NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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1.
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BUSINESS AND SIGNIFICANT ACCOUNTING POLICIES
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Description of Business
References in this report to "we," "our," "us" and "the Company" are to Vistra Energy and/or its subsidiaries, as apparent in the context. See
Glossary
for defined terms.
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.
Vistra Energy has
three
reportable segments: (i) our Wholesale Generation segment, consisting largely of Luminant; (ii) our Retail Electricity segment, consisting largely of TXU Energy, and (iii) our Asset Closure segment, consisting of financial results associated with retired plants and mines. The Asset Closure segment was established as of January 1, 2018, and we have recast information from prior periods to reflect this change in reportable segments. See Note
16
for further information concerning reportable business segments.
Merger Transaction
On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. Because the Merger occurred after March 31, 2018, Vistra Energy's condensed consolidated financial statements and the notes related thereto do not include the financial condition or the operating results of Dynegy in any of the periods presented herein or otherwise take into account the closing of the Merger or the effects of the Merger or any transactions related thereto. See Note
2
for a summary of the Merger and related transactions.
Basis of Presentation
The condensed consolidated financial statements have been prepared in accordance with U.S. GAAP and on the same basis as the audited financial statements included in our 2017 Form 10-K, with the exception of the change in reporting segments as detailed above. 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 U.S. 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 U.S. GAAP, they should be read in conjunction with the audited financial statements and related notes contained in our 2017 Form 10-K. 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 U.S. 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.
Adoption of New Accounting Standards
Revenue from Contracts with Customers
—
On January 1, 2018, we adopted Accounting Standards Update (ASU) 2014-09,
Revenue from Contracts with Customers (Topic 606)
and all related amendments (new revenue standard) using the modified retrospective method for all contracts outstanding at the time of adoption. We recognized the cumulative effect of initially applying the new revenue standard as an adjustment to the opening balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis and our retail electricity and wholesale generation revenues will continue to be recognized when electricity and other services are delivered to our customers. The impact of adopting the new revenue standard primarily relates to the deferral of acquisition costs associated with retail contracts with customers that were previously expensed as incurred. Under the new revenue standard, these amounts will be capitalized and amortized over the expected life of the customer.
As of January 1, 2018, the cumulative effect of the changes made to our condensed consolidated balance sheet for the adoption of the new revenue standard was as follows:
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December 31, 2017
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Adoption of New Revenue Standard
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January 1,
2018
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Impact on condensed consolidated balance sheet:
|
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Assets
|
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Prepaid expense and other current assets
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$
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72
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|
$
|
5
|
|
|
$
|
77
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|
Accumulated deferred income taxes
|
$
|
710
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|
|
$
|
(4
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)
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$
|
706
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|
Other noncurrent assets
|
$
|
162
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|
|
$
|
16
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|
|
$
|
178
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|
Equity
|
|
|
|
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Retained deficit
|
$
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(1,410
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)
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|
$
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17
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|
$
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(1,393
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)
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In accordance with the new revenue standard requirements, the disclosure of the impact of adoption on our condensed statement of consolidated income (loss) and condensed consolidated balance sheet was as follows:
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Three Months Ended March 31, 2018
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As Reported
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Amount Without Adoption of New Revenue Standard
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Effect of Change
Higher (Lower)
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Impact on condensed statement of consolidated income (loss):
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|
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Operating revenues
|
$
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765
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$
|
764
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|
$
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1
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|
Selling, general and administrative expenses
|
$
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(162
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)
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$
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(165
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)
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$
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3
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Net income (loss)
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(306
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)
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(309
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)
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3
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March 31, 2018
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As Reported
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Balances Without Adoption of New Revenue Standard
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Effect of Change
Higher (Lower)
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Impact on condensed consolidated balance sheet:
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Assets
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Prepaid expense and other current assets
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$
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75
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$
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69
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$
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6
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Accumulated deferred income taxes
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$
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793
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$
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797
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$
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(4
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)
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Other noncurrent assets
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$
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189
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$
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169
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$
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20
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Equity
|
|
|
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Retained deficit
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$
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(1,700
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)
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$
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(1,720
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)
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$
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20
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See Note
5
for the disclosures required by the new revenue standard.
Statement of Cash Flows
—
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 (see Note
17
). We adopted the standard on January 1, 2018. The ASU modified our presentation of our condensed statements of consolidated cash flows, and retrospective application to comparative periods presented was required. For the
three months
ended
March 31, 2017
, our condensed statement of consolidated cash flows previously reflected a source of cash of
$1 million
reported as changes in restricted cash that is now reported in net change in cash, cash equivalents and restricted cash. See the condensed statements of consolidated cash flows and Note
17
for disclosures related to the adoption of this accounting standard.
Changes in Accounting Standards
In February 2016, the Financial Accounting Standards Board (FASB) issued ASU 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.
2. MERGER TRANSACTION
Merger Summary
On the Merger Date, Vistra Energy and Dynegy completed the transactions contemplated by the Merger Agreement entered into in October 2017. Pursuant to the Merger Agreement, Dynegy merged with and into Vistra Energy, with Vistra Energy continuing as the surviving corporation. The Merger is intended to qualify as a tax-free reorganization under the Internal Revenue Code, as amended, so that none of Vistra Energy, Dynegy or any of the Dynegy stockholders will recognize any gain or loss in the transaction, except that Dynegy stockholders could recognize a gain or loss with respect to cash received in lieu of fractional shares of Vistra Energy's common stock. Vistra Energy is the acquirer for both federal tax and accounting purposes.
At 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, was automatically converted into
0.652
shares of common stock, par value
$0.01
per share, of Vistra Energy (the Exchange Ratio), except that cash was paid in lieu of fractional shares, which resulted in Vistra Energy issuing
94,409,573
shares of Vistra Energy common stock to the former Dynegy stockholders. The total number of Vistra Energy shares outstanding at the close of the Merger was
522,932,453
shares. Dynegy stock options and equity-based awards outstanding immediately prior to the Effective Time were generally automatically converted 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.
Following is a list of events that took place in connection with the completion of the Merger.
Warrants
— The Company entered into an agreement whereby holders of each outstanding warrant previously issued by Dynegy will be entitled to receive, upon exercise, the equity securities to which the holder would have been entitled to receive of Dynegy common stock converted into shares of Vistra Energy common stock at the Exchange Ratio. As of the Merger Date,
nine million
warrants expiring in 2024 with an exercise price of
$35.00
were outstanding, each of which can be redeemed for
0.652
share of Vistra Energy common stock.
Credit Agreement
—
The Company assumed the obligations under Dynegy's
$3.563 billion
credit agreement consisting of a
$2.018 billion
senior secured term loan facility due 2024 and a
$1.545 billion
senior secured revolving credit facility. As of the Merger Date, there were
no
cash borrowings and
$656 million
of letters of credit outstanding under the senior secured revolving credit facility. On April 23, 2018,
$70 million
of the senior secured revolving credit facility matured.
Senior Notes
— The Company and certain of the Company's wholly-owned subsidiaries that guarantee obligations under the Dynegy credit agreement assumed the following obligations of Dynegy:
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•
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$850 million
of outstanding
6.75%
Senior Notes due 2019, which were redeemed on May 1, 2018 at a redemption price of
101.688%
, plus accrued and unpaid interest to but not including the date of redemption;
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•
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$1.750 billion
of
7.375%
Senior Notes due 2022;
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•
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$500 million
of
5.875%
Senior Notes due 2023;
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•
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$1.250 billion
of
7.625%
Senior Notes due 2024;
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•
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$188 million
of
8.034%
Senior Notes due 2024;
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•
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$750 million
of
8.000%
Senior Notes due 2025, and
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•
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$850 million
of
8.125%
Senior Notes due 2026.
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Tangible Equity Units
— The Company assumed the obligations of Dynegy's
4,600,000
7.00%
tangible equity units, each with a stated amount of
$100.00
and each comprised of (i) a prepaid stock purchase contract that will deliver to the holder, not later than July 1, 2019, unless earlier redeemed or settled, not more than
4.0421
shares of Vistra Energy common stock and not less than
3.2731
shares of Vistra Energy common stock per contract based upon the applicable fixed settlement rate in the contract and (ii) a senior amortizing note with an outstanding principal amount of
$45 million
that pays an equal quarterly cash installment of
$1.7500
per am
ortizing note. In the aggregate, the annual quarterly cash installments will be equivalent to a
7.00%
cash payment per year with respect to each
$100.00
stated
amount of tangible equity units.
Business Combination
The Merger is anticipated to provide a number of significant potential strategic benefits and opportunities to Vistra Energy, including increased scale and market diversification, rebalanced asset portfolio and improved earnings and cash flow. The Merger is being 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 Merger Date. Due to the limited time between the Merger Date and this filing, our purchase price allocation for the assets acquired and the liabilities assumed in the Merger has not been completed. The results of operations of Dynegy will be reported in our consolidated financial statements beginning as of the Merger Date.
Based on the opening price of Vistra Energy common stock on the Merger Date, the preliminary purchase price was approximately
$2.3 billion
. Our initial accounting of the purchase price allocation for the assets acquired and the liabilities assumed in the Merger and the supplemental pro forma financial results is currently underway and will be presented no later than the second quarter of 2018.
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3.
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ACQUISITION AND DEVELOPMENT OF GENERATION FACILITIES
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Odessa Acquisition
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 approximately
$355 million
purchase price 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, and a partial buyback of the earn-out provision was settled in February 2018.
Upton Solar Development
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
three months
ended
March 31, 2018
, we have spent approximately
$21 million
related to this project primarily for progress payments under the engineering, procurement and construction agreement. The facility began test operations in March 2018 and is expected to begin commercial operations in May 2018.
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4.
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RETIREMENT OF GENERATION FACILITIES
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In January and February 2018, we retired
three
power plants with a total installed nameplate generation capacity of
4,167
MW. Luminant decided to retire these units because they were projected to be uneconomic based on current market conditions and would have faced significant environmental costs associated with operating such units. In the case of the Sandow units, the decision also reflected the execution of a contract termination agreement pursuant to which the Company and Alcoa agreed to an early settlement of a long-standing power and mining agreement. The following table details the units retired.
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Name
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|
Location (all in the state of Texas)
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Fuel Type
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Installed Nameplate Generation Capacity (MW)
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Number of Units
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Date Units Taken Offline
|
Monticello
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|
Titus County
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|
Lignite/Coal
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|
1,880
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|
|
3
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|
January 4, 2018
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Sandow
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Milam County
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Lignite
|
|
1,137
|
|
|
2
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|
January 11, 2018
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Big Brown
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Freestone County
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|
Lignite/Coal
|
|
1,150
|
|
|
2
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|
February 12, 2018
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Total
|
|
|
|
|
|
4,167
|
|
|
7
|
|
|
The following table disaggregates our revenue by major source:
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Three Months Ended March 31, 2018
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Retail Electricity
|
|
Wholesale Generation
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|
Asset
Closure
|
|
Eliminations
|
|
Consolidated
|
Revenue from contracts with customers:
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|
|
|
|
|
|
|
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|
Revenue from Oncor service area
|
$
|
662
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
662
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|
Revenue from other TDSP service areas
|
287
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
287
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|
Wholesale generation revenue from ERCOT
|
—
|
|
|
174
|
|
|
36
|
|
|
—
|
|
|
210
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|
Revenue from non-affiliated REPs
|
—
|
|
|
19
|
|
|
—
|
|
|
—
|
|
|
19
|
|
Revenue from other wholesale contracts
|
—
|
|
|
34
|
|
|
—
|
|
|
—
|
|
|
34
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|
Total revenue from contracts with customers
|
949
|
|
|
227
|
|
|
36
|
|
|
—
|
|
|
1,212
|
|
Other revenues:
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|
|
|
|
|
|
|
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Retail contract amortization
|
(12
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)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(12
|
)
|
Hedging and other revenues
|
35
|
|
|
(462
|
)
|
|
(8
|
)
|
|
—
|
|
|
(435
|
)
|
Affiliate sales
|
—
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|
|
(298
|
)
|
|
—
|
|
|
298
|
|
|
—
|
|
Total other revenues
|
23
|
|
|
(760
|
)
|
|
(8
|
)
|
|
298
|
|
|
(447
|
)
|
Total revenues
|
$
|
972
|
|
|
$
|
(533
|
)
|
|
$
|
28
|
|
|
$
|
298
|
|
|
$
|
765
|
|
Energy Charges
Revenue is recognized when electricity is delivered to our customers in an amount that we expect to invoice for volumes delivered or services provided. Sales tax is excluded from revenue. Residential invoices are due within
20 days
from invoice date and business customer payment terms vary from
15
to
45 days
from invoice date. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Energy charges are delivered as a series of distinct services and are accounted for as a single performance obligation.
Wholesale Generation Revenue from ERCOT
Revenue is recognized when volumes are delivered to ERCOT. Cash settlement occurs within
10
business days after delivery. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Luminant operates as a market participant within ERCOT and expects to continue to remain in a contract agreement with ERCOT indefinitely. Wholesale generation revenues are delivered as a series of distinct services and are accounted for as a single performance obligation.
Revenue from Nonaffiliated Retail Electric Providers
Revenue is recognized when volumes are delivered to the non-affiliated retail electric provider. Cash settlement occurs within
20
days following the month of delivery. Revenue is recognized over-time using the output method based on kilowatt hours delivered. Revenue from non-affiliated retail electric providers are delivered as a series of distinct services and are accounted for as a single performance obligation.
Revenue from Other Wholesale Contracts
Other wholesale contracts include other revenue activity with ERCOT, such as ancillary services, auction revenue and ERCOT neutrality revenue. Revenue is recognized when the service is performed. Cash settlement occurs within
10
business days after invoicing. Revenue is recognized over-time using the output method based on kilowatt hours delivered or other applicable measurements. Luminant operates as a market participant within ERCOT and expects to continue to remain in a contract agreement with ERCOT indefinitely. Other wholesale contracts are delivered as a series of distinct services and are accounted for as a single performance obligation.
Contract and Other Customer Acquisition Costs
We defer costs to acquire residential and business retail contracts and amortize these costs over the expected life of the contract. The expected life of a retail contract is calculated using historical attrition rates, which we believe to be an accurate indicator of future attrition rates. The deferred acquisition and contract cost balance as of
March 31, 2018
and January 1, 2018 was
$27 million
and
$22 million
, respectively. The amortization expense related to these costs during the
three months
ended
March 31, 2018
totaled
$3 million
and was recorded as selling, general and administrative expenses and
$1 million
was recorded to operating costs in the condensed statement of consolidated income (loss).
Practical Expedients
The vast majority of revenues are recognized under the right to invoice practical expedient, which allows us to recognize revenue in the same amount that we invoice our customers. We do not disclose the value of unsatisfied performance obligations for contracts for which we recognize revenue using the right to invoice practical expedient. We use the portfolio approach to categorize similar customer contracts into single performance obligations. Sales taxes are not included in revenue.
Accounts Receivable
The following table presents trade accounts receivable relating to both contracts with customers and other activities:
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|
|
|
|
|
March 31, 2018
|
Trade accounts receivable from contracts with customers — net
|
$
|
415
|
|
Other trade accounts receivable — net
|
48
|
|
Total trade accounts receivable — net
|
$
|
463
|
|
|
|
6.
|
GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS
|
Goodwill
The carrying value of goodwill totaled
$1.907 billion
at both
March 31, 2018 and December 31, 2017
. The goodwill arose in connection with our application of fresh start reporting at Emergence and was allocated entirely to the Retail Electricity reporting unit (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 are comprised of the following:
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|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
Identifiable Intangible Asset
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
|
Gross
Carrying
Amount
|
|
Accumulated
Amortization
|
|
Net
|
Retail customer relationship
|
|
$
|
1,648
|
|
|
$
|
645
|
|
|
$
|
1,003
|
|
|
$
|
1,648
|
|
|
$
|
572
|
|
|
$
|
1,076
|
|
Software and other technology-related assets
|
|
186
|
|
|
57
|
|
|
129
|
|
|
183
|
|
|
47
|
|
|
136
|
|
Retail and wholesale contracts
|
|
154
|
|
|
99
|
|
|
55
|
|
|
154
|
|
|
87
|
|
|
67
|
|
Other identifiable intangible assets (a)
|
|
33
|
|
|
11
|
|
|
22
|
|
|
33
|
|
|
11
|
|
|
22
|
|
Total identifiable intangible assets subject to amortization
|
|
$
|
2,021
|
|
|
$
|
812
|
|
|
1,209
|
|
|
$
|
2,018
|
|
|
$
|
717
|
|
|
1,301
|
|
Retail trade names (not subject to amortization)
|
|
|
|
|
|
1,225
|
|
|
|
|
|
|
1,225
|
|
Mineral interests (not currently subject to amortization)
|
|
|
|
|
|
3
|
|
|
|
|
|
|
4
|
|
Total identifiable intangible assets
|
|
|
|
|
|
$
|
2,437
|
|
|
|
|
|
|
$
|
2,530
|
|
____________
|
|
(a)
|
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:
|
|
|
|
|
|
|
|
|
|
|
Identifiable Intangible Asset
|
|
Condensed Statements of Consolidated Income (Loss) Line
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Retail customer relationship
|
|
Depreciation and amortization
|
$
|
73
|
|
|
$
|
105
|
|
Software and other technology-related assets
|
|
Depreciation and amortization
|
10
|
|
|
8
|
|
Retail and wholesale contracts
|
|
Operating revenues/fuel, purchased power costs and delivery fees
|
12
|
|
|
28
|
|
Other identifiable intangible assets
|
|
Operating revenues/fuel, purchased power costs and delivery fees/depreciation and amortization
|
2
|
|
|
4
|
|
Total amortization expense (a)
|
$
|
97
|
|
|
$
|
145
|
|
____________
|
|
(a)
|
Amounts recorded in depreciation and amortization totaled
$85 million
and
$115 million
for the
three months
ended
March 31, 2018 and 2017
, respectively.
|
Estimated Amortization of Identifiable Intangible Assets
As of
March 31, 2018
, 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
|
2018
|
|
$
|
368
|
|
2019
|
|
$
|
268
|
|
2020
|
|
$
|
192
|
|
2021
|
|
$
|
142
|
|
2022
|
|
$
|
89
|
|
The calculation of our effective tax rate is as follows:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Income (loss) before income taxes
|
$
|
(395
|
)
|
|
$
|
119
|
|
Income tax benefit (expense)
|
$
|
89
|
|
|
$
|
(41
|
)
|
Effective tax rate
|
22.5
|
%
|
|
34.5
|
%
|
For the
three months
ended
March 31, 2018
, the effective tax rate of
22.5%
related to our income tax expense was higher than the U.S. Federal statutory rate of
21%
due primarily to nondeductible TRA accretion and the Texas margin tax, net of federal benefit, offset by the difference in the forecasted effective tax rate and the statutory tax rate applied to mark-to-market unrealized losses.
For the
three months
ended
March 31, 2017
, the effective tax rate of
34.5%
related to our income tax expense was lower than the U.S. Federal statutory rate of
35%
due primarily to the difference in the forecasted effective tax rate and the statutory tax rate applied to mark-to-market unrealized gains, offset by deductible TRA accretion and the Texas margin tax, net of federal benefit.
Liability for Uncertain Tax Positions
Vistra Energy and its subsidiaries file income tax returns in U.S. federal and state jurisdictions and are expected to be subject to examinations by the IRS and other taxing authorities. Vistra Energy has limited operational history and filed its first federal tax return in October 2017. Vistra Energy is not currently under audit for any period, and we had no uncertain tax positions at both
March 31, 2018 and December 31, 2017
.
|
|
8.
|
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 our predecessor. 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 U.S. 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 acquisition of two CCGT natural gas fueled generation facilities 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 TCEH entitled to receive such TRA Rights under the Plan of Reorganization. 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
15
).
The following table summarizes the changes to the TRA obligation, reported as other current liabilities and Tax Receivable Agreement obligation in our condensed consolidated balance sheets, for the
three months
ended
March 31, 2018 and 2017
:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
TRA obligation at the beginning of the period
|
$
|
357
|
|
|
$
|
596
|
|
Accretion expense
|
18
|
|
|
21
|
|
TRA obligation at the end of the period
|
375
|
|
|
617
|
|
Less amounts due currently
|
(24
|
)
|
|
(16
|
)
|
Noncurrent TRA obligation at the end of the period
|
$
|
351
|
|
|
$
|
601
|
|
As of
March 31, 2018
, the estimated carrying value of the TRA obligation totaled
$375 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
21%
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
$1.2 billion
, with more than 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 months
ended
March 31, 2018 and 2017
, the Impacts of Tax Receivable Agreement on the condensed statements of consolidated income (loss) totaled
$18 million
and
$21 million
, respectively, which represents accretion expense for the period.
Basic earnings per share available to common shareholders are based on the weighted average number of common shares outstanding during the period. Diluted earnings per share is calculated using the treasury stock method and includes the effect of all potential issuances of common shares under stock-based incentive compensation arrangements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2018
|
|
Three Months Ended March 31, 2017
|
|
Net Loss
|
|
Shares
|
|
Per Share Amount
|
|
Net Income
|
|
Shares
|
|
Per Share Amount
|
Net income (loss) available for common stock — basic
|
$
|
(306
|
)
|
|
428,450,384
|
|
|
$
|
(0.71
|
)
|
|
$
|
78
|
|
|
427,583,339
|
|
|
$
|
0.18
|
|
Dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
Stock-based incentive compensation plan
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
217,011
|
|
|
—
|
|
Net income (loss) available for common stock — diluted
|
$
|
(306
|
)
|
|
428,450,384
|
|
|
$
|
(0.71
|
)
|
|
$
|
78
|
|
|
427,800,350
|
|
|
$
|
0.18
|
|
For the
three months
ended
March 31, 2018 and 2017
, stock-based incentive compensation plan awards totaling
2,863,872
and
602,403
shares, respectively, were excluded from the calculation of diluted earnings per share because the effect would have been antidilutive.
Amounts in the table below represent the categories of long-term debt obligations incurred by the Company.
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Vistra Operations Credit Facilities (a)
|
$
|
4,313
|
|
|
$
|
4,323
|
|
Mandatorily redeemable subsidiary preferred stock (b)
|
70
|
|
|
70
|
|
8.82% Building Financing due semiannually through February 11, 2022 (c)
|
27
|
|
|
30
|
|
Total long-term debt including amounts due currently
|
4,410
|
|
|
4,423
|
|
Less amounts due currently
|
(44
|
)
|
|
(44
|
)
|
Total long-term debt less amounts due currently
|
$
|
4,366
|
|
|
$
|
4,379
|
|
____________
|
|
(a)
|
At
March 31, 2018
, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of
$19 million
, debt discounts of
$2 million
and debt issuance costs of
$6 million
. At
December 31, 2017
, borrowings under the Vistra Operations Credit Facilities in our condensed consolidated balance sheet include debt premiums of
$21 million
, debt discounts of
$2 million
and debt issuance costs of
$7 million
.
|
|
|
(b)
|
Shares of mandatorily redeemable preferred stock in PrefCo issued as part of the Spin-Off (see Note
1
). 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. This obligation will be funded by amounts held in an escrow account that is reflected in other noncurrent assets in our condensed consolidated balance sheets.
|
Vistra Operations Credit Facilities
— At
March 31, 2018
, the Vistra Operations Credit Facilities consisted of up to
$5.162 billion
in senior secured, first lien revolving credit commitments and outstanding term loans, consisting of revolving credit commitments of up to
$860 million
, including a
$715 million
letter of credit sub-facility (Revolving Credit Facility), initial term loans totaling
$2.814 billion
(Initial Term Loan B Facility), incremental term loans totaling
$988 million
(Incremental Term Loan B Facility, and together with the Initial Term Loan B Facility, the Term Loan B Facility) and letter of credit term loans totaling
$500 million
(Term Loan C Facility).
The Vistra Operations Credit Facilities and related available capacity at
March 31, 2018
are presented below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
Vistra Operations Credit Facilities
|
|
Maturity Date
|
|
Facility
Limit
|
|
Cash
Borrowings
|
|
Available
Capacity
|
Revolving Credit Facility (a)
|
|
August 4, 2021
|
|
$
|
860
|
|
|
$
|
—
|
|
|
$
|
584
|
|
Initial Term Loan B Facility (b)
|
|
August 4, 2023
|
|
2,814
|
|
|
2,814
|
|
|
—
|
|
Incremental Term Loan B Facility (b)
|
|
December 14, 2023
|
|
988
|
|
|
988
|
|
|
—
|
|
Term Loan C Facility (c)
|
|
August 4, 2023
|
|
500
|
|
|
500
|
|
|
18
|
|
Total Vistra Operations Credit Facilities
|
|
|
|
$
|
5,162
|
|
|
$
|
4,302
|
|
|
$
|
602
|
|
___________
|
|
(a)
|
Facility to be used for general corporate purposes. Facility includes a
$715 million
letter of credit sub-facility, of which
$276 million
of letters of credit were outstanding at
March 31, 2018
.
|
|
|
(b)
|
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. Principal amounts paid cannot be reborrowed.
|
|
|
(c)
|
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
March 31, 2018
, the restricted cash supported
$482 million
in letters of credit outstanding (see Note
17
), leaving
$18 million
in available letter of credit capacity.
|
In February 2018, certain pricing terms for the Vistra Operations Credit Facility were amended. We accounted for this transaction as a modification of debt. At
March 31, 2018
, cash borrowings under the Revolving Credit Facility would bear interest based on applicable LIBOR rates, plus a fixed spread of
2.25%
, and there were
no
outstanding borrowings. Letters of credit issued under the Revolving Credit Facility bear interest of
2.25%
. 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
0.75%
floor, plus a fixed spread of
2.50%
. Amounts borrowed under the Incremental Term Loan B Facility bear interest based on applicable LIBOR rates plus a fixed spread of
2.25%
. At
March 31, 2018
, the weighted average interest rate before taking into consideration interest rate swaps on outstanding borrowings was
4.38%
,
4.07%
and
4.38%
under the Initial Term Loan B Facility, the Incremental Term Loan B Facility and the Term Loan C Facility, respectively. 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 the period ended
March 31, 2018
was not a compliance period, 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
— Effective January 2017, 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 expire in July 2023 and effectively fix the interest rates between
4.38%
and
4.50%
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.
|
|
11.
|
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
March 31, 2018
, 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
March 31, 2018
, we had outstanding letters of credit under the Vistra Operations Credit Facilities totaling
$758 million
as follows:
|
|
•
|
$634 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;
|
|
|
•
|
$36 million
to support executory contracts and insurance agreements;
|
|
|
•
|
$55 million
to support our REP financial requirements with the PUCT, and
|
|
|
•
|
$33 million
for other credit support requirements.
|
Litigation
Litigation Related to EPA Reviews
— In August 2013, the U.S. Department of Justice (DOJ), acting as the attorneys for the EPA, filed a civil enforcement lawsuit against Luminant in federal district court in Dallas, alleging violations of the Clean Air Act (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 January 2017, the EPA dismissed its two remaining claims with prejudice and the district court entered final judgment in Luminant's favor. In March 2017, the EPA and the Sierra Club appealed the final judgment to the U.S. Court of Appeals for the Fifth Circuit (Fifth Circuit Court). After the parties filed their respective briefs in the Fifth Circuit Court, the appeal was argued before the Fifth Circuit Court in March 2018. We believe that we have complied with all requirements of the CAA and intend to vigorously defend against the remaining allegations. The lawsuit requests (i) 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 (ii) 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 remaining plant at issue, Martin Lake, and could possibly require the payment of substantial penalties. The recent retirement of the Big Brown plant should have a favorable impact on this litigation. 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 emissions from new, modified and reconstructed and existing electricity generation units, referred to as the Clean Power Plan, including rules for existing facilities that would establish state-specific emissions rate goals to reduce nationwide CO
2
emissions. Various parties (including Luminant) filed petitions for review in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) and subsequently, in January 2016, a coalition of states, industry (including Luminant) and other parties filed applications with the U.S. 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 was heard in September 2016 before the entire D.C. Circuit Court.
Following a March 2017 Executive Order entitled
Promoting Energy Independence and Economic Growth
issued by President Trump covering a number of matters, including the Clean Power Plan (Order), in April 2017, in accordance with the Order, the EPA published its intent to review the Clean Power Plan. In October 2017, the EPA issued a proposed rule that would repeal the Clean Power Plan, with the proposed repeal focusing on what the EPA believes to be the unlawful nature of the Clean Power Plan and asking for public comment on the EPA's interpretations of its authority under the Clean Air Act. In December 2017, the EPA published an advance notice of proposed rulemaking (ANPR) soliciting information from the public as the EPA considers proposing a future rule. Vistra Energy submitted comments on the ANPR in February 2018. Vistra Energy submitted comments to the proposed repeal in April 2018. 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 (SO
2
) and nitrogen oxide (NO
X
) emissions from our fossil fueled generation units. After certain EPA revisions to the rule, the CSAPR became effective January 1, 2015. With respect to Texas's SO
2
and annual NO
X
emission budgets, in November 2016, the EPA proposed to withdraw the CSAPR Federal Implementation Plan (FIP) addressing SO
2
and annual NO
X
for Texas and in September 2017, the EPA finalized its proposal to remove Texas from these annual CSAPR programs. The Sierra Club and the National Parks Conservation Association filed a petition for review in the D.C. Circuit Court challenging that final rule and Luminant intervened on behalf of the EPA. On April 10, 2018, the D.C. Circuit Court granted the EPA's and petitioners' motion to hold the case in abeyance pending the EPA's consideration of a pending petition for administrative reconsideration. As a result of the EPA's action, Texas electric generating units are no longer subject to the CSAPR annual SO
2
and NO
X
limits, but remain subject to the CSAPR's ozone season NO
X
requirements. While we cannot predict the outcome of future proceedings related to the CSAPR, based upon our current operating plans, including the recent retirements of our Monticello, Big Brown and Sandow 4 plants (see Note
3
), we do not believe that the CSAPR in its current form 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 which impairment results from man-made pollution." In February 2009, the TCEQ submitted a State Implementation Plan (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. The EPA finalized the limited disapproval of Texas's Regional Haze SIP in June 2012 and, on March 20, 2018, the D.C. Circuit Court issued a decision upholding the EPA's actions and denying all of Luminant's petitions for review.
In January 2016, the EPA issued a final rule approving in part and disapproving in part Texas' SIP addressing the reasonable progress component of the Regional Haze program and issuing a FIP. 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 granted the motions to stay filed by Luminant and the other parties 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. 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, and the EPA is required to file status reports of its reconsideration every 60 days. The recent retirements of our Monticello, Big Brown and Sandow 4 plants should have a favorable impact on this rulemaking and litigation. 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 (BART)
In September 2017, the EPA signed the final BART FIP for Texas, with the rule serving as a partial approval of Texas's 2009 SIP and a partial FIP. For SO
2
, 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). The compliance obligations in the program will start on January 1, 2019 and the identified units will receive an annual allowance allocation that is equal to their most recent annual CSAPR SO
2
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. We believe the recent retirements of our Monticello, Big Brown and Sandow 4 plants will enhance our ability to comply with this BART rule for SO
2
. For NO
X
, 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 BART for particulate matter. The National Parks Conservation Association, the Sierra Club and the Environmental Defense Fund filed a petition challenging the rule in the Fifth Circuit Court as well as a petition for reconsideration filed with the EPA. In March 2018, the Fifth Circuit Court granted a joint motion filed by the EPA and the environmental groups involved to abate the Fifth Circuit Court proceedings until the EPA has taken action on the reconsideration petition and concludes the reconsideration process. While we cannot predict the outcome of the rulemaking and 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.
Affirmative Defenses During Malfunctions
In February 2013, 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 May 2015, the EPA finalized 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 June 2015, the State of Texas and various industry parties (including Luminant) filed petitions for review in the Fifth Circuit Court challenging certain aspects of the EPA's final rule as they apply to the Texas SIP. 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. Before the originally scheduled oral argument was held, 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.
SO
2
Designations for Texas
In November 2016, the EPA finalized its nonattainment designations for counties surrounding our Big Brown, Monticello and Martin Lake generation plants. The final designations require Texas to develop nonattainment plans for these areas. In February 2017, the State of Texas and Luminant filed challenges to the nonattainment designations in the Fifth Circuit Court. Subsequently, 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 intended to revisit the nonattainment rule. In December 2017, the TCEQ submitted a petition for reconsideration to the EPA. In addition, with respect to Monticello and Big Brown, 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, which we dispute, of alleged SO
2
emissions from Monticello and Big Brown. Regardless, considering these retirements, 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.
Litigation Related to the Merger
In January 2018, a purported Dynegy stockholder filed a putative class action lawsuit in the U.S. District Court for the Southern Division of Texas, Houston Division, alleging that Dynegy, each member of the Dynegy board of directors and Vistra Energy violated federal securities laws by filing a Form S-4 Registration Statement in connection with the Merger that omitted purportedly material information. The lawsuit sought to enjoin the Merger and to have Dynegy and Vistra Energy issue an amended Form S-4 or, alternatively, damages if the Merger closed without an amended Form S-4 having been filed. Two other related lawsuits were also filed but neither of those named Vistra Energy. In February 2018, Vistra Energy and Dynegy filed supplemental disclosures to the Registration Statement and the plaintiffs agreed to forego any further effort to enjoin the Merger, dismiss the individual claims with prejudice, and dismissed without prejudice claims of the putative class following the stockholder vote on March 2, 2018.
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.
Vistra Energy did not declare or pay any dividends during the
three months
ended
March 31, 2018 and 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
March 31, 2018
, Vistra Operations can distribute approximately
$975 million
to Vistra Energy Corp. (the Parent) under the Credit Facilities Agreement without the consent of any party. The amount that can be distributed by Vistra Operations to the Parent was partially reduced by distributions made by Vistra Operations to the Parent during the year ended December 31, 2017 of approximately
$1.1 billion
. There were
no
distributions made by Vistra Operations to the Parent during the
three months
ended
March 31, 2018
. Additionally, Vistra Operations may make distributions to the Parent in amounts sufficient for the Parent to make any payments required under the TRA or the Tax Matters Agreement or, to the extent arising out of the Parent's ownership or operation of Vistra Operations, to pay any taxes or general operating or corporate overhead expenses. As of
March 31, 2018
, the maximum amount of restricted net assets of Vistra Operations that may not be distributed to the Parent totaled approximately
$3.6 billion
.
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
three months
ended
March 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock (a)
|
|
Additional Paid-in Capital
|
|
Retained Earnings (Deficit)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total Shareholders' Equity
|
Balance at December 31, 2017
|
$
|
4
|
|
|
$
|
7,765
|
|
|
$
|
(1,410
|
)
|
|
$
|
(17
|
)
|
|
$
|
6,342
|
|
Net loss
|
—
|
|
|
—
|
|
|
(306
|
)
|
|
—
|
|
|
(306
|
)
|
Adoption of accounting standard (Note 1)
|
—
|
|
|
—
|
|
|
17
|
|
|
—
|
|
|
17
|
|
Effects of stock-based incentive compensation plans
|
—
|
|
|
7
|
|
|
—
|
|
|
—
|
|
|
7
|
|
Change in unrecognized losses related to pension and OPEB plans
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
1
|
|
Other
|
—
|
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
(1
|
)
|
Balance at March 31, 2018
|
$
|
4
|
|
|
$
|
7,772
|
|
|
$
|
(1,700
|
)
|
|
$
|
(16
|
)
|
|
$
|
6,060
|
|
________________
|
|
(a)
|
Authorized shares totaled
1,800,000,000
at
March 31, 2018
. Outstanding shares totaled
428,506,325
and
428,398,802
at
March 31, 2018
and
December 31, 2017
, respectively.
|
The following table presents the changes to shareholder's equity for the
three months
ended
March 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common
Stock (a)
|
|
Additional Paid-in Capital
|
|
Retained Earnings (Deficit)
|
|
Accumulated Other Comprehensive Income (Loss)
|
|
Total Shareholders' Equity
|
Balance at December 31, 2016
|
$
|
4
|
|
|
$
|
7,742
|
|
|
$
|
(1,155
|
)
|
|
$
|
6
|
|
|
$
|
6,597
|
|
Net income
|
—
|
|
|
—
|
|
|
78
|
|
|
—
|
|
|
78
|
|
Effects of stock-based incentive compensation plans
|
—
|
|
|
4
|
|
|
—
|
|
|
—
|
|
|
4
|
|
Other
|
—
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
1
|
|
Balance at March 31, 2017
|
$
|
4
|
|
|
$
|
7,746
|
|
|
$
|
(1,076
|
)
|
|
$
|
6
|
|
|
$
|
6,680
|
|
________________
|
|
(a)
|
Authorized shares totaled
1,800,000,000
at
March 31, 2017
. Outstanding shares totaled
427,587,401
and
427,580,232
at
March 31, 2017
and
December 31, 2016
, respectively.
|
|
|
13.
|
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 that reports to the Vistra Energy Chief Financial Officer.
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
14
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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
Level 1
|
|
Level 2
|
|
Level 3 (a)
|
|
Reclassification (b)
|
|
Total
|
Assets:
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
40
|
|
|
$
|
286
|
|
|
$
|
163
|
|
|
$
|
7
|
|
|
$
|
496
|
|
Interest rate swaps
|
—
|
|
|
77
|
|
|
—
|
|
|
—
|
|
|
77
|
|
Nuclear decommissioning trust –
equity securities (c)
|
465
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
465
|
|
Nuclear decommissioning trust –
debt securities (c)
|
—
|
|
|
427
|
|
|
—
|
|
|
—
|
|
|
427
|
|
Sub-total
|
$
|
505
|
|
|
$
|
790
|
|
|
$
|
163
|
|
|
$
|
7
|
|
|
1,465
|
|
Assets measured at net asset value (d):
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trust –
equity securities (c)
|
|
|
|
|
|
|
|
|
288
|
|
Total assets
|
|
|
|
|
|
|
|
|
$
|
1,753
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
82
|
|
|
$
|
505
|
|
|
$
|
387
|
|
|
$
|
7
|
|
|
$
|
981
|
|
Total liabilities
|
$
|
82
|
|
|
$
|
505
|
|
|
$
|
387
|
|
|
$
|
7
|
|
|
$
|
981
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
Level 1
|
|
Level 2
|
|
Level 3 (a)
|
|
Reclassification (b)
|
|
Total
|
Assets:
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
47
|
|
|
$
|
98
|
|
|
$
|
75
|
|
|
$
|
2
|
|
|
$
|
222
|
|
Interest rate swaps
|
—
|
|
|
18
|
|
|
—
|
|
|
8
|
|
|
26
|
|
Nuclear decommissioning trust –
equity securities (c)
|
468
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
468
|
|
Nuclear decommissioning trust –
debt securities (c)
|
—
|
|
|
430
|
|
|
—
|
|
|
—
|
|
|
430
|
|
Sub-total
|
$
|
515
|
|
|
$
|
546
|
|
|
$
|
75
|
|
|
$
|
10
|
|
|
1,146
|
|
Assets measured at net asset value (d):
|
|
|
|
|
|
|
|
|
|
Nuclear decommissioning trust –
equity securities (c)
|
|
|
|
|
|
|
|
|
290
|
|
Total assets
|
|
|
|
|
|
|
|
|
$
|
1,436
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
$
|
45
|
|
|
$
|
143
|
|
|
$
|
128
|
|
|
$
|
2
|
|
|
$
|
318
|
|
Interest rate swaps
|
—
|
|
|
—
|
|
|
—
|
|
|
8
|
|
|
8
|
|
Total liabilities
|
$
|
45
|
|
|
$
|
143
|
|
|
$
|
128
|
|
|
$
|
10
|
|
|
$
|
326
|
|
____________
|
|
(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
17
.
|
|
|
(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
14
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
March 31, 2018 and December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
|
Fair Value
|
|
|
|
|
|
|
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
Electricity purchases and sales
|
|
$
|
41
|
|
|
$
|
(149
|
)
|
|
$
|
(108
|
)
|
|
Valuation Model
|
|
Hourly price curve shape (c)
|
|
$0 to $60/ MWh
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
|
|
$20 to $90/ MWh
|
Electricity and weather options
|
|
41
|
|
|
(232
|
)
|
|
(191
|
)
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
40% to 100%
|
|
|
|
|
|
|
|
|
|
|
Power volatility (e)
|
|
5% to 195%
|
Electricity congestion revenue rights
|
|
66
|
|
|
(6
|
)
|
|
60
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$0 to $15/ MWh
|
Other (h)
|
|
15
|
|
|
—
|
|
|
15
|
|
|
|
|
|
|
|
Total
|
|
$
|
163
|
|
|
$
|
(387
|
)
|
|
$
|
(224
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
|
Fair Value
|
|
|
|
|
|
|
Contract Type (a)
|
|
Assets
|
|
Liabilities
|
|
Total
|
|
Valuation Technique
|
|
Significant Unobservable Input
|
|
Range (b)
|
Electricity purchases and sales
|
|
$
|
12
|
|
|
$
|
(33
|
)
|
|
$
|
(21
|
)
|
|
Valuation Model
|
|
Hourly price curve shape (c)
|
|
$0 to $40/ MWh
|
|
|
|
|
|
|
|
|
|
|
Illiquid delivery periods for ERCOT hub power prices and heat rates (d)
|
|
$20 to $70/ MWh
|
Electricity and weather options
|
|
10
|
|
|
(91
|
)
|
|
(81
|
)
|
|
Option Pricing Model
|
|
Gas to power correlation (e)
|
|
30% to 100%
|
|
|
|
|
|
|
|
|
|
|
Power volatility (e)
|
|
5% to 180%
|
Electricity congestion revenue rights
|
|
45
|
|
|
(4
|
)
|
|
41
|
|
|
Market Approach (f)
|
|
Illiquid price differences between settlement points (g)
|
|
$0 to $15/ MWh
|
Other (h)
|
|
8
|
|
|
—
|
|
|
8
|
|
|
|
|
|
|
|
Total
|
|
$
|
75
|
|
|
$
|
(128
|
)
|
|
$
|
(53
|
)
|
|
|
|
|
|
|
____________
|
|
(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 and coal options.
|
There were no transfers between Level 1 and Level 2 of the fair value hierarchy for the
three months
ended
March 31, 2018 and 2017
. See the table below for discussion of transfers between Level 2 and Level 3 for the
three months
ended
March 31, 2018 and 2017
.
The following table presents the changes in fair value of the Level 3 assets and liabilities for the
three months
ended
March 31, 2018 and 2017
.
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Net asset (liability) balance at beginning of period
|
$
|
(53
|
)
|
|
$
|
83
|
|
Total unrealized valuation gains (losses)
|
(213
|
)
|
|
40
|
|
Purchases, issuances and settlements (a):
|
|
|
|
Purchases
|
29
|
|
|
10
|
|
Issuances
|
(4
|
)
|
|
(12
|
)
|
Settlements
|
17
|
|
|
(19
|
)
|
Transfers into Level 3 (b)
|
—
|
|
|
3
|
|
Transfers out of Level 3 (b)
|
—
|
|
|
2
|
|
Net change (c)
|
(171
|
)
|
|
24
|
|
Net asset (liability) balance at end of period
|
$
|
(224
|
)
|
|
$
|
107
|
|
Unrealized valuation gains (losses) relating to instruments held at end of period
|
$
|
(206
|
)
|
|
$
|
36
|
|
____________
|
|
(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)
|
Activity excludes change in fair value in the month positions settle. Substantially all changes in value of commodity contracts are reported as operating revenues in our condensed statements of consolidated income (loss).
|
|
|
14.
|
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
13
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.
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
March 31, 2018 and December 31, 2017
. Derivative asset and liability totals represent the net value of the contract, while the balance sheet totals represent the gross value of the contract.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Total
|
Current assets
|
$
|
397
|
|
|
$
|
3
|
|
|
$
|
4
|
|
|
$
|
—
|
|
|
$
|
404
|
|
Noncurrent assets
|
95
|
|
|
74
|
|
|
—
|
|
|
—
|
|
|
169
|
|
Current liabilities
|
(2
|
)
|
|
—
|
|
|
(593
|
)
|
|
—
|
|
|
(595
|
)
|
Noncurrent liabilities
|
(1
|
)
|
|
—
|
|
|
(385
|
)
|
|
—
|
|
|
(386
|
)
|
Net assets (liabilities)
|
$
|
489
|
|
|
$
|
77
|
|
|
$
|
(974
|
)
|
|
$
|
—
|
|
|
$
|
(408
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
Derivative Assets
|
|
Derivative Liabilities
|
|
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Commodity Contracts
|
|
Interest Rate Swaps
|
|
Total
|
Current assets
|
$
|
190
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
190
|
|
Noncurrent assets
|
30
|
|
|
22
|
|
|
2
|
|
|
4
|
|
|
58
|
|
Current liabilities
|
—
|
|
|
(4
|
)
|
|
(216
|
)
|
|
(4
|
)
|
|
(224
|
)
|
Noncurrent liabilities
|
—
|
|
|
—
|
|
|
(102
|
)
|
|
—
|
|
|
(102
|
)
|
Net assets (liabilities)
|
$
|
220
|
|
|
$
|
18
|
|
|
$
|
(316
|
)
|
|
$
|
—
|
|
|
$
|
(78
|
)
|
At
March 31, 2018 and December 31, 2017
, there were no derivative positions accounted for as cash flow or fair value hedges. There were no amounts recognized in OCI for both the
three months
ended
March 31, 2018 and 2017
.
The following table presents the pretax effect of derivative gains (losses) on net income, including realized and unrealized effects. 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.
|
|
|
|
|
|
|
|
|
Derivative (condensed statements of consolidated income (loss) presentation)
|
Three Months Ended March 31,
|
2018
|
|
2017
|
Commodity contracts (Operating revenues)
|
$
|
(446
|
)
|
|
$
|
175
|
|
Commodity contracts (Fuel, purchased power costs and delivery fees)
|
(1
|
)
|
|
(5
|
)
|
Interest rate swaps (Interest expense and related charges)
|
56
|
|
|
3
|
|
Net gain (loss)
|
$
|
(391
|
)
|
|
$
|
173
|
|
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 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
|
|
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
|
|
$
|
489
|
|
|
$
|
(277
|
)
|
|
$
|
(1
|
)
|
|
$
|
211
|
|
|
$
|
220
|
|
|
$
|
(113
|
)
|
|
$
|
(1
|
)
|
|
$
|
106
|
|
Interest rate swaps
|
|
77
|
|
|
—
|
|
|
—
|
|
|
77
|
|
|
18
|
|
|
—
|
|
|
—
|
|
|
18
|
|
Total derivative assets
|
|
566
|
|
|
(277
|
)
|
|
(1
|
)
|
|
288
|
|
|
238
|
|
|
(113
|
)
|
|
(1
|
)
|
|
124
|
|
Derivative liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts
|
|
(974
|
)
|
|
277
|
|
|
85
|
|
|
(612
|
)
|
|
(316
|
)
|
|
113
|
|
|
1
|
|
|
(202
|
)
|
Interest rate swaps
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total derivative liabilities
|
|
(974
|
)
|
|
277
|
|
|
85
|
|
|
(612
|
)
|
|
(316
|
)
|
|
113
|
|
|
1
|
|
|
(202
|
)
|
Net amounts
|
|
$
|
(408
|
)
|
|
$
|
—
|
|
|
$
|
84
|
|
|
$
|
(324
|
)
|
|
$
|
(78
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(78
|
)
|
____________
|
|
(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
March 31, 2018 and December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
|
|
Derivative type
|
|
Notional Volume
|
|
Unit of Measure
|
Natural gas (a)
|
|
1,423
|
|
|
1,259
|
|
|
Million MMBtu
|
Electricity
|
|
102,316
|
|
|
114,129
|
|
|
GWh
|
Congestion Revenue Rights (b)
|
|
142,560
|
|
|
110,913
|
|
|
GWh
|
Coal
|
|
2
|
|
|
2
|
|
|
Million U.S. tons
|
Fuel oil
|
|
22
|
|
|
5
|
|
|
Million gallons
|
Uranium
|
|
125
|
|
|
325
|
|
|
Thousand pounds
|
Interest rate swaps – floating/fixed (c)
|
|
$
|
3,000
|
|
|
$
|
3,000
|
|
|
Million U.S. 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 with 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:
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Fair value of derivative contract liabilities (a)
|
$
|
(758
|
)
|
|
$
|
(204
|
)
|
Offsetting fair value under netting arrangements (b)
|
215
|
|
|
103
|
|
Cash collateral and letters of credit
|
336
|
|
|
41
|
|
Liquidity exposure
|
$
|
(207
|
)
|
|
$
|
(60
|
)
|
____________
|
|
(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
March 31, 2018
, total credit risk exposure to all counterparties related to derivative contracts totaled
$634 million
(including associated accounts receivable). The net exposure to those counterparties totaled
$293 million
at
March 31, 2018
after taking into effect netting arrangements, setoff provisions and collateral, with the largest net exposure to a single counterparty totaling
$77 million
. At
March 31, 2018
, the credit risk exposure to the banking and financial sector represented
29%
of the total credit risk exposure and
29%
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.
|
|
15.
|
RELATED PARTY TRANSACTIONS
|
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, which was declared effective by the SEC in May 2017. The registration statement was amended in March 2018. 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 of 1933, as amended, 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 months
ended
March 31, 2018 and 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
8
for discussion of the TRA.
The operations of Vistra Energy are aligned into
three
reportable business segments: Wholesale Generation, Retail Electricity and Asset Closure. Our chief operating decision maker reviews the results of these three segments separately and allocates resources to the respective segments as part of our strategic operations. The Wholesale Generation and Retail Electricity businesses 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.
As discussed in Note
1
, the Asset Closure segment was established effective January 1, 2018. The Asset Closure segment is engaged in the decommissioning and reclamation of retired plants and mines. Separately reporting the Asset Closure segment provides management with better information related to the performance and earnings power of Vistra Energy's ongoing operations and facilitates management's focus on minimizing the cost associated with decommissioning and reclamation of retired plants and mines. We have recast information from prior periods to reflect this change in reportable segments. We have not allocated any unrealized gains or losses to the Asset Closure segment for the generation plants that were retired in January and February 2018.
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, Retail Electricity and Asset Closure 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 2017 Form 10-K. Our chief operating decision maker uses more than one measure to assess segment performance, including 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 March 31,
|
|
2018
|
|
2017
|
Operating revenues (a)
|
|
|
|
Wholesale Generation
|
$
|
(533
|
)
|
|
$
|
785
|
|
Retail Electricity
|
972
|
|
|
865
|
|
Asset Closure
|
28
|
|
|
186
|
|
Corporate and Other
|
—
|
|
|
(1
|
)
|
Eliminations
|
298
|
|
|
(478
|
)
|
Consolidated operating revenues
|
$
|
765
|
|
|
$
|
1,357
|
|
Depreciation and amortization
|
|
|
|
Wholesale Generation
|
$
|
(64
|
)
|
|
$
|
(53
|
)
|
Retail Electricity
|
(76
|
)
|
|
$
|
(106
|
)
|
Corporate and Other
|
(12
|
)
|
|
$
|
(11
|
)
|
Eliminations
|
$
|
(1
|
)
|
|
$
|
—
|
|
Consolidated depreciation and amortization
|
$
|
(153
|
)
|
|
$
|
(170
|
)
|
Operating income (loss)
|
|
|
|
Wholesale Generation
|
$
|
(1,087
|
)
|
|
$
|
300
|
|
Retail Electricity
|
757
|
|
|
$
|
(118
|
)
|
Asset Closure
|
(23
|
)
|
|
$
|
(15
|
)
|
Corporate and Other
|
(40
|
)
|
|
$
|
(12
|
)
|
Eliminations
|
$
|
(1
|
)
|
|
$
|
—
|
|
Consolidated operating income (loss)
|
$
|
(394
|
)
|
|
$
|
155
|
|
Net income (loss)
|
|
|
|
Wholesale Generation
|
$
|
(1,086
|
)
|
|
$
|
303
|
|
Retail Electricity
|
771
|
|
|
(113
|
)
|
Asset Closure
|
(22
|
)
|
|
(13
|
)
|
Corporate and Other
|
31
|
|
|
(99
|
)
|
Consolidated net income (loss)
|
$
|
(306
|
)
|
|
$
|
78
|
|
____________
|
|
(a)
|
For the
three months
ended
March 31, 2018 and 2017
, includes third-party unrealized net gains (losses) from mark-to-market valuations of commodity positions of
$(426) million
and
$126 million
, respectively, recorded to the Wholesale Generation segment and
$12 million
and
$8 million
, respectively, recorded to the Retail Electricity segment. In addition, for the
three months
ended
March 31, 2018 and 2017
, unrealized net gains (losses) with affiliate of
$(643) million
and
$170 million
, respectively, were recorded to operating revenues for the Wholesale Generation segment and corresponding unrealized net gains (losses) with affiliate of
$643 million
and
$(170) million
, respectively, were recorded to fuel, purchased power costs and delivery fees for the Retail Electricity segment, with no impact to consolidated results.
|
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31, 2017
|
Total assets
|
|
|
|
Wholesale Generation
|
$
|
7,048
|
|
|
$
|
6,834
|
|
Retail Electricity
|
6,890
|
|
|
6,156
|
|
Asset Closure
|
235
|
|
|
235
|
|
Corporate and Other and Eliminations
|
603
|
|
|
1,375
|
|
Consolidated total assets
|
$
|
14,776
|
|
|
$
|
14,600
|
|
|
|
17.
|
SUPPLEMENTARY FINANCIAL INFORMATION
|
Interest Expense and Related Charges
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Interest paid/accrued
|
$
|
50
|
|
|
$
|
54
|
|
Unrealized mark-to-market net gains on interest rate swaps
|
(59
|
)
|
|
(9
|
)
|
Debt extinguishment gain
|
—
|
|
|
(21
|
)
|
Capitalized interest
|
(3
|
)
|
|
(3
|
)
|
Other
|
3
|
|
|
3
|
|
Total interest expense and related charges
|
$
|
(9
|
)
|
|
$
|
24
|
|
The weighted average interest rate applicable to the Vistra Operations Credit Facilities, taking into account the interest rate swaps discussed in Note
10
, was
4.43%
at
March 31, 2018
.
Other Income and Deductions
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Other income:
|
|
|
|
Office space sublease rental income (a)
|
$
|
2
|
|
|
$
|
3
|
|
Mineral rights royalty income (b)
|
—
|
|
|
1
|
|
Sale of land (b)
|
1
|
|
|
2
|
|
Interest income
|
6
|
|
|
1
|
|
All other
|
1
|
|
|
2
|
|
Total other income
|
$
|
10
|
|
|
$
|
9
|
|
Other deductions:
|
|
|
|
All other
|
$
|
2
|
|
|
$
|
—
|
|
Total other deductions
|
$
|
2
|
|
|
$
|
—
|
|
____________
|
|
(a)
|
Reported in Corporate and Other non-segment.
|
|
|
(b)
|
Reported in Wholesale Generation segment.
|
Restricted Cash
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
|
Current
Assets
|
|
Noncurrent Assets
|
|
Current
Assets
|
|
Noncurrent Assets
|
Amounts related to the Vistra Operations Credit Facilities (Note 10)
|
$
|
—
|
|
|
$
|
500
|
|
|
$
|
—
|
|
|
$
|
500
|
|
Amounts related to restructuring escrow accounts
|
59
|
|
|
—
|
|
|
59
|
|
|
—
|
|
Total restricted cash
|
$
|
59
|
|
|
$
|
500
|
|
|
$
|
59
|
|
|
$
|
500
|
|
Trade Accounts Receivable
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Wholesale and retail trade accounts receivable
|
$
|
477
|
|
|
$
|
596
|
|
Allowance for uncollectible accounts
|
(14
|
)
|
|
(14
|
)
|
Trade accounts receivable — net
|
$
|
463
|
|
|
$
|
582
|
|
Gross trade accounts receivable at
March 31, 2018 and December 31, 2017
included unbilled retail revenues of
$187 million
and
$251 million
, respectively.
Allowance for Uncollectible Accounts Receivable
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Allowance for uncollectible accounts receivable at beginning of period
|
$
|
14
|
|
|
$
|
10
|
|
Increase for bad debt expense
|
11
|
|
|
7
|
|
Decrease for account write-offs
|
(11
|
)
|
|
(9
|
)
|
Allowance for uncollectible accounts receivable at end of period
|
$
|
14
|
|
|
$
|
8
|
|
Inventories by Major Category
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Materials and supplies
|
$
|
149
|
|
|
$
|
149
|
|
Fuel stock
|
62
|
|
|
83
|
|
Natural gas in storage
|
15
|
|
|
21
|
|
Total inventories
|
$
|
226
|
|
|
$
|
253
|
|
Other Investments
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Nuclear plant decommissioning trust
|
$
|
1,180
|
|
|
$
|
1,188
|
|
Land
|
49
|
|
|
49
|
|
Miscellaneous other
|
3
|
|
|
3
|
|
Total other investments
|
$
|
1,232
|
|
|
$
|
1,240
|
|
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 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. A summary of investments in the fund follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
Cost (a)
|
|
Unrealized gain
|
|
Unrealized loss
|
|
Fair market
value
|
Debt securities (b)
|
$
|
425
|
|
|
$
|
8
|
|
|
$
|
(6
|
)
|
|
$
|
427
|
|
Equity securities (c)
|
268
|
|
|
487
|
|
|
(2
|
)
|
|
753
|
|
Total
|
$
|
693
|
|
|
$
|
495
|
|
|
$
|
(8
|
)
|
|
$
|
1,180
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2017
|
|
Cost (a)
|
|
Unrealized gain
|
|
Unrealized loss
|
|
Fair market
value
|
Debt securities (b)
|
$
|
418
|
|
|
$
|
14
|
|
|
$
|
(2
|
)
|
|
$
|
430
|
|
Equity securities (c)
|
265
|
|
|
495
|
|
|
(2
|
)
|
|
758
|
|
Total
|
$
|
683
|
|
|
$
|
509
|
|
|
$
|
(4
|
)
|
|
$
|
1,188
|
|
____________
|
|
(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 government and municipal bonds and investment grade corporate bonds. The debt securities had an average coupon rate of
3.45%
and
3.55%
at
March 31, 2018 and December 31, 2017
, respectively, and an average maturity of
nine years
at both
March 31, 2018 and December 31, 2017
.
|
|
|
(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
March 31, 2018
mature as follows:
$133 million
in one to five years,
$91 million
in five to 10 years and
$203 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.
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Realized gains
|
$
|
—
|
|
|
$
|
1
|
|
Realized losses
|
$
|
(2
|
)
|
|
$
|
(2
|
)
|
Proceeds from sales of securities
|
$
|
46
|
|
|
$
|
79
|
|
Investments in securities
|
$
|
(51
|
)
|
|
$
|
(84
|
)
|
Property, Plant and Equipment
At
March 31, 2018 and December 31, 2017
, property, plant and equipment of
$4.850 billion
and
$4.820 billion
, respectively, is stated net of accumulated depreciation and amortization of
$480 million
and
$393 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.
At
March 31, 2018
, the carrying value of our ARO related to our nuclear generation plant decommissioning totaled
$1.244 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
$64 million
in other noncurrent assets.
The following table summarizes the changes to these obligations, reported as asset retirement obligations (current and noncurrent liabilities) in our condensed consolidated balance sheets, for the
three months
ended
March 31, 2018
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Nuclear Plant Decommissioning
|
|
Mining Land Reclamation
|
|
Other
|
|
Total
|
Liability at December 31, 2017
|
$
|
1,233
|
|
|
$
|
438
|
|
|
$
|
265
|
|
|
$
|
1,936
|
|
Additions:
|
|
|
|
|
|
|
|
Accretion
|
11
|
|
|
5
|
|
|
3
|
|
|
19
|
|
Adjustment for change in estimates
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
Reductions:
|
|
|
|
|
|
|
|
Payments
|
—
|
|
|
(16
|
)
|
|
—
|
|
|
(16
|
)
|
Liability at March 31, 2018
|
1,244
|
|
|
431
|
|
|
268
|
|
|
1,943
|
|
Less amounts due currently
|
—
|
|
|
(117
|
)
|
|
(9
|
)
|
|
(126
|
)
|
Noncurrent liability at March 31, 2018
|
$
|
1,244
|
|
|
$
|
314
|
|
|
$
|
259
|
|
|
$
|
1,817
|
|
Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Unfavorable purchase and sales contracts
|
$
|
32
|
|
|
$
|
36
|
|
Other, including retirement and other employee benefits
|
207
|
|
|
220
|
|
Total other noncurrent liabilities and deferred credits
|
$
|
239
|
|
|
$
|
256
|
|
Unfavorable Purchase and Sales Contracts
— The amortization of unfavorable purchase and sales contracts totaled
$4 million
and
$3 million
for the
three months
ended
March 31, 2018 and 2017
, respectively. See Note
6
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
|
2018
|
|
$
|
11
|
|
2019
|
|
$
|
9
|
|
2020
|
|
$
|
9
|
|
2021
|
|
$
|
1
|
|
2022
|
|
$
|
3
|
|
Fair Value of Debt
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
March 31, 2018
|
|
December 31, 2017
|
Debt:
|
|
Carrying Amount
|
|
Fair
Value
|
|
Carrying Amount
|
|
Fair
Value
|
Long-term debt under the Vistra Operations Credit Facilities (Note 10)
|
|
$
|
4,313
|
|
|
$
|
4,328
|
|
|
$
|
4,323
|
|
|
$
|
4,334
|
|
Other long-term debt, excluding capital lease obligations (Note 10)
|
|
27
|
|
|
24
|
|
|
30
|
|
|
27
|
|
Mandatorily redeemable subsidiary preferred stock (Note 10)
|
|
70
|
|
|
70
|
|
|
70
|
|
|
70
|
|
We determine fair value in accordance with accounting standards as discussed in Note
13
, and at
March 31, 2018
, 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.
Cash Flow Information
The following table reconciles cash, cash equivalents and restricted cash reported in our condensed statements of consolidated cash flows to the amounts reported in our condensed balance sheets at
March 31, 2018 and December 31, 2017
:
|
|
|
|
|
|
|
|
|
|
March 31,
2018
|
|
December 31,
2017
|
Cash and cash equivalents
|
$
|
1,379
|
|
|
$
|
1,487
|
|
Restricted cash included in current assets
|
59
|
|
|
59
|
|
Restricted cash included in noncurrent assets
|
500
|
|
|
500
|
|
Total cash, cash equivalents and restricted cash
|
$
|
1,938
|
|
|
$
|
2,046
|
|
The following table summarizes our supplemental cash flow information for the
three months
ended
March 31, 2018 and 2017
:
|
|
|
|
|
|
|
|
|
|
Three Months Ended March 31,
|
|
2018
|
|
2017
|
Cash payments related to:
|
|
|
|
Interest paid
|
$
|
65
|
|
|
$
|
89
|
|
Capitalized interest
|
(3
|
)
|
|
(3
|
)
|
Interest paid (net of capitalized interest)
|
$
|
62
|
|
|
$
|
86
|
|
Noncash investing and financing activities:
|
|
|
|
Construction expenditures (a)
|
$
|
26
|
|
|
$
|
1
|
|
____________
|
|
(a)
|
Represents end-of-period accruals for ongoing construction projects.
|