ | (33 | ) | $ | (22,884 | ) | |||
Net loss |
(656 | ) | — | (656 | ) | |||||||
Net effects of cash flow hedges |
— | 1 | 1 | |||||||||
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Balance at September 30, 2016 |
$ | (23,507 | ) | $ | (32 | ) | $ | (23,539 | ) | |||
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15. EQUITY
Successor Shareholders’ Equity
Equity Issuances — As of December 31, 2016, 427,580,232 shares of Vistra Energy common stock were outstanding. On the Effective Date, 427,500,000 shares were issued pursuant to the Plan of Reorganization (see Note 2).
Dividends Declared — In December 2016, the board of directors of Vistra Energy approved the payment of a special cash dividend (Special Dividend) in the aggregate amount of approximately $1 billion ($2.32 per share of common stock) to holders of record of our common stock on December 19, 2016. The dividend was funded using borrowings under the Vistra Operations Credit Facilities (see Note 13).
Dividend Restrictions — The agreement governing the Vistra Operations Credit Facilities generally restricts our ability to make distributions or loans to any of our parent companies or their subsidiaries unless such distributions or loans were expressly permitted under the agreement governing such facility.
Under applicable Delaware General Corporate Law, we are prohibited from paying any distribution to the extent that immediately following payment of such distribution, we would be insolvent.
Accumulated Other Comprehensive Income — During the period from October 3, 2016 through December 31, 2016, we recorded a $6 million change in the funded status of our pension and other postretirement employee benefit liability; there were no amounts reclassified from accumulated other comprehensive income.
Predecessor Membership Interests
TCEH paid no dividends in the period from January 1, 2016 through October 2, 2016 nor the years ended December 31, 2015 and 2014.
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12. | FAIR VALUE MEASUREMENTS |
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs. Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group.
Fair value measurements of derivative assets and liabilities incorporate an adjustment for credit-related nonperformance risk. These nonperformance risk adjustments take into consideration master netting arrangements, credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 13 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
• | Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Our Level 1 assets and liabilities include CME or ICE (electronic commodity derivative exchanges) futures and options transacted through clearing brokers for which prices are actively quoted. We report the fair value of CME and ICE transactions without taking into consideration margin deposits, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017, are legally characterized as settlement of derivative contracts rather than collateral. |
• | Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs such as interest rates and yield curves observable at commonly quoted intervals. We attempt to obtain multiple quotes from brokers that are active in the markets in which we participate and require at least one quote from two brokers to determine a pricing input as observable. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. |
• |
Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing delivery periods and locations and credit-related nonperformance risk assumptions. These inputs and valuation models are developed and maintained by employees trained and experienced in market operations and fair value measurements and validated by the Company’s risk management group. |
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement.
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
September 30, 2017 |
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Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
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Commodity contracts |
$ | 27 | $ | 90 | $ | 182 | $ | 3 | $ | 302 | ||||||||||
Interest rate swaps |
— | 2 | — | 7 | 9 | |||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
486 | — | — | — | 486 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 365 | — | — | 365 | |||||||||||||||
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Sub-total |
$ | 513 | $ | 457 | $ | 182 | $ | 10 | 1,162 | |||||||||||
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Assets measured at net asset value (d): |
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Nuclear decommissioning trust — equity securities (c) |
281 | |||||||||||||||||||
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Total assets |
$ | 1,443 | ||||||||||||||||||
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Liabilities: |
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Commodity contracts |
$ | 28 | $ | 25 | $ | 25 | $ | 3 | $ | 81 | ||||||||||
Interest rate swaps |
— | 16 | — | 7 | 23 | |||||||||||||||
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Total liabilities |
$ | 28 | $ | 41 | $ | 25 | $ | 10 | $ | 104 | ||||||||||
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December 31, 2016 |
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Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
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Commodity contracts |
$ | 167 | $ | 131 | $ | 98 | $ | — | $ | 396 | ||||||||||
Interest rate swaps |
— | 5 | — | 13 | 18 | |||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
425 | — | — | — | 425 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 340 | — | — | 340 | |||||||||||||||
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Sub-total |
$ | 592 | $ | 476 | $ | 98 | $ | 13 | 1,179 | |||||||||||
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Assets measured at net asset value (d): |
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Nuclear decommissioning trust — equity securities (c) |
247 | |||||||||||||||||||
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Total assets |
$ | 1,426 | ||||||||||||||||||
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Liabilities: |
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Commodity contracts |
$ | 302 | $ | 15 | $ | 15 | $ | — | $ | 332 | ||||||||||
Interest rate swaps |
— | 16 | — | 13 | 29 | |||||||||||||||
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Total liabilities |
$ | 302 | $ | 31 | $ | 15 | $ | 13 | $ | 361 | ||||||||||
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(a) | See table below for description of Level 3 assets and liabilities. |
(b) | Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our condensed consolidated balance sheets. |
(c) | The nuclear decommissioning trust investment is included in the other investments line in our condensed consolidated balance sheets. See Note 16. |
(d) | The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our condensed consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. |
Commodity contracts consist primarily of natural gas, electricity, coal, fuel oil and uranium agreements and include financial instruments entered into for economic hedging purposes as well as physical contracts that have not been designated as normal purchases or sales. Interest rate swaps are used to reduce exposure to interest rate changes by converting floating-rate interest to fixed rates. See Note 13 for further discussion regarding derivative instruments.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at September 30, 2017 and December 31, 2016:
September 30, 2017 |
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Fair Value | ||||||||||||||||||||
Contract Type (a) |
Assets | Liabilities | Total |
Valuation |
Significant Unobservable Input |
Range (b) | ||||||||||||||
Electricity purchases and sales |
$ | 101 | $ | (8 | ) | $ | 93 | Valuation Model | Hourly price curve shape (c) | |
$0 to $35/ MWh |
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||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) | |
$20 to $60/ MWh |
|
|||||||||||||||||
Electricity options |
33 | (13 | ) | 20 | Option Pricing Model | Gas to power correlation (e) | 30% to 95% | |||||||||||||
Power volatility (e) | 5% to 180% | |||||||||||||||||||
Electricity congestion revenue rights |
35 | (4 | ) | 31 | Market Approach (f) | Illiquid price differences between settlement points (g) | |
$0 to $15/ MWh |
|
|||||||||||
Other (h) |
13 | — | 13 | |||||||||||||||||
|
|
|
|
|
|
|||||||||||||||
Total |
$ | 182 | $ | (25 | ) | $ | 157 | |||||||||||||
|
|
|
|
|
|
|||||||||||||||
December 31, 2016 |
||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Contract Type (a) |
Assets | Liabilities | Total |
Valuation |
Significant Unobservable Input |
Range (b) | ||||||||||||||
Electricity purchases and sales |
$ | 32 | $ | — | $ | 32 | Valuation Model | Hourly price curve shape (c) | |
$0 to $35/ MWh |
|
|||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) | |
$30 to $70/ MWh |
|
|||||||||||||||||
Electricity congestion revenue rights |
42 | (6 | ) | 36 | Market Approach (f) | Illiquid price differences between settlement points (g) | |
$0 to $10/ MWh |
|
|||||||||||
Other (h) |
24 | (9 | ) | 15 | ||||||||||||||||
|
|
|
|
|
|
|||||||||||||||
Total |
$ | 98 | $ | (15 | ) | $ | 83 | |||||||||||||
|
|
|
|
|
|
(a) | Electricity purchase and sales contracts include power and heat rate positions in ERCOT regions. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Electricity options consist of physical electricity options and spread options. |
(b) | The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. |
(c) | Based on the historical range of forward average hourly ERCOT North Hub prices. |
(d) | Based on historical forward ERCOT power price and heat rate variability. |
(e) | Based on historical forward correlation and volatility within ERCOT. |
(f) | While we use the market approach, there is insufficient market data to consider the valuation liquid. |
(g) | Based on the historical price differences between settlement points within ERCOT hubs and load zones. |
(h) | Other includes contracts for natural gas, coal and coal options. December 31, 2016 also includes an immaterial amount of electricity options. |
There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the three and nine months ended September 30, 2017 and 2016. See the table below for discussion of transfers between Level 2 and Level 3 for the three and nine months ended September 30, 2017 and 2016.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2017 and 2016.
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Net asset (liability) balance at beginning of period |
$ | 75 | $ | (9 | ) | $ | 83 | $ | 37 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total unrealized valuation gains (losses) |
132 | 126 | 139 | 122 | ||||||||||||
Purchases, issuances and settlements (a): |
||||||||||||||||
Purchases |
16 | 11 | 51 | 37 | ||||||||||||
Issuances |
(5 | ) | (4 | ) | (19 | ) | (20 | ) | ||||||||
Settlements |
(45 | ) | (24 | ) | (87 | ) | (51 | ) | ||||||||
Transfers into Level 3 (b) |
— | — | 4 | 1 | ||||||||||||
Transfers out of Level 3 (b) |
— | — | 2 | 1 | ||||||||||||
Earn-out provision (c) |
(16 | ) | — | (16 | ) | — | ||||||||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) |
— | (3 | ) | — | (30 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net change (d) |
82 | 106 | 74 | 60 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net asset balance at end of period |
$ | 157 | $ | 97 | $ | 157 | $ | 97 | ||||||||
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|
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|
|||||||||
Unrealized valuation gains relating to instruments held at end of period |
$ | 106 | $ | 92 | $ | 110 | $ | 98 |
(a) | Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received. |
(b) | Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. |
(c) | Represents initial fair value of the earn-out provision incurred as part of the Odessa Acquisition. See Note 3. |
(d) | Substantially all changes in value of commodity contracts (excluding the initial fair value of the earn-out provision related to the Odessa Acquisition in 2017 and the net liability assumed in the Lamar and Forney Acquisition in 2016) are reported as operating revenues in our condensed statements of consolidated income (loss). Activity excludes change in fair value in the month positions settle. |
16. FAIR VALUE MEASUREMENTS
Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between willing market participants at the measurement date. We use a mid-market valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
• | Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange-traded commodity contracts. For example, some of our derivatives are NYMEX or the IntercontinentalExchange (ICE, an electronic commodity derivative exchange) futures and swaps transacted through clearing brokers for which prices are actively quoted. |
• | Level 2 valuations use inputs that, in the absence of actively quoted market prices, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other mathematical means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means, and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available. |
• | Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives with values derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. See further discussion below. |
Our valuation policies and procedures were developed, maintained and validated by a centralized risk management group that reports to the Vistra Energy Chief Financial Officer.
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.
In utilizing broker quotes, we attempt to obtain multiple quotes from brokers (generally non-binding) that are active in the markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors.
Probable loss from default by either us or our counterparties is considered in determining the fair value of derivative assets and liabilities. These non-performance risk adjustments take into consideration credit enhancements and the credit risks associated with our credit standing and the credit standing of our counterparties (see Note 17 for additional information regarding credit risk associated with our derivatives). We utilize credit ratings and default rate factors in calculating these fair value measurement adjustments.
Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including, but not limited to, commodity prices, volatility factors, discount rates and other market based factors. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Significant unobservable inputs used to develop the valuation models include volatility curves, correlation curves, illiquid pricing locations and credit/non-performance risk assumptions. Those valuation models are generally used in developing long-term forward price curves for certain commodities, in particular, long-term ERCOT wholesale power prices. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.
The significant unobservable inputs and valuation models are developed by employees trained and experienced in market operations and fair value measurements and validated by the company’s risk management group, which also further analyzes any significant changes in Level 3 measurements. Significant changes in the unobservable inputs could result in significant upward or downward changes in the fair value measurement.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
Successor |
||||||||||||||||||||
December 31, 2016 |
||||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
||||||||||||||||||||
Commodity contracts |
$ | 167 | $ | 131 | $ | 98 | $ | — | $ | 396 | ||||||||||
Interest rate swaps |
— | 5 | — | 13 | 18 | |||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
425 | — | — | — | 425 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 340 | — | — | 340 | |||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Subtotal |
$ | 592 | $ | 476 | $ | 98 | $ | 13 | 1,179 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Assets measured at net asset value (d): |
||||||||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
247 | |||||||||||||||||||
|
|
|||||||||||||||||||
Total assets |
$ | 1,426 | ||||||||||||||||||
|
|
|||||||||||||||||||
Liabilities: |
||||||||||||||||||||
Commodity contracts |
$ | 302 | $ | 15 | $ | 15 | $ | — | $ | 332 | ||||||||||
Interest rate swaps |
— | 16 | — | 13 | 29 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total liabilities |
$ | 302 | $ | 31 | $ | 15 | $ | 13 | $ | 361 | ||||||||||
|
|
|
|
|
|
|
|
|
|
Predecessor |
||||||||||||||||||||
December 31, 2015 |
||||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
||||||||||||||||||||
Commodity contracts |
$ | 385 | $ | 41 | $ | 49 | $ | — | $ | 475 | ||||||||||
Nuclear decommissioning trust — equity securities (c) |
380 | — | — | — | 380 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 319 | — | — | 319 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Subtotal |
$ | 765 | $ | 360 | $ | 49 | $ | — | 1,174 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Assets measured at net asset value (d): |
||||||||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
219 | |||||||||||||||||||
|
|
|||||||||||||||||||
Total assets |
$ | 1,393 | ||||||||||||||||||
|
|
|||||||||||||||||||
Liabilities: |
||||||||||||||||||||
Commodity contracts |
$ | 128 | $ | 64 | $ | 12 | $ | — | $ | 204 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total liabilities |
$ | 128 | $ | 64 | $ | 12 | $ | — | $ | 204 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | See table below for description of Level 3 assets and liabilities. |
(b) | Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in the consolidated balance sheets. |
(c) | The nuclear decommissioning trust investment is included in the investments line in the condensed consolidated balance sheets. See Note 22. |
(d) | Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the condensed consolidated balance sheets. |
Commodity contracts consist primarily of natural gas, electricity, fuel oil, uranium and coal agreements and include financial instruments entered into for hedging purposes as well as physical contracts that have not been designated normal purchases or sales. See Note 17 for further discussion regarding derivative instruments.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of our nuclear generation facility. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at December 31, 2016 and 2015:
Successor |
||||||||||||||||||
December 31, 2016 |
||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) |
Assets |
Liabilities |
Total |
Valuation |
Significant Unobservable Input |
Range (b) |
||||||||||||
Electricity purchases and sales |
$ | 32 | $ | — | $ | 32 | Valuation Model |
Hourly price curve shape (d) | $0 to $35/MWh |
|||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (e) |
$30 to $70/MWh |
|||||||||||||||||
Electricity congestion revenue rights |
42 | (6 | ) | 36 | Market Approach (f) |
Illiquid price differences between settlement points (g) |
$0 to $10/MWh |
|||||||||||
Other (h) |
24 | (9 | ) | 15 | ||||||||||||||
|
|
|
|
|
|
|||||||||||||
Total |
$ | 98 | $ | (15 | ) | $ | 83 | |||||||||||
|
|
|
|
|
|
Predecessor |
||||||||||||||||||
December 31, 2015 |
||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) |
Assets |
Liabilities |
Total |
Valuation |
Significant Unobservable Input |
Range (b) |
||||||||||||
Electricity purchases and sales |
$ | 1 | $ | (1 | ) | $ | — | Valuation Model |
Illiquid pricing locations (c) | $15 to $35/MWh |
||||||||
Hourly price curve shape (d) | $15 to $45/MWh |
|||||||||||||||||
Electricity congestion revenue rights |
39 | (4 | ) | 35 | Market Approach (f) |
Illiquid price differences between settlement points (g) |
$0 to $10/MWh |
|||||||||||
Other (h) |
9 | (7 | ) | 2 | ||||||||||||||
|
|
|
|
|
|
|||||||||||||
Total |
$ | 49 | $ | (12 | ) | $ | 37 | |||||||||||
|
|
|
|
|
|
(a) | Electricity purchase and sales contracts include power and heat rate hedging positions in ERCOT regions. Electricity options contracts consist of physical electricity options and spread options. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. |
(b) | The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. |
(c) | Based on the historical range of forward average monthly ERCOT hub and load zone prices. |
(d) | Based on the historical range of forward average hourly ERCOT North Hub prices. |
(e) | Based on historical forward ERCOT power price and heat rate variability. |
(f) | While we use the market approach, there is insufficient market data to consider the valuation liquid. |
(g) | Based on the historical price differences between settlement points within ERCOT hubs and load zones. |
(h) | Other includes contracts for ancillary services, natural gas, electricity options and coal options. |
There were no significant transfers between Level 1 and Level 2 of the fair value hierarchy for the Successor period from October 3, 2016 through December 31, 2016 or the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014. See the table of changes in fair values of Level 3 assets and liabilities below for discussion of transfers between Level 2 and Level 3 for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014. During the Predecessor period from January 1, 2016 through October 2, 2016, in conjunction with the Lamar and Forney Acquisition, we acquired certain electricity spread options that are classified in Level 3 of the fair value hierarchy.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the Successor period from October 3, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014.
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Net asset (liability) balance at beginning of period (a) |
$ | 81 | $ | 37 | $ | 35 | $ | (973 | ) | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total unrealized valuation gains (losses) |
31 | 122 | 27 | (97 | ) | |||||||||||
Purchases, issuances and settlements (b) |
||||||||||||||||
Purchases |
15 | 37 | 49 | 63 | ||||||||||||
Issuances |
(7 | ) | (20 | ) | (13 | ) | (5 | ) | ||||||||
Settlements |
(30 | ) | (51 | ) | (48 | ) | 1,053 | |||||||||
Transfers into Level 3 (c) |
3 | 1 | 1 | — | ||||||||||||
Transfers out of Level 3 (c) |
(10 | ) | 1 | (14 | ) | (6 | ) | |||||||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 6) (d) |
— | (30 | ) | — | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net change (e) |
2 | 60 | 2 | 1,008 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net asset balance at end of period |
$ | 83 | $ | 97 | $ | 37 | $ | 35 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Unrealized valuation gains (losses) relating to instruments held at end of period |
$ | 28 | $ | 98 | $ | 18 | $ | (5 | ) |
(a) | The beginning balance for the Successor period reflects a $16 million adjustment to the fair value of certain Level 3 assets driven by power prices utilized by the Successor for unobservable delivery periods. |
(b) | Settlements reflect reversals of unrealized mark-to-market valuations. Purchases and issuances reflect option premiums paid or received, respectively. |
(c) | Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. |
(d) | Includes fair value of Level 3 assets and liabilities as of the purchase date and any related rolloff between the purchase date and the period ended October 2, 2016. |
(e) |
Activity excludes changes in fair value in the month the positions settled as well as amounts related to positions entered into and settled in the same quarter. For the Successor period, substantially all changes in values of commodity contracts are reported in the statements of consolidated income (loss) in operating revenues or fuel, purchased power costs and delivery fees. For the Predecessor period, substantially all changes in values of commodity contracts (excluding net liabilities assumed in the Lamar and Forney Acquisition) are reported in the statements of consolidated income (loss) in net gain from commodity hedging and trading activities. |
|
13. | COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES |
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 12 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — We utilize natural gas and electricity derivatives to reduce exposure to changes in electricity prices primarily to hedge future revenues from electricity sales from our generation assets. We also utilize short-term electricity, natural gas, coal, fuel oil and uranium derivative instruments for fuel hedging and other purposes. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy marketing companies. Unrealized gains and losses arising from changes in the fair value of derivative instruments as well as realized gains and losses upon settlement of the instruments are reported in our condensed statements of consolidated income (loss) in operating revenues and fuel, purchased power costs and delivery fees in the Successor period and net gain from commodity hedging and trading activities in the Predecessor period.
Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in our condensed statements of consolidated income (loss) in interest expense and related charges.
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets at September 30, 2017 and December 31, 2016. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
September 30, 2017 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity Contracts |
Interest Rate Swaps |
Commodity Contracts |
Interest Rate Swaps |
Total | ||||||||||||||||
Current assets |
$ | 181 | $ | — | $ | 1 | $ | — | $ | 182 | ||||||||||
Noncurrent assets |
120 | 9 | — | — | 129 | |||||||||||||||
Current liabilities |
(2 | ) | (7 | ) | (53 | ) | (10 | ) | (72 | ) | ||||||||||
Noncurrent liabilities |
— | — | (26 | ) | (6 | ) | (32 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net assets (liabilities) |
$ | 299 | $ | 2 | $ | (78 | ) | $ | (16 | ) | $ | 207 | ||||||||
|
|
|
|
|
|
|
|
|
|
December 31, 2016 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity Contracts |
Interest Rate Swaps |
Commodity Contracts |
Interest Rate Swaps |
Total | ||||||||||||||||
Current assets |
$ | 350 | $ | — | $ | — | $ | — | $ | 350 | ||||||||||
Noncurrent assets |
46 | 17 | — | 1 | 64 | |||||||||||||||
Current liabilities |
— | (12 | ) | (330 | ) | (17 | ) | (359 | ) | |||||||||||
Noncurrent liabilities |
— | — | (2 | ) | — | (2 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net assets (liabilities) |
$ | 396 | $ | 5 | $ | (332 | ) | $ | (16 | ) | $ | 53 | ||||||||
|
|
|
|
|
|
|
|
|
|
At September 30, 2017 and December 31, 2016, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects:
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Derivative (condensed statements of consolidated income |
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
||||||||||||
Commodity contracts (Operating revenues) (a) |
$ | 166 | $ | — | $ | 333 | $ | — | ||||||||
Commodity contracts (Fuel, purchased power costs and delivery fees) (a) |
9 | — | 3 | — | ||||||||||||
Commodity contracts (Net gain from commodity hedging and trading activities) (a) |
— | 239 | — | 194 | ||||||||||||
Interest rate swaps (Interest expense and related charges) (b) |
(4 | ) | — | (24 | ) | — | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net gain (loss) |
$ | 171 | $ | 239 | $ | 312 | $ | 194 | ||||||||
|
|
|
|
|
|
|
|
(a) | Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. |
(b) | Includes unrealized mark-to-market net gains as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 7). |
In conjunction with fresh start reporting, the balances in accumulated other comprehensive income were eliminated from our condensed consolidated balance sheet on the Effective Date. The pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges by the Predecessor was immaterial in the three and nine months ended September 30, 2016. There were no amounts recognized in OCI for the three and nine months ended September 30, 2017.
Balance Sheet Presentation of Derivatives
We elect to report derivative assets and liabilities in our condensed consolidated balance sheets on a gross basis without taking into consideration netting arrangements we have with counterparties to those derivatives. We maintain standardized master netting agreements with certain counterparties that allow for the right to offset assets and liabilities and collateral in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.
Generally, margin deposits that contractually offset these derivative instruments are reported separately in our condensed consolidated balance sheets, with the exception of certain margin amounts related to changes in fair value on certain CME transactions that, beginning in January 2017, are legally characterized as settlement of forward exposure rather than collateral. Margin deposits received from counterparties are primarily used for working capital or other general corporate purposes.
The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||
Derivative Assets and Liabilities |
Offsetting Instruments (a) |
Cash Collateral (Received) Pledged (b) |
Net Amounts |
Derivative Assets and Liabilities |
Offsetting Instruments (a) |
Cash Collateral (Received) Pledged (b) |
Net Amounts |
|||||||||||||||||||||||||
Derivative assets: |
||||||||||||||||||||||||||||||||
Commodity contracts |
$ | 299 | $ | (64 | ) | $ | (9 | ) | $ | 226 | $ | 396 | $ | (193 | ) | $ | (20 | ) | $ | 183 | ||||||||||||
Interest rate swaps |
2 | — | — | 2 | 5 | — | — | 5 | ||||||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Total derivative assets |
301 | (64 | ) | (9 | ) | 228 | 401 | (193 | ) | (20 | ) | 188 | ||||||||||||||||||||
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|
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|
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|
|
|
|
|
|
|||||||||||||||||
Derivative liabilities: |
||||||||||||||||||||||||||||||||
Commodity contracts |
(78 | ) | 64 | 1 | (13 | ) | (332 | ) | 193 | 136 | (3 | ) | ||||||||||||||||||||
Interest rate swaps |
(16 | ) | — | — | (16 | ) | (16 | ) | — | — | (16 | ) | ||||||||||||||||||||
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Total derivative liabilities |
(94 | ) | 64 | 1 | (29 | ) | (348 | ) | 193 | 136 | (19 | ) | ||||||||||||||||||||
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Net amounts |
$ | 207 | $ | — | $ | (8 | ) | $ | 199 | $ | 53 | $ | — | $ | 116 | $ | 169 | |||||||||||||||
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|
(a) | Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements and, to a lesser extent, initial margin requirements. |
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at September 30, 2017 and December 31, 2016:
September 30, 2017 |
December 31, 2016 |
|||||||||
Derivative type |
Notional Volume | Unit of Measure | ||||||||
Natural gas (a) |
1,420 | 1,282 | Million MMBtu | |||||||
Electricity |
106,190 | 75,322 | GWh | |||||||
Congestion Revenue Rights (b) |
96,269 | 126,573 | GWh | |||||||
Coal |
4 | 12 | Million US tons | |||||||
Fuel oil |
19 | 34 | Million gallons | |||||||
Uranium |
450 | 25 | Thousand pounds | |||||||
Interest rate swaps — floating/fixed (c) |
$ | 3,000 | $ | 3,000 | Million US dollars |
(a) | Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions. |
(b) | Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT. |
(c) | Includes notional amounts of interest rate swaps that became effective in January 2017 and have maturity dates through July 2023. |
Credit Risk-Related Contingent Features of Derivatives
Our derivative contracts may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies or include cross-default contractual provisions that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants.
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
September 30, 2017 |
December 31, 2016 |
|||||||
Fair value of derivative contract liabilities (a) |
$ | (41 | ) | $ | (31 | ) | ||
Offsetting fair value under netting arrangements (b) |
22 | 13 | ||||||
Cash collateral and letters of credit |
1 | 1 | ||||||
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|
|
|
|||||
Liquidity exposure |
$ | (18 | ) | $ | (17 | ) | ||
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(a) | Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). |
(b) | Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements. |
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At September 30, 2017, total credit risk exposure to all counterparties related to derivative contracts totaled $442 million (including associated accounts receivable). The net exposure to those counterparties totaled $337 million at September 30, 2017 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $68 million. At September 30, 2017, the credit risk exposure to the banking and financial sector represented 41% of the total credit risk exposure and 36% of the net exposure.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
17. COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES
Strategic Use of Derivatives
We transact in derivative instruments, such as options, swaps, futures and forward contracts, to manage commodity price and interest rate risk. See Note 16 for a discussion of the fair value of derivatives.
Commodity Hedging and Trading Activity — We utilize natural gas derivatives as hedging instruments designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales from our generation assets. In ERCOT, the wholesale price of electricity has generally moved with the price of natural gas. We also enter into derivatives, including electricity, natural gas, fuel oil, uranium, emission and coal instruments, generally for short-term fuel hedging and other purposes. Unrealized gains and losses arising from changes in the fair value of hedging and trading instruments as well as realized gains and losses upon settlement of the instruments are reported in the statements of consolidated income (loss) in operating revenues and fuel, purchased power costs and delivery fees in the Successor period and net gain from commodity hedging and trading activities in the Predecessor periods.
Interest Rate Swaps — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate interest rates to fixed rates, thereby hedging future interest costs and related cash flows. Unrealized gains and losses arising from changes in the fair value of the swaps as well as realized gains and losses upon settlement of the swaps are reported in the statements of consolidated income (loss) in interest expense and related charges.
Termination of Predecessor’s Commodity Hedges and Interest Rate Swaps — Commodity hedges and interest rate swaps entered into prior to the Petition Date are deemed to be forward contracts under the Bankruptcy Code. The Bankruptcy Filing constituted an event of default under these arrangements, and in accordance with the contractual terms, counterparties terminated certain positions shortly after the Bankruptcy Filing. The positions terminated consisted almost entirely of natural gas hedging positions and interest rate swaps that were secured by a first-lien interest in the same assets of TCEH on a pari passu basis with the TCEH Senior Secured Facilities and the TCEH Senior Secured Notes.
Entities with a first-lien security interest included counterparties to both our Predecessor’s natural gas hedging positions and interest rate swaps, which had entered into master agreements that provided for netting and setoff of amounts related to these positions. Additionally, certain counterparties to only our Predecessor’s interest rate swaps hold the same first-lien security interest. The total net liability of $1.243 billion as of December 31, 2015 was reported in the consolidated balance sheets as a liability subject to compromise. Additionally, prior to the Effective Date, counterparties associated with the net liability were allowed, and had been receiving, adequate protection payments related to their claims as permitted by TCEH’s cash collateral order approved by the Bankruptcy Court (see Note 11).
Financial Statement Effects of Derivatives
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in the consolidated balance sheets at December 31, 2016 and 2015. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
Successor | ||||||||||||||||||||
December 31, 2016 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity contracts |
Interest rate swaps |
Commodity contracts |
Interest rate swaps |
Total | ||||||||||||||||
Current assets |
$ | 350 | $ | — | $ | — | $ | — | $ | 350 | ||||||||||
Noncurrent assets |
46 | 17 | — | 1 | 64 | |||||||||||||||
Current liabilities |
— | (12 | ) | (330 | ) | (17 | ) | (359 | ) | |||||||||||
Noncurrent liabilities |
— | — | (2 | ) | — | (2 | ) | |||||||||||||
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|
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|
|||||||||||
Net assets (liabilities) |
$ | 396 | $ | 5 | $ | (332 | ) | $ | (16 | ) | $ | 53 | ||||||||
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Predecessor | ||||||||||||||||||||
December 31, 2015 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity contracts |
Interest rate swaps |
Commodity contracts |
Interest rate swaps |
Total | ||||||||||||||||
Current assets |
$ | 465 | $ | — | $ | — | $ | — | $ | 465 | ||||||||||
Noncurrent assets |
10 | — | — | — | 10 | |||||||||||||||
Current liabilities |
— | — | (203 | ) | — | (203 | ) | |||||||||||||
Noncurrent liabilities |
— | — | (1 | ) | — | (1 | ) | |||||||||||||
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|||||||||||
Net assets (liabilities) |
$ | 475 | $ | — | $ | (204 | ) | $ | — | $ | 271 | |||||||||
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At December 31, 2016 and 2015, there were no derivative positions accounted for as cash flow or fair value hedges.
The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
Derivative (statements of consolidated income (loss) presentation) |
2015 |
2014 |
||||||||||||||
Commodity contracts (Operating revenues) (a) |
$ | (92 | ) | $ | — | $ | — | $ | — | |||||||
Commodity contracts (Fuel, purchased power costs and delivery fees) (a) |
21 | — | — | — | ||||||||||||
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a) |
— | 194 | 380 | 17 | ||||||||||||
Interest rate swaps (Interest expense and related charges) (b) |
(11 | ) | — | — | (128 | ) | ||||||||||
Interest rate swaps (Reorganization items) (Note 4) |
— | — | — | (277 | ) | |||||||||||
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Net gain (loss) |
$ | (82 | ) | $ | 194 | $ | 380 | $ | (388 | ) | ||||||
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(a) | Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. |
(b) | Includes unrealized mark-to-market net gain (loss) as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 11). |
The pretax effect (all losses) on net income and other comprehensive income (OCI) of derivative instruments previously accounted for as cash flow hedges were immaterial in the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014. There were no amounts recognized in OCI for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014.
Accumulated other comprehensive income related to cash flow hedges at December 31, 2015 totaled $33 million in net losses (after-tax), substantially all of which related to interest rate swaps previously accounted for as cash flow hedges. In conjunction with fresh start reporting (see Note 3), the balances in accumulated other comprehensive income were eliminated from the consolidated balance sheet on the Effective Date.
Balance Sheet Presentation of Derivatives
Consistent with elections under US GAAP to present amounts on a gross basis, we report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties to those derivatives. We may enter into offsetting positions with the same counterparty, resulting in both assets and liabilities. Volatility in underlying commodity prices can result in significant changes in derivative assets and liabilities presented from period to period.
Margin deposits that contractually offset these derivative instruments are reported separately in the condensed consolidated balance sheets. Margin deposits received from counterparties are either used for working capital or other general corporate purposes or, if there are restrictions on the use of cash, amounts are deposited in a separate restricted cash account. At December 31, 2016 and 2015, essentially all margin deposits held were unrestricted.
We maintain standardized master netting agreements with certain counterparties that allow for the netting of positive and negative exposures. These agreements contain credit enhancements that allow for the right to offset assets and liabilities and collateral received in order to reduce credit exposure between us and the counterparty. These agreements contain specific language related to margin requirements, monthly settlement netting, cross-commodity netting and early termination netting, which is negotiated with the contract counterparty.
The following tables reconcile our derivative assets and liabilities as presented in the condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
Successor | Predecessor | |||||||||||||||||||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||||||||||||||||||
Amounts Presented in Balance Sheet |
Offsetting Instruments (a) |
Financial Collateral (Received) Pledged (b) |
Net Amounts |
Amounts Presented in Balance Sheet |
Offsetting Instruments (a) |
Financial Collateral (Received) Pledged (b) |
Net Amounts |
|||||||||||||||||||||||||
Derivative assets: |
||||||||||||||||||||||||||||||||
Commodity contracts |
$ | 396 | $ | (193 | ) | $ | (20 | ) | $ | 183 | $ | 475 | $ | (145 | ) | $ | (147 | ) | $ | 183 | ||||||||||||
Interest rate swaps |
5 | — | — | 5 | — | — | — | — | ||||||||||||||||||||||||
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|||||||||||||||||
Total derivative assets |
401 | (193 | ) | (20 | ) | 188 | 475 | (145 | ) | (147 | ) | 183 | ||||||||||||||||||||
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Derivative liabilities: |
||||||||||||||||||||||||||||||||
Commodity contracts |
(332 | ) | 193 | 136 | (3 | ) | (204 | ) | 145 | 6 | (53 | ) | ||||||||||||||||||||
Interest rate swaps |
(16 | ) | — | — | (16 | ) | — | — | — | — | ||||||||||||||||||||||
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Total derivative liabilities |
(348 | ) | 193 | 136 | (19 | ) | (204 | ) | 145 | 6 | (53 | ) | ||||||||||||||||||||
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Net amounts |
$ | 53 | $ | — | $ | 116 | $ | 169 | $ | 271 | $ | — | $ | (141 | ) | $ | 130 | |||||||||||||||
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(a) | Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Financial collateral consists entirely of cash margin deposits. |
Derivative Volumes
The following table presents the gross notional amounts of derivative volumes at December 31, 2016 and 2015:
Successor | Predecessor | |||||||||
December 31, 2016 |
December 31, 2015 |
|||||||||
Derivative type |
Notional Volume |
Notional Volume |
Unit of Measure | |||||||
Natural gas (a) |
1,282 | 1,489 | Million MMBtu | |||||||
Electricity |
75,322 | 58,022 | GWh | |||||||
Congestion Revenue Rights (b) |
126,573 | 106,260 | GWh | |||||||
Coal |
12 | 10 | Million US tons | |||||||
Fuel oil |
34 | 35 | Million gallons | |||||||
Uranium |
25 | 75 | Thousand pounds | |||||||
Interest rate swaps — Floating/Fixed (c) |
$ | 3,000 | $ | — | Million US dollars |
(a) | Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions. |
(b) | Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT. |
(c) | Successor period includes notional amounts of interest rate swaps that become effective in January 2017 and have maturity dates through July 2023. |
Credit Risk-Related Contingent Features of Derivatives
The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of these agreements require the posting of collateral if our credit rating is downgraded by one or more credit rating agencies.
At December 31, 2016 and 2015, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully collateralized totaled $13 million and $58 million, respectively. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with counterparties totaling $1 million and $31 million at December 31, 2016 and 2015, respectively. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross-default provisions, remaining liquidity requirements would be immaterial at both December 31, 2016 and 2015.
In addition, certain derivative agreements include cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. At December 31, 2016 and 2015, the fair value of derivative liabilities subject to such cross-default provisions totaled $18 million and $1 million, respectively. At December 31, 2016 and 2015, no cash collateral or letters of credit were posted with these counterparties, and the liquidity exposure associated with these liabilities totaled $17 million and zero at December 31, 2016 and 2015, respectively.
As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $31 million and $59 million at December 31, 2016 and 2015, respectively. These amounts are before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets subject to related liens.
Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.
Concentrations of Credit Risk Related to Derivatives
We have concentrations of credit risk with the counterparties to our derivative contracts. At December 31, 2016, total credit risk exposure to all counterparties related to derivative contracts totaled $555 million (including associated accounts receivable). The net exposure to those counterparties totaled $306 million at December 31, 2016 after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling $88 million. At December 31, 2016, the credit risk exposure to the banking and financial sector represented 59% of the total credit risk exposure and 39% of the net exposure.
Exposure to banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because all of this exposure is with counterparties with investment grade credit ratings. However, this concentration increases the risk that a default by any of these counterparties would have a material effect on our financial condition, results of operations and liquidity. The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating.
We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies authorize specific risk mitigation tools including, but not limited to, use of standardized master agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the derivative contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
|
18. PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS
On the Effective Date, the EFH Retirement Plan was transferred to Vistra Energy pursuant to a separation agreement between Vistra Energy and EFH Corp. As of the Effective Date, Vistra Energy is the plan sponsor of the Vistra Retirement Plan (the Retirement Plan), which provides benefits to eligible employees of its subsidiaries. Oncor is a participant in the Retirement Plan. As Vistra Energy accounts for its interests in the Retirement Plan as a multiple employer plan, only Vistra Energy’s share of the plan assets and obligations are reported in the pension benefit information presented below. After amendments in 2012, employees in the Retirement Plan now consist entirely of active and retired collective bargaining unit employees. The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs. It is our policy to fund the Retirement Plan assets only to the extent deductible under existing federal tax regulations.
Vistra Energy offers other postretirement employee benefits (OPEB) in the form of health care and life insurance to eligible employees of its subsidiaries and their eligible dependents upon the retirement of such employees. Vistra Energy is the sponsor of an OPEB plan that EFH Corp. participates in, and Oncor is the sponsor of an OPEB plan that Vistra Energy participates in. As Vistra Energy accounts for its interest in these OPEB plans as multiple employer plans, only Vistra Energy’s share of the plan assets and obligations are reported in postretirement benefits other than pension information presented below. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.
Pension and OPEB Costs
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Pension costs |
$ | 2 | $ | 4 | $ | 8 | $ | 7 | ||||||||
OPEB costs |
2 | — | 3 | 5 | ||||||||||||
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Total benefit costs recognized as expense |
$ | 4 | $ | 4 | $ | 11 | $ | 12 | ||||||||
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Market-Related Value of Assets Held in Postretirement Benefit Trusts
We use the calculated value method to determine the market-related value of the assets held in the trust for purposes of calculating pension costs. We include the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
Detailed Information Regarding Pension Benefits
The following information is based on a December 31, 2016 measurement date:
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Assumptions Used to Determine Net Periodic Pension Cost: |
||||
Discount rate |
3.79 | % | ||
Expected return on plan assets |
4.89 | % | ||
Expected rate of compensation increase |
3.50 | % | ||
Components of Net Pension Cost: |
||||
Service cost |
$ | 2 | ||
Interest cost |
1 | |||
Expected return on assets |
(1 | ) | ||
|
|
|||
Net periodic pension cost |
$ | 2 | ||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: |
||||
Net gain |
$ | (4 | ) | |
|
|
|||
Total recognized in net periodic benefit cost and other comprehensive income |
$ | (2 | ) | |
|
|
|||
Assumptions Used to Determine Benefit Obligations: |
||||
Discount rate |
4.31 | % | ||
Expected rate of compensation increase |
3.50 | % |
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Change in Pension Obligation: |
||||
Projected benefit obligation at beginning of period |
$ | 154 | ||
Service cost |
2 | |||
Interest cost |
1 | |||
Actuarial gain |
(12 | ) | ||
Benefits paid |
(1 | ) | ||
|
|
|||
Projected benefit obligation at end of year |
$ | 144 | ||
|
|
|||
Accumulated benefit obligation at end of year |
$ | 136 | ||
|
|
|||
Change in Plan Assets: |
||||
Fair value of assets at beginning of period |
$ | 124 | ||
Actual loss on assets |
(6 | ) | ||
Benefits paid |
(1 | ) | ||
|
|
|||
Fair value of assets at end of year |
$ | 117 | ||
|
|
|||
Funded Status: |
||||
Projected pension benefit obligation |
$ | (144 | ) | |
Fair value of assets |
117 | |||
|
|
|||
Funded status at end of year |
$ | (27 | ) | |
|
|
|||
Amounts Recognized in Accumulated Other Comprehensive Income Consist of: |
||||
Net gain |
$ | 4 | ||
|
|
The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.
Successor | ||||
December 31, 2016 |
||||
Pension Plans with PBO and ABO in Excess Of Plan Assets: |
||||
Projected benefit obligations |
$ | 144 | ||
Accumulated benefit obligation |
$ | 136 | ||
Plan assets |
$ | 117 |
Pension Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Fixed income securities held primarily consist of corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Equity securities are held to enhance returns by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging markets.
The target asset allocation ranges of pension plan investments by asset category are as follows:
Asset Category: | Target Allocation Ranges |
|
Fixed income |
74% - 86% | |
US equities |
8% - 14% | |
International equities |
6% - 12% |
Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan’s advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Retirement Plan |
||||
Asset Class: | Expected Long- Term Rate of Return |
|||
US equity securities |
6.4 | % | ||
International equity securities |
7.0 | % | ||
Fixed income securities |
4.2 | % | ||
Weighted average |
4.9 | % |
Fair Value Measurement of Pension Plan Assets
At December 31, 2016, pension plan assets measured at fair value on a recurring basis consisted of the following:
Successor | ||||
Asset Category: | December 31, 2016 |
|||
Level 2 valuations (see Note 16): |
||||
Interest-bearing cash |
$ | (4 | ) | |
Fixed income securities: |
||||
Corporate bonds (a) |
54 | |||
US Treasuries |
30 | |||
Other (b) |
6 | |||
|
|
|||
Total assets categorized as Level 2 |
86 | |||
Assets measured at net asset value (c): |
||||
Interest-bearing cash |
2 | |||
Equity securities: |
||||
US |
14 | |||
International |
9 | |||
Fixed income securities: |
||||
Corporate bonds (a) |
6 | |||
|
|
|||
Total assets measured at net asset value |
31 | |||
|
|
|||
Total assets |
$ | 117 | ||
|
|
(a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
(b) | Other consists primarily of municipal bonds. |
(c) | Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to total Vistra Retirement Plan assets. |
Detailed Information Regarding Postretirement Benefits Other Than Pensions
The following OPEB information is based on a December 31, 2016 measurement date:
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Assumptions Used to Determine Net Periodic Benefit Cost: |
||||
Discount rate (Vistra Energy Plan) |
4.00 | % | ||
Discount rate (Oncor Plan) |
3.69 | % | ||
Components of Net Postretirement Benefit Cost: |
||||
Service cost |
$ | 1 | ||
Interest cost |
1 | |||
Plan amendments (a) |
(4 | ) | ||
|
|
|||
Net periodic OPEB cost |
$ | (2 | ) | |
|
|
|||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: |
||||
Net gain |
$ | (5 | ) | |
|
|
|||
Total recognized in net periodic benefit cost and other comprehensive income |
$ | (7 | ) | |
|
|
|||
Assumptions Used to Determine Benefit Obligations at Period End: |
||||
Discount rate (Vistra Energy Plan) |
4.11 | % | ||
Discount rate (Oncor Plan) |
4.18 | % |
(a) | Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees. |
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Change in Postretirement Benefit Obligation: |
||||
Benefit obligation at beginning of year |
$ | 97 | ||
Service cost |
1 | |||
Interest cost |
1 | |||
Participant contributions |
1 | |||
Plan amendments (a) |
(4 | ) | ||
Actuarial gain |
(5 | ) | ||
Benefits paid |
(3 | ) | ||
|
|
|||
Benefit obligation at end of year |
$ | 88 | ||
|
|
|||
Change in Plan Assets: |
||||
Fair value of assets at beginning of year |
$ | — | ||
Employer contributions |
1 | |||
Participant contributions |
1 | |||
Benefits paid |
(2 | ) | ||
|
|
|||
Fair value of assets at end of year |
$ | — | ||
|
|
|||
Funded Status: |
||||
Benefit obligation |
$ | 88 | ||
|
|
|||
Funded status at end of year |
$ | 88 | ||
|
|
|||
Amounts Recognized on the Balance Sheet Consist of: |
||||
Other current liabilities |
$ | 5 | ||
Other noncurrent liabilities |
83 | |||
|
|
|||
Net liability recognized |
$ | 88 | ||
|
|
|||
Amounts Recognized in Accumulated Other Comprehensive Income Consist of: |
||||
Net gain |
$ | 5 | ||
|
|
|||
Net amount recognized |
$ | 5 | ||
|
|
(a) | Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees. |
The following tables provide information regarding the assumed health care cost trend rates.
Successor | ||||
December 31, 2016 |
||||
Assumed Health Care Cost Trend Rates-Not Medicare Eligible: |
||||
Health care cost trend rate assumed for next year |
5.80 | % | ||
Rate to which the cost trend is expected to decline (the ultimate trend rate) |
5.00 | % | ||
Year that the rate reaches the ultimate trend rate |
2024 | |||
Assumed Health Care Cost Trend Rates-Medicare Eligible: |
||||
Health care cost trend rate assumed for next year |
5.70 | % | ||
Rate to which the cost trend is expected to decline (the ultimate trend rate) |
5.00 | % | ||
Year that the rate reaches the ultimate trend rate |
2024 |
1-Percentage Point Increase |
1-Percentage Point Decrease |
|||||||
Sensitivity Analysis of Assumed Health Care Cost Trend Rates: |
||||||||
Effect on accumulated postretirement obligation |
$ | (5 | ) | $ | 4 | |||
Effect on postretirement benefits cost |
$ | — | $ | — |
Fair Value Measurement of OPEB Plan Assets
At December 31, 2016, the Vistra Energy OPEB plan had no plan assets.
Significant Concentrations of Risk
The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rate using the Aon Hewitt AA Above Median yield curve, which is based on corporate bond yields and at December 31, 2016 consisted of 489 corporate bonds with an average rating of AA using Moody’s, Standard & Poor’s Rating Services and Fitch Ratings, Ltd. ratings.
Amortization in 2017
We estimate amortization of the net actuarial gain for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be immaterial. We estimate amortization of the net actuarial gain and prior service credit for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be immaterial.
Contributions
No contributions are expected to be made to the pension plan in 2017. OPEB plan funding in the period from October 3, 2016 through December 31, 2016 totaled $1 million, and funding in 2017 is expected to total $5 million.
In September 2016, a cash contribution totaling $2 million was made to the EFH Retirement Plan, all of which was contributed by our Predecessor. In December 2015, a cash contribution totaling $67 million was made to the EFH Retirement Plan assets, of which $51 million was contributed by Oncor and $16 million was contributed by our Predecessor. Each of these contributions resulted in the Retirement Plan being fully funded as calculated under the provisions of ERISA. As a result of the Bankruptcy Filing, participants in the EFH Retirement Plan who chose to retire would not be eligible for the lump sum payout option under the EFH Retirement Plan unless the EFH Retirement Plan was fully funded. OPEB plan funding in the period from January 1, 2016 through October 2, 2016 totaled $3 million.
Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
2017 | 2018 | 2019 | 2020 | 2021 | 2022-26 | |||||||||||||||||||
Pension benefits |
$ | 6 | $ | 6 | $ | 7 | $ | 8 | $ | 8 | $ | 53 | ||||||||||||
OPEB |
$ | 5 | $ | 5 | $ | 5 | $ | 6 | $ | 6 | $ | 32 |
Thrift Plan
Our employees may participate in a qualified savings plan (the Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 20% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% (75% for employees covered under the Traditional Retirement Plan Formula) of the first 6% of employee contributions. Employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options.
Employer contributions to the Thrift Plan totaled $5 million, $16 million, $21 million and $21 million for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively.
|
19. STOCK-BASED COMPENSATION
Vistra Energy 2016 Omnibus Incentive Plan
On the Effective Date, the Vistra Energy board of directors (Board) adopted the 2016 Omnibus Incentive Plan (2016 Incentive Plan), under which an aggregate of 22,500,000 shares of our common stock were reserved for issuance as equity-based awards to our non-employee directors, employees, and certain other persons. The Board or any committee duly authorized by the Board will administer the 2016 Incentive Plan and has broad authority under the 2016 Incentive Plan to, among other things: (a) select participants, (b) determine the types of awards that participants are to receive and the number of shares that are to be subject to such awards and (c) establish the terms and conditions of awards, including the price (if any) to be paid for the shares of the award. The types of awards that may be granted under the 2016 Incentive Plan include stock options, RSUs, restricted stock, performance awards and other forms of awards granted or denominated in shares of Vistra Energy common stock, as well as certain cash-based awards.
If any stock option or other stock-based award granted under the 2016 Incentive Plan expires, terminates or is canceled for any reason without having been exercised in full, the number of shares of Vistra Energy common stock underlying any unexercised award shall again be available for the purpose of awards under the 2016 Incentive Plan. If any shares of restricted stock, performance awards or other stock-based awards denominated in shares of Vistra Energy common stock awarded under the 2016 Incentive Plan are forfeited for any reason, the number of forfeited shares shall again be available for purposes of awards under the 2016 Incentive Plan. Any award under the 2016 Incentive Plan settled in cash shall not be counted against the maximum share limitation.
As is customary in incentive plans of this nature, each share limit and the number and kind of shares available under the 2016 Incentive Plan and any outstanding awards, as well as the exercise or purchase price of awards, and performance targets under certain types of performance-based awards, are required to be adjusted in the event of certain reorganizations, mergers, combinations, recapitalizations, stock splits, stock dividends or other similar events that change the number or kind of shares outstanding, and extraordinary dividends or distributions of property to the Vistra Energy stockholders.
Stock-based compensation expense is reported as SG&A in the statement of consolidated net income (loss) as follows:
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Total stock-based compensation expense |
$ | 3 | ||
Income tax benefit |
(1 | ) | ||
|
|
|||
Stock based-compensation expense, net of tax |
$ | 2 | ||
|
|
Stock Options
The table below summarizes information about stock options granted during the the Successor period from October 3, 2016 through December 31, 2016. The fair value of each stock option is estimated on the date of grant using a Black-Scholes option-pricing model. The risk-free interest rate used in the option valuation model was based on yields available on the grant dates for US Treasury Strips with maturity consistent with the expected life assumption. The expected term of the option represents the period of time that options granted are expected to be outstanding and is based on the SEC Simplified Method (midpoint of average vesting time and contractual term). Expected volatility is based on an average of the historical, daily volatility of a peer group selected by Vistra Energy over a period consistent with the expected life assumption ending on the grant date. We assumed no dividend yield in the valuation of the options. These options may be exercised over a four year graded vesting period and will expire ten years from the grant date. The 2016 Incentive Plan includes an anti-dilutive provision that requires any outstanding option awards to be adjusted for the effect of equity restructurings. In March 2017, the board of directors of Vistra Energy declared that the exercise price of each outstanding option be reduced by $2.32, the amount per share of common stock related to the Special Dividend (see Note 15). Stock options outstanding at December 31, 2016 are all held by current employees. The weighted average assumptions used to value grant options are detailed below:
Stock Options (in thousands) |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Term (Years) |
Aggregate Intrinsic Value (in millions) |
|||||||||||||
Total outstanding at beginning of period |
— | $ | — | — | $ | — | ||||||||||
Granted |
7,379 | $ | 15.81 | 9.81 | $ | — | ||||||||||
Forfeited or expired |
(22 | ) | $ | 15.58 | 9.81 | $ | — | |||||||||
|
|
|
|
|||||||||||||
Total outstanding at end of period |
7,357 | $ | 15.81 | 9.81 | $ | — | ||||||||||
Expected to vest |
7,357 | $ | 15.81 | 9.81 | $ | — |
At December 31, 2016, $32 million of unrecognized compensation cost related to unvested stock options granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of 3.8 years.
Restricted Stock Units
We granted 2.165 million restricted stock units to employees in the Successor period from October 3, 2016 through December 31, 2016.
Restricted Stock Units (in thousands) |
Weighted Average Grant Date Fair Value |
Weighted Average Remaining Contractual Term (Years) |
Aggregate Intrinsic Value (in millions) |
|||||||||||||
Total outstanding at beginning of period |
— | $ | — | — | $ | — | ||||||||||
Granted |
2,165 | $ | 15.79 | 2.3 | $ | 33.6 | ||||||||||
Forfeited or expired |
(6 | ) | $ | 15.58 | 2.3 | $ | (0.1 | ) | ||||||||
|
|
|
|
|||||||||||||
Total outstanding at end of period |
2,159 | $ | 15.79 | 2.3 | $ | 33.5 | ||||||||||
Expected to vest |
2,159 | $ | 15.79 | 2.3 | $ | 33.5 |
At December 31, 2016, $32 million of unrecognized compensation cost related to unvested restricted stock units granted under the 2016 Incentive Plan are expected to be recognized over a weighted average period of 3.8 years.
|
14. | RELATED PARTY TRANSACTIONS |
Successor
In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra Energy common stock held by such selling stockholders.
In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra Energy common stock held by certain significant stockholders pursuant to the Registration Rights Agreement. The registration statement was amended in February 2017, April 2017 and May 2017. The registration statement was declared effective by the SEC in May 2017. Among other things, under the terms of the Registration Rights Agreement:
• | we will be required to use reasonable best efforts to convert the Form S-1 registration statement into a registration statement on Form S-3 as soon as reasonably practicable after we become eligible to do so and to have such Form S-3 declared effective as promptly as practicable (but in no event more than 30 days after it is filed with the SEC); |
• | if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and |
• | the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra Energy common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed. |
All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us. Legal fee expenses paid or accrued by Vistra Energy on behalf of the selling stockholders totaled less than $1 million during both the three and nine months ended September 30, 2017.
Tax Receivable Agreement
On the Effective Date, Vistra Energy entered into the TRA with a transfer agent on behalf of certain former first lien creditors of TCEH. See Note 6 for discussion of the TRA.
Predecessor
See Note 2 for a discussion of certain agreements entered into on the Effective Date between EFH Corp. and Vistra Energy with respect to the separation of the entities, including a separation agreement, a transition services agreement, a tax matters agreement and a settlement agreement.
The following represent our Predecessor’s significant related-party transactions. As of the Effective Date, pursuant to the Plan of Reorganization, the Sponsor Group, EFH Corp., EFIH, Oncor Holdings and Oncor ceased being affiliates of Vistra Energy and its subsidiaries, including the TCEH Debtors and the Contributed EFH Debtors.
• | Our retail operations (and prior to the Effective Date, our Predecessor) pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled $265 million and $700 million for the three and nine months ended September 30, 2016, respectively. |
• | A former subsidiary of EFH Corp. billed our Predecessor’s subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are largely settled in cash and primarily reported in SG&A expenses, totaled $51 million and $157 million for the three and nine months ended September 30, 2016, respectively. |
• | Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to Vistra Energy (and prior to the Effective Date, our Predecessor) for contribution to the trust fund with the intent that the trust fund assets, reported in other investments in our condensed consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in asset retirement obligations in our condensed consolidated balance sheets. The delivery fee surcharges remitted to our Predecessor totaled $6 million and $15 million for the three and nine months ended September 30, 2016, respectively. Income and expenses associated with the trust fund and the decommissioning liability incurred by Vistra Energy (and prior to the Effective Date, our Predecessor) are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor’s delivery fee rates. |
• | EFH Corp. files consolidated federal income tax and Texas state margin tax returns that included our results prior to the Effective Date; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., were recorded as if our Predecessor filed its own corporate income tax return. For the nine months ended September 30, 2016, our Predecessor made income tax payments totaling $22 million to EFH Corp. |
• | In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with TCEH and/or provided financial advisory services to TCEH, in each case in the normal course of business. |
• | Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with our Predecessor in the normal course of business. |
• | Affiliates of the Sponsor Group have sold or acquired, and in the future may sell or acquire, debt or debt securities issued by our Predecessor in open market transactions or through loan syndications. |
20. RELATED-PARTY TRANSACTIONS
Successor
In connection with Emergence, we entered into agreements with certain of our affiliates and with parties who received shares of common stock and TRA Rights in exchange for their claims.
Registration Rights Agreement
Pursuant to the Plan of Reorganization, on the Effective Date, we entered into a Registration Rights Agreement (the Registration Rights Agreement) with certain selling stockholders providing for registration of the resale of the Vistra Energy common stock held by such selling stockholders.
In December 2016, we filed a Form S-1 registration statement with the SEC to register for resale the shares of Vistra Energy common stock held by certain significant stockholders pursuant to the Registration Rights Agreement. The registration statement was amended in February 2017. The registration statement has not yet been declared effective by the SEC. Among other things, under the terms of the Registration Rights Agreement:
• | we will be required to use reasonable best efforts to convert the Form S-1 registration statement into a registration statement on Form S-3 as soon as reasonably practicable after we become eligible to do so and to have such Form S-3 declared effective as promptly as practicable (but in no event more than 30 days after it is filed with the SEC); |
• | if we propose to file certain types of registration statements under the Securities Act with respect to an offering of equity securities, we will be required to use our reasonable best efforts to offer the other parties to the Registration Rights Agreement the opportunity to register all or part of their shares on the terms and conditions set forth in the Registration Rights Agreement; and |
• | the selling stockholders received the right, subject to certain conditions and exceptions, to request that we file registration statements or amend or supplement registration statements, with the SEC for an underwritten offering of all or part of their respective shares of Vistra Energy common stock (a Demand Registration), and the Company is required to cause any such registration statement or amendment or supplement (a) to be filed with the SEC promptly and, in any event, on or before the date that is 45 days, in the case of a registration statement on Form S-1, or 30 days, in the case of a registration statement on Form S-3, after we receive the written request from the relevant selling stockholders to effectuate the Demand Registration and (b) to become effective as promptly as reasonably practicable and in any event no later than 120 days after it is initially filed. |
All expenses of registration under the Registration Rights Agreement, including the legal fees of one counsel retained by or on behalf of the selling stockholders, will be paid by us. There were no legal fee expenses paid or accrued by Vistra Energy on behalf of the selling stockholders during the Successor period from October 3, 2016 through December 31, 2016.
Tax Receivable Agreement
On the Effective Date, Vistra Energy entered into the TRA with a transfer agent on behalf of certain former first lien creditors of TCEH. See Note 10 for discussion of the TRA.
Predecessor
See Note 2 for a discussion of certain agreements entered into on the Effective Date between EFH Corp. and Vistra Energy with respect to the separation of the entities, including a separation agreement, a transition services agreement, a tax matters agreement and a settlement agreement.
The following represent our Predecessor’s significant related-party transactions. As of the Effective Date, pursuant to the Plan of Reorganization, the Sponsor Group, EFH Corp., EFIH, Oncor Holdings and Oncor ceased being affiliates of Vistra Energy and its subsidiaries, including the TCEH Debtors and the Contributed EFH Debtors.
• | Our retail operations (and prior to the Effective Date, our Predecessor) pay Oncor for services it provides, principally the delivery of electricity. Expenses recorded for these services, reported in fuel, purchased power costs and delivery fees, totaled approximately $700 million, $955 million and $971 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. The consolidated balance sheet at December 31, 2015 reflected amounts due currently to Oncor totaling $118 million (included in trade accounts and other payables to affiliates) largely related to these electricity delivery fees. |
• | Contributions to the EFH Corp. retirement plan by both Oncor and TCEH in 2014, 2015 and 2016 resulted in the EFH Corp. retirement plan being fully funded as calculated under the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). In September 2016, a cash contribution totaling $2 million was made to the EFH Corp. retirement plan, all of which was contributed by TCEH, which resulted in the EFH Retirement Plan continuing to be fully funded as calculated under the provisions of ERISA. The balance of the advance totaled $24 million at December 31, 2015, with $6 million recorded as a current asset and $18 million recorded as a noncurrent asset. On the Effective Date, the EFH Retirement Plan was transferred to Vistra Energy pursuant to a separation agreement between Vistra Energy and EFH Corp., and the advance was settled as part of fresh-start reporting. |
• | Receivables from affiliates were measured at historical cost and primarily consisted of notes receivable for cash loaned by our Predecessor to EFH Corp. for debt principal and interest payments and other general corporate purposes of EFH Corp. as discussed above. Our Predecessor reviewed economic conditions, counterparty credit scores and historical payment activity to assess the overall collectability of its affiliated receivables. There were no credit loss allowances at December 31, 2015. |
• | A former subsidiary of EFH Corp. billed our subsidiaries for information technology, financial, accounting and other administrative services at cost. These charges, which are largely settled in cash and primarily reported in SG&A expenses, totaled $157 million, $205 million and $204 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. These amounts included allocated expense, which totaled $10 million for the year ended December 31, 2014, for management fees owed and paid by EFH Corp. to the Sponsor Group. Effective with the Petition Date, EFH Corp. suspended allocations of such fees to TCEH. Fees accrued as of the Petition Date were classified as LSTC and were eliminated in December 2015 as part of the Settlement Agreement. |
• | Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility is funded by a delivery fee surcharge billed to REPs by Oncor, as collection agent, and remitted monthly to a subsidiary of Vistra Energy (and prior to the Effective Date, our Predecessor) for contribution to the trust fund with the intent that the trust fund assets, reported in investments in the consolidated balance sheets, will ultimately be sufficient to fund the future decommissioning liability, reported in noncurrent liabilities in the consolidated balance sheets. The delivery fee surcharges remitted to our Predecessor totaled $15 million, $17 million and $17 million for the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. Income and expenses associated with the trust fund and the decommissioning liability incurred by a subsidiary of Vistra Energy (and prior to the Effective Date, our Predecessor) are offset by a net change in a receivable/payable that ultimately will be settled through changes in Oncor’s delivery fee rates. At December 31, 2015, the excess of the trust fund balance over the decommissioning liability resulted in a payable totaling $409 million and is reported in noncurrent liabilities. |
• | EFH Corp. files consolidated federal income tax and Texas state margin tax returns that included our results prior to the Effective Date; however, under a Federal and State Income Tax Allocation Agreement, our federal income tax and Texas margin tax expense and related balance sheet amounts, including income taxes payable to or receivable from EFH Corp., were recorded as if our Predecessor filed its own corporate income tax return. As of December 31, 2015, our Predecessor had current income tax liabilities due to EFH Corp. of $11 million. Our Predecessor made tax payments to EFH Corp. of $22 million, $29 million and $31 million for the Predecessor period from January 1, 2016 through December 31, 2016 and the years ended December 31, 2015 and 2014, respectively. In 2015, $609 million of income tax liability was eliminated under the terms of the Settlement Agreement. See Note 9 for discussion of cessation of payment of federal income taxes pursuant to the Settlement Agreement. |
• | In 2007, TCEH entered into the TCEH Senior Secured Facilities with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of each member of the Sponsor Group have from time to time engaged in commercial banking transactions with TCEH and/or provided financial advisory services to TCEH, in each case in the normal course of business. |
• | Affiliates of GS Capital Partners were parties to certain commodity and interest rate hedging transactions with our Predecessor in the normal course of business. |
• | Affiliates of the Sponsor Group sold or acquired debt or debt securities issued by our Predecessor in open market transactions or through loan syndications. |
• | As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debt securities at December 31, 2014 as shown below (principal amounts). The $382 million in notes payable as of the Petition Date was classified as LSTC. The amounts of TCEH debt held by EFIH or EFH Corp. were eliminated as a result of the Settlement Agreement approved by the Bankruptcy Court in December 2015 (see Note 2). In conjunction with the Settlement Agreement approved by the Bankruptcy Court in December 2015, EFH Corp. and EFIH waived their rights to the claims associated with these debt securities resulting in a gain recorded in reorganization items (see Note 4). |
Principal Amount |
||||
TCEH Senior Notes: |
||||
Held by EFH Corp. |
$ | 284 | ||
Held by EFIH |
79 | |||
TCEH Term Loan Facilities: |
||||
Held by EFH Corp. |
19 | |||
|
|
|||
Total |
$ | 382 | ||
|
|
Interest expense on the notes totaled $1 million and $13 million for the years ended December 31, 2015 and 2014, respectively. Contractual interest, not paid or recorded, totaled $37 million and $25 million for the years ended December 31, 2015 and 2014, respectively. See Note 11.
2. | RESTRICTIONS ON SUBSIDIARIES |
The agreement governing the Vistra Operations Credit Facilities (the Credit Facilities Agreement) generally restricts the ability of Vistra Operations to make distributions to any direct or indirect parent unless such distributions are expressly permitted thereunder. As of December 31, 2016, Vistra Operations Company LLC (Vistra Operations) can distribute approximately $1.1 billion to Vistra Energy Corp. (Parent) under the Credit Facilities Agreement without the consent of any party. Additionally, Vistra Operations may make distributions to Vistra Energy Corp. (Parent) in amounts sufficient for Vistra Energy Corp. (Parent) to make any payments required under the Tax Receivables Agreement or the Tax Matters Agreement or, to the extent arising out of Vistra Energy Corp.’s (Parent) ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses.
|
15. | SEGMENT INFORMATION |
The operations of Vistra Energy are aligned into two reportable business segments: Wholesale Generation and Retail Electricity. Our chief operating decision maker reviews the results of these two segments separately and allocates resources to the respective segments as part of our strategic operations. These two business units offer different products or services and involve different risks.
The Wholesale Generation segment is engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely in the ERCOT market. These activities are substantially all conducted by Luminant.
The Retail Electricity segment is engaged in retail sales of electricity and related services to residential, commercial and industrial customers, all largely in the ERCOT market. These activities are substantially all conducted by TXU Energy.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our Wholesale Generation and Retail Electricity segments.
The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1 to the Financial Statements in our December 31, 2016 audited financial statements. Our chief operating decision maker uses more than one measure to assess segment performance, including reported segment operating income and segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices. Certain shared services costs are allocated to the segments.
Three Months Ended September 30, 2017 |
Nine Months Ended September 30, 2017 |
|||||||
Operating revenues (a) |
||||||||
Wholesale Generation |
$ | 1,203 | $ | 2,757 | ||||
Retail Electricity |
1,286 | 3,136 | ||||||
Eliminations |
(656 | ) | (1,406 | ) | ||||
|
|
|
|
|||||
Consolidated operating revenues |
$ | 1,833 | $ | 4,487 | ||||
|
|
|
|
|||||
Depreciation and amortization |
||||||||
Wholesale Generation |
$ | 60 | $ | 167 | ||||
Retail Electricity |
108 | 322 | ||||||
Corporate and Other |
10 | 30 | ||||||
|
|
|
|
|||||
Consolidated depreciation and amortization |
$ | 178 | $ | 519 | ||||
|
|
|
|
|||||
Operating income (loss) |
||||||||
Wholesale Generation |
$ | 469 | $ | 651 | ||||
Retail Electricity |
(3 | ) | 54 | |||||
Corporate and Other |
(14 | ) | (47 | ) | ||||
|
|
|
|
|||||
Consolidated operating income |
$ | 452 | $ | 658 | ||||
|
|
|
|
|||||
Net income (loss) |
||||||||
Wholesale Generation |
$ | 469 | $ | 653 | ||||
Retail Electricity |
7 | 77 | ||||||
Corporate and Other |
(203 | ) | (405 | ) | ||||
|
|
|
|
|||||
Consolidated net income |
$ | 273 | $ | 325 | ||||
|
|
|
|
(a) |
For the three and nine months ended September 30, 2017, includes third-party unrealized net gains from mark-to-market valuations of commodity positions of $137 million and $204 million, respectively, recorded to the Wholesale Generation segment and $2 million and $11 million, respectively, recorded to the Retail Electricity segment. In addition, for the three and nine months ended September 30, 2017, unrealized net gains with affiliate of $89 million and $171 million, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net losses with affiliate of $(89) million and $(171) million, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results. |
September 30, 2017 |
December 31, 2016 |
|||||||
Total assets |
||||||||
Wholesale Generation |
$ | 7,445 | $ | 6,952 | ||||
Retail Electricity |
5,926 | 5,753 | ||||||
Corporate and Other and Eliminations |
1,629 | 2,462 | ||||||
|
|
|
|
|||||
Consolidated total assets |
$ | 15,000 | $ | 15,167 | ||||
|
|
|
|
21. SEGMENT INFORMATION
The operations of Vistra Energy are aligned into two reportable business segments: Wholesale Generation and Retail Electricity. Our chief operating decision maker reviews the results of these two segments separately and allocates resources to the respective segments as part of our strategic operations. These two business units offer different products or services and involve different risks.
The Wholesale Generation segment is engaged in electricity generation, wholesale energy sales and purchases, commodity risk management activities, fuel production and fuel logistics management, all largely in the ERCOT market. These activities are substantially all conducted by Luminant.
The Retail Electricity segment is engaged in retail sales of electricity and related services to residential, commercial and industrial customers, all largely in the ERCOT market. These activities are substantially all conducted by TXU Energy.
Corporate and Other represents the remaining non-segment operations consisting primarily of general corporate expenses, interest, taxes and other expenses related to our support functions that provide shared services to our Wholesale Generation and Retail Electricity segments.
The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. Our chief operating decision maker uses more than one measure to assess segment performance, including reported segment operating income and segment net income (loss), which is the measure most comparable to consolidated net income (loss) prepared based on GAAP. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices or regulated rates. Certain shared services costs are allocated to the segments.
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Operating revenues (a) |
||||
Wholesale Generation |
$ | 450 | ||
Retail Electricity |
912 | |||
Eliminations |
(171 | ) | ||
|
|
|||
Consolidated operating revenues |
$ | 1,191 | ||
Depreciation and amortization |
||||
Wholesale Generation |
$ | 53 | ||
Retail Electricity |
153 | |||
Corporate and Other |
11 | |||
Eliminations |
(1 | ) | ||
|
|
|||
Consolidated depreciation and amortization |
$ | 216 | ||
|
|
|||
Operating income (loss) |
||||
Wholesale Generation |
$ | (255 | ) | |
Retail Electricity |
111 | |||
Corporate and Other |
(17 | ) | ||
|
|
|||
Consolidated operating income (loss) |
$ | (161 | ) | |
|
|
|||
Interest expense and related charges |
||||
Wholesale Generation |
$ | (1 | ) | |
Retail Electricity |
— | |||
Corporate and Other |
66 | |||
Eliminations |
(5 | ) | ||
|
|
|||
Consolidated interest expense and related charges |
$ | 60 | ||
|
|
|||
Income tax benefit (all Corporate and Other) |
$ | 70 | ||
|
|
|||
Net income (loss) |
||||
Wholesale Generation |
$ | (251 | ) | |
Retail Electricity |
114 | |||
Corporate and Other |
(26 | ) | ||
|
|
|||
Consolidated net income (loss) |
$ | (163 | ) | |
|
|
|||
Capital expenditures |
||||
Wholesale Generation |
$ | 84 | ||
Retail Electricity |
5 | |||
|
|
|||
Consolidated capital expenditures |
$ | 89 | ||
|
|
(a) | Includes third-party unrealized net losses from mark-to-market valuations of commodity positions of $182 million recorded to the Wholesale Generation segment and $6 million recorded to the Retail Electricity segment. In addition, an unrealized net loss with an affiliate of $113 million was recorded to the Wholesale Generation segment which is eliminated in the consolidated results. |
Successor | ||||
December 31, 2016 |
||||
Total assets |
||||
Wholesale Generation |
$ | 6,952 | ||
Retail Electricity |
5,753 | |||
Corporate and Other and Eliminations |
2,462 | |||
|
|
|||
Consolidated total assets |
$ | 15,167 |
Prior to the Effective Date, our Predecessor’s chief operating decision maker reviewed the retail electricity, wholesale generation and commodity risk management activities together. Consequently, there were no reportable business segments for TCEH.
|
16. | SUPPLEMENTARY FINANCIAL INFORMATION |
Other Income and Deductions
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Other income: |
||||||||||||||||
Office space sublease rental income (a) |
$ | 3 | $ | — | $ | 9 | $ | — | ||||||||
Insurance settlement |
— | — | — | 9 | ||||||||||||
Sale of land (b) |
1 | 2 | 4 | 2 | ||||||||||||
Interest income |
4 | 2 | 10 | 3 | ||||||||||||
All other |
2 | 3 | 6 | 5 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income |
$ | 10 | $ | 7 | $ | 29 | $ | 19 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Other deductions: |
||||||||||||||||
Write-off of generation equipment (b) |
$ | — | $ | 4 | $ | 2 | $ | 45 | ||||||||
Adjustment to asbestos liability |
— | 11 | — | 11 | ||||||||||||
Fees associated with TCEH DIP Roll Facilities |
— | 5 | — | 5 | ||||||||||||
All other |
— | 8 | 3 | 14 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other deductions |
$ | — | $ | 28 | $ | 5 | $ | 75 | ||||||||
|
|
|
|
|
|
|
|
(a) | Reported in Corporate and Other non-segment (Successor period only). |
(b) | Reported in Wholesale Generation segment (Successor period only). |
Restricted Cash
September 30, 2017 | December 31, 2016 | |||||||||||||||
Current Assets |
Noncurrent Assets |
Current Assets |
Noncurrent Assets |
|||||||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 9) |
$ | — | $ | 650 | $ | — | $ | 650 | ||||||||
Amounts related to restructuring escrow accounts |
61 | — | 90 | — | ||||||||||||
Other |
— | — | 5 | — | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total restricted cash |
$ | 61 | $ | 650 | $ | 95 | $ | 650 | ||||||||
|
|
|
|
|
|
|
|
Trade Accounts Receivable
September 30, 2017 |
December 31, 2016 |
|||||||
Wholesale and retail trade accounts receivable |
$ | 738 | $ | 622 | ||||
Allowance for uncollectible accounts |
(21 | ) | (10 | ) | ||||
|
|
|
|
|||||
Trade accounts receivable — net |
$ | 717 | $ | 612 | ||||
|
|
|
|
Gross trade accounts receivable at September 30, 2017 and December 31, 2016 included unbilled retail revenues of $250 million and $225 million, respectively.
Allowance for Uncollectible Accounts Receivable
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||
Allowance for uncollectible accounts receivable at beginning of period |
$ | 10 | $ | 9 | ||||
Increase for bad debt expense |
35 | 20 | ||||||
Decrease for account write-offs |
(24 | ) | (16 | ) | ||||
|
|
|
|
|||||
Allowance for uncollectible accounts receivable at end of period |
$ | 21 | $ | 13 | ||||
|
|
|
|
Inventories by Major Category
September 30, 2017 |
December 31, 2016 |
|||||||
Materials and supplies |
$ | 172 | $ | 173 | ||||
Fuel stock |
102 | 88 | ||||||
Natural gas in storage |
21 | 24 | ||||||
|
|
|
|
|||||
Total inventories |
$ | 295 | $ | 285 | ||||
|
|
|
|
Other Investments
September 30, 2017 |
December 31, 2016 |
|||||||
Nuclear plant decommissioning trust |
$ | 1,132 | $ | 1,012 | ||||
Land |
49 | 49 | ||||||
Miscellaneous other |
2 | 3 | ||||||
|
|
|
|
|||||
Total other investments |
$ | 1,183 | $ | 1,064 | ||||
|
|
|
|
Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited by Vistra Energy (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a receivable reported in noncurrent assets) that will ultimately be settled through changes in Oncor’s delivery fees rates. The nuclear decommissioning trust fund was not a debtor in the Chapter 11 Cases. A summary of investments in the fund follows:
September 30, 2017 | ||||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value |
|||||||||||||
Debt securities (b) |
$ | 352 | $ | 14 | $ | (1 | ) | $ | 365 | |||||||
Equity securities (c) |
321 | 451 | (5 | ) | 767 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 673 | $ | 465 | $ | (6 | ) | $ | 1,132 | |||||||
|
|
|
|
|
|
|
|
December 31, 2016 | ||||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value |
|||||||||||||
Debt securities (b) |
$ | 333 | $ | 10 | $ | (3 | ) | $ | 340 | |||||||
Equity securities (c) |
309 | 368 | (5 | ) | 672 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 642 | $ | 378 | $ | (8 | ) | $ | 1,012 | |||||||
|
|
|
|
|
|
|
|
(a) | Includes realized gains and losses on securities sold. |
(b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.57% and 3.56% at September 30, 2017 and December 31, 2016, respectively, and an average maturity of 9 years at both September 30, 2017 and December 31, 2016. |
(c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
Debt securities held at September 30, 2017 mature as follows: $102 million in one to 5 years, $99 million in five to 10 years and $164 million after 10 years.
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Realized gains |
$ | 1 | $ | 3 | $ | 3 | $ | 3 | ||||||||
Realized losses |
$ | (1 | ) | $ | (2 | ) | $ | (3 | ) | $ | (2 | ) | ||||
Proceeds from sales of securities |
$ | 56 | $ | 46 | $ | 154 | $ | 201 | ||||||||
Investments in securities |
$ | (62 | ) | $ | (52 | ) | $ | (169 | ) | $ | (215 | ) |
Property, Plant and Equipment
At September 30, 2017 and December 31, 2016, property, plant and equipment of $4.746 billion and $4.443 billion, respectively, is stated net of accumulated depreciation and amortization of $318 million and $85 million, respectively.
Asset Retirement and Mining Reclamation Obligations (ARO)
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor. As part of fresh start reporting, new fair values were established for all AROs for the Successor.
At September 30, 2017, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled $1.223 billion, which exceeds the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor’s delivery fees, a corresponding regulatory asset has been recorded to our condensed consolidated balance sheet of $91 million in other noncurrent assets.
The following table summarizes the changes to these obligations, reported in other current liabilities and asset retirement obligations in our condensed consolidated balance sheets, for the nine months ended September 30, 2017:
Nuclear Plant Decommissioning |
Mining Land Reclamation |
Other | Total | |||||||||||||
Liability at December 31, 2016 |
$ | 1,200 | $ | 375 | $ | 151 | $ | 1,726 | ||||||||
Additions: |
||||||||||||||||
Accretion |
23 | 14 | 4 | 41 | ||||||||||||
Adjustment for change in estimates (a) |
— | 3 | 4 | 7 | ||||||||||||
Reductions: |
||||||||||||||||
Payments |
— | (23 | ) | — | (23 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at September 30, 2017 |
1,223 | 369 | 159 | 1,751 | ||||||||||||
Less amounts due currently |
— | (83 | ) | (2 | ) | (85 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Noncurrent liability at September 30, 2017 |
$ | 1,223 | $ | 286 | $ | 157 | $ | 1,666 | ||||||||
|
|
|
|
|
|
|
|
(a) | Relates to the impacts of accelerating the ARO associated with the planned retirement of the Monticello plant (see Note 17). |
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
September 30, 2017 |
December 31, 2016 |
|||||||
Unfavorable purchase and sales contracts |
$ | 39 | $ | 46 | ||||
Other, including retirement and other employee benefits |
193 | 174 | ||||||
|
|
|
|
|||||
Total other noncurrent liabilities and deferred credits |
$ | 232 | $ | 220 | ||||
|
|
|
|
Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $2 million and $6 million for the three months ended September 30, 2017 and 2016, respectively, and $7 million and $18 million for the nine months ended September 30, 2017 and 2016, respectively. See Note 4 for intangible assets related to favorable purchase and sales contracts.
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year |
Amount | |||
2017 |
$ | 10 | ||
2018 |
$ | 11 | ||
2019 |
$ | 9 | ||
2020 |
$ | 9 | ||
2021 |
$ | 1 |
Fair Value of Debt
September 30, 2017 | December 31, 2016 | |||||||||||||||
Debt: |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||||
Long-term debt under the Vistra Operations Credit Facilities (Note 9) |
$ | 4,484 | $ | 4,484 | $ | 4,515 | $ | 4,552 | ||||||||
Other long-term debt, excluding capital lease obligations (Note 9) |
30 | 27 | 36 | 32 | ||||||||||||
Mandatorily redeemable subsidiary preferred stock (Note 9) |
70 | 70 | 70 | 70 |
We determine fair value in accordance with accounting standards as discussed in Note 12, and at September 30, 2017, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg.
Supplemental Cash Flow Information
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||
Cash payments related to: |
||||||||
Interest paid (a) |
$ | 197 | $ | 1,064 | ||||
Capitalized interest |
(5 | ) | (9 | ) | ||||
|
|
|
|
|||||
Interest paid (net of capitalized interest) (a) |
$ | 192 | $ | 1,055 | ||||
Income taxes |
$ | 51 | $ | 22 | ||||
Reorganization items (b) |
$ | — | $ | 104 | ||||
Noncash investing and financing activities: |
||||||||
Construction expenditures (c) |
$ | 16 | $ | 53 |
(a) | Predecessor period includes amounts paid for adequate protection. |
(b) | Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court. |
(c) | Represents end-of-period accruals for ongoing construction projects. |
22. SUPPLEMENTARY FINANCIAL INFORMATION
Other Income and Deductions
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Other income: |
||||||||||||||||
Office space sublease rental income (a) |
$ | 2 | $ | — | $ | — | $ | — | ||||||||
Curtailment gain on employee benefit plans (a) |
4 | — | — | — | ||||||||||||
Mineral rights royalty income (b) |
1 | 3 | 4 | 4 | ||||||||||||
Insurance settlement |
— | 9 | — | — | ||||||||||||
All other |
2 | 4 | 13 | 12 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income |
$ | 9 | $ | 16 | $ | 17 | $ | 16 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Other deductions: |
||||||||||||||||
Adjustment to asbestos liability |
$ | — | $ | 11 | $ | — | $ | — | ||||||||
Write-off of generation equipment |
— | 45 | — | — | ||||||||||||
Fees associated with DIP Roll Facilities |
— | 5 | — | |||||||||||||
Impairment of favorable purchase contracts (Note 7) |
— | — | 8 | 183 | ||||||||||||
Impairment of emission allowances (Note 7) |
— | — | 55 | 80 | ||||||||||||
Impairment of mining development costs (Note 7) |
— | — | 19 | — | ||||||||||||
All other |
— | 14 | 11 | 18 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other deductions |
$ | — | $ | 75 | $ | 93 | $ | 281 | ||||||||
|
|
|
|
|
|
|
|
(a) | Corporate and Other nonsegment (Successor period only). |
(b) | Wholesale Generation segment (Successor period only). |
Restricted Cash
Successor | Predecessor | |||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||
Current Assets |
Noncurrent Assets |
Current Assets |
Noncurrent Assets |
|||||||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 13) |
$ | — | $ | 650 | $ | — | $ | — | ||||||||
Amounts related to the DIP Facility (Note 13) |
519 | — | ||||||||||||||
Amounts related to TCEH’s pre-petition Letter of Credit Facility (Note 5) |
— | — | — | 507 | ||||||||||||
Amounts related to restructuring escrow accounts |
90 | — | — | — | ||||||||||||
Other |
5 | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total restricted cash |
$ | 95 | $ | 650 | $ | 519 | $ | 507 | ||||||||
|
|
|
|
|
|
|
|
Trade Accounts Receivable
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Wholesale and retail trade accounts receivable |
$ | 622 | $ | 542 | ||||
Allowance for uncollectible accounts |
(10 | ) | (9 | ) | ||||
|
|
|
|
|||||
Trade accounts receivable — net |
$ | 612 | $ | 533 | ||||
|
|
|
|
Gross trade accounts receivable at December 31, 2016 and 2015 included unbilled revenues of $225 million and $231 million, respectively.
Allowance for Uncollectible Accounts Receivable
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Allowance for uncollectible accounts receivable at beginning of period |
$ | — | $ | 9 | $ | 15 | $ | 14 | ||||||||
Increase for bad debt expense |
(10 | ) | 20 | 34 | 38 | |||||||||||
Decrease for account write-offs |
— | (16 | ) | (40 | ) | (37 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Allowance for uncollectible accounts receivable at end of period |
$ | (10 | ) | $ | 13 | $ | 9 | $ | 15 | |||||||
|
|
|
|
|
|
|
|
Inventories by Major Category
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Materials and supplies |
$ | 173 | $ | 226 | ||||
Fuel stock |
88 | 170 | ||||||
Natural gas in storage |
24 | 32 | ||||||
|
|
|
|
|||||
Total inventories |
$ | 285 | $ | 428 | ||||
|
|
|
|
Investments
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Nuclear plant decommissioning trust |
$ | 1,012 | $ | 918 | ||||
Land |
49 | 36 | ||||||
Miscellaneous other |
3 | 8 | ||||||
|
|
|
|
|||||
Total investments |
$ | 1,064 | $ | 962 | ||||
|
|
|
|
Nuclear Decommissioning Trust — Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited by Vistra Energy (and prior to the Effective Date, a subsidiary of TCEH) in the trust fund. Income and expense associated with the trust fund and the decommissioning liability are offset by a corresponding change in a receivable/payable (currently a payable reported in noncurrent liabilities) that will ultimately be settled through changes in Oncor’s delivery fees rates. The nuclear decommissioning trust fund was not a debtor in the Chapter 11 Cases. A summary of investments in the fund follows:
Successor | ||||||||||||||||
December 31, 2016 | ||||||||||||||||
Cost (a) | Unrealized gain |
Unrealized loss |
Fair market value |
|||||||||||||
Debt securities (b) |
$ | 333 | $ | 10 | $ | (3 | ) | $ | 340 | |||||||
Equity securities (c) |
309 | 368 | (5 | ) | 672 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 642 | $ | 378 | $ | (8 | ) | $ | 1,012 | |||||||
|
|
|
|
|
|
|
|
Predecessor | ||||||||||||||||
December 31, 2015 | ||||||||||||||||
Cost (a) | Unrealized gain |
Unrealized loss |
Fair market value |
|||||||||||||
Debt securities (b) |
$ | 310 | $ | 11 | $ | (2 | ) | $ | 319 | |||||||
Equity securities (c) |
291 | 315 | (7 | ) | 599 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 601 | $ | 326 | $ | (9 | ) | $ | 918 | |||||||
|
|
|
|
|
|
|
|
(a) | Includes realized gains and losses on securities sold. |
(b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.56% and 3.68% at December 31, 2016 and 2015, respectively, and an average maturity of 9 years and 8 years at December 31, 2016 and 2015, respectively. |
(c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
Debt securities held at December 31, 2016 mature as follows: $102 million in one to five years, $90 million in five to ten years and $148 million after ten years.
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Realized gains |
$ | 1 | $ | 3 | $ | 1 | $ | 11 | ||||||||
Realized losses |
$ | — | $ | (2 | ) | $ | (1 | ) | $ | (2 | ) | |||||
Proceeds from sales of securities |
$ | 25 | $ | 201 | $ | 401 | $ | 314 | ||||||||
Investments in securities |
$ | (30 | ) | $ | (215 | ) | $ | (418 | ) | $ | (331 | ) |
Property, Plant and Equipment
Successor | ||||
December 31, 2016 |
||||
Successor |
||||
Wholesale Generation: |
||||
Generation and mining |
$ | 3,997 | ||
Retail Electricity |
3 | |||
Corporate and Other |
107 | |||
|
|
|||
Total |
4,107 | |||
Less accumulated depreciation |
(54 | ) | ||
|
|
|||
Net of accumulated depreciation |
4,053 | |||
Nuclear fuel (net of accumulated amortization of $31 million) |
166 | |||
Construction work in progress: |
||||
Wholesale Generation |
210 | |||
Retail Electricity |
6 | |||
Corporate and Other |
8 | |||
|
|
|||
Total construction work in progress |
224 | |||
|
|
|||
Property, plant and equipment — net |
$ | 4,443 | ||
|
|
Predecessor | ||||
December 31, 2015 |
||||
Predecessor |
||||
Generation and mining |
$ | 10,886 | ||
Other assets |
546 | |||
|
|
|||
Total |
11,432 | |||
Less accumulated depreciation |
(2,654 | ) | ||
|
|
|||
Net of accumulated depreciation |
8,778 | |||
Nuclear fuel (net of accumulated amortization of $1.383 billion) |
248 | |||
Construction work in progress |
323 | |||
|
|
|||
Property, plant and equipment — net |
$ | 9,349 | ||
|
|
Depreciation expense totaled $54 million, $401 million, $767 million and $1.154 billion for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively.
Our property, plant and equipment consists of our power generation assets, related mining assets, information system hardware, capitalized corporate office lease space and other leasehold improvements. At December 31, 2016, the capital lease for the building totaled $64 million with accumulated depreciation of less than $1 million. The estimated remaining useful lives range from 3 to 37 years for our property, plant and equipment.
Asset Retirement and Mining Reclamation Obligations (ARO)
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to changes in the nuclear plant decommissioning liability, as all costs are recoverable through the regulatory process as part of delivery fees charged by Oncor. As part of fresh start reporting, new fair values were established for all AROs for the Successor.
At December 31, 2016, the current value of our ARO related to our nuclear generation plant decommissioning totaled $1.2 billion, which exceeds the fair value of the assets contained in the nuclear decommissioning trust. Since the costs to ultimately decommission that plant are recoverable through the regulatory rate making process as part of Oncor’s delivery fees, a corresponding regulatory asset has been recorded to our consolidated balance sheet of $188 million in other noncurrent assets.
The following tables summarize the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the consolidated balance sheets for the Successor period ended December 31, 2016, and the Predecessor periods ended October 2, 2016 and December 31, 2015:
Successor: | Nuclear Plant Decommissioning |
Mining Land Reclamation |
Other | Total | ||||||||||||
Fair value of liability established at October 3, 2016 |
$ | 1,192 | $ | 374 | $ | 152 | $ | 1,718 | ||||||||
Additions: |
||||||||||||||||
Accretion — October 3, 2016 through December 31, 2016 |
8 | 5 | 1 | 14 | ||||||||||||
Reductions: |
||||||||||||||||
Payments — October 3, 2016 through December 31, 2016 |
— | (4 | ) | (2 | ) | (6 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at December 31, 2016 |
1,200 | 375 | 151 | 1,726 | ||||||||||||
Less amounts due currently |
— | (53 | ) | (2 | ) | (55 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Noncurrent liability at December 31, 2016 |
$ | 1,200 | $ | 322 | $ | 149 | $ | 1,671 | ||||||||
|
|
|
|
|
|
|
|
Predecessor: | Nuclear Plant Decommissioning |
Mining Land Reclamation |
Other | Total | ||||||||||||
Liability at January 1, 2015 |
$ | 413 | $ | 165 | $ | 36 | $ | 614 | ||||||||
Additions: |
||||||||||||||||
Accretion |
25 | 20 | 6 | 51 | ||||||||||||
Adjustment for new cost estimate (a) |
70 | — | — | 70 | ||||||||||||
Incremental reclamation costs (b) |
— | 84 | 69 | 153 | ||||||||||||
Reductions: |
||||||||||||||||
Payments |
— | (54 | ) | (4 | ) | (58 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at December 31, 2015 (c) |
508 | 215 | 107 | 830 | ||||||||||||
Additions: |
||||||||||||||||
Accretion — January 1, 2016 through October 2, 2016 |
22 | 16 | 5 | 43 | ||||||||||||
Adjustment for new cost estimate |
— | — | 1 | 1 | ||||||||||||
Incremental reclamation costs |
— | 14 | 12 | 26 | ||||||||||||
Reductions: |
||||||||||||||||
Payments — January 1, 2016 through October 2, 2016 |
— | (37 | ) | (3 | ) | (40 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at October 2, 2016 |
530 | 208 | 122 | 860 | ||||||||||||
Less amounts due currently |
— | (50 | ) | (1 | ) | (51 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Noncurrent liability at October 2, 2016 |
$ | 530 | $ | 158 | $ | 121 | $ | 809 | ||||||||
|
|
|
|
|
|
|
|
(a) | The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2015. Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occurs, and PUCT rules require a new cost estimate at least every five years. The increase in the liability was driven by increased security and fuel-handling costs. |
(b) | The adjustment for other asset retirement obligations resulted from the effect on our estimated retirement obligation related to coal combustion residual facilities at our lignite/coal fueled generation facilities that arose from the Disposal of Coal Combustion Residuals from Electric Utilities rule. |
(c) | Includes $66 million recorded to other current liabilities in the consolidated balance sheet of the Predecessor. |
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Unfavorable purchase and sales contracts |
$ | 46 | $ | 543 | ||||
Nuclear decommissioning fund excess over asset retirement obligation (Note 20) |
— | 409 | ||||||
Uncertain tax positions, including accrued interest |
— | 41 | ||||||
Other, including retirement and other employee benefits |
174 | 22 | ||||||
|
|
|
|
|||||
Total other noncurrent liabilities and deferred credits |
$ | 220 | $ | 1,015 | ||||
|
|
|
|
Unfavorable Purchase and Sales Contracts — The amortization of unfavorable purchase and sales contracts totaled $3 million, $18 million, $23 million and $23 million for the Successor period from October 3, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. See Note 7 for intangible assets related to favorable purchase and sales contracts.
Fair Value of Debt
Successor | Predecessor | |||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||
Debt: |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||||
Long-term debt under the Vistra Operations Credit Facilities (Note 13) |
$ | 4,515 | $ | 4,552 | $ | — | $ | — | ||||||||
Other long-term debt, excluding capital lease obligations (Note 13) |
$ | 36 | $ | 32 | $ | 14 | $ | 15 | ||||||||
Mandatorily redeemable preferred stock (Note 13) |
$ | 70 | $ | 70 | $ | — | $ | — | ||||||||
Borrowings under debtor-in-possession or senior secured exit facilities (Note 13) |
$ | — | $ | — | $ | 1,425 | $ | 1,411 |
We determine fair value in accordance with accounting standards as discussed in Note 16, and at December 31, 2016, our debt fair value represents Level 2 valuations. We obtain security pricing from an independent party who uses broker quotes and third-party pricing services to determine fair values. Where relevant, these prices are validated through subscription services such as Bloomberg. The fair value estimates of Predecessor pre-petition notes, loans and other debt reported as liabilities subject to compromise have been excluded from the table above.
Supplemental Cash Flow Information
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Cash payments related to: |
||||||||||||||||
Interest paid (a) |
$ | 19 | $ | 1,064 | $ | 1,298 | $ | 1,252 | ||||||||
Capitalized interest |
(3 | ) | (9 | ) | (11 | ) | (17 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Interest paid (net of capitalized interest) (a) |
$ | 16 | $ | 1,055 | $ | 1,287 | $ | 1,235 | ||||||||
Reorganization items (b) |
$ | — | $ | 104 | $ | 224 | $ | 93 | ||||||||
Income taxes paid (refund) |
$ | (2 | ) | $ | 22 | $ | 29 | $ | 31 | |||||||
Noncash investing and financing activities: |
||||||||||||||||
Construction expenditures (c) |
$ | 1 | $ | 53 | $ | 75 | $ | 108 | ||||||||
Contribution to membership interests |
$ | — | $ | — | $ | — | $ | 2 |
(a) | This amount includes amounts paid for adequate protection. Net of amounts received under interest rate swap agreements in 2014. |
(b) | Represents cash payments for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court. |
(c) | Represents end-of-period accruals for ongoing construction projects. |
|
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
VISTRA ENERGY CORP. (PARENT)
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENT OF LOSS
(Millions of Dollars)
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Selling, general and administrative expense |
$ | (7 | ) | |
|
|
|||
Loss from operations |
(7 | ) | ||
Impacts of Tax Receivable Agreement |
(22 | ) | ||
|
|
|||
Loss before income taxes and equity earnings |
(29 | ) | ||
Pretax equity in losses of consolidated subsidiaries |
(204 | ) | ||
Income tax benefit |
70 | |||
|
|
|||
Net loss |
$ | (163 | ) | |
|
|
See Notes to the Condensed Financial Statements.
CONDENSED STATEMENT OF CASH FLOWS
(Millions of Dollars)
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Cash flows — operating activities: |
||||
Net loss |
$ | (163 | ) | |
Adjustments to reconcile net loss to cash provided by (used in) operating activities: |
||||
Pretax equity in losses of consolidated subsidiaries |
204 | |||
Deferred income tax benefit, net |
(76 | ) | ||
Impacts of Tax Receivables Agreement |
22 | |||
Other, net |
3 | |||
Changes in operating assets and liabilities |
(26 | ) | ||
|
|
|||
Cash used in operating activities |
(36 | ) | ||
Cash flows — financing activities: |
||||
Special dividend (Note 4) |
(992 | ) | ||
Other, net |
1 | |||
|
|
|||
Cash used in financing activities |
(991 | ) | ||
Cash flows — investing activities: |
||||
Dividend received from subsidiaries |
997 | |||
Changes in restricted cash |
36 | |||
|
|
|||
Cash provided by financing activities |
1,033 | |||
Net change in cash and cash equivalents |
6 | |||
Cash and cash equivalents — beginning balance |
20 | |||
|
|
|||
Cash and cash equivalents — ending balance |
$ | 26 | ||
|
|
See Notes to the Condensed Financial Statements.
VISTRA ENERGY CORP. (PARENT)
SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEET
(Millions of Dollars)
Successor | ||||
December 31, 2016 | ||||
ASSETS | ||||
Current assets: |
||||
Cash and cash equivalents |
$ | 26 | ||
Restricted cash |
90 | |||
Other current assets |
3 | |||
|
|
|||
Total current assets |
119 | |||
Equity investments in consolidated subsidiaries |
6,067 | |||
Accumulated deferred income taxes |
1,122 | |||
Other noncurrent assets |
7 | |||
|
|
|||
Total assets |
$ | 7,315 | ||
|
|
|||
LIABILITIES AND EQUITY | ||||
Current liabilities: |
||||
Accrued taxes |
$ | 31 | ||
Other current liabilities |
91 | |||
|
|
|||
Total current liabilities |
122 | |||
Tax Receivable Agreement obligation |
596 | |||
|
|
|||
Total liabilities |
718 | |||
Total shareholders’ equity |
6,597 | |||
|
|
|||
Total liabilities and equity |
$ | 7,315 | ||
|
|
See Notes to the Condensed Financial Statements.
|
1. | BASIS OF PRESENTATION |
The accompanying unconsolidated condensed balance sheets, statements of net loss and cash flows present results of operations and cash flows of Vistra Energy Corp. (Parent). Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the financial statements and related notes of Vistra Energy Corp. and Subsidiaries included in the 2016 Annual Financial Statements. Vistra Energy Corp.‘s subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.
Vistra Energy Corp. (Parent) will file a consolidated US federal income tax return. All consolidated tax expenses/benefits and deferred tax assets/liabilities are recorded at Vistra Energy Corp. (Parent).
|
3. | GUARANTEES |
As of December 31, 2016, there are no material outstanding guarantees at Vistra Energy Corp. (Parent).
|
4. | DIVIDEND RESTRICTIONS |
Under applicable law, Vistra Energy Corp. (Parent) is prohibited from paying any dividend to the extent that immediately following payment of such dividend there would be no statutory surplus or Vistra Energy Corp. (Parent) would be insolvent. On December 30, 2016, Vistra Energy Corp. (Parent) paid a special cash dividend in the aggregate amount of approximately $992 million to holders of record of its common stock on December 19, 2016.
Vistra Energy Corp. received $997 million in dividends from its consolidated subsidiaries in the Successor period from October 3, 2016 through December 31, 2016.
|
17. | SUBSEQUENT EVENTS |
Merger Agreement
On October 29, 2017, Vistra Energy and Dynegy Inc., a Delaware corporation (Dynegy), entered into an Agreement and Plan of Merger (the Merger Agreement). The following description of the Merger Agreement does not purport to be a complete description and is qualified in its entirety by reference to the full text of the Merger Agreement filed as Exhibit 2.1 to our Current Report on Form 8-K filed on October 31, 2017.
Upon the terms and subject to the conditions set forth in the Merger Agreement, which has been approved by the boards of directors of Vistra Energy and Dynegy, Dynegy will merge with and into Vistra Energy (the Merger), with Vistra Energy continuing as the surviving corporation. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code of 1986, as amended (the Code), so that none of Vistra Energy, Dynegy or any of the Dynegy stockholders generally will recognize any gain or loss in the transaction, except that Dynegy stockholders will recognize gain with respect to cash received in lieu of fractional shares of Vistra Energy’s common stock. We expect that Vistra Energy will be the acquirer for both federal tax and accounting purposes.
Upon the closing of the Merger, each issued and outstanding share of Dynegy common stock, par value $0.01 per share, other than shares owned by Vistra Energy or its subsidiaries, held in treasury by Dynegy or held by a subsidiary of Dynegy, will automatically be converted into the right to receive 0.652 shares of common stock, par value $0.01 per share, of Vistra Energy (the Exchange Ratio), except that cash will be paid in lieu of fractional shares, which we expect will result in Vistra Energy’s stockholders and Dynegy’s stockholders owning approximately 79% and 21%, respectively, of the combined company. Dynegy stock options and equity-based awards outstanding immediately prior to the Effective Time will generally automatically convert upon completion of the Merger into stock options and equity-based awards, respectively, with respect to Vistra Energy’s common stock, after giving effect to the Exchange Ratio.
The Merger Agreement also provides that, upon the closing of the Merger, the board of directors of the combined company will be comprised of 11 members, consisting of (a) the eight current directors of Vistra Energy and (b) three of Dynegy’s current directors, of whom one will be a Class I director, one will be a Class II director and one will be a Class III director, unless the closing of the Merger occurs after the date of Vistra Energy’s 2018 Annual General Meeting, in which case one will be a Class I director and two will be Class II directors. Upon completion of the Merger, each of Curtis A. Morgan, currently a director and the President and Chief Executive Officer of Vistra Energy, Jim Burke, currently Chief Operating Officer of Vistra Energy, and J. William Holden, currently Chief Financial Officer of Vistra Energy, will continue in those roles at the combined company.
Completion of the Merger is subject to various customary conditions, including, among others, (a) approval by Vistra Energy’s stockholders of the issuance of Vistra Energy’s common stock in the Merger, (b) adoption of the Merger Agreement by Vistra Energy’s stockholders and Dynegy’s stockholders, (c) receipt of all requisite regulatory approvals, which includes approvals of the Federal Energy Regulatory Commission, the PUCT, the Federal Communications Commission and the New York Public Service Commission, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and (d) effectiveness of the registration statement for the shares of Vistra Energy’s common stock to be issued in the Merger, and the approval of the listing of such shares on the New York Stock Exchange. Each party’s obligation to consummate the Merger is also subject to certain additional customary conditions, including (i) subject to certain exceptions, the accuracy of the representations and warranties of the other party, (ii) performance in all material respects by the other party of its obligations under the Merger Agreement and (iii) the receipt by such party of an opinion from its counsel to the effect that the Merger will qualify as a tax-free reorganization within the meaning of the Code.
The Merger Agreement contains customary representations, warranties and covenants of Vistra Energy and Dynegy, including, among others, covenants (a) to conduct their respective businesses in the ordinary course during the interim period between the execution of the Merger Agreement and completion of the Merger, (b) not to take certain actions during the interim period except with the consent of the other party, (c) that Vistra Energy and Dynegy will convene and hold meetings of their respective stockholders to obtain the required stockholder approvals, and (d) that the parties use their respective reasonable best efforts to take all actions necessary to obtain all governmental and regulatory approvals and consents (except that Vistra Energy shall not be required, and Dynegy shall not be permitted, to take any action that constitutes or would reasonably be expected to have certain specified burdensome effects). Each of Vistra Energy and Dynegy is also subject to restrictions on its ability to solicit alternative acquisition proposals and to provide information to, and engage in discussion with, third parties regarding such proposals, except under limited circumstances to permit Vistra Energy’s and Dynegy’s boards of directors to comply with their respective fiduciary duties.
The Merger Agreement contains certain termination rights for both Vistra Energy and Dynegy, including in specified circumstances in connection with an alternative acquisition proposal that has been determined to be a superior offer. Upon termination of the Merger Agreement, under specified circumstances (a) for a failure by Vistra Energy to obtain certain requisite regulatory approvals, Vistra Energy may be required to pay Dynegy a termination fee of $100 million, (b) in connection with a superior offer, acquisition proposal or unforeseeable material intervening event, Vistra Energy may be required to pay a termination fee to Dynegy of $100 million, and (c) in connection with a superior offer, acquisition proposal or an unforeseeable material intervening event, Dynegy may be required to pay to Vistra Energy a termination fee of $87 million. In addition, if the Merger Agreement is terminated (i) because Vistra Energy’s stockholders do not approve the issuance of Vistra Energy’s common stock in the Merger or do not adopt the Merger Agreement, then Vistra Energy will be obligated to reimburse Dynegy for its reasonable out-of-pocket fees and expenses incurred in connection with the Merger Agreement, or (ii) because Dynegy’s stockholders do not adopt the Merger Agreement, then Dynegy will reimburse Vistra Energy for its reasonable out-of-pocket fees and expenses incurred in connection with the Merger Agreement, each of which is subject to a cap of $22 million. Such expense reimbursement may be deducted from the abovementioned termination fees, if ultimately payable.
The Merger is subject to certain risks and uncertainties, and there can be no assurance that we will be able to complete the Merger on the expected timeline or at all.
Merger Support Agreements — Concurrently with the execution of the Merger Agreement, certain stockholders of Vistra Energy, including affiliates of Apollo Management Holdings L.P. (collectively, the Apollo Entities), affiliates of Brookfield Asset Management Private Institutional Capital Adviser (Canada), L.P. (collectively, the Brookfield Entities) and certain affiliates of Oaktree Capital Management, L.P. (Oaktree), such agreements representing in the aggregate approximately 34% of the shares of Vistra Energy’s common stock that will be entitled to vote on the Merger, and certain stockholders of Dynegy, including Terawatt Holdings, LP, an affiliate of certain affiliated investment funds of Energy Capital Partners III, LLC (Terawatt) and certain affiliates of Oaktree, such agreements representing in the aggregate approximately 21% of the shares of Dynegy’s common stock that will be entitled to vote on the Merger, have entered into merger support agreements (the Merger Support Agreements), pursuant to which each such stockholder agreed to vote their shares of common stock of Vistra Energy or Dynegy, as applicable, to adopt the Merger Agreement, and in the case of stockholders of Vistra Energy, approve the stock issuance. The Merger Support Agreements will automatically terminate upon a change of recommendation by the applicable board of directors or the termination of the Merger Agreement in accordance with its terms.
The foregoing description of the Merger Support Agreements does not purport to be complete and is qualified in its entirety by reference to that certain Merger Support Agreement, dated as of October 29, 2017, by and among Dynegy and the Apollo Entities, the Brookfield Entities and certain affiliates of Oaktree (filed as Exhibit 10.1 to Dynegy Inc.’s Current Report on Form 8-K filed on October 30, 2017), the Merger Support Agreement entered into between Vistra Energy and Terawatt (filed as Exhibit 10.1 to our Current Report on Form 8-K filed on October 31, 2017) and the Merger Support Agreement entered into between Vistra Energy and certain affiliates of Oaktree (filed as Exhibit 10.2 to our Current Report on Form 8-K filed on October 31, 2017).
Planned Retirement of Generation Facilities
Monticello Site — In September 2017, we decided to retire our Monticello plant given that it is projected to be uneconomic based on current market conditions and given the significant environmental costs associated with operating the plant. In the three months ended September 30, 2017, we recorded a charge of approximately $24 million related to the retirement, including employee-related severance costs, noncash charges for materials inventory and the acceleration of Luminant’s mining reclamation obligations (see Note 16). The charge, all of which related to our Wholesale Generation segment, was recorded to operating costs in our condensed statements of consolidated income (loss). In addition, we will continue the ongoing reclamation work at the plant’s mines, which ceased active operations in the spring of 2016.
Sandow and Big Brown Sites — In October 2017, the Company and Alcoa entered into a contract termination agreement pursuant to which the parties agreed to an early settlement of a long-standing power and mining agreement. In consideration for the early termination, Alcoa made a one-time payment to Luminant of $238 million in October 2017. We expect to record the impacts of the Settlement Agreement in our consolidated financial statements for the fourth quarter of 2017, which would include the receipt of the cash payment, the acquisition of real property and the incurrence of certain liabilities and asset retirement obligations, along with the elimination of a related electric supply contract intangible asset on our consolidated balance sheet (see Note 4). The contract was important to the overall economic viability of the Sandow plant.
In October 2017, we decided to retire the Sandow and Big Brown plants and a related mine which supplies the Sandow plants. Management had previously announced its decision to retire a mine which supplies the Big Brown plant.
Regulatory Review — As part of the retirement process, Luminant has filed notices with ERCOT, which trigger a reliability review regarding such proposed retirements. If, at the end of the applicable ERCOT reliability review period, ERCOT determines the units are not needed for reliability, Luminant would expect to cease plant operations at Sandow and Monticello in January 2018 and at Big Brown in February 2018, which would result in the plants being taken offline by February 2018. In October 2017, ERCOT determined our Monticello plant would not be needed for system reliability purposes.
The announced retirements total installed nameplate generation capacity of 4,167 MW as detailed below.
Name |
Location (all in the |
Fuel Type |
Installed Nameplate Generation Capacity (MW) |
Number of Units |
Estimated Date Units Will Be Taken Offline |
|||||||||
Monticello |
Titus County | Lignite/Coal | 1,880 | 3 | January 4, 2018 | |||||||||
Sandow |
Milam County | Lignite | 1,137 | 2 | January 11, 2018 | |||||||||
Big Brown |
Freestone County | Lignite/Coal | 1,150 | 2 | February 12, 2018 | |||||||||
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|
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Total |
4,167 | 7 | ||||||||||||
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Basis of Presentation
As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852). Fresh start reporting included (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring (TCEH, or the Predecessor) from the financial statements of the entity that emerges from restructuring (Vistra Energy, or the Successor), (2) accounting for the effects of the Plan of Reorganization, (3) assigning the reorganization value of the Successor entity by measuring all assets and liabilities of the Successor entity at fair value, and (4) selecting accounting policies for the Successor entity. The financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh start reporting. The reorganization value of Vistra Energy was assigned to its assets and liabilities in conformity with the procedures specified by FASB ASC 805, Business Combinations, and the portion of the reorganization value that was not attributable to identifiable tangible or intangible assets was recognized as goodwill.
The condensed consolidated financial statements of the Predecessor reflect the application of ASC 852 as it applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. As a result, the condensed consolidated financial statements of the Predecessor have been prepared as if TCEH was a going concern and contemplated the realization of assets and liabilities in the normal course of business. During the Chapter 11 Cases, the Debtors operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. Prior to the Effective Date, the Predecessor recorded the effects of the Plan of Reorganization in accordance with ASC 852. SeeReorganization Items in Note 2 for further discussion of these accounting and reporting changes.
Adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All intercompany items and transactions have been eliminated in consolidation. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the condensed consolidated interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated.
Basis of Presentation
As of the Effective Date, Vistra Energy applied fresh start reporting under the applicable provisions of Financial Accounting Standards Board (FASB) Accounting Standards Codification (ASC) 852, Reorganizations (ASC 852). Fresh start reporting includes (1) distinguishing the consolidated financial statements of the entity that was previously in restructuring (TCEH, or the Predecessor) from the financial statements of the entity that emerges from restructuring (Vistra Energy, or the Successor), (2) accounting for the effects of the Plan of Reorganization, (3) assigning the reorganized value of the Successor entity by measuring all assets and liabilities of the Successor entity at fair value, and (4) selecting accounting policies for the Successor entity. The financial statements of Vistra Energy for periods subsequent to the Effective Date are not comparable to the financial statements of TCEH for periods prior to the Effective Date, as those previous periods do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh start reporting. The reorganization value of Vistra Energy was assigned to its assets and liabilities in conformity with the procedures specified by FASB ASC 805, Business Combinations, and the portion of the reorganization value that was not attributable to identifiable tangible or intangible assets was recognized as goodwill. See Note 3 for further discussion regarding fresh start reporting.
The consolidated financial statements of the Predecessor reflect the application of ASC 852 as it applies to entities that have filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. As a result, the consolidated financial statements of the Predecessor have been prepared as if TCEH was a going concern and contemplated the realization of assets and liabilities in the normal course of business. During the Chapter 11 Cases, the Debtors operated their businesses as debtors-in-possession under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code. The guidance requires that transactions and events directly associated with the reorganization be distinguished from the ongoing operations of the business. In addition, the guidance provides for changes in the accounting and presentation of liabilities. Prior to the Effective Date, the Predecessor recorded the effects of the Plan of Reorganization in accordance with ASC 852. See Notes 4 and 5 for further discussion of these accounting and reporting changes.
The consolidated financial statements have been prepared in accordance with US GAAP. All intercompany transactions and balances have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through March 30, 2017, the date these consolidated financial statements were issued.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgment related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements, estimates of expected obligations, judgment related to the potential timing of events and other estimates. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas, coal, uranium and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the consolidated balance sheets. This recognition is referred to as mark-to-market accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the consolidated balance sheets as commodity and other derivative contractual assets or liabilities. We report derivative assets and liabilities in the consolidated balance sheets without taking into consideration netting arrangements we have with counterparties. Margin deposits that contractually offset these assets and liabilities are reported separately in the consolidated balance sheets. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 16 and 17 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the normal purchase and sale exemption. A commodity-related derivative contract may be designated as a normal purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
Because derivative instruments are frequently used as economic hedges, accounting standards related to derivative instruments and hedging activities allow for hedge accounting, which provides for the designation of such instruments as cash flow or fair value hedges if certain conditions are met. At December 31, 2016 and 2015, there were no derivative positions accounted for as cash flow or fair value hedges.
Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the statements of consolidated income (loss) in either operating revenues or fuel, purchased power costs and delivery fees in the Successor period depending on the type of derivative instrument and net gain (loss) from commodity hedging and trading activities in the Predecessor period. Further, realized and unrealized gains and losses associated with interest rate swap transactions are reported in the statements of consolidated income (loss) in interest expense for both the Predecessor and Successor.
Revenue Recognition
We record revenue from electricity sales under the accrual method of accounting. Revenues are recognized when electricity is provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).
In the statements of consolidated income (loss), we report physically delivered commodity sales and related hedging activity in operating revenues and physically delivered purchases and related hedging activity in fuel, purchased power costs and delivery fees for the Successor period, whereas hedging activity was reported as net gain (loss) from commodity hedging and trading activities in the Predecessor period. Volumes under bilateral purchase and sales contracts, including contracts intended as hedges, are not scheduled as physical power with ERCOT. Accordingly, unless the volumes represent physical deliveries to customers or purchases from counterparties, such contracts are reported in operating revenues, for the Successor, and in net gain (loss) from commodity hedging and trading activities, for the Predecessor. If volumes delivered to our retail and wholesale customers are less than our generation volumes (as determined on a daily settlement basis), we record net bilateral activity as wholesale revenues, and if volumes delivered to our retail and wholesale customers exceed our generation volumes, we record net bilateral activity as purchased costs in the Successor period. The additional wholesale revenues or purchased power costs were offset in net gain (loss) from commodity hedging and trading activities in the Predecessor period.
Advertising Expense
We expense advertising costs as incurred and include them within selling, general and administrative expenses. Advertising expenses totaled $9 million, $35 million, $44 million and $42 million for the Successor period from October 3, 2016 through December 31, 2016 and the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 8 for discussion of impairments of certain long-lived assets recorded by the Predecessor.
Finite-lived intangibles identified as a result of fresh start reporting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 7 for details of intangible assets with indefinite lives, including discussion of fair value determinations.
Goodwill and Intangible Assets with Indefinite Lives
As part of fresh start reporting, reorganization value is generally allocated, first, to identifiable tangible assets, identifiable intangible assets and liabilities, then any remaining excess reorganization value is allocated to goodwill (see Note 3). We evaluate goodwill and intangible assets with indefinite lives for impairment at least annually, or when indications of impairment exist. As part of fresh start reporting, we have established October 1 as the date we evaluate goodwill and intangible assets with indefinite lives for impairment. The Predecessor’s annual evaluation date was December 1. See Note 7 for details of goodwill, including discussion of fair value determinations and our Predecessor’s goodwill impairments.
Nuclear Fuel
Nuclear fuel is capitalized and reported as a component of our property, plant and equipment in our consolidated balance sheets. Amortization of nuclear fuel is calculated on the units-of-production method and is reported as a component of fuel, purchased power costs and delivery fees in our statements of consolidated income (loss).
Major Maintenance Costs
Major maintenance costs incurred by the Successor during generation plant outages are deferred and amortized into operating costs over the period between the major maintenance outages for the respective asset. Other costs of maintenance activities are charged to expense as incurred and reported as operating costs in our statements of consolidated income (loss). The Predecessor charged major and other maintenance activities to expense as incurred.
Defined Benefit Pension Plans and OPEB Plans
On the Effective Date, EFH Corp. transferred sponsorship of certain employee benefit plans (including related assets), programs and policies to a subsidiary of Vistra Energy. Certain health care and life insurance benefits are offered to eligible employees and their dependents upon the retirement of such employee from the company and also offer pension benefits to eligible employees under collective bargaining agreements based on either a traditional defined benefit formula or a cash balance formula. Effective January 1, 2017, the OPEB plan was amended to discontinue the life insurance benefits for active employees. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates.
Prior to the Effective Date, our Predecessor bore a portion of the costs of the EFH Corp. sponsored pension and OPEB plans and accounted for the arrangement under multiemployer plan accounting.
See Note 18 for additional information regarding pension and OPEB plans.
Stock-Based Compensation
Stock-based compensation is accounted for in accordance with ASC 718, Compensation — Stock Compensation. The fair value of our non-qualified stock options is estimated on the date of grant using the Black-Scholes option-pricing model. Forfeitures are recognized as they occur. We recognize compensation expense for graded vesting awards on a straight-line basis over the requisite service period for the entire award. See Note 19 for additional information regarding stock-based compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as a “pass through” item on the consolidated balance sheets with no effect on the statements of consolidated income (loss) (i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction).
Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and gross receipt taxes are not a “pass through” item. These taxes are imposed on us by state and local taxing authorities, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates we charge to customers are intended to recover our costs, including the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers. We report franchise and revenue-based taxes in SG&A expense in our statements of consolidated income (loss).
Income Taxes
Subsequent to the Effective Date, Vistra Energy will file a consolidated US federal income tax return. Prior to the Effective Date, EFH Corp. filed a consolidated US federal income tax return that included the results of our Predecessor; however, our Predecessor’s income tax expense and related balance sheet amounts were recorded as if it filed separate corporate income tax returns.
Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities as required under accounting rules. See Note 9.
We report interest and penalties related to uncertain tax positions as current income tax expense. See Note 9.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 14 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. See Notes 13 and 22 for more details regarding restricted cash.
Property, Plant and Equipment
In connection with fresh start reporting, carrying amounts of property, plant and equipment were adjusted to estimated fair values as of the Effective Date (see Note 3). Significant improvements or additions to our property, plant and equipment that extend the life of the respective asset are capitalized at cost, while other costs are expensed when incurred. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs. Interest related to qualifying construction projects and qualifying software projects is capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 11.
Depreciation of our property, plant and equipment (except for nuclear fuel) is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation expense is calculated on an asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives. See Note 22.
Asset Retirement Obligations (ARO)
A liability is initially recorded at fair value for an asset retirement obligation associated with the legal obligation associated with law, regulatory, contractual or constructive retirement requirements of tangible long-lived assets in the period in which it is incurred if a fair value is reasonably estimable. At initial recognition of an ARO obligation, an offsetting asset is also recorded for the long-lived asset that the liability corresponds with, which is subsequently depreciated over the estimated useful life of the asset. These liabilities primarily relate to our nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. Over time, the liability is accreted for the change in present value and the initial capitalized costs are depreciated over the remaining useful lives of the assets. Generally, changes in estimates related to ARO obligations are recorded as increases to the liability and related asset as information becomes available. See Note 22.
Inventories
Inventories consist of materials and supplies, fuel stock and natural gas in storage. Materials and supplies inventory is valued at weighted average cost and is expensed or capitalized when used for repairs/maintenance or capital projects, respectively. Fuel stock and natural gas in storage are reported at the lower of cost (on a weighted average basis) or market. We expect to recover the value of inventory costs in the normal course of business.
Investments
Investments in a nuclear decommissioning trust fund are carried at current market value in the consolidated balance sheets. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at current market value. See Note 22 for discussion of these and other investments.
Changes in Accounting Standards
In May 2014, the FASB issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers (Topic 606), which was further amended through several updates issued by the FASB in 2016 and 2017. The guidance under Topic 606 provides the core principle and key steps in determining the recognition of revenue and expands disclosure requirements related to revenue recognition. We intend to adopt the new standard on January 1, 2018 using the modified retrospective method and expect to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date. In recent periods, we completed an assessment of substantially all of our performance obligations in our contractual relationships and continued to assess the expanded disclosure requirements. We do not anticipate that the adoption of the standard will have a material effect on our results of operations, cash flows or financial condition.
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-02 (ASU 2016-02), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We are currently evaluating the impact of this ASU on our financial statements.
In November 2016, the FASB issued ASU 2016-18 Statement of Cash Flows (Topic 230): Restricted Cash. The ASU requires restricted cash to be included in the cash and cash equivalents and a reconciliation between the change in cash and cash equivalents and the amounts presented on the balance sheet. This ASU will be effective for fiscal years beginning after December 15, 2017, and we will adopt the new standard on January 1, 2018. The ASU will modify the presentation of our statement of consolidated cash flows, but will not have a material impact on our statement of consolidated net income and consolidated balance sheet.
In January 2017, the FASB issued ASU 2017-01 Business Combinations (Topic 805): Clarifying the Definition of a Business. The ASU provides an updated model for determining if acquired assets and liabilities constitute a business. In a business combination, the acquired assets and liabilities are recognized at fair value and goodwill could be recognized. In an asset acquisition, the assets are allocated value based on relative fair value and no goodwill is recognized. The ASU narrows the definition of a business. We adopted this standard in the first quarter of 2017. ASU 2017-01 did not have a material impact on our financial statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). The ASU provides for the elimination of Step 2 from the goodwill impairment test. If impairment charges are recognized, the amount recorded will be the amount by which the carrying amount exceeds the reporting unit’s fair value with certain limitations. We adopted this standard in the first quarter of 2017. ASU 2017-04 did not have a material impact on our financial statements.
Changes in Accounting Standards
In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2016-02 (ASU 2016-02), Leases. The ASU amends previous GAAP to require the recognition of lease assets and liabilities for operating leases. The ASU will be effective for fiscal years beginning after December 15, 2018, including interim periods within those years. Retrospective application to comparative periods presented will be required in the year of adoption. We are currently evaluating the impact of this ASU on our financial statements.
In May 2016, the FASB issued Accounting Standards Update 2016-09, Revenue from Contracts with Customers (Topic 606), which was further amended through various updates issued by the FASB thereafter. The guidance under Topic 606 provides the core principle and key steps in determining the recognition of revenue and expands disclosure requirements related to revenue recognition. We intend to adopt the new standard on January 1, 2018 using the modified retrospective method and expect to elect the practical expedient available under Topic 606 for measuring progress toward complete satisfaction of a performance obligation and for disclosure requirements of remaining performance obligations. The practical expedient allows an entity to recognize revenue in the amount to which the entity has the right to invoice such that the entity has a right to the consideration in an amount that corresponds directly with the value to the customer for performance completed to date by the entity. In 2016, we continued to assess the new standard, including the expanded disclosure requirements. We do not anticipate that the adoption of the standard will have a material effect on our results of operations, cash flows or financial condition.
In June 2016, the FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments (ASU 2016-13). The ASU provides for a new impairment model which requires measurement and recognition of expected credit losses for most financial assets held. The ASU is effective for public companies for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. We do not anticipate ASU 2016-13 to have a material impact on our financial statements.
In January 2017, the FASB issued ASU 2017-04, Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment (ASU 2017-04). The ASU provides for the elimination of Step 2 from the goodwill impairment test. If impairment charges are recognized, the amount recorded will be the amount by which the carrying amount exceeds the reporting unit’s fair value with certain limitations. The ASU is effective for public companies for annual periods, and interim periods within those annual periods, beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017 and the adoption should be applied prospectively. We expect to early adopt this standard in 2017. We do not currently anticipate ASU 2017-04 to have a material impact on our financial statements.
|
Vistra Energy estimates its reorganization value of assets at approximately $15.161 billion as of October 3, 2016, which consists of the following:
Business enterprise value |
$ | 10,500 | ||
Cash excluded from business enterprise value |
1,594 | |||
Deferred asset related to prepaid capital lease obligation |
38 | |||
Current liabilities, excluding short-term portion of debt and capital leases |
1,123 | |||
Noncurrent, non-interest bearing liabilities |
1,906 | |||
|
|
|||
Vistra Energy reorganization value of assets |
$ | 15,161 | ||
|
|
The adjustments to TCEH’s October 3, 2016 consolidated balance sheet below include the impacts of the Plan of Reorganization and the adoption of fresh start reporting.
October 3, 2016 | ||||||||||||||||||||||||
TCEH (Predecessor) (1) |
Reorganization Adjustments (2) |
Fresh Start Adjustments |
Vistra Energy (Successor) |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
$ | 1,829 | $ | (1,028 | ) | (3) | $ | — | $ | 801 | ||||||||||||||
Restricted cash |
12 | 131 | (4) | — | 143 | |||||||||||||||||||
Trade accounts receivable — net |
750 | 4 | — | 754 | ||||||||||||||||||||
Advances to parents and affiliates of Predecessor |
78 | (78 | ) | — | — | |||||||||||||||||||
Inventories |
374 | — | (86 | ) | (17) | 288 | ||||||||||||||||||
Commodity and other derivative contractual assets |
255 | — | — | 255 | ||||||||||||||||||||
Margin deposits related to commodity contracts |
42 | — | — | 42 | ||||||||||||||||||||
Other current assets |
47 | 17 | 3 | 67 | ||||||||||||||||||||
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|
|
|
|
|
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Total current assets |
3,387 | (954 | ) | (83 | ) | 2,350 | ||||||||||||||||||
Restricted cash |
650 | — | — | 650 | ||||||||||||||||||||
Advance to parent and affiliates of Predecessor |
17 | (21 | ) | 4 | — | |||||||||||||||||||
Investments |
1,038 | 1 | 9 | (18) | 1,048 | |||||||||||||||||||
Property, plant and equipment — net |
10,359 | 53 | (5,970 | ) | (19) | 4,442 | ||||||||||||||||||
Goodwill |
152 | — | 1,755 | (27) | 1,907 | |||||||||||||||||||
Identifiable intangible assets — net |
1,148 | 4 | 2,256 | (20) | 3,408 | |||||||||||||||||||
Commodity and other derivative contractual assets |
73 | — | (14 | ) | 59 | |||||||||||||||||||
Deferred income taxes |
— | 320 | (5) | 730 | (21) | 1,050 | ||||||||||||||||||
Other noncurrent assets |
51 | 38 | 158 | (22) | 247 | |||||||||||||||||||
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|
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|
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|
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Total assets |
$ | 16,875 | $ | (559 | ) | $ | (1,155 | ) | $ | 15,161 | ||||||||||||||
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LIABILITIES AND EQUITY |
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Current liabilities: |
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Long-term debt due currently |
$ | 4 | $ | 5 | $ | (1 | ) | $ | 8 | |||||||||||||||
Trade accounts payable |
402 | 145 | (6) | 3 | 550 | |||||||||||||||||||
Trade accounts and other payables to affiliates of Predecessor |
152 | (152 | ) | (6) | — | — | ||||||||||||||||||
Commodity and other derivative contractual liabilities |
125 | — | — | 125 | ||||||||||||||||||||
Margin deposits related to commodity contracts |
64 | — | — | 64 | ||||||||||||||||||||
Accrued income taxes |
12 | 12 | — | 24 | ||||||||||||||||||||
Accrued taxes other than income |
119 | 4 | — | 123 | ||||||||||||||||||||
Accrued interest |
110 | (109 | ) | (7) | — | 1 | ||||||||||||||||||
Other current liabilities |
243 | 170 | (8) | 5 | 418 | |||||||||||||||||||
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|
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Total current liabilities |
1,231 | 75 | 7 | 1,313 | ||||||||||||||||||||
Long-term debt, less amounts due currently |
— | 3,476 | (9) | 151 | (23) | 3,627 | ||||||||||||||||||
Borrowings under debtor-in-possession credit facilities |
3,387 | (3,387 | ) | (9) | — | — | ||||||||||||||||||
Liabilities subject to compromise |
33,749 | (33,749 | ) | (10) | — | — | ||||||||||||||||||
Commodity and other derivative contractual liabilities |
5 | — | 3 | 8 | ||||||||||||||||||||
Deferred income taxes |
256 | (256 | ) | (11) | — | — | ||||||||||||||||||
Tax Receivable Agreement obligation |
— | 574 | (12) | — | 574 | |||||||||||||||||||
Asset retirement obligations |
809 | — | 854 | (24) | 1,663 | |||||||||||||||||||
Other noncurrent liabilities and deferred credits |
1,018 | 117 | (13) | (900 | ) | (25) | 235 | |||||||||||||||||
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|
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Total liabilities |
40,455 | (33,150 | ) | 115 | 7,420 | |||||||||||||||||||
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Equity: |
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Common stock |
— | 4 | (14) | — | 4 | |||||||||||||||||||
Additional paid-in-capital |
— | 7,737 | (15) | — | 7,737 | |||||||||||||||||||
Accumulated other comprehensive income (loss) |
(32 | ) | 22 | 10 | (26) | — | ||||||||||||||||||
Predecessor membership interests |
(23,548 | ) | 24,828 | (16) | (1,280 | ) | (26) | — | ||||||||||||||||
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|
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|
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|
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Total equity |
(23,580 | ) | 32,591 | (1,270 | ) | 7,741 | ||||||||||||||||||
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|
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|
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|
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Total liabilities and equity |
$ | 16,875 | $ | (559 | ) | $ | (1,155 | ) | $ | 15,161 | ||||||||||||||
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(1) | Represents the consolidated balance sheet of TCEH as of October 3, 2016. |
Net adjustments to cash, which represent distributions made or funding provided to an escrow account, classified as restricted cash, under the Plan of Reorganization, as follows: |
Sources (uses): |
||||
Net proceeds from PrefCo preferred stock sale |
$ | 69 | ||
Addition of cash balances from the Contributed EFH Debtors |
22 | |||
Payments to TCEH first lien creditors, including adequate protection |
(486 | ) | ||
Payment to TCEH unsecured creditors (including $73 million to escrow) |
(502 | ) | ||
Payment of administrative claims to TCEH creditors |
(53 | ) | ||
Payment of legal fees, professional fees and other costs (including $52 million to escrow) |
(78 | ) | ||
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|
|||
Net use of cash |
$ | (1,028 | ) | |
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|
Liabilities subject to compromise were settled as follows in accordance with the Plan of Reorganization:
Notes, loans and other debt |
$ | 31,668 | ||
Accrued interest on notes, loans and other debt |
646 | |||
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements |
1,243 | |||
Trade accounts payable and other expected allowed claims |
192 | |||
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|
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Third-party liabilities subject to compromise |
33,749 | |||
LSTC from the Contributed EFH Entities |
8 | |||
|
|
|||
Total liabilities subject to compromise |
33,757 | |||
Fair value of equity issued to TCEH first lien creditors |
(7,741 | ) | ||
TRA Rights issued to TCEH first lien creditors |
(574 | ) | ||
Cash distributed and accruals for TCEH first lien creditors |
(377 | ) | ||
Cash distributed for TCEH unsecured claims |
(502 | ) | ||
Cash distributed and accruals for TCEH administrative claims |
(60 | ) | ||
Settlement of affiliate balances |
(99 | ) | ||
Net liabilities of contributed entities and other items |
(60 | ) | ||
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|
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Gain on extinguishment of LSTC |
$ | 24,344 | ||
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|
Reflects adjustments to present Vistra Energy equity value at approximately $7.741 billion based on a reconciliation from the $10.5 billion enterprise value described above under Reorganization Value as depicted below: |
Enterprise value |
$ | 10,500 | ||
Vistra Operations Credit Facility — Initial Term Loan B Facility |
(2,871 | ) | ||
Vistra Operations Credit Facility — Term Loan C Facility |
(655 | ) | ||
Accrual for post-Emergence claims satisfaction |
(181 | ) | ||
Tax Receivable Agreement Obligation |
(574 | ) | ||
Preferred stock of PrefCo |
(70 | ) | ||
Other items |
(2 | ) | ||
Cash and cash equivalents |
801 | |||
Restricted cash |
793 | |||
|
|
|||
Equity value at Emergence |
$ | 7,741 | ||
|
|
|||
Common stock at par value |
$ | 4 | ||
Additional paid-in capital |
7,737 | |||
|
|
|||
Equity value |
$ | 7,741 | ||
Shares outstanding at October 3, 2016 (in millions) |
427.5 | |||
Per share value |
$ | 18.11 |
Reflects the change in fair value of property, plant and equipment related primarily to generation and mining assets as detailed below: |
Property, Plant and Equipment |
Adjustment | Fair Value |
||||||
Generation plants and mining assets |
$ | (6,057 | ) | $ | 3,698 | |||
Land |
140 | 490 | ||||||
Nuclear Fuel |
(23 | ) | 157 | |||||
Other equipment |
(30 | ) | 97 | |||||
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|
|
|
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Total |
$ | (5,970 | ) | $ | 4,442 | |||
|
|
|
|
Reflects increase in goodwill balance to present final goodwill as the reorganization value in excess of the identifiable tangible assets, intangible assets, and liabilities at Emergence. |
Business enterprise value |
$ | 10,500 | ||
Add: Fair value of liabilities excluded from enterprise value |
3,030 | |||
Less: Fair value of tangible assets |
(8,215 | ) | ||
Less: Fair value of identified intangible assets |
(3,408 | ) | ||
|
|
|||
Vistra Energy goodwill |
$ | 1,907 | ||
|
|
|
Expenses and income directly associated with the Chapter 11 Cases are reported separately in the condensed statements of consolidated income (loss) as reorganization items as required by ASC 852, Reorganizations. Reorganization items also included adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments were determined. The following table presents reorganization items incurred in the three and nine months ended September 30, 2016 as reported in the condensed statements of consolidated income (loss):
Predecessor | ||||||||
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2016 |
|||||||
Expenses related to legal advisory and representation services |
$ | 28 | $ | 55 | ||||
Expenses related to other professional consulting and advisory services |
19 | 39 | ||||||
Contract claims adjustments |
10 | 13 | ||||||
Other |
7 | 9 | ||||||
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|
|
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Total reorganization items |
$ | 64 | $ | 116 | ||||
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|
Expenses and income directly associated with the Chapter 11 Cases are reported separately in the statements of consolidated loss as reorganization items as required by ASC 852, Reorganizations. Reorganization items also included adjustments to reflect the carrying value of LSTC at their estimated allowed claim amounts, as such adjustments were determined. For the period from January 1, 2016 through October 2, 2016, reorganization items include the gain from extinguishing LSTC and the impacts of fresh start reporting. The following table presents reorganization items as reported in the statements of consolidated loss:
Predecessor | ||||||||||||
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, 2015 |
Post-Petition Period Ended December 31, 2014 |
||||||||||
Gain on reorganization adjustments (Note 3) |
$ | (24,252 | ) | $ | — | $ | — | |||||
Loss from the adoption of fresh start reporting |
2,013 | — | — | |||||||||
Expenses related to legal advisory and representation services |
55 | 141 | 65 | |||||||||
Expenses related to other professional consulting and advisory services |
39 | 69 | 67 | |||||||||
Contract claims adjustments |
13 | 54 | 19 | |||||||||
Noncash adjustment for estimated allowed claims related to debt |
— | 896 | — | |||||||||
Adjustment to affiliate claims pursuant to Settlement Agreement (Note 20) |
— | (635 | ) | — | ||||||||
Gain on settlement of debt held by affiliates (Note 20) |
— | (382 | ) | — | ||||||||
Gain on settlement of interest on debt held by affiliates |
— | (20 | ) | — | ||||||||
Sponsor management agreement settlement (Notes 2 and 20) |
— | (19 | ) | — | ||||||||
Contract assumption adjustments |
— | (14 | ) | — | ||||||||
Fees associated with extension/completion of the DIP Facility |
— | 9 | 92 | |||||||||
Noncash liability adjustment arising from termination of interest rate swaps |
— | — | 277 | |||||||||
Other |
11 | 2 | — | |||||||||
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|
|
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|
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Total reorganization items |
$ | (22,121 | ) | $ | 101 | $ | 520 | |||||
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The following table presents LSTC as reported in the consolidated balance sheet at December 31, 2015:
Predecessor | ||||
December 31, 2015 |
||||
Notes, loans and other debt per the following table |
$ | 31,668 | ||
Accrued interest on notes, loans and other debt |
646 | |||
Net liability under terminated TCEH interest rate swap and natural gas hedging agreements (Note 17) |
1,243 | |||
Trade accounts payable, advances and other payables to affiliates and other expected allowed claims |
177 | |||
|
|
|||
Total liabilities subject to compromise |
$ | 33,734 | ||
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|
|
See Note 6 to the audited financial statements contained in our prospectus filed with the SEC pursuant to Rule 424(b) of the Securities Act in May 2017 for a summary of the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.
The following table summarizes the consideration paid and the allocation of the purchase price to the fair value amounts recognized for the assets acquired and liabilities assumed related to the Lamar and Forney Acquisition as of the acquisition date. During the three months ended September 30, 2016, the working capital adjustment included in the purchase price was finalized between the parties, and the purchase price allocation was completed.
Cash paid to seller at close |
$ | 603 | ||
Net working capital adjustments |
(4 | ) | ||
|
|
|||
Consideration paid to seller |
599 | |||
Cash paid to repay project financing at close |
950 | |||
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|
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Total cash paid related to acquisition |
$ | 1,549 | ||
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|
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Cash and cash equivalents |
$ | 210 | ||
Property, plant and equipment — net |
1,316 | |||
Commodity and other derivative contractual assets |
47 | |||
Other assets |
44 | |||
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|
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Total assets acquired |
1,617 | |||
|
|
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Commodity and other derivative contractual liabilities |
53 | |||
Trade accounts payable and other liabilities |
15 | |||
|
|
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Total liabilities assumed |
68 | |||
|
|
|||
Identifiable net assets acquired |
$ | 1,549 | ||
|
|
The following unaudited pro forma financial information for the nine months ended September 30, 2016 assumes that the Lamar and Forney Acquisition occurred on January 1, 2016. The unaudited pro forma financial information is provided for information purposes only and isnot necessarily indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January 1, 2016, nor is the unaudited pro forma financial information indicative of future results of operations.
Predecessor | ||||
Nine Months Ended September 30, 2016 |
||||
Revenues |
$ | 4,116 | ||
Net loss |
$ | (672 | ) |
The following unaudited pro forma financial information for the Predecessor periods indicated assumes that the Lamar and Forney Acquisition occurred on January 1, 2015. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Lamar and Forney Acquisition been completed on January 1, 2015, nor are they indicative of future results of operations.
Predecessor | ||||||||
Period from January 1, 2016 through October 2, 2016 |
December 31, 2015 |
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Revenues |
$ | 4,116 | $ | 6,133 | ||||
Net income (loss) |
$ | 22,835 | $ | (4,671 | ) |
|
The goodwill of our Predecessor arose in connection with accounting for the Merger.
Successor | Predecessor | |||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, 2015 |
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Balance at beginning of period |
$ | 1,907 | $ | 152 | $ | 2,352 | ||||||
Noncash impairment charges |
— | — | (2,200 | ) | ||||||||
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Balance at end of period (a) |
$ | 1,907 | $ | 152 | $ | 152 | ||||||
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(a) | At December 31, 2016, all goodwill related to the Retail Electricity segment. Predecessor periods are net of accumulated impairment charges totaling $18.170 billion. |
Identifiable intangible assets, including the impact of fresh start reporting (see Note 1), are comprised of the following:
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||
Identifiable Intangible Asset |
Gross Carrying Amount |
Accumulated Amortization |
Net | Gross Carrying Amount |
Accumulated Amortization |
Net | ||||||||||||||||||
Retail customer relationship |
$ | 1,648 | $ | 467 | $ | 1,181 | $ | 1,648 | $ | 152 | $ | 1,496 | ||||||||||||
Software and other technology-related assets |
178 | 36 | 142 | 147 | 9 | 138 | ||||||||||||||||||
Electricity supply contract (a) |
190 | 9 | 181 | 190 | 2 | 188 | ||||||||||||||||||
Retail and wholesale contracts |
164 | 72 | 92 | 164 | 38 | 126 | ||||||||||||||||||
Other identifiable intangible assets (b) |
33 | 9 | 24 | 30 | 2 | 28 | ||||||||||||||||||
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Total identifiable intangible assets subject to amortization |
$ | 2,213 | $ | 593 | 1,620 | $ | 2,179 | $ | 203 | 1,976 | ||||||||||||||
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Retail trade names (not subject to amortization) |
1,225 | 1,225 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) |
4 | 4 | ||||||||||||||||||||||
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Total identifiable intangible assets |
$ | 2,849 | $ | 3,205 | ||||||||||||||||||||
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(a) | Contract terminated in October 2017. See Note 17. |
(b) | Includes mining development costs and environmental allowances and credits. |
Identifiable intangible assets, including the impact of fresh start reporting (see Note 3), are comprised of the following:
Successor | Predecessor | |||||||||||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||||||||||
Identifiable Intangible Asset |
Gross Carrying Amount |
Accumulated Amortization |
Net | Gross Carrying Amount |
Accumulated Amortization |
Net | ||||||||||||||||||
Retail customer relationship |
$ | 1,648 | $ | 152 | $ | 1,496 | $ | 463 | $ | 442 | $ | 21 | ||||||||||||
Software and other technology-related assets |
147 | 9 | 138 | 385 | 224 | 161 | ||||||||||||||||||
Electricity supply contract |
190 | 2 | 188 | — | — | — | ||||||||||||||||||
Retail and wholesale contracts |
164 | 38 | 126 | — | — | — | ||||||||||||||||||
Other identifiable intangible assets (a) |
30 | 2 | 28 | 72 | 35 | 37 | ||||||||||||||||||
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Total identifiable intangible assets subject to amortization (b) |
$ | 2,179 | $ | 203 | 1,976 | $ | 920 | $ | 701 | 219 | ||||||||||||||
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Retail trade names (not subject to amortization) |
1,225 | 955 | ||||||||||||||||||||||
Mineral interests (not currently subject to amortization) |
4 | 5 | ||||||||||||||||||||||
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Total identifiable intangible assets |
$ | 3,205 | $ | 1,179 | ||||||||||||||||||||
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(a) | Includes favorable purchase and sales contracts, environmental allowances and credits and mining development costs. See discussion below regarding impairment charges recorded in the year ended December 31, 2015 related to other identifiable intangible assets. |
(b) | Amounts related to fully amortized assets that are expired, or of no economic value, have been excluded from both the gross carrying and accumulated amortization amounts. |
Amortization expense related to finite-lived identifiable intangible assets (including the classification in the condensed statements of consolidated income (loss)) consisted of:
Successor | Predecessor | Successor | Predecessor | |||||||||||||||
Identifiable Intangible Asset |
Condensed Statements of |
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Retail customer relationship |
Depreciation and amortization |
$ | 105 | $ | 3 | $ | 315 | $ | 9 | |||||||||
Software and other technology-related assets |
Depreciation and amortization |
10 | 15 | 27 | 44 | |||||||||||||
Electricity supply contract |
Operating revenues |
2 | — | 7 | — | |||||||||||||
Retail and wholesale contracts |
Operating revenues/fuel, purchased power costs and delivery fees |
(17 | ) | — | 34 | — | ||||||||||||
Other identifiable intangible assets |
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization |
3 | 3 | 7 | 6 | |||||||||||||
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Total amortization expense (a) |
$ | 103 | $ | 21 | $ | 390 | $ | 59 | ||||||||||
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(a) | Amounts recorded in depreciation and amortization totaled $116 million and $20 million for the three months ended September 30, 2017 and 2016, respectively, and $347 million and $58 million for the nine months ended September 30, 2017 and 2016, respectively. |
Amortization expense related to finite-lived identifiable intangible assets (including the classification in the statements of consolidated income (loss)) consisted of:
Identifiable Intangible Asset |
Statements of |
Successor | Predecessor | |||||||||||||||||||
Remaining useful lives at December 31, 2016 (weighted average in years) |
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
|||||||||||||||||||
2015 | 2014 | |||||||||||||||||||||
Retail customer relationship | Depreciation and amortization | 4 | $ | 152 | $ | 9 | $ | 17 | $ | 23 | ||||||||||||
Software and other technology-related assets | Depreciation and amortization | 4 | 9 | 44 | 60 | 59 | ||||||||||||||||
Electricity supply contract | Operating revenues | 22 | 2 | — | — | — | ||||||||||||||||
Retail and wholesale contracts | Operating revenues/fuel, purchased power costs and delivery fees | 2 | 38 | — | — | — | ||||||||||||||||
Other identifiable intangible assets | Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization | 5 | 2 | 6 | 30 | 88 | ||||||||||||||||
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Total amortization expense (a) | $ | 203 | $ | 59 | $ | 107 | $ | 170 | ||||||||||||||
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(a) | Amounts recorded in depreciation and amortization totaled $162 million, $58 million, $85 million and $116 million for the Successor period from October 3, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. |
As of September 30, 2017, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.
Year |
Estimated Amortization Expense |
|||
2017 |
$ | 560 | ||
2018 |
$ | 374 | ||
2019 |
$ | 266 | ||
2020 |
$ | 198 | ||
2021 |
$ | 130 |
As of December 31, 2016, the estimated aggregate amortization expense of identifiable intangible assets for each of the next five fiscal years is as shown below.
Year |
Estimated Amortization Expense | |||
2017 |
$ | 523 | ||
2018 |
$ | 365 | ||
2019 |
$ | 267 | ||
2020 |
$ | 191 | ||
2021 |
$ | 143 |
|
The components of our income tax expense (benefit) are as follows:
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Current: |
||||||||||||||||
US Federal |
$ | — | $ | (6 | ) | $ | (17 | ) | $ | 30 | ||||||
State |
6 | 9 | 21 | 28 | ||||||||||||
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Total current |
6 | 3 | 4 | 58 | ||||||||||||
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Deferred: |
||||||||||||||||
US Federal |
(75 | ) | (1,234 | ) | (811 | ) | (2,361 | ) | ||||||||
State |
(1 | ) | (36 | ) | (72 | ) | (17 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total deferred |
(76 | ) | (1,270 | ) | (883 | ) | (2,378 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | (70 | ) | $ | (1,267 | ) | $ | (879 | ) | $ | (2,320 | ) | ||||
|
|
|
|
|
|
|
|
The calculation of our effective tax rate is as follows:
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Income (loss) before income taxes |
$ | 524 | $ | 184 | $ | 609 | $ | (653 | ) | |||||||
Income tax (expense) benefit |
$ | (251 | ) | $ | 3 | $ | (284 | ) | $ | (3 | ) | |||||
Effective tax rate |
47.9 | % | (1.6 | )% | 46.6 | % | (0.5 | )% |
Reconciliation of income taxes computed at the US federal statutory rate to income tax benefit recorded:
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Income (loss) before income taxes |
$ | (233 | ) | $ | 21,584 | $ | (5,556 | ) | $ | (8,549 | ) | |||||
|
|
|
|
|
|
|
|
|||||||||
Income taxes at the US federal statutory rate of 35% |
(82 | ) | 7,554 | (1,945 | ) | (2,992 | ) | |||||||||
Nondeductible TRA accretion |
5 | — | — | — | ||||||||||||
IRS audit and appeals settlements |
— | — | — | 53 | ||||||||||||
Nondeductible goodwill impairment |
— | — | 770 | 560 | ||||||||||||
Texas margin tax, net of federal benefit |
3 | (21 | ) | — | 10 | |||||||||||
Lignite depletion allowance |
— | — | (8 | ) | (14 | ) | ||||||||||
Interest accrued for uncertain tax positions, net of tax |
— | — | (2 | ) | — | |||||||||||
Nondeductible interest expense |
— | 12 | 21 | 21 | ||||||||||||
Nondeductible debt restructuring costs |
2 | 38 | 64 | 42 | ||||||||||||
Valuation allowance |
— | (210 | ) | 210 | — | |||||||||||
Nontaxable gain on extinguishment of LSTC |
— | (8,593 | ) | — | — | |||||||||||
Other |
2 | (47 | ) | 11 | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income tax benefit |
$ | (70 | ) | $ | (1,267 | ) | $ | (879 | ) | $ | (2,320 | ) | ||||
|
|
|
|
|
|
|
|
|||||||||
Effective tax rate |
30.0 | % | (5.9 | )% | 15.8 | % | 27.1 | % |
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2016 and 2015 are as follows:
Successor | Predecessor | |||||||
December 31, 2016 | December 31, 2015 | |||||||
Noncurrent Deferred Income Tax Assets |
||||||||
Alternative minimum tax credit carryforwards |
$ | — | $ | 22 | ||||
Net operating loss (NOL) carryforwards |
8 | 440 | ||||||
Unfavorable purchase and sales contracts |
— | 193 | ||||||
Commodity contracts and interest rate swaps |
— | 125 | ||||||
Property, plant and equipment |
943 | — | ||||||
Intangible assets |
29 | — | ||||||
Debt extinguishment gains |
52 | 1,109 | ||||||
Employee benefit obligations |
84 | 51 | ||||||
Other |
6 | 55 | ||||||
|
|
|
|
|||||
Total deferred tax assets |
1,122 | 1,995 | ||||||
|
|
|
|
|||||
Noncurrent Deferred Income Tax Liabilities |
||||||||
Property, plant and equipment |
— | 1,541 | ||||||
Identifiable intangible assets |
— | 320 | ||||||
Accrued interest |
— | 138 | ||||||
|
|
|
|
|||||
Total deferred tax liabilities |
— | 1,999 | ||||||
|
|
|
|
|||||
Valuation allowance |
— | 209 | ||||||
|
|
|
|
|||||
Net Deferred Income Tax (Asset) Liability |
$ | (1,122 | ) | $ | 213 | |||
|
|
|
|
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheets, during the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively:
Predecessor | ||||||||||||
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
|||||||||||
2015 | 2014 | |||||||||||
Balance at beginning of period, excluding interest and penalties |
$ | 36 | $ | 65 | $ | 184 | ||||||
Additions based on tax positions related to prior years |
— | — | 55 | |||||||||
Reductions based on tax positions related to prior years |
(1 | ) | (11 | ) | (155 | ) | ||||||
Additions based on tax positions related to the current year |
— | — | — | |||||||||
Settlements with taxing authorities |
(35 | ) | (18 | ) | (19 | ) | ||||||
|
|
|
|
|
|
|||||||
Balance at end of period, excluding interest and penalties |
$ | — | $ | 36 | $ | 65 | ||||||
|
|
|
|
|
|
|
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Interest paid/accrued post-Emergence |
$ | 52 | $ | — | $ | 157 | $ | — | ||||||||
Interest paid/accrued on debtor-in-possession financing |
— | 38 | — | 76 | ||||||||||||
Adequate protection amounts paid/accrued |
— | 331 | — | 977 | ||||||||||||
Unrealized mark-to-market net (gains) losses on interest rate swaps |
(3 | ) | — | 3 | — | |||||||||||
Reversal of debt extinguishment gain |
21 | — | — | — | ||||||||||||
Capitalized interest |
(1 | ) | (2 | ) | (5 | ) | (9 | ) | ||||||||
Other |
7 | 4 | 14 | 5 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total interest expense and related charges |
$ | 76 | $ | 371 | $ | 169 | $ | 1,049 | ||||||||
|
|
|
|
|
|
|
|
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Interest paid/accrued post-Emergence |
$ | 51 | $ | — | $ | — | $ | — | ||||||||
Interest paid/accrued on debtor-in-possession financing |
— | 76 | 63 | 37 | ||||||||||||
Adequate protection amounts paid/accrued |
— | 977 | 1,233 | 828 | ||||||||||||
Interest paid/accrued on pre-petition debt (a) |
— | 1 | 4 | 878 | ||||||||||||
Noncash realized net loss on termination of interest rate swaps (offset in unrealized net gain) (Note 17) |
— | — | — | 1,225 | ||||||||||||
Unrealized mark-to-market net (gain) loss on interest rate swaps |
11 | — | — | (1,290 | ) | |||||||||||
Amortization of debt issuance, amendment and extension costs and premiums/discounts |
(1 | ) | 4 | — | 86 | |||||||||||
Dividends on mandatorily redeemable preferred stock |
2 | — | — | — | ||||||||||||
Capitalized interest |
(3 | ) | (9 | ) | (11 | ) | (17 | ) | ||||||||
Other |
— | — | — | 2 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total interest expense and related charges |
$ | 60 | $ | 1,049 | $ | 1,289 | $ | 1,749 | ||||||||
|
|
|
|
|
|
|
|
(a) | Includes amounts related to interest rate swaps totaling $193 million for the year ended December 31, 2014. Of the $193 million, $127 million is included in the liability arising from the termination of TCEH interest swaps as discussed in Note 17. |
Predecessor | ||||||||
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2016 |
|||||||
Contractual interest on debt classified as LSTC |
$ | 528 | $ | 1,570 | ||||
Adequate protection amounts paid/accrued |
315 | 930 | ||||||
|
|
|
|
|||||
Contractual interest on debt classified as LSTC not paid/accrued |
$ | 213 | $ | 640 | ||||
|
|
|
|
Predecessor | ||||||||||||
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, 2015 |
Post-Petition Period Ended December 31, 2014 |
||||||||||
Contractual interest on debt classified as LSTC |
$ | 1,570 | $ | 2,070 | $ | 1,392 | ||||||
Adequate protection amounts paid/accrued |
930 | 1,173 | 788 | |||||||||
|
|
|
|
|
|
|||||||
Contractual interest on debt classified as LSTC not paid/accrued |
$ | 640 | $ | 897 | $ | 604 | ||||||
|
|
|
|
|
|
|
Amounts in the table below represent the categories of long-term debt obligations incurred by the Successor.
September 30, 2017 |
December 31, 2016 |
|||||||
Vistra Operations Credit Facilities (a) |
$ | 4,484 | $ | 4,515 | ||||
Mandatorily redeemable subsidiary preferred stock (b) |
70 | 70 | ||||||
8.82% Building Financing due semiannually through February 11, 2022 (c) |
30 | 36 | ||||||
Capital lease obligations |
— | 2 | ||||||
|
|
|
|
|||||
Total long-term debt including amounts due currently |
4,584 | 4,623 | ||||||
Less amounts due currently |
(44 | ) | (46 | ) | ||||
|
|
|
|
|||||
Total long-term debt less amounts due currently |
$ | 4,540 | $ | 4,577 | ||||
|
|
|
|
(a) | At September 30, 2017, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $22 million, debt discounts of $2 million and debt issuance costs of $7 million. At December 31, 2016, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million. |
(b) | Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 2). This subsidiary preferred stock is accounted for as a debt instrument under relevant accounting guidance. |
(c) | Obligation related to a corporate office space capital lease contributed to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account and reflected in other noncurrent assets in our condensed consolidated balance sheets. |
Amounts in the table below represent the categories of long-term debt obligation incurred by the Successor.
Successor | ||||
December 31, 2016 |
||||
Vistra Operations Credit Facilities (a) |
$ | 4,515 | ||
Mandatorily redeemable preferred stock (b) |
70 | |||
8.82% Building Financing due semiannually through February 11, 2022 (c) |
36 | |||
Capital lease obligations |
2 | |||
|
|
|||
Total long-term debt including amounts due currently |
4,623 | |||
Less amounts due currently |
(46 | ) | ||
|
|
|||
Total long-term debt less amounts due currently |
$ | 4,577 | ||
|
|
(a) | Borrowings under the Vistra Operations Credit Facilities in the consolidated balance sheet include debt premiums of $25 million, debt discounts of $2 million and debt issuance costs of $8 million. |
(b) | Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the spin-off of Vistra Energy from EFH Corp. (see Note 2). This subsidiary’s preferred stock is accounted for as a debt instrument under relevant accounting guidance. |
(c) | Obligation related to a corporate office space capital lease contributed to Vistra Energy pursuant to the Plan of Reorganization. This obligation will be funded by amounts held in an escrow account and reflected in other noncurrent assets on the consolidated balance sheet at December 31, 2016. |
The Vistra Operations Credit Facilities and related available capacity at September 30, 2017 are presented below.
September 30, 2017 | ||||||||||||||||
Vistra Operations Credit Facilities |
Maturity Date | Facility Limit |
Cash Borrowings |
Available Capacity |
||||||||||||
Revolving Credit Facility (a) |
August 4, 2021 | $ | 860 | $ | — | $ | 860 | |||||||||
Initial Term Loan B Facility (b)(c) |
August 4, 2023 | 2,850 | 2,829 | — | ||||||||||||
Incremental Term Loan B Facility (c) |
December 14, 2023 | 1,000 | 992 | — | ||||||||||||
Term Loan C Facility (d) |
August 4, 2023 | 650 | 650 | 170 | ||||||||||||
|
|
|
|
|
|
|||||||||||
Total Vistra Operations Credit Facilities |
$ | 5,360 | $ | 4,471 | $ | 1,030 | ||||||||||
|
|
|
|
|
|
(a) | Facility to be used for general corporate purposes. |
(b) | Facility used to repay all amounts outstanding under our Predecessor’s DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes. |
(c) | Cash borrowings under the Term Loan B Facility reflect required scheduled quarterly payment in annual amount equal to 1% of the original principal amount with the balance paid at maturity. Amounts paid cannot be reborrowed. |
(d) | Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in our condensed consolidated balance sheets. At September 30, 2017, the restricted cash supported $480 million in letters of credit outstanding (see Note 16), leaving $170 million in available letter of credit capacity. |
The Vistra Operations Credit Facilities and related available capacity at December 31, 2016 are presented below.
December 31, 2016 | ||||||||||||||||
Vistra Operations Credit Facilities |
Maturity Date | Facility Limit | Cash Borrowings |
Available Credit Capacity |
||||||||||||
Revolving Credit Facility (a) |
August 4, 2021 | $ | 860 | $ | — | $ | 860 | |||||||||
Initial Term Loan B Facility (b) |
August 4, 2023 | 2,850 | 2,850 | — | ||||||||||||
Incremental Term Loan B Facility (c) |
December 14, 2023 | 1,000 | 1,000 | — | ||||||||||||
Term Loan C Facility (d) |
August 4, 2023 | 650 | 650 | 131 | ||||||||||||
|
|
|
|
|
|
|||||||||||
Total Vistra Operations Credit Facilities |
$ | 5,360 | $ | 4,500 | $ | 991 | ||||||||||
|
|
|
|
|
|
(a) | Facility to be used for general corporate purposes. |
(b) | Facility used to repay all amounts outstanding under the Predecessor’s DIP Facility and issuance costs for the DIP Roll Facilities, with the remaining balance used for general corporate purposes. |
(c) | Facility used to fund a special cash dividend paid in December 2016 (see Note 15). |
(d) | Facility used for issuing letters of credit for general corporate purposes. Borrowings under this facility were funded to collateral accounts that are reported as restricted cash in the consolidated balance sheet. At December 31, 2016, the restricted cash supported $519 million in letters of credit outstanding (see Note 22), leaving $131 million in available letter of credit capacity. |
Maturities — Long-term debt maturities at December 31, 2016 are as follows:
Successor | ||||
December 31, 2016 |
||||
2017 |
$ | 46 | ||
2018 |
44 | |||
2019 |
44 | |||
2020 |
44 | |||
2021 |
45 | |||
Thereafter |
4,380 | |||
Unamortized premiums, discounts and debt issuance costs |
20 | |||
|
|
|||
Total long-term debt including amounts due currently |
$ | 4,623 | ||
|
|
Predecessor | ||||
December 31, 2015 |
||||
7.48% Fixed Secured Facility Bonds with amortizing payments through January 2017 (a) |
$ | 13 | ||
Capital lease and other obligations |
6 | |||
|
|
|||
Total |
19 | |||
Less amounts due currently |
(16 | ) | ||
|
|
|||
Total long-term debt not subject to compromise |
$ | 3 | ||
|
|
(a) | Debt issued by trust and secured by assets held by the trust. |
|
At December 31, 2016, we had contractual commitments under energy-related contracts, leases and other agreements as follows.
Coal purchase and transportation agreements |
Pipeline transportation and storage reservation fees |
Nuclear Fuel Contracts |
Other Contracts |
|||||||||||||
2017 |
$ | 338 | $ | 30 | $ | 72 | $ | 128 | ||||||||
2018 |
— | 21 | 91 | 55 | ||||||||||||
2019 |
— | 22 | 39 | 57 | ||||||||||||
2020 |
— | 22 | 43 | 54 | ||||||||||||
2021 |
— | 22 | 49 | 36 | ||||||||||||
Thereafter |
— | 161 | 222 | 350 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 338 | $ | 278 | $ | 516 | $ | 680 | ||||||||
|
|
|
|
|
|
|
|
At December 31, 2016, future minimum lease payments under both capital leases and operating leases are as follows:
Capital Leases |
Operating Leases (a) |
|||||||
2017 |
$ | 2 | $ | 25 | ||||
2018 |
— | 17 | ||||||
2019 |
— | 14 | ||||||
2020 |
— | 12 | ||||||
2021 |
— | 9 | ||||||
Thereafter |
— | 153 | ||||||
|
|
|
|
|||||
Total future minimum lease payments |
2 | $ | 230 | |||||
|
|
|||||||
Less amounts representing interest |
— | |||||||
|
|
|||||||
Present value of future minimum lease payments |
2 | |||||||
Less current portion |
(2 | ) | ||||||
|
|
|||||||
Long-term capital lease obligation |
$ | — | ||||||
|
|
|
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
September 30, 2017 |
||||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
||||||||||||||||||||
Commodity contracts |
$ | 27 | $ | 90 | $ | 182 | $ | 3 | $ | 302 | ||||||||||
Interest rate swaps |
— | 2 | — | 7 | 9 | |||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
486 | — | — | — | 486 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 365 | — | — | 365 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Sub-total |
$ | 513 | $ | 457 | $ | 182 | $ | 10 | 1,162 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Assets measured at net asset value (d): |
||||||||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
281 | |||||||||||||||||||
|
|
|||||||||||||||||||
Total assets |
$ | 1,443 | ||||||||||||||||||
|
|
|||||||||||||||||||
Liabilities: |
||||||||||||||||||||
Commodity contracts |
$ | 28 | $ | 25 | $ | 25 | $ | 3 | $ | 81 | ||||||||||
Interest rate swaps |
— | 16 | — | 7 | 23 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total liabilities |
$ | 28 | $ | 41 | $ | 25 | $ | 10 | $ | 104 | ||||||||||
|
|
|
|
|
|
|
|
|
|
December 31, 2016 |
||||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
||||||||||||||||||||
Commodity contracts |
$ | 167 | $ | 131 | $ | 98 | $ | — | $ | 396 | ||||||||||
Interest rate swaps |
— | 5 | — | 13 | 18 | |||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
425 | — | — | — | 425 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 340 | — | — | 340 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Sub-total |
$ | 592 | $ | 476 | $ | 98 | $ | 13 | 1,179 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Assets measured at net asset value (d): |
||||||||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
247 | |||||||||||||||||||
|
|
|||||||||||||||||||
Total assets |
$ | 1,426 | ||||||||||||||||||
|
|
|||||||||||||||||||
Liabilities: |
||||||||||||||||||||
Commodity contracts |
$ | 302 | $ | 15 | $ | 15 | $ | — | $ | 332 | ||||||||||
Interest rate swaps |
— | 16 | — | 13 | 29 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total liabilities |
$ | 302 | $ | 31 | $ | 15 | $ | 13 | $ | 361 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | See table below for description of Level 3 assets and liabilities. |
(b) | Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in our condensed consolidated balance sheets. |
(c) | The nuclear decommissioning trust investment is included in the other investments line in our condensed consolidated balance sheets. See Note 16. |
(d) | The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our condensed consolidated balance sheets. Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. |
Assets and liabilities measured at fair value on a recurring basis consisted of the following at the respective balance sheet dates shown below:
Successor |
||||||||||||||||||||
December 31, 2016 |
||||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
||||||||||||||||||||
Commodity contracts |
$ | 167 | $ | 131 | $ | 98 | $ | — | $ | 396 | ||||||||||
Interest rate swaps |
— | 5 | — | 13 | 18 | |||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
425 | — | — | — | 425 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 340 | — | — | 340 | |||||||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Subtotal |
$ | 592 | $ | 476 | $ | 98 | $ | 13 | 1,179 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Assets measured at net asset value (d): |
||||||||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
247 | |||||||||||||||||||
|
|
|||||||||||||||||||
Total assets |
$ | 1,426 | ||||||||||||||||||
|
|
|||||||||||||||||||
Liabilities: |
||||||||||||||||||||
Commodity contracts |
$ | 302 | $ | 15 | $ | 15 | $ | — | $ | 332 | ||||||||||
Interest rate swaps |
— | 16 | — | 13 | 29 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total liabilities |
$ | 302 | $ | 31 | $ | 15 | $ | 13 | $ | 361 | ||||||||||
|
|
|
|
|
|
|
|
|
|
Predecessor |
||||||||||||||||||||
December 31, 2015 |
||||||||||||||||||||
Level 1 | Level 2 | Level 3 (a) | Reclassification (b) | Total | ||||||||||||||||
Assets: |
||||||||||||||||||||
Commodity contracts |
$ | 385 | $ | 41 | $ | 49 | $ | — | $ | 475 | ||||||||||
Nuclear decommissioning trust — equity securities (c) |
380 | — | — | — | 380 | |||||||||||||||
Nuclear decommissioning trust — debt securities (c) |
— | 319 | — | — | 319 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Subtotal |
$ | 765 | $ | 360 | $ | 49 | $ | — | 1,174 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||||||
Assets measured at net asset value (d): |
||||||||||||||||||||
Nuclear decommissioning trust — equity securities (c) |
219 | |||||||||||||||||||
|
|
|||||||||||||||||||
Total assets |
$ | 1,393 | ||||||||||||||||||
|
|
|||||||||||||||||||
Liabilities: |
||||||||||||||||||||
Commodity contracts |
$ | 128 | $ | 64 | $ | 12 | $ | — | $ | 204 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total liabilities |
$ | 128 | $ | 64 | $ | 12 | $ | — | $ | 204 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(a) | See table below for description of Level 3 assets and liabilities. |
(b) | Fair values are determined on a contract basis, but certain contracts result in a current asset and a noncurrent liability, or vice versa, as presented in the consolidated balance sheets. |
(c) | The nuclear decommissioning trust investment is included in the investments line in the condensed consolidated balance sheets. See Note 22. |
(d) | Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to the amounts presented in the condensed consolidated balance sheets. |
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at September 30, 2017 and December 31, 2016:
September 30, 2017 |
||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Contract Type (a) |
Assets | Liabilities | Total |
Valuation |
Significant Unobservable Input |
Range (b) | ||||||||||||||
Electricity purchases and sales |
$ | 101 | $ | (8 | ) | $ | 93 | Valuation Model | Hourly price curve shape (c) | |
$0 to $35/ MWh |
|
||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) | |
$20 to $60/ MWh |
|
|||||||||||||||||
Electricity options |
33 | (13 | ) | 20 | Option Pricing Model | Gas to power correlation (e) | 30% to 95% | |||||||||||||
Power volatility (e) | 5% to 180% | |||||||||||||||||||
Electricity congestion revenue rights |
35 | (4 | ) | 31 | Market Approach (f) | Illiquid price differences between settlement points (g) | |
$0 to $15/ MWh |
|
|||||||||||
Other (h) |
13 | — | 13 | |||||||||||||||||
|
|
|
|
|
|
|||||||||||||||
Total |
$ | 182 | $ | (25 | ) | $ | 157 | |||||||||||||
|
|
|
|
|
|
|||||||||||||||
December 31, 2016 |
||||||||||||||||||||
Fair Value | ||||||||||||||||||||
Contract Type (a) |
Assets | Liabilities | Total |
Valuation |
Significant Unobservable Input |
Range (b) | ||||||||||||||
Electricity purchases and sales |
$ | 32 | $ | — | $ | 32 | Valuation Model | Hourly price curve shape (c) | |
$0 to $35/ MWh |
|
|||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (d) | |
$30 to $70/ MWh |
|
|||||||||||||||||
Electricity congestion revenue rights |
42 | (6 | ) | 36 | Market Approach (f) | Illiquid price differences between settlement points (g) | |
$0 to $10/ MWh |
|
|||||||||||
Other (h) |
24 | (9 | ) | 15 | ||||||||||||||||
|
|
|
|
|
|
|||||||||||||||
Total |
$ | 98 | $ | (15 | ) | $ | 83 | |||||||||||||
|
|
|
|
|
|
(a) | Electricity purchase and sales contracts include power and heat rate positions in ERCOT regions. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. Electricity options consist of physical electricity options and spread options. |
(b) | The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. |
(c) | Based on the historical range of forward average hourly ERCOT North Hub prices. |
(d) | Based on historical forward ERCOT power price and heat rate variability. |
(e) | Based on historical forward correlation and volatility within ERCOT. |
(f) | While we use the market approach, there is insufficient market data to consider the valuation liquid. |
(g) | Based on the historical price differences between settlement points within ERCOT hubs and load zones. |
(h) | Other includes contracts for natural gas, coal and coal options. December 31, 2016 also includes an immaterial amount of electricity options. |
The following tables present the fair value of the Level 3 assets and liabilities by major contract type and the significant unobservable inputs used in the valuations at December 31, 2016 and 2015:
Successor |
||||||||||||||||||
December 31, 2016 |
||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) |
Assets |
Liabilities |
Total |
Valuation |
Significant Unobservable Input |
Range (b) |
||||||||||||
Electricity purchases and sales |
$ | 32 | $ | — | $ | 32 | Valuation Model |
Hourly price curve shape (d) | $0 to $35/MWh |
|||||||||
Illiquid delivery periods for ERCOT hub power prices and heat rates (e) |
$30 to $70/MWh |
|||||||||||||||||
Electricity congestion revenue rights |
42 | (6 | ) | 36 | Market Approach (f) |
Illiquid price differences between settlement points (g) |
$0 to $10/MWh |
|||||||||||
Other (h) |
24 | (9 | ) | 15 | ||||||||||||||
|
|
|
|
|
|
|||||||||||||
Total |
$ | 98 | $ | (15 | ) | $ | 83 | |||||||||||
|
|
|
|
|
|
Predecessor |
||||||||||||||||||
December 31, 2015 |
||||||||||||||||||
Fair Value | ||||||||||||||||||
Contract Type (a) |
Assets |
Liabilities |
Total |
Valuation |
Significant Unobservable Input |
Range (b) |
||||||||||||
Electricity purchases and sales |
$ | 1 | $ | (1 | ) | $ | — | Valuation Model |
Illiquid pricing locations (c) | $15 to $35/MWh |
||||||||
Hourly price curve shape (d) | $15 to $45/MWh |
|||||||||||||||||
Electricity congestion revenue rights |
39 | (4 | ) | 35 | Market Approach (f) |
Illiquid price differences between settlement points (g) |
$0 to $10/MWh |
|||||||||||
Other (h) |
9 | (7 | ) | 2 | ||||||||||||||
|
|
|
|
|
|
|||||||||||||
Total |
$ | 49 | $ | (12 | ) | $ | 37 | |||||||||||
|
|
|
|
|
|
(a) | Electricity purchase and sales contracts include power and heat rate hedging positions in ERCOT regions. Electricity options contracts consist of physical electricity options and spread options. Electricity congestion revenue rights contracts consist of forward purchase contracts (swaps and options) used to hedge electricity price differences between settlement points within ERCOT. |
(b) | The range of the inputs may be influenced by factors such as time of day, delivery period, season and location. |
(c) | Based on the historical range of forward average monthly ERCOT hub and load zone prices. |
(d) | Based on the historical range of forward average hourly ERCOT North Hub prices. |
(e) | Based on historical forward ERCOT power price and heat rate variability. |
(f) | While we use the market approach, there is insufficient market data to consider the valuation liquid. |
(g) | Based on the historical price differences between settlement points within ERCOT hubs and load zones. |
(h) | Other includes contracts for ancillary services, natural gas, electricity options and coal options. |
The following table presents the changes in fair value of the Level 3 assets and liabilities for the three and nine months ended September 30, 2017 and 2016.
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Net asset (liability) balance at beginning of period |
$ | 75 | $ | (9 | ) | $ | 83 | $ | 37 | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total unrealized valuation gains (losses) |
132 | 126 | 139 | 122 | ||||||||||||
Purchases, issuances and settlements (a): |
||||||||||||||||
Purchases |
16 | 11 | 51 | 37 | ||||||||||||
Issuances |
(5 | ) | (4 | ) | (19 | ) | (20 | ) | ||||||||
Settlements |
(45 | ) | (24 | ) | (87 | ) | (51 | ) | ||||||||
Transfers into Level 3 (b) |
— | — | 4 | 1 | ||||||||||||
Transfers out of Level 3 (b) |
— | — | 2 | 1 | ||||||||||||
Earn-out provision (c) |
(16 | ) | — | (16 | ) | — | ||||||||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 3) |
— | (3 | ) | — | (30 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net change (d) |
82 | 106 | 74 | 60 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net asset balance at end of period |
$ | 157 | $ | 97 | $ | 157 | $ | 97 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Unrealized valuation gains relating to instruments held at end of period |
$ | 106 | $ | 92 | $ | 110 | $ | 98 |
(a) | Settlements reflect reversals of unrealized mark-to-market valuations previously recognized in net income. Purchases and issuances reflect option premiums paid or received. |
(b) | Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. |
(c) | Represents initial fair value of the earn-out provision incurred as part of the Odessa Acquisition. See Note 3. |
(d) | Substantially all changes in value of commodity contracts (excluding the initial fair value of the earn-out provision related to the Odessa Acquisition in 2017 and the net liability assumed in the Lamar and Forney Acquisition in 2016) are reported as operating revenues in our condensed statements of consolidated income (loss). Activity excludes change in fair value in the month positions settle. |
The following table presents the changes in fair value of the Level 3 assets and liabilities for the Successor period from October 3, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014.
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Net asset (liability) balance at beginning of period (a) |
$ | 81 | $ | 37 | $ | 35 | $ | (973 | ) | |||||||
|
|
|
|
|
|
|
|
|||||||||
Total unrealized valuation gains (losses) |
31 | 122 | 27 | (97 | ) | |||||||||||
Purchases, issuances and settlements (b) |
||||||||||||||||
Purchases |
15 | 37 | 49 | 63 | ||||||||||||
Issuances |
(7 | ) | (20 | ) | (13 | ) | (5 | ) | ||||||||
Settlements |
(30 | ) | (51 | ) | (48 | ) | 1,053 | |||||||||
Transfers into Level 3 (c) |
3 | 1 | 1 | — | ||||||||||||
Transfers out of Level 3 (c) |
(10 | ) | 1 | (14 | ) | (6 | ) | |||||||||
Net liabilities assumed in the Lamar and Forney Acquisition (Note 6) (d) |
— | (30 | ) | — | — | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net change (e) |
2 | 60 | 2 | 1,008 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net asset balance at end of period |
$ | 83 | $ | 97 | $ | 37 | $ | 35 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Unrealized valuation gains (losses) relating to instruments held at end of period |
$ | 28 | $ | 98 | $ | 18 | $ | (5 | ) |
(a) | The beginning balance for the Successor period reflects a $16 million adjustment to the fair value of certain Level 3 assets driven by power prices utilized by the Successor for unobservable delivery periods. |
(b) | Settlements reflect reversals of unrealized mark-to-market valuations. Purchases and issuances reflect option premiums paid or received, respectively. |
(c) | Includes transfers due to changes in the observability of significant inputs. All Level 3 transfers during the periods presented are in and out of Level 2. |
(d) | Includes fair value of Level 3 assets and liabilities as of the purchase date and any related rolloff between the purchase date and the period ended October 2, 2016. |
(e) |
Activity excludes changes in fair value in the month the positions settled as well as amounts related to positions entered into and settled in the same quarter. For the Successor period, substantially all changes in values of commodity contracts are reported in the statements of consolidated income (loss) in operating revenues or fuel, purchased power costs and delivery fees. For the Predecessor period, substantially all changes in values of commodity contracts (excluding net liabilities assumed in the Lamar and Forney Acquisition) are reported in the statements of consolidated income (loss) in net gain from commodity hedging and trading activities. |
|
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in our condensed consolidated balance sheets at September 30, 2017 and December 31, 2016. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
September 30, 2017 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity Contracts |
Interest Rate Swaps |
Commodity Contracts |
Interest Rate Swaps |
Total | ||||||||||||||||
Current assets |
$ | 181 | $ | — | $ | 1 | $ | — | $ | 182 | ||||||||||
Noncurrent assets |
120 | 9 | — | — | 129 | |||||||||||||||
Current liabilities |
(2 | ) | (7 | ) | (53 | ) | (10 | ) | (72 | ) | ||||||||||
Noncurrent liabilities |
— | — | (26 | ) | (6 | ) | (32 | ) | ||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net assets (liabilities) |
$ | 299 | $ | 2 | $ | (78 | ) | $ | (16 | ) | $ | 207 | ||||||||
|
|
|
|
|
|
|
|
|
|
December 31, 2016 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity Contracts |
Interest Rate Swaps |
Commodity Contracts |
Interest Rate Swaps |
Total | ||||||||||||||||
Current assets |
$ | 350 | $ | — | $ | — | $ | — | $ | 350 | ||||||||||
Noncurrent assets |
46 | 17 | — | 1 | 64 | |||||||||||||||
Current liabilities |
— | (12 | ) | (330 | ) | (17 | ) | (359 | ) | |||||||||||
Noncurrent liabilities |
— | — | (2 | ) | — | (2 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net assets (liabilities) |
$ | 396 | $ | 5 | $ | (332 | ) | $ | (16 | ) | $ | 53 | ||||||||
|
|
|
|
|
|
|
|
|
|
Substantially all derivative contractual assets and liabilities are accounted for under mark-to-market accounting consistent with accounting standards related to derivative instruments and hedging activities. The following tables provide detail of derivative contractual assets and liabilities as reported in the consolidated balance sheets at December 31, 2016 and 2015. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
Successor | ||||||||||||||||||||
December 31, 2016 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity contracts |
Interest rate swaps |
Commodity contracts |
Interest rate swaps |
Total | ||||||||||||||||
Current assets |
$ | 350 | $ | — | $ | — | $ | — | $ | 350 | ||||||||||
Noncurrent assets |
46 | 17 | — | 1 | 64 | |||||||||||||||
Current liabilities |
— | (12 | ) | (330 | ) | (17 | ) | (359 | ) | |||||||||||
Noncurrent liabilities |
— | — | (2 | ) | — | (2 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net assets (liabilities) |
$ | 396 | $ | 5 | $ | (332 | ) | $ | (16 | ) | $ | 53 | ||||||||
|
|
|
|
|
|
|
|
|
|
Predecessor | ||||||||||||||||||||
December 31, 2015 | ||||||||||||||||||||
Derivative Assets | Derivative Liabilities | |||||||||||||||||||
Commodity contracts |
Interest rate swaps |
Commodity contracts |
Interest rate swaps |
Total | ||||||||||||||||
Current assets |
$ | 465 | $ | — | $ | — | $ | — | $ | 465 | ||||||||||
Noncurrent assets |
10 | — | — | — | 10 | |||||||||||||||
Current liabilities |
— | — | (203 | ) | — | (203 | ) | |||||||||||||
Noncurrent liabilities |
— | — | (1 | ) | — | (1 | ) | |||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Net assets (liabilities) |
$ | 475 | $ | — | $ | (204 | ) | $ | — | $ | 271 | |||||||||
|
|
|
|
|
|
|
|
|
|
The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects:
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Derivative (condensed statements of consolidated income |
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
||||||||||||
Commodity contracts (Operating revenues) (a) |
$ | 166 | $ | — | $ | 333 | $ | — | ||||||||
Commodity contracts (Fuel, purchased power costs and delivery fees) (a) |
9 | — | 3 | — | ||||||||||||
Commodity contracts (Net gain from commodity hedging and trading activities) (a) |
— | 239 | — | 194 | ||||||||||||
Interest rate swaps (Interest expense and related charges) (b) |
(4 | ) | — | (24 | ) | — | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net gain (loss) |
$ | 171 | $ | 239 | $ | 312 | $ | 194 | ||||||||
|
|
|
|
|
|
|
|
(a) | Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. |
(b) | Includes unrealized mark-to-market net gains as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 7). |
The following table presents the pretax effect of derivatives on net income (gains (losses)), including realized and unrealized effects:
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
Derivative (statements of consolidated income (loss) presentation) |
2015 |
2014 |
||||||||||||||
Commodity contracts (Operating revenues) (a) |
$ | (92 | ) | $ | — | $ | — | $ | — | |||||||
Commodity contracts (Fuel, purchased power costs and delivery fees) (a) |
21 | — | — | — | ||||||||||||
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) (a) |
— | 194 | 380 | 17 | ||||||||||||
Interest rate swaps (Interest expense and related charges) (b) |
(11 | ) | — | — | (128 | ) | ||||||||||
Interest rate swaps (Reorganization items) (Note 4) |
— | — | — | (277 | ) | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Net gain (loss) |
$ | (82 | ) | $ | 194 | $ | 380 | $ | (388 | ) | ||||||
|
|
|
|
|
|
|
|
(a) | Amount represents changes in fair value of positions in the derivative portfolio during the period, as realized amounts related to positions settled are assumed to equal reversals of previously recorded unrealized amounts. |
(b) | Includes unrealized mark-to-market net gain (loss) as well as the net realized effect on interest paid/accrued, both reported in Interest Expense and Related Charges (see Note 11). |
The following tables reconcile our derivative assets and liabilities on a contract basis to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||||||||||
Derivative Assets and Liabilities |
Offsetting Instruments (a) |
Cash Collateral (Received) Pledged (b) |
Net Amounts |
Derivative Assets and Liabilities |
Offsetting Instruments (a) |
Cash Collateral (Received) Pledged (b) |
Net Amounts |
|||||||||||||||||||||||||
Derivative assets: |
||||||||||||||||||||||||||||||||
Commodity contracts |
$ | 299 | $ | (64 | ) | $ | (9 | ) | $ | 226 | $ | 396 | $ | (193 | ) | $ | (20 | ) | $ | 183 | ||||||||||||
Interest rate swaps |
2 | — | — | 2 | 5 | — | — | 5 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Total derivative assets |
301 | (64 | ) | (9 | ) | 228 | 401 | (193 | ) | (20 | ) | 188 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Derivative liabilities: |
||||||||||||||||||||||||||||||||
Commodity contracts |
(78 | ) | 64 | 1 | (13 | ) | (332 | ) | 193 | 136 | (3 | ) | ||||||||||||||||||||
Interest rate swaps |
(16 | ) | — | — | (16 | ) | (16 | ) | — | — | (16 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Total derivative liabilities |
(94 | ) | 64 | 1 | (29 | ) | (348 | ) | 193 | 136 | (19 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Net amounts |
$ | 207 | $ | — | $ | (8 | ) | $ | 199 | $ | 53 | $ | — | $ | 116 | $ | 169 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) | Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Represents cash amounts received or pledged pursuant to a master netting arrangement, including fair value-based margin requirements and, to a lesser extent, initial margin requirements. |
The following tables reconcile our derivative assets and liabilities as presented in the condensed consolidated balance sheets to net amounts after taking into consideration netting arrangements with counterparties and financial collateral:
Successor | Predecessor | |||||||||||||||||||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||||||||||||||||||
Amounts Presented in Balance Sheet |
Offsetting Instruments (a) |
Financial Collateral (Received) Pledged (b) |
Net Amounts |
Amounts Presented in Balance Sheet |
Offsetting Instruments (a) |
Financial Collateral (Received) Pledged (b) |
Net Amounts |
|||||||||||||||||||||||||
Derivative assets: |
||||||||||||||||||||||||||||||||
Commodity contracts |
$ | 396 | $ | (193 | ) | $ | (20 | ) | $ | 183 | $ | 475 | $ | (145 | ) | $ | (147 | ) | $ | 183 | ||||||||||||
Interest rate swaps |
5 | — | — | 5 | — | — | — | — | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Total derivative assets |
401 | (193 | ) | (20 | ) | 188 | 475 | (145 | ) | (147 | ) | 183 | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Derivative liabilities: |
||||||||||||||||||||||||||||||||
Commodity contracts |
(332 | ) | 193 | 136 | (3 | ) | (204 | ) | 145 | 6 | (53 | ) | ||||||||||||||||||||
Interest rate swaps |
(16 | ) | — | — | (16 | ) | — | — | — | — | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Total derivative liabilities |
(348 | ) | 193 | 136 | (19 | ) | (204 | ) | 145 | 6 | (53 | ) | ||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
Net amounts |
$ | 53 | $ | — | $ | 116 | $ | 169 | $ | 271 | $ | — | $ | (141 | ) | $ | 130 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) | Amounts presented exclude trade accounts receivable and payable related to settled financial instruments. |
(b) | Financial collateral consists entirely of cash margin deposits. |
The following table presents the gross notional amounts of derivative volumes at September 30, 2017 and December 31, 2016:
September 30, 2017 |
December 31, 2016 |
|||||||||
Derivative type |
Notional Volume | Unit of Measure | ||||||||
Natural gas (a) |
1,420 | 1,282 | Million MMBtu | |||||||
Electricity |
106,190 | 75,322 | GWh | |||||||
Congestion Revenue Rights (b) |
96,269 | 126,573 | GWh | |||||||
Coal |
4 | 12 | Million US tons | |||||||
Fuel oil |
19 | 34 | Million gallons | |||||||
Uranium |
450 | 25 | Thousand pounds | |||||||
Interest rate swaps — floating/fixed (c) |
$ | 3,000 | $ | 3,000 | Million US dollars |
(a) | Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions. |
(b) | Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT. |
(c) | Includes notional amounts of interest rate swaps that became effective in January 2017 and have maturity dates through July 2023. |
The following table presents the gross notional amounts of derivative volumes at December 31, 2016 and 2015:
Successor | Predecessor | |||||||||
December 31, 2016 |
December 31, 2015 |
|||||||||
Derivative type |
Notional Volume |
Notional Volume |
Unit of Measure | |||||||
Natural gas (a) |
1,282 | 1,489 | Million MMBtu | |||||||
Electricity |
75,322 | 58,022 | GWh | |||||||
Congestion Revenue Rights (b) |
126,573 | 106,260 | GWh | |||||||
Coal |
12 | 10 | Million US tons | |||||||
Fuel oil |
34 | 35 | Million gallons | |||||||
Uranium |
25 | 75 | Thousand pounds | |||||||
Interest rate swaps — Floating/Fixed (c) |
$ | 3,000 | $ | — | Million US dollars |
(a) | Represents gross notional forward sales, purchases and options transactions, locational basis swaps and other natural gas transactions. |
(b) | Represents gross forward purchases associated with instruments used to hedge electricity price differences between settlement points within ERCOT. |
(c) | Successor period includes notional amounts of interest rate swaps that become effective in January 2017 and have maturity dates through July 2023. |
The following table presents the commodity derivative liabilities subject to credit risk-related contingent features that are not fully collateralized:
September 30, 2017 |
December 31, 2016 |
|||||||
Fair value of derivative contract liabilities (a) |
$ | (41 | ) | $ | (31 | ) | ||
Offsetting fair value under netting arrangements (b) |
22 | 13 | ||||||
Cash collateral and letters of credit |
1 | 1 | ||||||
|
|
|
|
|||||
Liquidity exposure |
$ | (18 | ) | $ | (17 | ) | ||
|
|
|
|
(a) | Excludes fair value of contracts that contain contingent features that do not provide specific amounts to be posted if features are triggered, including provisions that generally provide the right to request additional collateral (material adverse change, performance assurance and other clauses). |
(b) | Amounts include the offsetting fair value of in-the-money derivative contracts and net accounts receivable under master netting arrangements. |
|
Pension and OPEB Costs
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Pension costs |
$ | 2 | $ | 4 | $ | 8 | $ | 7 | ||||||||
OPEB costs |
2 | — | 3 | 5 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total benefit costs recognized as expense |
$ | 4 | $ | 4 | $ | 11 | $ | 12 | ||||||||
|
|
|
|
|
|
|
|
The following table provides information regarding pension plans with projected benefit obligation (PBO) and accumulated benefit obligation (ABO) in excess of the fair value of plan assets.
Successor | ||||
December 31, 2016 |
||||
Pension Plans with PBO and ABO in Excess Of Plan Assets: |
||||
Projected benefit obligations |
$ | 144 | ||
Accumulated benefit obligation |
$ | 136 | ||
Plan assets |
$ | 117 |
The target asset allocation ranges of pension plan investments by asset category are as follows:
Asset Category: | Target Allocation Ranges |
|
Fixed income |
74% - 86% | |
US equities |
8% - 14% | |
International equities |
6% - 12% |
Expected Long-Term Rate of Return on Assets Assumption
The Retirement Plan strategic asset allocation is determined in conjunction with the plan’s advisors and utilizes a comprehensive Asset-Liability modeling approach to evaluate potential long-term outcomes of various investment strategies. The study incorporates long-term rate of return assumptions for each asset class based on historical and future expected asset class returns, current market conditions, rate of inflation, current prospects for economic growth, and taking into account the diversification benefits of investing in multiple asset classes and potential benefits of employing active investment management.
Retirement Plan |
||||
Asset Class: | Expected Long- Term Rate of Return |
|||
US equity securities |
6.4 | % | ||
International equity securities |
7.0 | % | ||
Fixed income securities |
4.2 | % | ||
Weighted average |
4.9 | % |
The following tables provide information regarding the assumed health care cost trend rates.
Successor | ||||
December 31, 2016 |
||||
Assumed Health Care Cost Trend Rates-Not Medicare Eligible: |
||||
Health care cost trend rate assumed for next year |
5.80 | % | ||
Rate to which the cost trend is expected to decline (the ultimate trend rate) |
5.00 | % | ||
Year that the rate reaches the ultimate trend rate |
2024 | |||
Assumed Health Care Cost Trend Rates-Medicare Eligible: |
||||
Health care cost trend rate assumed for next year |
5.70 | % | ||
Rate to which the cost trend is expected to decline (the ultimate trend rate) |
5.00 | % | ||
Year that the rate reaches the ultimate trend rate |
2024 |
1-Percentage Point Increase |
1-Percentage Point Decrease |
|||||||
Sensitivity Analysis of Assumed Health Care Cost Trend Rates: |
||||||||
Effect on accumulated postretirement obligation |
$ | (5 | ) | $ | 4 | |||
Effect on postretirement benefits cost |
$ | — | $ | — |
Estimated future benefit payments to beneficiaries are as follows:
2017 | 2018 | 2019 | 2020 | 2021 | 2022-26 | |||||||||||||||||||
Pension benefits |
$ | 6 | $ | 6 | $ | 7 | $ | 8 | $ | 8 | $ | 53 | ||||||||||||
OPEB |
$ | 5 | $ | 5 | $ | 5 | $ | 6 | $ | 6 | $ | 32 |
The following information is based on a December 31, 2016 measurement date:
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Assumptions Used to Determine Net Periodic Pension Cost: |
||||
Discount rate |
3.79 | % | ||
Expected return on plan assets |
4.89 | % | ||
Expected rate of compensation increase |
3.50 | % | ||
Components of Net Pension Cost: |
||||
Service cost |
$ | 2 | ||
Interest cost |
1 | |||
Expected return on assets |
(1 | ) | ||
|
|
|||
Net periodic pension cost |
$ | 2 | ||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: |
||||
Net gain |
$ | (4 | ) | |
|
|
|||
Total recognized in net periodic benefit cost and other comprehensive income |
$ | (2 | ) | |
|
|
|||
Assumptions Used to Determine Benefit Obligations: |
||||
Discount rate |
4.31 | % | ||
Expected rate of compensation increase |
3.50 | % |
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Change in Pension Obligation: |
||||
Projected benefit obligation at beginning of period |
$ | 154 | ||
Service cost |
2 | |||
Interest cost |
1 | |||
Actuarial gain |
(12 | ) | ||
Benefits paid |
(1 | ) | ||
|
|
|||
Projected benefit obligation at end of year |
$ | 144 | ||
|
|
|||
Accumulated benefit obligation at end of year |
$ | 136 | ||
|
|
|||
Change in Plan Assets: |
||||
Fair value of assets at beginning of period |
$ | 124 | ||
Actual loss on assets |
(6 | ) | ||
Benefits paid |
(1 | ) | ||
|
|
|||
Fair value of assets at end of year |
$ | 117 | ||
|
|
|||
Funded Status: |
||||
Projected pension benefit obligation |
$ | (144 | ) | |
Fair value of assets |
117 | |||
|
|
|||
Funded status at end of year |
$ | (27 | ) | |
|
|
|||
Amounts Recognized in Accumulated Other Comprehensive Income Consist of: |
||||
Net gain |
$ | 4 | ||
|
|
At December 31, 2016, pension plan assets measured at fair value on a recurring basis consisted of the following:
Successor | ||||
Asset Category: | December 31, 2016 |
|||
Level 2 valuations (see Note 16): |
||||
Interest-bearing cash |
$ | (4 | ) | |
Fixed income securities: |
||||
Corporate bonds (a) |
54 | |||
US Treasuries |
30 | |||
Other (b) |
6 | |||
|
|
|||
Total assets categorized as Level 2 |
86 | |||
Assets measured at net asset value (c): |
||||
Interest-bearing cash |
2 | |||
Equity securities: |
||||
US |
14 | |||
International |
9 | |||
Fixed income securities: |
||||
Corporate bonds (a) |
6 | |||
|
|
|||
Total assets measured at net asset value |
31 | |||
|
|
|||
Total assets |
$ | 117 | ||
|
|
(a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
(b) | Other consists primarily of municipal bonds. |
(c) | Certain investments measured at fair value using the net asset value per share (or its equivalent) have not been classified in the fair value hierarchy. The fair value amounts presented in this line are intended to permit reconciliation of the fair value hierarchy to total Vistra Retirement Plan assets. |
The following OPEB information is based on a December 31, 2016 measurement date:
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Assumptions Used to Determine Net Periodic Benefit Cost: |
||||
Discount rate (Vistra Energy Plan) |
4.00 | % | ||
Discount rate (Oncor Plan) |
3.69 | % | ||
Components of Net Postretirement Benefit Cost: |
||||
Service cost |
$ | 1 | ||
Interest cost |
1 | |||
Plan amendments (a) |
(4 | ) | ||
|
|
|||
Net periodic OPEB cost |
$ | (2 | ) | |
|
|
|||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: |
||||
Net gain |
$ | (5 | ) | |
|
|
|||
Total recognized in net periodic benefit cost and other comprehensive income |
$ | (7 | ) | |
|
|
|||
Assumptions Used to Determine Benefit Obligations at Period End: |
||||
Discount rate (Vistra Energy Plan) |
4.11 | % | ||
Discount rate (Oncor Plan) |
4.18 | % |
(a) | Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees. |
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Change in Postretirement Benefit Obligation: |
||||
Benefit obligation at beginning of year |
$ | 97 | ||
Service cost |
1 | |||
Interest cost |
1 | |||
Participant contributions |
1 | |||
Plan amendments (a) |
(4 | ) | ||
Actuarial gain |
(5 | ) | ||
Benefits paid |
(3 | ) | ||
|
|
|||
Benefit obligation at end of year |
$ | 88 | ||
|
|
|||
Change in Plan Assets: |
||||
Fair value of assets at beginning of year |
$ | — | ||
Employer contributions |
1 | |||
Participant contributions |
1 | |||
Benefits paid |
(2 | ) | ||
|
|
|||
Fair value of assets at end of year |
$ | — | ||
|
|
|||
Funded Status: |
||||
Benefit obligation |
$ | 88 | ||
|
|
|||
Funded status at end of year |
$ | 88 | ||
|
|
|||
Amounts Recognized on the Balance Sheet Consist of: |
||||
Other current liabilities |
$ | 5 | ||
Other noncurrent liabilities |
83 | |||
|
|
|||
Net liability recognized |
$ | 88 | ||
|
|
|||
Amounts Recognized in Accumulated Other Comprehensive Income Consist of: |
||||
Net gain |
$ | 5 | ||
|
|
|||
Net amount recognized |
$ | 5 | ||
|
|
(a) | Curtailment gain recognized as other income in the statements of consolidated income (loss) as a result of discontinued life insurance benefits for active employees. |
|
Stock-based compensation expense is reported as SG&A in the statement of consolidated net income (loss) as follows:
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Total stock-based compensation expense |
$ | 3 | ||
Income tax benefit |
(1 | ) | ||
|
|
|||
Stock based-compensation expense, net of tax |
$ | 2 | ||
|
|
The weighted average assumptions used to value grant options are detailed below:
Stock Options (in thousands) |
Weighted Average Exercise Price |
Weighted Average Remaining Contractual Term (Years) |
Aggregate Intrinsic Value (in millions) |
|||||||||||||
Total outstanding at beginning of period |
— | $ | — | — | $ | — | ||||||||||
Granted |
7,379 | $ | 15.81 | 9.81 | $ | — | ||||||||||
Forfeited or expired |
(22 | ) | $ | 15.58 | 9.81 | $ | — | |||||||||
|
|
|
|
|||||||||||||
Total outstanding at end of period |
7,357 | $ | 15.81 | 9.81 | $ | — | ||||||||||
Expected to vest |
7,357 | $ | 15.81 | 9.81 | $ | — |
We granted 2.165 million restricted stock units to employees in the Successor period from October 3, 2016 through December 31, 2016.
Restricted Stock Units (in thousands) |
Weighted Average Grant Date Fair Value |
Weighted Average Remaining Contractual Term (Years) |
Aggregate Intrinsic Value (in millions) |
|||||||||||||
Total outstanding at beginning of period |
— | $ | — | — | $ | — | ||||||||||
Granted |
2,165 | $ | 15.79 | 2.3 | $ | 33.6 | ||||||||||
Forfeited or expired |
(6 | ) | $ | 15.58 | 2.3 | $ | (0.1 | ) | ||||||||
|
|
|
|
|||||||||||||
Total outstanding at end of period |
2,159 | $ | 15.79 | 2.3 | $ | 33.5 | ||||||||||
Expected to vest |
2,159 | $ | 15.79 | 2.3 | $ | 33.5 |
|
• | As a result of debt repurchase and exchange transactions in 2009 through 2011, EFH Corp. and EFIH held TCEH debt securities at December 31, 2014 as shown below (principal amounts). The $382 million in notes payable as of the Petition Date was classified as LSTC. The amounts of TCEH debt held by EFIH or EFH Corp. were eliminated as a result of the Settlement Agreement approved by the Bankruptcy Court in December 2015 (see Note 2). In conjunction with the Settlement Agreement approved by the Bankruptcy Court in December 2015, EFH Corp. and EFIH waived their rights to the claims associated with these debt securities resulting in a gain recorded in reorganization items (see Note 4). |
Principal Amount |
||||
TCEH Senior Notes: |
||||
Held by EFH Corp. |
$ | 284 | ||
Held by EFIH |
79 | |||
TCEH Term Loan Facilities: |
||||
Held by EFH Corp. |
19 | |||
|
|
|||
Total |
$ | 382 | ||
|
|
|
Three Months Ended September 30, 2017 |
Nine Months Ended September 30, 2017 |
|||||||
Operating revenues (a) |
||||||||
Wholesale Generation |
$ | 1,203 | $ | 2,757 | ||||
Retail Electricity |
1,286 | 3,136 | ||||||
Eliminations |
(656 | ) | (1,406 | ) | ||||
|
|
|
|
|||||
Consolidated operating revenues |
$ | 1,833 | $ | 4,487 | ||||
|
|
|
|
|||||
Depreciation and amortization |
||||||||
Wholesale Generation |
$ | 60 | $ | 167 | ||||
Retail Electricity |
108 | 322 | ||||||
Corporate and Other |
10 | 30 | ||||||
|
|
|
|
|||||
Consolidated depreciation and amortization |
$ | 178 | $ | 519 | ||||
|
|
|
|
|||||
Operating income (loss) |
||||||||
Wholesale Generation |
$ | 469 | $ | 651 | ||||
Retail Electricity |
(3 | ) | 54 | |||||
Corporate and Other |
(14 | ) | (47 | ) | ||||
|
|
|
|
|||||
Consolidated operating income |
$ | 452 | $ | 658 | ||||
|
|
|
|
|||||
Net income (loss) |
||||||||
Wholesale Generation |
$ | 469 | $ | 653 | ||||
Retail Electricity |
7 | 77 | ||||||
Corporate and Other |
(203 | ) | (405 | ) | ||||
|
|
|
|
|||||
Consolidated net income |
$ | 273 | $ | 325 | ||||
|
|
|
|
(a) |
For the three and nine months ended September 30, 2017, includes third-party unrealized net gains from mark-to-market valuations of commodity positions of $137 million and $204 million, respectively, recorded to the Wholesale Generation segment and $2 million and $11 million, respectively, recorded to the Retail Electricity segment. In addition, for the three and nine months ended September 30, 2017, unrealized net gains with affiliate of $89 million and $171 million, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net losses with affiliate of $(89) million and $(171) million, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results. |
September 30, 2017 |
December 31, 2016 |
|||||||
Total assets |
||||||||
Wholesale Generation |
$ | 7,445 | $ | 6,952 | ||||
Retail Electricity |
5,926 | 5,753 | ||||||
Corporate and Other and Eliminations |
1,629 | 2,462 | ||||||
|
|
|
|
|||||
Consolidated total assets |
$ | 15,000 | $ | 15,167 | ||||
|
|
|
|
Certain shared services costs are allocated to the segments.
Successor | ||||
Period from October 3, 2016 through December 31, 2016 |
||||
Operating revenues (a) |
||||
Wholesale Generation |
$ | 450 | ||
Retail Electricity |
912 | |||
Eliminations |
(171 | ) | ||
|
|
|||
Consolidated operating revenues |
$ | 1,191 | ||
Depreciation and amortization |
||||
Wholesale Generation |
$ | 53 | ||
Retail Electricity |
153 | |||
Corporate and Other |
11 | |||
Eliminations |
(1 | ) | ||
|
|
|||
Consolidated depreciation and amortization |
$ | 216 | ||
|
|
|||
Operating income (loss) |
||||
Wholesale Generation |
$ | (255 | ) | |
Retail Electricity |
111 | |||
Corporate and Other |
(17 | ) | ||
|
|
|||
Consolidated operating income (loss) |
$ | (161 | ) | |
|
|
|||
Interest expense and related charges |
||||
Wholesale Generation |
$ | (1 | ) | |
Retail Electricity |
— | |||
Corporate and Other |
66 | |||
Eliminations |
(5 | ) | ||
|
|
|||
Consolidated interest expense and related charges |
$ | 60 | ||
|
|
|||
Income tax benefit (all Corporate and Other) |
$ | 70 | ||
|
|
|||
Net income (loss) |
||||
Wholesale Generation |
$ | (251 | ) | |
Retail Electricity |
114 | |||
Corporate and Other |
(26 | ) | ||
|
|
|||
Consolidated net income (loss) |
$ | (163 | ) | |
|
|
|||
Capital expenditures |
||||
Wholesale Generation |
$ | 84 | ||
Retail Electricity |
5 | |||
|
|
|||
Consolidated capital expenditures |
$ | 89 | ||
|
|
(a) | Includes third-party unrealized net losses from mark-to-market valuations of commodity positions of $182 million recorded to the Wholesale Generation segment and $6 million recorded to the Retail Electricity segment. In addition, an unrealized net loss with an affiliate of $113 million was recorded to the Wholesale Generation segment which is eliminated in the consolidated results. |
Successor | ||||
December 31, 2016 |
||||
Total assets |
||||
Wholesale Generation |
$ | 6,952 | ||
Retail Electricity |
5,753 | |||
Corporate and Other and Eliminations |
2,462 | |||
|
|
|||
Consolidated total assets |
$ | 15,167 |
|
Other Income and Deductions
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Other income: |
||||||||||||||||
Office space sublease rental income (a) |
$ | 3 | $ | — | $ | 9 | $ | — | ||||||||
Insurance settlement |
— | — | — | 9 | ||||||||||||
Sale of land (b) |
1 | 2 | 4 | 2 | ||||||||||||
Interest income |
4 | 2 | 10 | 3 | ||||||||||||
All other |
2 | 3 | 6 | 5 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income |
$ | 10 | $ | 7 | $ | 29 | $ | 19 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Other deductions: |
||||||||||||||||
Write-off of generation equipment (b) |
$ | — | $ | 4 | $ | 2 | $ | 45 | ||||||||
Adjustment to asbestos liability |
— | 11 | — | 11 | ||||||||||||
Fees associated with TCEH DIP Roll Facilities |
— | 5 | — | 5 | ||||||||||||
All other |
— | 8 | 3 | 14 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other deductions |
$ | — | $ | 28 | $ | 5 | $ | 75 | ||||||||
|
|
|
|
|
|
|
|
(a) | Reported in Corporate and Other non-segment (Successor period only). |
(b) | Reported in Wholesale Generation segment (Successor period only). |
Other Income and Deductions
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Other income: |
||||||||||||||||
Office space sublease rental income (a) |
$ | 2 | $ | — | $ | — | $ | — | ||||||||
Curtailment gain on employee benefit plans (a) |
4 | — | — | — | ||||||||||||
Mineral rights royalty income (b) |
1 | 3 | 4 | 4 | ||||||||||||
Insurance settlement |
— | 9 | — | — | ||||||||||||
All other |
2 | 4 | 13 | 12 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other income |
$ | 9 | $ | 16 | $ | 17 | $ | 16 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Other deductions: |
||||||||||||||||
Adjustment to asbestos liability |
$ | — | $ | 11 | $ | — | $ | — | ||||||||
Write-off of generation equipment |
— | 45 | — | — | ||||||||||||
Fees associated with DIP Roll Facilities |
— | 5 | — | |||||||||||||
Impairment of favorable purchase contracts (Note 7) |
— | — | 8 | 183 | ||||||||||||
Impairment of emission allowances (Note 7) |
— | — | 55 | 80 | ||||||||||||
Impairment of mining development costs (Note 7) |
— | — | 19 | — | ||||||||||||
All other |
— | 14 | 11 | 18 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total other deductions |
$ | — | $ | 75 | $ | 93 | $ | 281 | ||||||||
|
|
|
|
|
|
|
|
(a) | Corporate and Other nonsegment (Successor period only). |
(b) | Wholesale Generation segment (Successor period only). |
Restricted Cash
September 30, 2017 | December 31, 2016 | |||||||||||||||
Current Assets |
Noncurrent Assets |
Current Assets |
Noncurrent Assets |
|||||||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 9) |
$ | — | $ | 650 | $ | — | $ | 650 | ||||||||
Amounts related to restructuring escrow accounts |
61 | — | 90 | — | ||||||||||||
Other |
— | — | 5 | — | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total restricted cash |
$ | 61 | $ | 650 | $ | 95 | $ | 650 | ||||||||
|
|
|
|
|
|
|
|
Restricted Cash
Successor | Predecessor | |||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||
Current Assets |
Noncurrent Assets |
Current Assets |
Noncurrent Assets |
|||||||||||||
Amounts related to the Vistra Operations Credit Facilities (Note 13) |
$ | — | $ | 650 | $ | — | $ | — | ||||||||
Amounts related to the DIP Facility (Note 13) |
519 | — | ||||||||||||||
Amounts related to TCEH’s pre-petition Letter of Credit Facility (Note 5) |
— | — | — | 507 | ||||||||||||
Amounts related to restructuring escrow accounts |
90 | — | — | — | ||||||||||||
Other |
5 | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total restricted cash |
$ | 95 | $ | 650 | $ | 519 | $ | 507 | ||||||||
|
|
|
|
|
|
|
|
Allowance for Uncollectible Accounts Receivable
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||
Allowance for uncollectible accounts receivable at beginning of period |
$ | 10 | $ | 9 | ||||
Increase for bad debt expense |
35 | 20 | ||||||
Decrease for account write-offs |
(24 | ) | (16 | ) | ||||
|
|
|
|
|||||
Allowance for uncollectible accounts receivable at end of period |
$ | 21 | $ | 13 | ||||
|
|
|
|
Trade Accounts Receivable
September 30, 2017 |
December 31, 2016 |
|||||||
Wholesale and retail trade accounts receivable |
$ | 738 | $ | 622 | ||||
Allowance for uncollectible accounts |
(21 | ) | (10 | ) | ||||
|
|
|
|
|||||
Trade accounts receivable — net |
$ | 717 | $ | 612 | ||||
|
|
|
|
Gross trade accounts receivable at September 30, 2017 and December 31, 2016 included unbilled retail revenues of $250 million and $225 million, respectively.
Trade Accounts Receivable
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Wholesale and retail trade accounts receivable |
$ | 622 | $ | 542 | ||||
Allowance for uncollectible accounts |
(10 | ) | (9 | ) | ||||
|
|
|
|
|||||
Trade accounts receivable — net |
$ | 612 | $ | 533 | ||||
|
|
|
|
Gross trade accounts receivable at December 31, 2016 and 2015 included unbilled revenues of $225 million and $231 million, respectively.
Allowance for Uncollectible Accounts Receivable
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Allowance for uncollectible accounts receivable at beginning of period |
$ | — | $ | 9 | $ | 15 | $ | 14 | ||||||||
Increase for bad debt expense |
(10 | ) | 20 | 34 | 38 | |||||||||||
Decrease for account write-offs |
— | (16 | ) | (40 | ) | (37 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Allowance for uncollectible accounts receivable at end of period |
$ | (10 | ) | $ | 13 | $ | 9 | $ | 15 | |||||||
|
|
|
|
|
|
|
|
Inventories by Major Category
September 30, 2017 |
December 31, 2016 |
|||||||
Materials and supplies |
$ | 172 | $ | 173 | ||||
Fuel stock |
102 | 88 | ||||||
Natural gas in storage |
21 | 24 | ||||||
|
|
|
|
|||||
Total inventories |
$ | 295 | $ | 285 | ||||
|
|
|
|
Inventories by Major Category
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Materials and supplies |
$ | 173 | $ | 226 | ||||
Fuel stock |
88 | 170 | ||||||
Natural gas in storage |
24 | 32 | ||||||
|
|
|
|
|||||
Total inventories |
$ | 285 | $ | 428 | ||||
|
|
|
|
Other Investments
September 30, 2017 |
December 31, 2016 |
|||||||
Nuclear plant decommissioning trust |
$ | 1,132 | $ | 1,012 | ||||
Land |
49 | 49 | ||||||
Miscellaneous other |
2 | 3 | ||||||
|
|
|
|
|||||
Total other investments |
$ | 1,183 | $ | 1,064 | ||||
|
|
|
|
Investments
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Nuclear plant decommissioning trust |
$ | 1,012 | $ | 918 | ||||
Land |
49 | 36 | ||||||
Miscellaneous other |
3 | 8 | ||||||
|
|
|
|
|||||
Total investments |
$ | 1,064 | $ | 962 | ||||
|
|
|
|
September 30, 2017 | ||||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value |
|||||||||||||
Debt securities (b) |
$ | 352 | $ | 14 | $ | (1 | ) | $ | 365 | |||||||
Equity securities (c) |
321 | 451 | (5 | ) | 767 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 673 | $ | 465 | $ | (6 | ) | $ | 1,132 | |||||||
|
|
|
|
|
|
|
|
December 31, 2016 | ||||||||||||||||
Cost (a) | Unrealized gain | Unrealized loss | Fair market value |
|||||||||||||
Debt securities (b) |
$ | 333 | $ | 10 | $ | (3 | ) | $ | 340 | |||||||
Equity securities (c) |
309 | 368 | (5 | ) | 672 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 642 | $ | 378 | $ | (8 | ) | $ | 1,012 | |||||||
|
|
|
|
|
|
|
|
(a) | Includes realized gains and losses on securities sold. |
(b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.57% and 3.56% at September 30, 2017 and December 31, 2016, respectively, and an average maturity of 9 years at both September 30, 2017 and December 31, 2016. |
(c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
A summary of investments in the fund follows:
Successor | ||||||||||||||||
December 31, 2016 | ||||||||||||||||
Cost (a) | Unrealized gain |
Unrealized loss |
Fair market value |
|||||||||||||
Debt securities (b) |
$ | 333 | $ | 10 | $ | (3 | ) | $ | 340 | |||||||
Equity securities (c) |
309 | 368 | (5 | ) | 672 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 642 | $ | 378 | $ | (8 | ) | $ | 1,012 | |||||||
|
|
|
|
|
|
|
|
Predecessor | ||||||||||||||||
December 31, 2015 | ||||||||||||||||
Cost (a) | Unrealized gain |
Unrealized loss |
Fair market value |
|||||||||||||
Debt securities (b) |
$ | 310 | $ | 11 | $ | (2 | ) | $ | 319 | |||||||
Equity securities (c) |
291 | 315 | (7 | ) | 599 | |||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total |
$ | 601 | $ | 326 | $ | (9 | ) | $ | 918 | |||||||
|
|
|
|
|
|
|
|
(a) | Includes realized gains and losses on securities sold. |
(b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s Investors Services, Inc. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 3.56% and 3.68% at December 31, 2016 and 2015, respectively, and an average maturity of 9 years and 8 years at December 31, 2016 and 2015, respectively. |
(c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Successor | Predecessor | Successor | Predecessor | |||||||||||||
Three Months Ended September 30, 2017 |
Three Months Ended September 30, 2016 |
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||||||||
Realized gains |
$ | 1 | $ | 3 | $ | 3 | $ | 3 | ||||||||
Realized losses |
$ | (1 | ) | $ | (2 | ) | $ | (3 | ) | $ | (2 | ) | ||||
Proceeds from sales of securities |
$ | 56 | $ | 46 | $ | 154 | $ | 201 | ||||||||
Investments in securities |
$ | (62 | ) | $ | (52 | ) | $ | (169 | ) | $ | (215 | ) |
The following table summarizes proceeds from sales of available-for-sale securities and the related realized gains and losses from such sales.
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Realized gains |
$ | 1 | $ | 3 | $ | 1 | $ | 11 | ||||||||
Realized losses |
$ | — | $ | (2 | ) | $ | (1 | ) | $ | (2 | ) | |||||
Proceeds from sales of securities |
$ | 25 | $ | 201 | $ | 401 | $ | 314 | ||||||||
Investments in securities |
$ | (30 | ) | $ | (215 | ) | $ | (418 | ) | $ | (331 | ) |
Property, Plant and Equipment
Successor | ||||
December 31, 2016 |
||||
Successor |
||||
Wholesale Generation: |
||||
Generation and mining |
$ | 3,997 | ||
Retail Electricity |
3 | |||
Corporate and Other |
107 | |||
|
|
|||
Total |
4,107 | |||
Less accumulated depreciation |
(54 | ) | ||
|
|
|||
Net of accumulated depreciation |
4,053 | |||
Nuclear fuel (net of accumulated amortization of $31 million) |
166 | |||
Construction work in progress: |
||||
Wholesale Generation |
210 | |||
Retail Electricity |
6 | |||
Corporate and Other |
8 | |||
|
|
|||
Total construction work in progress |
224 | |||
|
|
|||
Property, plant and equipment — net |
$ | 4,443 | ||
|
|
Predecessor | ||||
December 31, 2015 |
||||
Predecessor |
||||
Generation and mining |
$ | 10,886 | ||
Other assets |
546 | |||
|
|
|||
Total |
11,432 | |||
Less accumulated depreciation |
(2,654 | ) | ||
|
|
|||
Net of accumulated depreciation |
8,778 | |||
Nuclear fuel (net of accumulated amortization of $1.383 billion) |
248 | |||
Construction work in progress |
323 | |||
|
|
|||
Property, plant and equipment — net |
$ | 9,349 | ||
|
|
The following table summarizes the changes to these obligations, reported in other current liabilities and asset retirement obligations in our condensed consolidated balance sheets, for the nine months ended September 30, 2017:
Nuclear Plant Decommissioning |
Mining Land Reclamation |
Other | Total | |||||||||||||
Liability at December 31, 2016 |
$ | 1,200 | $ | 375 | $ | 151 | $ | 1,726 | ||||||||
Additions: |
||||||||||||||||
Accretion |
23 | 14 | 4 | 41 | ||||||||||||
Adjustment for change in estimates (a) |
— | 3 | 4 | 7 | ||||||||||||
Reductions: |
||||||||||||||||
Payments |
— | (23 | ) | — | (23 | ) | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at September 30, 2017 |
1,223 | 369 | 159 | 1,751 | ||||||||||||
Less amounts due currently |
— | (83 | ) | (2 | ) | (85 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Noncurrent liability at September 30, 2017 |
$ | 1,223 | $ | 286 | $ | 157 | $ | 1,666 | ||||||||
|
|
|
|
|
|
|
|
(a) | Relates to the impacts of accelerating the ARO associated with the planned retirement of the Monticello plant (see Note 17). |
The following tables summarize the changes to these obligations, reported in other current liabilities and other noncurrent liabilities and deferred credits in the consolidated balance sheets for the Successor period ended December 31, 2016, and the Predecessor periods ended October 2, 2016 and December 31, 2015:
Successor: | Nuclear Plant Decommissioning |
Mining Land Reclamation |
Other | Total | ||||||||||||
Fair value of liability established at October 3, 2016 |
$ | 1,192 | $ | 374 | $ | 152 | $ | 1,718 | ||||||||
Additions: |
||||||||||||||||
Accretion — October 3, 2016 through December 31, 2016 |
8 | 5 | 1 | 14 | ||||||||||||
Reductions: |
||||||||||||||||
Payments — October 3, 2016 through December 31, 2016 |
— | (4 | ) | (2 | ) | (6 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at December 31, 2016 |
1,200 | 375 | 151 | 1,726 | ||||||||||||
Less amounts due currently |
— | (53 | ) | (2 | ) | (55 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Noncurrent liability at December 31, 2016 |
$ | 1,200 | $ | 322 | $ | 149 | $ | 1,671 | ||||||||
|
|
|
|
|
|
|
|
Predecessor: | Nuclear Plant Decommissioning |
Mining Land Reclamation |
Other | Total | ||||||||||||
Liability at January 1, 2015 |
$ | 413 | $ | 165 | $ | 36 | $ | 614 | ||||||||
Additions: |
||||||||||||||||
Accretion |
25 | 20 | 6 | 51 | ||||||||||||
Adjustment for new cost estimate (a) |
70 | — | — | 70 | ||||||||||||
Incremental reclamation costs (b) |
— | 84 | 69 | 153 | ||||||||||||
Reductions: |
||||||||||||||||
Payments |
— | (54 | ) | (4 | ) | (58 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at December 31, 2015 (c) |
508 | 215 | 107 | 830 | ||||||||||||
Additions: |
||||||||||||||||
Accretion — January 1, 2016 through October 2, 2016 |
22 | 16 | 5 | 43 | ||||||||||||
Adjustment for new cost estimate |
— | — | 1 | 1 | ||||||||||||
Incremental reclamation costs |
— | 14 | 12 | 26 | ||||||||||||
Reductions: |
||||||||||||||||
Payments — January 1, 2016 through October 2, 2016 |
— | (37 | ) | (3 | ) | (40 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Liability at October 2, 2016 |
530 | 208 | 122 | 860 | ||||||||||||
Less amounts due currently |
— | (50 | ) | (1 | ) | (51 | ) | |||||||||
|
|
|
|
|
|
|
|
|||||||||
Noncurrent liability at October 2, 2016 |
$ | 530 | $ | 158 | $ | 121 | $ | 809 | ||||||||
|
|
|
|
|
|
|
|
(a) | The adjustment for nuclear plant decommissioning resulted from a new cost estimate completed in 2015. Under applicable accounting standards, the liability is remeasured when significant changes in the amount or timing of cash flows occurs, and PUCT rules require a new cost estimate at least every five years. The increase in the liability was driven by increased security and fuel-handling costs. |
(b) | The adjustment for other asset retirement obligations resulted from the effect on our estimated retirement obligation related to coal combustion residual facilities at our lignite/coal fueled generation facilities that arose from the Disposal of Coal Combustion Residuals from Electric Utilities rule. |
(c) | Includes $66 million recorded to other current liabilities in the consolidated balance sheet of the Predecessor. |
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
September 30, 2017 |
December 31, 2016 |
|||||||
Unfavorable purchase and sales contracts |
$ | 39 | $ | 46 | ||||
Other, including retirement and other employee benefits |
193 | 174 | ||||||
|
|
|
|
|||||
Total other noncurrent liabilities and deferred credits |
$ | 232 | $ | 220 | ||||
|
|
|
|
The balance of other noncurrent liabilities and deferred credits consists of the following:
Successor | Predecessor | |||||||
December 31, 2016 |
December 31, 2015 |
|||||||
Unfavorable purchase and sales contracts |
$ | 46 | $ | 543 | ||||
Nuclear decommissioning fund excess over asset retirement obligation (Note 20) |
— | 409 | ||||||
Uncertain tax positions, including accrued interest |
— | 41 | ||||||
Other, including retirement and other employee benefits |
174 | 22 | ||||||
|
|
|
|
|||||
Total other noncurrent liabilities and deferred credits |
$ | 220 | $ | 1,015 | ||||
|
|
|
|
Fair Value of Debt
September 30, 2017 | December 31, 2016 | |||||||||||||||
Debt: |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||||
Long-term debt under the Vistra Operations Credit Facilities (Note 9) |
$ | 4,484 | $ | 4,484 | $ | 4,515 | $ | 4,552 | ||||||||
Other long-term debt, excluding capital lease obligations (Note 9) |
30 | 27 | 36 | 32 | ||||||||||||
Mandatorily redeemable subsidiary preferred stock (Note 9) |
70 | 70 | 70 | 70 |
The amortization of unfavorable purchase and sales contracts totaled $3 million, $18 million, $23 million and $23 million for the Successor period from October 3, 2016 through December 31, 2016, the Predecessor period from January 1, 2016 through October 2, 2016 and the years ended December 31, 2015 and 2014, respectively. See Note 7 for intangible assets related to favorable purchase and sales contracts.
Fair Value of Debt
Successor | Predecessor | |||||||||||||||
December 31, 2016 | December 31, 2015 | |||||||||||||||
Debt: |
Carrying Amount |
Fair Value |
Carrying Amount |
Fair Value |
||||||||||||
Long-term debt under the Vistra Operations Credit Facilities (Note 13) |
$ | 4,515 | $ | 4,552 | $ | — | $ | — | ||||||||
Other long-term debt, excluding capital lease obligations (Note 13) |
$ | 36 | $ | 32 | $ | 14 | $ | 15 | ||||||||
Mandatorily redeemable preferred stock (Note 13) |
$ | 70 | $ | 70 | $ | — | $ | — | ||||||||
Borrowings under debtor-in-possession or senior secured exit facilities (Note 13) |
$ | — | $ | — | $ | 1,425 | $ | 1,411 |
Supplemental Cash Flow Information
Successor | Predecessor | |||||||
Nine Months Ended September 30, 2017 |
Nine Months Ended September 30, 2016 |
|||||||
Cash payments related to: |
||||||||
Interest paid (a) |
$ | 197 | $ | 1,064 | ||||
Capitalized interest |
(5 | ) | (9 | ) | ||||
|
|
|
|
|||||
Interest paid (net of capitalized interest) (a) |
$ | 192 | $ | 1,055 | ||||
Income taxes |
$ | 51 | $ | 22 | ||||
Reorganization items (b) |
$ | — | $ | 104 | ||||
Noncash investing and financing activities: |
||||||||
Construction expenditures (c) |
$ | 16 | $ | 53 |
(a) | Predecessor period includes amounts paid for adequate protection. |
(b) | Represents cash payments made by our Predecessor for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court. |
(c) | Represents end-of-period accruals for ongoing construction projects. |
Supplemental Cash Flow Information
Successor | Predecessor | |||||||||||||||
Period from October 3, 2016 through December 31, 2016 |
Period from January 1, 2016 through October 2, 2016 |
Year Ended December 31, |
||||||||||||||
2015 | 2014 | |||||||||||||||
Cash payments related to: |
||||||||||||||||
Interest paid (a) |
$ | 19 | $ | 1,064 | $ | 1,298 | $ | 1,252 | ||||||||
Capitalized interest |
(3 | ) | (9 | ) | (11 | ) | (17 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Interest paid (net of capitalized interest) (a) |
$ | 16 | $ | 1,055 | $ | 1,287 | $ | 1,235 | ||||||||
Reorganization items (b) |
$ | — | $ | 104 | $ | 224 | $ | 93 | ||||||||
Income taxes paid (refund) |
$ | (2 | ) | $ | 22 | $ | 29 | $ | 31 | |||||||
Noncash investing and financing activities: |
||||||||||||||||
Construction expenditures (c) |
$ | 1 | $ | 53 | $ | 75 | $ | 108 | ||||||||
Contribution to membership interests |
$ | — | $ | — | $ | — | $ | 2 |
(a) | This amount includes amounts paid for adequate protection. Net of amounts received under interest rate swap agreements in 2014. |
(b) | Represents cash payments for legal and other consulting services, including amounts paid on behalf of third parties pursuant to contractual obligations approved by the Bankruptcy Court. |
(c) | Represents end-of-period accruals for ongoing construction projects. |
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year |
Amount | |||
2017 |
$ | 10 | ||
2018 |
$ | 11 | ||
2019 |
$ | 9 | ||
2020 |
$ | 9 | ||
2021 |
$ | 1 |
|
The following table presents the changes to shareholder’s equity for the nine months ended September 30, 2017:
Vistra Energy Shareholders’ Equity | ||||||||||||||||||||
Common Stock (a) |
Additional Paid-in Capital |
Retained Earnings (Deficit) |
Accumulated Other Comprehensive Income |
Total Shareholders’ Equity |
||||||||||||||||
Balance at December 31, 2016 |
$ | 4 | $ | 7,742 | $ | (1,155 | ) | $ | 6 | $ | 6,597 | |||||||||
Net income |
— | — | 325 | — | 325 | |||||||||||||||
Effects of stock-based incentive compensation plans |
— | 13 | — | — | 13 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Balance at September 30, 2017 |
$ | 4 | $ | 7,755 | $ | (830 | ) | $ | 6 | $ | 6,935 | |||||||||
|
|
|
|
|
|
|
|
|
|
(a) | Authorized shares totaled 1,800,000,000 at September 30, 2017. Outstanding shares totaled 427,597,368 and 427,580,232 at September 30, 2017 and December 31, 2016, respectively. |
Predecessor Membership Interests
The following table presents the changes to membership interests for the nine months ended September 30, 2016:
TCEH Membership Interests | ||||||||||||
Capital Account |
Accumulated Other Comprehensive Loss |
Total Membership Interests |
||||||||||
Balance at December 31, 2015 |
$ | (22,851 | ) | $ | (33 | ) | $ | (22,884 | ) | |||
Net loss |
(656 | ) | — | (656 | ) | |||||||
Net effects of cash flow hedges |
— | 1 | 1 | |||||||||
|
|
|
|
|
|
|||||||
Balance at September 30, 2016 |
$ | (23,507 | ) | $ | (32 | ) | $ | (23,539 | ) | |||
|
|
|
|
|
|
|
The announced retirements total installed nameplate generation capacity of 4,167 MW as detailed below.
Name |
Location (all in the |
Fuel Type |
Installed Nameplate Generation Capacity (MW) |
Number of Units |
Estimated Date Units Will Be Taken Offline |
|||||||||
Monticello |
Titus County | Lignite/Coal | 1,880 | 3 | January 4, 2018 | |||||||||
Sandow |
Milam County | Lignite | 1,137 | 2 | January 11, 2018 | |||||||||
Big Brown |
Freestone County | Lignite/Coal | 1,150 | 2 | February 12, 2018 | |||||||||
|
|
|
|
|||||||||||
Total |
4,167 | 7 | ||||||||||||
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