State of Incorporation | I.R.S. Employer Identification No. | |
Delaware | 20-5653152 | |
601 Travis, Suite 1400 | ||
Houston, Texas | 77002 | |
(Address of principal executive offices) | (Zip Code) |
Large accelerated filer ý | Accelerated filer o | |
Non-accelerated filer o | Smaller reporting company o | |
(Do not check if a smaller reporting company) | Emerging growth company o |
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Item 2. | ||
Item 3. | ||
Item 4. | ||
Item 1. | ||
Item 1A. | ||
Item 4. | ||
Item 6. | ||
ATSI | American Transmission Service, Inc. | |
CAA | Clean Air Act | |
CAISO | The California Independent System Operator | |
CDD | Cooling Degree Days | |
COMED | Commonwealth Edison | |
CT | Combustion Turbine | |
EBITDA | Earnings Before Interest, Taxes, Depreciation and Amortization | |
EMAAC | Eastern Mid-Atlantic Area Council | |
EPA | Environmental Protection Agency | |
ERCOT | Electric Reliability Council of Texas | |
FCA | Forward Capacity Auction | |
FERC | Federal Energy Regulatory Commission | |
FTR | Financial Transmission Rights | |
HDD | Heating Degree Days | |
IMA | In-market Asset Availability | |
IPH | IPH, LLC | |
ISO | Independent System Operator | |
ISO-NE | Independent System Operator New England | |
kW | Kilowatt | |
LIBOR | London Interbank Offered Rate | |
MAAC | Mid-Atlantic Area Council | |
MISO | Midcontinent Independent System Operator, Inc. | |
MMBtu | One Million British Thermal Units | |
Moody’s | Moody’s Investors Service Inc. | |
MW | Megawatts | |
MWh | Megawatt Hour | |
NYISO | New York Independent System Operator | |
PJM | PJM Interconnection, LLC | |
PPE | Ponderosa Pine Energy, LLC | |
PPL | PPL Electric Utilities, Corp. | |
PRIDE | Producing Results through Innovation by Dynegy Employees | |
RGGI | Regional Greenhouse Gas Initiative | |
RTO | Regional Transmission Organization | |
S&P | Standard & Poor’s Ratings Services | |
SEC | U.S. Securities and Exchange Commission |
September 30, 2017 | December 31, 2016 | |||||||
ASSETS | ||||||||
Current Assets | ||||||||
Cash and cash equivalents | $ | 613 | $ | 1,776 | ||||
Restricted cash | — | 62 | ||||||
Accounts receivable, net of allowance for doubtful accounts of $1 and $1, respectively | 478 | 386 | ||||||
Inventory | 429 | 445 | ||||||
Assets from risk management activities | 50 | 130 | ||||||
Intangible assets | 24 | 38 | ||||||
Prepayments and other current assets | 110 | 150 | ||||||
Total Current Assets | 1,704 | 2,987 | ||||||
Property, plant and equipment, net | 8,929 | 7,121 | ||||||
Investment in unconsolidated affiliate | 154 | — | ||||||
Restricted cash | — | 2,000 | ||||||
Assets from risk management activities | 49 | 16 | ||||||
Goodwill | 772 | 799 | ||||||
Intangible assets | 49 | 23 | ||||||
Assets held-for-sale | 181 | — | ||||||
Other long-term assets | 169 | 107 | ||||||
Total Assets | $ | 12,007 | $ | 13,053 |
September 30, 2017 | December 31, 2016 | |||||||
LIABILITIES AND EQUITY | ||||||||
Current Liabilities | ||||||||
Accounts payable | $ | 288 | $ | 332 | ||||
Accrued interest | 154 | 81 | ||||||
Intangible liabilities | 18 | 21 | ||||||
Accrued taxes | 57 | 45 | ||||||
Accrued liabilities and other current liabilities | 136 | 88 | ||||||
Liabilities from risk management activities | 58 | 97 | ||||||
Asset retirement obligations | 57 | 51 | ||||||
Debt, current portion, net | 99 | 201 | ||||||
Total Current Liabilities | 867 | 916 | ||||||
Liabilities subject to compromise (Note 18) | — | 832 | ||||||
Debt, long-term portion, net | 8,648 | 8,778 | ||||||
Liabilities from risk management activities | 20 | 43 | ||||||
Asset retirement obligations | 268 | 236 | ||||||
Deferred income taxes | 18 | 5 | ||||||
Intangible liabilities | 36 | 34 | ||||||
Other long-term liabilities | 166 | 170 | ||||||
Total Liabilities | 10,023 | 11,014 | ||||||
Commitments and Contingencies (Note 13) | ||||||||
Stockholders’ Equity | ||||||||
Preferred stock, $0.01 par value, 20,000,000 shares authorized: | ||||||||
Series A 5.375% mandatory convertible preferred stock, $0.01 par value; 4,000,000 shares issued and outstanding, respectively | 400 | 400 | ||||||
Common stock, $0.01 par value, 420,000,000 shares authorized; 142,699,979 shares issued and 131,373,857 shares outstanding at September 30, 2017; 128,626,740 shares issued and 117,300,618 outstanding at December 31, 2016 | 1 | 1 | ||||||
Additional paid-in capital | 3,320 | 3,547 | ||||||
Accumulated other comprehensive income, net of tax | 26 | 21 | ||||||
Accumulated deficit | (1,758 | ) | (1,927 | ) | ||||
Total Dynegy Stockholders’ Equity | 1,989 | 2,042 | ||||||
Noncontrolling interest | (5 | ) | (3 | ) | ||||
Total Equity | 1,984 | 2,039 | ||||||
Total Liabilities and Equity | $ | 12,007 | $ | 13,053 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Revenues | $ | 1,437 | $ | 1,184 | $ | 3,848 | $ | 3,211 | ||||||||
Cost of sales, excluding depreciation expense | (787 | ) | (660 | ) | (2,225 | ) | (1,698 | ) | ||||||||
Gross margin | 650 | 524 | 1,623 | 1,513 | ||||||||||||
Operating and maintenance expense | (236 | ) | (218 | ) | (750 | ) | (695 | ) | ||||||||
Depreciation expense | (202 | ) | (163 | ) | (611 | ) | (494 | ) | ||||||||
Impairments | (29 | ) | (212 | ) | (148 | ) | (857 | ) | ||||||||
Loss on sale of assets, net | (78 | ) | — | (107 | ) | — | ||||||||||
General and administrative expense | (44 | ) | (41 | ) | (126 | ) | (117 | ) | ||||||||
Acquisition and integration costs | (3 | ) | (7 | ) | (55 | ) | (8 | ) | ||||||||
Other | — | — | 1 | (16 | ) | |||||||||||
Operating income (loss) | 58 | (117 | ) | (173 | ) | (674 | ) | |||||||||
Bankruptcy reorganization items (Note 18) | 12 | — | 494 | — | ||||||||||||
Earnings from unconsolidated investments | 4 | 4 | 4 | 7 | ||||||||||||
Interest expense | (161 | ) | (166 | ) | (478 | ) | (449 | ) | ||||||||
Loss on early extinguishment of debt (Note 12) | (66 | ) | — | (75 | ) | — | ||||||||||
Other income and expense, net | 19 | 29 | 65 | 60 | ||||||||||||
Loss before income taxes | (134 | ) | (250 | ) | (163 | ) | (1,056 | ) | ||||||||
Income tax benefit (expense) (Note 14) | 1 | 1 | 330 | (6 | ) | |||||||||||
Net income (loss) | (133 | ) | (249 | ) | 167 | (1,062 | ) | |||||||||
Less: Net loss attributable to noncontrolling interest | (1 | ) | — | (2 | ) | (2 | ) | |||||||||
Net income (loss) attributable to Dynegy Inc. | (132 | ) | (249 | ) | 169 | (1,060 | ) | |||||||||
Less: Dividends on preferred stock | 5 | 5 | 16 | 16 | ||||||||||||
Net income (loss) attributable to Dynegy Inc. common stockholders | $ | (137 | ) | $ | (254 | ) | $ | 153 | $ | (1,076 | ) | |||||
Earnings (Loss) Per Share (Note 16): | ||||||||||||||||
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders | $ | (0.89 | ) | $ | (1.81 | ) | $ | 1.01 | $ | (8.54 | ) | |||||
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders | $ | (0.89 | ) | $ | (1.81 | ) | $ | 0.96 | $ | (8.54 | ) | |||||
Basic shares outstanding | 154 | 140 | 152 | 126 | ||||||||||||
Diluted shares outstanding | 154 | 140 | 159 | 126 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
Net income (loss) | $ | (133 | ) | $ | (249 | ) | $ | 167 | $ | (1,062 | ) | |||||
Other comprehensive income before reclassifications: | ||||||||||||||||
Actuarial gain and plan amendment (net of tax of zero, zero, $4, and zero for each respective period) | — | — | 11 | — | ||||||||||||
Amounts reclassified from accumulated other comprehensive income: | ||||||||||||||||
Amortization of unrecognized prior service credit (net of tax of zero for each respective period) | (2 | ) | (2 | ) | (6 | ) | (4 | ) | ||||||||
Other comprehensive income (loss), net of tax | (2 | ) | (2 | ) | 5 | (4 | ) | |||||||||
Comprehensive income (loss) | (135 | ) | (251 | ) | 172 | (1,066 | ) | |||||||||
Less: Comprehensive loss attributable to noncontrolling interest | (1 | ) | — | (2 | ) | (2 | ) | |||||||||
Total comprehensive income (loss) attributable to Dynegy Inc. | $ | (134 | ) | $ | (251 | ) | $ | 174 | $ | (1,064 | ) |
Nine Months Ended September 30, | ||||||||
2017 | 2016 | |||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||
Net income (loss) | $ | 167 | $ | (1,062 | ) | |||
Adjustments to reconcile net income (loss) to net cash flows from operating activities: | ||||||||
Depreciation expense | 611 | 494 | ||||||
Non-cash interest expense | 36 | 37 | ||||||
Amortization of intangibles | 13 | 17 | ||||||
Risk management activities | (38 | ) | (75 | ) | ||||
Loss on sale of assets, net | 107 | — | ||||||
Loss on early extinguishment of debt | 75 | — | ||||||
Earnings from unconsolidated investments | (4 | ) | (7 | ) | ||||
Deferred income taxes | (330 | ) | 6 | |||||
Impairments | 148 | 857 | ||||||
Change in value of common stock warrants | (16 | ) | (5 | ) | ||||
Bankruptcy reorganization items | (494 | ) | — | |||||
Other | 50 | 1 | ||||||
Changes in working capital: | ||||||||
Accounts receivable, net | (20 | ) | 32 | |||||
Inventory | 106 | 153 | ||||||
Prepayments and other current assets | 81 | 179 | ||||||
Accounts payable and accrued liabilities | 9 | 104 | ||||||
Distributions from unconsolidated investments | 2 | 1 | ||||||
Changes in non-current assets | (2 | ) | (16 | ) | ||||
Changes in non-current liabilities | — | 12 | ||||||
Net cash provided by operating activities | 501 | 728 | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||
Capital expenditures | (129 | ) | (337 | ) | ||||
Acquisitions, net of cash acquired | (3,249 | ) | — | |||||
Distributions from unconsolidated investments | 7 | 14 | ||||||
Proceeds received from asset sales, net | 600 | — | ||||||
Other investing | — | 10 | ||||||
Net cash used in investing activities | (2,771 | ) | (313 | ) | ||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||
Proceeds from long-term borrowings, net of debt issuance costs | 1,747 | 2,277 | ||||||
Repayments of borrowings | (2,261 | ) | (21 | ) | ||||
Proceeds from issuance of equity, net of issuance costs | 150 | 359 | ||||||
Payments of debt extinguishment costs | (50 | ) | — | |||||
Preferred stock dividends paid | (16 | ) | (16 | ) | ||||
Interest rate swap settlement payments | (15 | ) | (13 | ) | ||||
Acquisition of noncontrolling interest | (375 | ) | — | |||||
Payments related to bankruptcy settlement | (133 | ) | — | |||||
Other financing | (2 | ) | (2 | ) | ||||
Net cash provided by (used in) financing activities | (955 | ) | 2,584 | |||||
Net increase (decrease) in cash, cash equivalents and restricted cash | (3,225 | ) | 2,999 | |||||
Cash, cash equivalents and restricted cash, beginning of period | 3,838 | 544 | ||||||
Cash, cash equivalents and restricted cash, end of period | $ | 613 | $ | 3,543 |
• | Working capital was valued using available market information (Level 2). |
• | Acquired property, plant and equipment (“PP&E”), excluding those assets classified as held-for-sale, was valued using a discounted cash flow (“DCF”) analysis based upon a debt-free, free cash flow model (Level 3). The DCF model was created for each power generation facility based on its remaining useful life, and: |
◦ | for the years 2017 and 2018, included gross margin forecasts using quoted forward commodity market prices; |
◦ | for the years 2019 through 2026, we used gross margin forecasts based upon commodity and capacity price curves developed internally using forward New York Mercantile Exchange natural gas prices and supply and demand factors; |
◦ | for periods beyond 2026, we assumed a 2.5 percent growth rate. |
• | Acquired PP&E classified as held-for-sale was valued based upon the sale price of the assets (Level 3). |
• | Acquired derivatives were valued using the methods described in Note 6—Fair Value Measurements (Level 2 or Level 3). |
• | Contracts with terms that were not at current market prices were also valued using a DCF analysis (Level 3). The cash flows generated by the contracts were compared with their cash flows based on current market prices with the resulting difference recorded as either an intangible asset or liability. |
• | Asset retirement obligations (“AROs”) were recorded in accordance with ASC 410, Asset Retirement and Environmental Obligations (Level 3). |
(amounts in millions) | ||||
Base purchase price | $ | 3,300 | ||
Working capital adjustments and other | (31 | ) | ||
Fair value of total consideration transferred | $ | 3,269 | ||
Cash | $ | 20 | ||
Accounts receivable | 22 | |||
Inventory | 101 | |||
Prepayments and other current assets | 3 | |||
Assets from risk management activities (including current portion of $21 million) | 25 | |||
Property, plant and equipment | 2,716 | |||
Investment in unconsolidated affiliate | 159 | |||
Intangible assets (including current portion of $7 million) | 50 | |||
Assets held-for-sale | 478 | |||
Other long-term assets | 131 | |||
Total assets acquired | 3,705 | |||
Accounts payable | 28 | |||
Liabilities from risk management activities (including current portion of $13 million) | 16 | |||
Asset retirement obligations | 19 | |||
Intangible liabilities (including current portion of $16 million) | 30 | |||
Deferred income taxes, net | 342 | |||
Other long-term liabilities | 1 | |||
Total liabilities assumed | 436 | |||
Net assets acquired | $ | 3,269 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(amounts in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Acquisition costs | $ | — | $ | 3 | $ | 35 | $ | 5 | ||||||||
Revenues | $ | 345 | N/A | $ | 669 | N/A | ||||||||||
Operating loss | $ | (36 | ) | N/A | $ | (32 | ) | N/A |
Nine Months Ended September 30, | ||||||||
(amounts in millions) | 2017 | 2016 | ||||||
Revenue | $ | 3,905 | $ | 3,942 | ||||
Net income (loss) | $ | 169 | $ | (1,090 | ) | |||
Net income (loss) attributable to Dynegy Inc. | $ | 171 | $ | (1,088 | ) |
Contract Type | Quantity | Unit of Measure | Fair Value (1) | ||||||
(dollars and quantities in millions) | Purchases (Sales) | Asset (Liability) | |||||||
Commodity contracts: | |||||||||
Electricity derivatives (2) | (60 | ) | MWh | $ | 14 | ||||
Electricity basis derivatives (3) | (34 | ) | MWh | $ | (7 | ) | |||
Natural gas derivatives (2) | 380 | MMBtu | $ | (1 | ) | ||||
Natural gas basis derivatives | 108 | MMBtu | $ | (14 | ) | ||||
Physical heat rate derivatives | 125/(13) | MMBtu/MWh | $ | 14 | |||||
Emissions derivatives | 17 | Metric Ton | $ | 4 | |||||
Interest rate swaps | 1,963 | U.S. Dollar | $ | (11 | ) | ||||
Common stock warrants (4) | 25 | Warrant | $ | (2 | ) |
(1) | Includes both asset and liability risk management positions but excludes margin and collateral netting of $22 million. |
(2) | Mainly comprised of swaps and physical forwards. |
(3) | Comprised of FTRs and swaps. |
(4) | Each warrant is convertible into one share of Dynegy common stock. |
September 30, 2017 | |||||||||||||||||||
Gross amounts offset in the balance sheet | |||||||||||||||||||
Contract Type | Balance Sheet Location | Gross Fair Value | Contract Netting | Collateral or Margin Received or Paid | Net Fair Value | ||||||||||||||
(amounts in millions) | |||||||||||||||||||
Derivative assets: | |||||||||||||||||||
Commodity contracts | Assets from risk management activities | $ | 204 | $ | (117 | ) | $ | — | $ | 87 | |||||||||
Interest rate contracts | Assets from risk management activities | 12 | — | — | 12 | ||||||||||||||
Total derivative assets | $ | 216 | $ | (117 | ) | $ | — | $ | 99 | ||||||||||
Derivative liabilities: | |||||||||||||||||||
Commodity contracts | Liabilities from risk management activities | $ | (194 | ) | $ | 117 | $ | 22 | $ | (55 | ) | ||||||||
Interest rate contracts | Liabilities from risk management activities | (23 | ) | — | — | (23 | ) | ||||||||||||
Common stock warrants | Accrued liabilities and other current liabilities and other long-term liabilities | (2 | ) | — | — | (2 | ) | ||||||||||||
Total derivative liabilities | $ | (219 | ) | $ | 117 | $ | 22 | $ | (80 | ) | |||||||||
Total derivatives | $ | (3 | ) | $ | — | $ | 22 | $ | 19 |
December 31, 2016 | |||||||||||||||||||
Gross amounts offset in the balance sheet | |||||||||||||||||||
Contract Type | Balance Sheet Location | Gross Fair Value | Contract Netting | Collateral or Margin Received or Paid | Net Fair Value | ||||||||||||||
(amounts in millions) | |||||||||||||||||||
Derivative assets: | |||||||||||||||||||
Commodity contracts | Assets from risk management activities | $ | 311 | $ | (165 | ) | $ | — | $ | 146 | |||||||||
Total derivative assets | $ | 311 | $ | (165 | ) | $ | — | $ | 146 | ||||||||||
Derivative liabilities: | |||||||||||||||||||
Commodity contracts | Liabilities from risk management activities | $ | (329 | ) | $ | 165 | $ | 54 | $ | (110 | ) | ||||||||
Interest rate contracts | Liabilities from risk management activities | (30 | ) | — | — | (30 | ) | ||||||||||||
Common stock warrants | Accrued liabilities and other current liabilities | (1 | ) | — | — | (1 | ) | ||||||||||||
Total derivative liabilities | $ | (360 | ) | $ | 165 | $ | 54 | $ | (141 | ) | |||||||||
Total derivatives | $ | (49 | ) | $ | — | $ | 54 | $ | 5 |
Location on Balance Sheet | September 30, 2017 | December 31, 2016 | ||||||
(amounts in millions) | ||||||||
Gross collateral posted with counterparties | $ | 54 | $ | 116 | ||||
Less: Collateral netted against risk management liabilities | 22 | 54 | ||||||
Net collateral within Prepayments and other current assets | $ | 32 | $ | 62 |
Derivatives Not Designated as Hedges | Location of Gain (Loss) Recognized in Income on Derivatives | Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||||
(amounts in millions) | ||||||||||||||||||
Commodity contracts | Revenues | $ | 29 | $ | (27 | ) | $ | 242 | $ | 188 | ||||||||
Interest rate contracts | Interest expense | $ | 1 | $ | 1 | $ | 4 | $ | (11 | ) | ||||||||
Common stock warrants | Other income and (expense), net | $ | 1 | $ | 4 | $ | 16 | $ | 5 |
Fair Value as of September 30, 2017 | ||||||||||||||||
(amounts in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: | ||||||||||||||||
Assets from commodity risk management activities: | ||||||||||||||||
Electricity derivatives | $ | — | $ | 100 | $ | 21 | $ | 121 | ||||||||
Natural gas derivatives | — | 45 | 6 | 51 | ||||||||||||
Physical heat rate derivatives | — | 20 | 1 | 21 | ||||||||||||
Emissions derivatives | — | 11 | — | 11 | ||||||||||||
Total assets from commodity risk management activities | — | 176 | 28 | 204 | ||||||||||||
Assets from interest rate contracts | — | 12 | — | 12 | ||||||||||||
Total assets | $ | — | $ | 188 | $ | 28 | $ | 216 | ||||||||
Liabilities: | ||||||||||||||||
Liabilities from commodity risk management activities: | ||||||||||||||||
Electricity derivatives | $ | — | $ | (94 | ) | $ | (20 | ) | $ | (114 | ) | |||||
Natural gas derivatives | — | (60 | ) | (6 | ) | (66 | ) | |||||||||
Physical heat rate derivatives | — | (7 | ) | — | (7 | ) | ||||||||||
Emissions derivatives | — | (7 | ) | — | (7 | ) | ||||||||||
Total liabilities from commodity risk management activities | — | (168 | ) | (26 | ) | (194 | ) | |||||||||
Liabilities from interest rate contracts | — | (23 | ) | — | (23 | ) | ||||||||||
Liabilities from outstanding common stock warrants | (2 | ) | — | — | (2 | ) | ||||||||||
Total liabilities | $ | (2 | ) | $ | (191 | ) | $ | (26 | ) | $ | (219 | ) |
Fair Value as of December 31, 2016 | ||||||||||||||||
(amounts in millions) | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
Assets: | ||||||||||||||||
Assets from commodity risk management activities: | ||||||||||||||||
Electricity derivatives | $ | — | $ | 118 | $ | 20 | $ | 138 | ||||||||
Natural gas derivatives | — | 169 | 4 | 173 | ||||||||||||
Total assets from commodity risk management activities | $ | — | $ | 287 | $ | 24 | $ | 311 | ||||||||
Liabilities: | ||||||||||||||||
Liabilities from commodity risk management activities: | ||||||||||||||||
Electricity derivatives | $ | — | $ | (245 | ) | $ | (12 | ) | $ | (257 | ) | |||||
Natural gas derivatives | — | (52 | ) | (10 | ) | (62 | ) | |||||||||
Emissions derivatives | — | (10 | ) | — | (10 | ) | ||||||||||
Total liabilities from commodity risk management activities | — | (307 | ) | (22 | ) | (329 | ) | |||||||||
Liabilities from interest rate contracts | — | (30 | ) | — | (30 | ) | ||||||||||
Liabilities from outstanding common stock warrants | (1 | ) | — | — | (1 | ) | ||||||||||
Total liabilities | $ | (1 | ) | $ | (337 | ) | $ | (22 | ) | $ | (360 | ) |
Transaction Type | Quantity | Unit of Measure | Net Fair Value | Valuation Technique | Significant Unobservable Input | Significant Unobservable Input Range | |||||||||
(dollars in millions) | |||||||||||||||
Electricity derivatives: | |||||||||||||||
Forward contracts—power (1) | (14 | ) | Million MWh | $ | 4 | Basis spread + liquid location | Basis spread | $4.25 - $6.25 | |||||||
FTRs | (29 | ) | Million MWh | $ | (3 | ) | Historical congestion | Forward price | $0 - $6.00 | ||||||
Physical heat rate derivatives | 23/(3) | Million MMBtu/Million MWh | $ | 1 | Discounted Cash Flow | Forward price | $2.40 - $3.30 / $20 - $24 | ||||||||
Natural gas derivatives (1) | 102 | Million MMBtu | $ | — | Illiquid location fixed price | Forward price | $1.75 - $2.15 |
(1) | Represents forward financial and physical transactions at illiquid pricing locations and long-dated contracts. |
Three Months Ended September 30, 2017 | ||||||||||||||||
(amounts in millions) | Electricity Derivatives | Natural Gas Derivatives | Heat Rate Derivatives | Total | ||||||||||||
Balance at June 30, 2017 | $ | (1 | ) | $ | 1 | $ | (2 | ) | $ | (2 | ) | |||||
Total gains (losses) included in earnings | 6 | (1 | ) | 3 | 8 | |||||||||||
Transfers out of level 3 (1) | (2 | ) | — | — | (2 | ) | ||||||||||
Settlements (2) | (2 | ) | — | — | (2 | ) | ||||||||||
Balance at September 30, 2017 | $ | 1 | $ | — | $ | 1 | $ | 2 | ||||||||
Unrealized gains (losses) relating to instruments held as of September 30, 2017 | $ | 6 | $ | (1 | ) | $ | 3 | $ | 8 |
Nine Months Ended September 30, 2017 | ||||||||||||||||
(amounts in millions) | Electricity Derivatives | Natural Gas Derivatives | Heat Rate Derivatives | Total | ||||||||||||
Balance at December 31, 2016 | $ | 8 | $ | (6 | ) | $ | — | $ | 2 | |||||||
Acquired derivatives | 1 | — | — | 1 | ||||||||||||
Total gains (losses) included in earnings | (16 | ) | 10 | 1 | (5 | ) | ||||||||||
Settlements (2) | 8 | (4 | ) | — | 4 | |||||||||||
Balance at September 30, 2017 | $ | 1 | $ | — | $ | 1 | $ | 2 | ||||||||
Unrealized gains (losses) relating to instruments held as of September 30, 2017 | $ | (16 | ) | $ | 10 | $ | 1 | $ | (5 | ) |
Three Months Ended September 30, 2016 | ||||||||||||||||
(amounts in millions) | Electricity Derivatives | Natural Gas Derivatives | Coal Derivatives | Total | ||||||||||||
Balance at June 30, 2016 | $ | (24 | ) | $ | (15 | ) | $ | 1 | $ | (38 | ) | |||||
Total gains (losses) included in earnings | 9 | (4 | ) | 1 | 6 | |||||||||||
Settlements (2) | 5 | 5 | (1 | ) | 9 | |||||||||||
Balance at September 30, 2016 | $ | (10 | ) | $ | (14 | ) | $ | 1 | $ | (23 | ) | |||||
Unrealized gains (losses) relating to instruments held as of September 30, 2016 | $ | 9 | $ | (4 | ) | $ | 1 | $ | 6 |
Nine Months Ended September 30, 2016 | ||||||||||||||||
(amounts in millions) | Electricity Derivatives | Natural Gas Derivatives | Coal Derivatives | Total | ||||||||||||
Balance at December 31, 2015 | $ | (18 | ) | $ | (32 | ) | $ | 2 | $ | (48 | ) | |||||
Total gains included in earnings | 4 | — | — | 4 | ||||||||||||
Settlements (2) | 4 | 18 | (1 | ) | 21 | |||||||||||
Balance at September 30, 2016 | $ | (10 | ) | $ | (14 | ) | $ | 1 | $ | (23 | ) | |||||
Unrealized gains relating to instruments held as of September 30, 2016 | $ | 4 | $ | — | $ | — | $ | 4 |
(1) | During the three months ended September 30, 2017, we had transfers from Level 3 to Level 2 due to changes in market liquidity. |
(2) | For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period. |
September 30, 2017 | December 31, 2016 | |||||||||||||||||
(amounts in millions) | Fair Value Hierarchy | Carrying Amount | Fair Value | Carrying Amount | Fair Value | |||||||||||||
Dynegy Inc.: | ||||||||||||||||||
Tranche C-1 Term Loan, due 2024 (1) | Level 2 | $ | (1,940 | ) | $ | (2,029 | ) | $ | (1,994 | ) | $ | (2,025 | ) | |||||
Tranche B-2 Term Loan, due 2020 (1) | Level 2 | $ | — | $ | — | $ | (219 | ) | $ | (225 | ) | |||||||
Revolving Facility (1) | Level 2 | $ | (300 | ) | $ | (300 | ) | $ | — | $ | — | |||||||
6.75% Senior Notes, due 2019 (1) | Level 2 | $ | (845 | ) | $ | (881 | ) | $ | (2,083 | ) | $ | (2,137 | ) | |||||
7.375% Senior Notes, due 2022 (1) | Level 2 | $ | (1,733 | ) | $ | (1,824 | ) | $ | (1,731 | ) | $ | (1,665 | ) | |||||
5.875% Senior Notes, due 2023 (1) | Level 2 | $ | (493 | ) | $ | (498 | ) | $ | (492 | ) | $ | (431 | ) | |||||
7.625% Senior Notes, due 2024 (1) | Level 2 | $ | (1,237 | ) | $ | (1,294 | ) | $ | (1,237 | ) | $ | (1,156 | ) | |||||
8.034% Senior Notes, due 2024 (1) | Level 2 | $ | (188 | ) | $ | (190 | ) | $ | — | $ | — | |||||||
8.00% Senior Notes, due 2025 (1) | Level 2 | $ | (739 | ) | $ | (778 | ) | $ | (738 | ) | $ | (703 | ) | |||||
8.125% Senior Notes, due 2026 (1) | Level 2 | $ | (842 | ) | $ | (880 | ) | $ | — | $ | — | |||||||
7.00% Amortizing Notes, due 2019 (TEUs) (1) | Level 2 | $ | (58 | ) | $ | (62 | ) | $ | (78 | ) | $ | (90 | ) | |||||
Forward capacity agreement (1) | Level 3 | $ | (212 | ) | $ | (212 | ) | $ | (205 | ) | $ | (205 | ) | |||||
Inventory financing agreements | Level 3 | $ | (48 | ) | $ | (48 | ) | $ | (129 | ) | $ | (127 | ) | |||||
Equipment financing agreements (1) | Level 3 | $ | (112 | ) | $ | (112 | ) | $ | (73 | ) | $ | (73 | ) | |||||
Genco: | ||||||||||||||||||
Liabilities subject to compromise (2) | Level 3 | $ | — | $ | — | $ | (825 | ) | $ | (366 | ) |
(1) | Carrying amounts include unamortized discounts and debt issuance costs. Please read Note 12—Debt for further discussion. |
(2) | Carrying amounts represent the Genco senior notes that were classified as liabilities subject to compromise as of December 31, 2016. The fair value of the senior notes was equal to the Genco Plan consideration and is a Level 3 valuation due to a lack of observable inputs that make up the consideration. Please read Note 22—Genco Chapter 11 Bankruptcy in our Form 10-K for further details. |
Nine Months Ended September 30, | ||||||||
(amounts in millions) | 2017 | 2016 | ||||||
Change in capital expenditures included in accounts payable | $ | 5 | $ | (10 | ) | |||
Change in capital expenditures pursuant to an equipment financing agreement | $ | 34 | $ | 11 | ||||
Issuance of 2017 Warrants | $ | 17 | $ | — | ||||
Issuance of senior notes related to the Genco restructuring | $ | 188 | $ | — | ||||
Sale of interest in Conesville facility | $ | (58 | ) | $ | — | |||
Acquisition of interest in Zimmer facility | $ | 27 | $ | — |
(amounts in millions) | September 30, 2017 | September 30, 2016 | ||||||
Cash and cash equivalents | $ | 613 | $ | 1,458 | ||||
Restricted cash included in current assets (1) | — | 85 | ||||||
Restricted cash included in long-term assets (2) | — | 2,000 | ||||||
Total cash, cash equivalents and restricted cash | $ | 613 | $ | 3,543 |
(1) | Includes $45 million placed in escrow for the issuance of the Tranche C Term Loan ($25 million of pre-funded interest and interest income earned and $20 million of pre-funded original issue discount) and $40 million related to collateral. |
(2) | Relates to amounts placed into escrow for the issuance of the Tranche C Term Loan. |
(amounts in millions) | September 30, 2017 | December 31, 2016 | ||||||
Materials and supplies | $ | 236 | $ | 182 | ||||
Coal | 165 | 238 | ||||||
Fuel oil | 14 | 17 | ||||||
Natural gas | 12 | — | ||||||
Emissions allowances (1) | 2 | 8 | ||||||
Total | $ | 429 | $ | 445 |
(1) | At September 30, 2017 and December 31, 2016, a portion of this inventory was held as collateral by one of our counterparties as part of an inventory financing agreement. Please read Note 12—Debt—Emissions Repurchase Agreements for further discussion. |
(amounts in millions) | September 30, 2017 | December 31, 2016 | ||||||
Power generation | $ | 9,845 | $ | 7,537 | ||||
Buildings and improvements | 958 | 944 | ||||||
Office and other equipment | 115 | 98 | ||||||
Property, plant and equipment | 10,918 | 8,579 | ||||||
Accumulated depreciation | (1,989 | ) | (1,458 | ) | ||||
Property, plant and equipment, net | $ | 8,929 | $ | 7,121 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||
Facility | Fair Value | 2017 | 2016 | 2017 | 2016 | |||||||||||||||
Baldwin (1) | $ | 97 | — | — | — | 645 | ||||||||||||||
Stuart (2) | $ | — | — | 55 | — | 55 | ||||||||||||||
Newton FGD (3) | $ | — | — | 148 | — | 148 | ||||||||||||||
Killen (4) | $ | — | — | — | 20 | — | ||||||||||||||
Hennepin (1) | $ | 16 | — | — | 10 | — | ||||||||||||||
Havana (1) | $ | 37 | — | — | 89 | — | ||||||||||||||
Total (5) | $ | — | $ | 203 | $ | 119 | $ | 848 |
(1) | Units failed to recover their basic operating costs in the MISO capacity auctions. The impairment was measured using a DCF model. |
(2) | We determined that the facility would experience recurring negative cash flows due to on-going required maintenance and environmental capital expenditures, combined with consistently poor reliability. The impairment was measured using a DCF model. |
(3) | We terminated the flue gas desulfurization (“FGD”) systems construction project at our Newton generation facility. The capitalized cost of the project was used to determine the impairment amount. |
(4) | In first quarter 2017, Dayton Power and Light Co., the partner and operator of Killen, announced the shutdown of the Killen generation facility by June 2018. The impairment charge was equal to the book value. |
(5) | Excludes impairments related to Goodwill and Materials and supplies inventory. |
September 30, 2017 | |||||||||||||||||||
(dollars in millions) | Ownership Interest | Property, Plant and Equipment | Accumulated Depreciation | Construction Work in Progress | Total | ||||||||||||||
Miami Fort | 64.0 | % | $ | 208 | $ | (55 | ) | $ | 4 | $ | 157 | ||||||||
Stuart (1)(2) | 39.0 | % | $ | — | $ | — | $ | 1 | $ | 1 | |||||||||
Zimmer | 71.9 | % | $ | 131 | $ | (37 | ) | $ | 8 | $ | 102 | ||||||||
Killen (1)(2) | 33.0 | % | $ | — | $ | — | $ | — | $ | — |
December 31, 2016 | |||||||||||||||||||
(dollars in millions) | Ownership Interest | Property, Plant and Equipment | Accumulated Depreciation | Construction Work in Progress | Total | ||||||||||||||
Miami Fort | 64.0 | % | $ | 207 | $ | (39 | ) | $ | 4 | $ | 172 | ||||||||
Stuart (1) | 39.0 | % | $ | — | $ | — | $ | 4 | $ | 4 | |||||||||
Conesville (1) | 40.0 | % | $ | 61 | $ | (3 | ) | $ | 6 | $ | 64 | ||||||||
Zimmer | 46.5 | % | $ | 115 | $ | (25 | ) | $ | 6 | $ | 96 | ||||||||
Killen (1) | 33.0 | % | $ | 19 | $ | (2 | ) | $ | 3 | $ | 20 |
(1) | Facilities not operated by Dynegy. |
(2) | Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. |
September 30, 2017 | December 31, 2016 | |||||||||||||||||||||||
(amounts in millions) | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | Gross Carrying Amount | Accumulated Amortization | Net Carrying Amount | ||||||||||||||||||
Intangible Assets: | ||||||||||||||||||||||||
Electricity contracts | $ | 230 | $ | (176 | ) | $ | 54 | $ | 260 | $ | (206 | ) | $ | 54 | ||||||||||
Gas transport contracts | 30 | (11 | ) | 19 | 13 | (6 | ) | 7 | ||||||||||||||||
Total intangible assets | $ | 260 | $ | (187 | ) | $ | 73 | $ | 273 | $ | (212 | ) | $ | 61 | ||||||||||
Intangible Liabilities: | ||||||||||||||||||||||||
Electricity contracts | $ | (19 | ) | $ | 17 | $ | (2 | ) | $ | (28 | ) | $ | 26 | $ | (2 | ) | ||||||||
Coal contracts | (32 | ) | 32 | — | (49 | ) | 42 | (7 | ) | |||||||||||||||
Coal transport contracts | (84 | ) | 78 | (6 | ) | (86 | ) | 73 | (13 | ) | ||||||||||||||
Gas transport contracts | (58 | ) | 13 | (45 | ) | (41 | ) | 8 | (33 | ) | ||||||||||||||
Gas storage contracts | (2 | ) | 1 | (1 | ) | — | — | — | ||||||||||||||||
Total intangible liabilities | $ | (195 | ) | $ | 141 | $ | (54 | ) | $ | (204 | ) | $ | 149 | $ | (55 | ) | ||||||||
Intangible assets and liabilities, net | $ | 65 | $ | (46 | ) | $ | 19 | $ | 69 | $ | (63 | ) | $ | 6 |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(amounts in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Electricity contracts, net (1) | $ | 5 | $ | 19 | $ | 29 | $ | 52 | ||||||||
Coal contracts, net (2) | (1 | ) | (9 | ) | (4 | ) | (32 | ) | ||||||||
Coal transport contracts, net (2) | (2 | ) | (7 | ) | (7 | ) | (21 | ) | ||||||||
Gas transport contracts, net (2) | (3 | ) | 1 | (4 | ) | 18 | ||||||||||
Gas storage contracts, net (2) | — | — | (1 | ) | — | |||||||||||
Total | $ | (1 | ) | $ | 4 | $ | 13 | $ | 17 |
(1) | The amortization of these contracts is recognized in Revenues or Cost of sales in our unaudited consolidated statements of operations. |
(2) | The amortization of these contracts is recognized in Cost of sales in our unaudited consolidated statements of operations. |
(amounts in millions/months) | Gross Carrying Amount | Weighted-Average Amortization Period | ||||
Intangible Assets: | ||||||
Electricity contracts | $ | 34 | 39 | |||
Gas transport contracts | 16 | 47 | ||||
Total intangible assets | $ | 50 | 41 | |||
Intangible Liabilities: | ||||||
Electricity contracts | $ | (11 | ) | 32 | ||
Gas contracts | — | 1 | ||||
Gas transport contracts | (17 | ) | 35 | |||
Gas storage contracts | (2 | ) | 13 | |||
Total intangible liabilities | $ | (30 | ) | 33 | ||
Total intangible assets and liabilities, net | $ | 20 |
(amounts in millions) | September 30, 2017 | December 31, 2016 | ||||||
Secured Obligations: | ||||||||
Tranche C-1 Term Loan, due 2024 (1) | $ | 2,018 | $ | 2,000 | ||||
Tranche B-2 Term Loan, due 2020 | — | 224 | ||||||
Revolving Facility | 300 | — | ||||||
Forward Capacity Agreements | 241 | 219 | ||||||
Inventory Financing Agreements | 48 | 129 | ||||||
Subtotal secured obligations | 2,607 | 2,572 | ||||||
Unsecured Obligations: | ||||||||
7.00% Amortizing Notes, due 2019 (TEUs) | 60 | 80 | ||||||
6.75% Senior Notes, due 2019 | 850 | 2,100 | ||||||
7.375% Senior Notes, due 2022 | 1,750 | 1,750 | ||||||
5.875% Senior Notes, due 2023 | 500 | 500 | ||||||
7.625% Senior Notes, due 2024 | 1,250 | 1,250 | ||||||
8.034% Senior Notes, due 2024 (2) | 188 | — | ||||||
8.00% Senior Notes, due 2025 | 750 | 750 | ||||||
8.125% Senior Notes, due 2026 | 850 | — | ||||||
Equipment Financing Agreements | 139 | 97 | ||||||
Subtotal unsecured obligations | 6,337 | 6,527 | ||||||
Total debt obligations | 8,944 | 9,099 | ||||||
Unamortized debt discounts and issuance costs | (197 | ) | (120 | ) | ||||
8,747 | 8,979 | |||||||
Less: Current maturities, including unamortized debt discounts and issuance costs, net | 99 | 201 | ||||||
Total long-term debt | $ | 8,648 | $ | 8,778 |
(1) | At December 31, 2016, the $2.0 billion Tranche C Term Loan was held by Dynegy Finance IV. Upon the close of the ENGIE Acquisition, this debt obligation became Dynegy Inc.’s secured obligation. |
(2) | See Note 18—Genco Chapter 11 Bankruptcy and Emergence for further discussion. |
• | On January 10, 2017, we amended the Credit Agreement (Fourth Amendment) to increase the revolver capacity by $45 million and to extend the maturity date on $450 million in revolver capacity to 2021, which was effective upon the ENGIE Acquisition Closing Date. |
• | On the ENGIE Acquisition Closing Date, we amended the Credit Agreement (Fifth Amendment) to (i) reduce the interest rate applicable to the Tranche C Term Loan by 75 basis points and (ii) extend the maturity to 2024 of the existing Tranche B-2 Term Loan through the exchange of the outstanding initial Tranche B-2 Term Loan for the $2.224 billion Tranche C-1 Term Loan. As a result of this exchange, we recorded a loss on early extinguishment of debt of approximately $9 million in our unaudited consolidated statements of operations in the first quarter of 2017, of which approximately $7 |
• | On August 22, 2017, we repaid $200 million of our Tranche C-1 term loan. As a result of this transaction, we recorded a loss on early extinguishment of debt of approximately $8 million in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2017, of which $6 million was related to the write-off of unamortized deferred financing costs and $2 million was related to the write-off of unamortized debt discount. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||
(amounts in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Expected refund of AMT credits previously subject to a valuation allowance | $ | 2 | $ | — | $ | 9 | $ | — | ||||||||
Release of valuation allowance for OCI transactions that impacted deferred income taxes | (1 | ) | — | 4 | — | |||||||||||
Valuation allowance release as a result of the 2017 ENGIE Acquisition and the 2016 EquiPower Acquisition | — | — | 317 | 3 | ||||||||||||
Other state taxes | — | 1 | — | (9 | ) | |||||||||||
Income tax benefit (expense) | $ | 1 | $ | 1 | $ | 330 | $ | (6 | ) |
Pension Benefits | Other Benefits | |||||||||||||||
Three Months Ended September 30, | ||||||||||||||||
(amounts in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Service cost benefits earned during period | $ | 4 | $ | 4 | $ | — | $ | — | ||||||||
Interest cost on projected benefit obligation | 5 | 5 | — | 1 | ||||||||||||
Expected return on plan assets | (6 | ) | (5 | ) | — | (1 | ) | |||||||||
Amortization of prior service credit | (1 | ) | (1 | ) | (1 | ) | (1 | ) | ||||||||
Net periodic benefit cost (gain) | $ | 2 | $ | 3 | $ | (1 | ) | $ | (1 | ) |
Pension Benefits | Other Benefits | |||||||||||||||
Nine Months Ended September 30, | ||||||||||||||||
(amounts in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||||||
Service cost benefits earned during period | $ | 13 | $ | 12 | $ | — | $ | — | ||||||||
Interest cost on projected benefit obligation | 15 | 15 | 1 | 3 | ||||||||||||
Expected return on plan assets | (19 | ) | (17 | ) | (1 | ) | (3 | ) | ||||||||
Amortization of prior service credit | (2 | ) | (1 | ) | (4 | ) | (3 | ) | ||||||||
Net periodic benefit cost (gain) | $ | 7 | $ | 9 | $ | (4 | ) | $ | (3 | ) |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
(in millions) | 2017 | 2016 | 2017 | 2016 | ||||||||
Shares outstanding at the beginning of the period (1) | 154 | 140 | 140 | 117 | ||||||||
Weighted-average shares outstanding during the period of: | ||||||||||||
Shares issued under long-term compensation plans | — | — | 1 | — | ||||||||
Shares issued under the PIPE Transaction | — | — | 11 | — | ||||||||
Prepaid stock purchase contract (TEUs) (1) | — | — | — | 9 | ||||||||
Basic weighted-average shares outstanding | 154 | 140 | 152 | 126 | ||||||||
Dilution from potentially dilutive shares (2) | — | — | 7 | — | ||||||||
Diluted weighted-average shares outstanding (3) | 154 | 140 | 159 | 126 |
(1) | The minimum settlement amount of the TEUs, or 23,092,460 shares, is considered to be outstanding since the issuance date of June 21, 2016, and is included in the computation of basic earnings (loss) per share for the three and nine months ended September 30, 2017 and 2016. Please read Note 13—Tangible Equity Units in our Form 10-K for further discussion. |
(2) | Shares included in the computation of diluted earnings per share for the nine months ended September 30, 2017 consist of: |
• | 5,425,700 additional shares upon settlement of the TEUs - which reflects the difference between the minimum settlement amount included in basic weighted-average shares outstanding and the maximum settlement amount (28,518,160 shares); and |
• | 1,279,515 additional shares attributable to restricted stock units and performance stock units. |
(3) | Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the three months ended September 30, 2017 and three and nine months ended September 30, 2016. |
Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||
(in millions of shares) | 2017 | 2016 | 2017 | 2016 | ||||||||
Stock options | 4.2 | 2.8 | 2.8 | 2.8 | ||||||||
Restricted stock units | 1.3 | 1.3 | — | 1.3 | ||||||||
Performance stock units | 1.6 | 1.2 | — | 1.2 | ||||||||
Warrants (1) | 24.6 | 15.6 | 24.6 | 15.6 | ||||||||
Series A 5.375% mandatory convertible preferred stock (2) | 12.9 | 12.9 | 12.9 | 12.9 | ||||||||
Prepaid stock purchase contract (TEUs) | 5.4 | 5.4 | — | 5.4 | ||||||||
Total | 50.0 | 39.2 | 40.3 | 39.2 |
(1) | Warrants to purchase 15,606,936 shares of our Common Stock expired on October 2, 2017. |
(2) | On November 1, 2017, our outstanding Preferred Stock was converted to approximately12.9 million shares of Common Stock. |
Nine Months Ended September 30, | ||||||||
(amounts in millions) | 2017 | 2016 | ||||||
Beginning of period | $ | 21 | $ | 19 | ||||
Other comprehensive income before reclassifications: | ||||||||
Actuarial gain and plan amendments (net of tax of $4 and zero, respectively) | 11 | — | ||||||
Amounts reclassified from accumulated other comprehensive income: | ||||||||
Amortization of unrecognized prior service credit (net of tax of zero and zero, respectively) (1) | (6 | ) | (4 | ) | ||||
Net current period other comprehensive income (loss), net of tax | 5 | (4 | ) | |||||
End of period | $ | 26 | $ | 15 |
(1) | Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost (gain). Please read Note 15—Pension and Other Post-Employment Benefit Plans for further discussion. |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Current Assets | |||||||||||||||||||
Cash and cash equivalents | $ | 354 | $ | 252 | $ | 7 | $ | — | $ | 613 | |||||||||
Accounts receivable, net | 157 | 3,990 | 12 | (3,681 | ) | 478 | |||||||||||||
Inventory | — | 388 | 41 | — | 429 | ||||||||||||||
Other current assets | 8 | 265 | 2 | (91 | ) | 184 | |||||||||||||
Total Current Assets | 519 | 4,895 | 62 | (3,772 | ) | 1,704 | |||||||||||||
Property, plant and equipment, net | — | 8,621 | 308 | — | 8,929 | ||||||||||||||
Investment in affiliates | 16,462 | — | — | (16,462 | ) | — | |||||||||||||
Investment in unconsolidated affiliates | — | 154 | — | — | 154 | ||||||||||||||
Goodwill | — | 772 | — | — | 772 | ||||||||||||||
Assets held-for-sale | — | 181 | — | — | 181 | ||||||||||||||
Other long-term assets | 17 | 214 | 36 | — | 267 | ||||||||||||||
Intercompany note receivable | 46 | — | — | (46 | ) | — | |||||||||||||
Total Assets | $ | 17,044 | $ | 14,837 | $ | 406 | $ | (20,280 | ) | $ | 12,007 | ||||||||
Current Liabilities | |||||||||||||||||||
Accounts payable | $ | 3,310 | $ | 426 | $ | 233 | $ | (3,681 | ) | $ | 288 | ||||||||
Other current liabilities | 226 | 342 | 102 | (91 | ) | 579 | |||||||||||||
Total Current Liabilities | 3,536 | 768 | 335 | (3,772 | ) | 867 | |||||||||||||
Debt, long-term portion, net | 8,347 | 268 | 33 | — | 8,648 | ||||||||||||||
Intercompany note payable | 3,042 | 46 | — | (3,088 | ) | — | |||||||||||||
Other long-term liabilities | 130 | 331 | 47 | — | 508 | ||||||||||||||
Total Liabilities | 15,055 | 1,413 | 415 | (6,860 | ) | 10,023 | |||||||||||||
Stockholders’ Equity | |||||||||||||||||||
Dynegy Stockholders’ Equity | 1,989 | 16,471 | (9 | ) | (16,462 | ) | 1,989 | ||||||||||||
Intercompany note receivable | — | (3,042 | ) | — | 3,042 | — | |||||||||||||
Total Dynegy Stockholders’ Equity | 1,989 | 13,429 | (9 | ) | (13,420 | ) | 1,989 | ||||||||||||
Noncontrolling interest | — | (5 | ) | — | — | (5 | ) | ||||||||||||
Total Equity | 1,989 | 13,424 | (9 | ) | (13,420 | ) | 1,984 | ||||||||||||
Total Liabilities and Equity | $ | 17,044 | $ | 14,837 | $ | 406 | $ | (20,280 | ) | $ | 12,007 |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Current Assets | |||||||||||||||||||
Cash and cash equivalents | $ | 1,529 | $ | 221 | $ | 26 | $ | — | $ | 1,776 | |||||||||
Restricted cash | 21 | 41 | — | — | 62 | ||||||||||||||
Accounts receivable, net | 141 | 2,604 | 39 | (2,398 | ) | 386 | |||||||||||||
Inventory | — | 326 | 119 | — | 445 | ||||||||||||||
Other current assets | 12 | 408 | 2 | (104 | ) | 318 | |||||||||||||
Total Current Assets | 1,703 | 3,600 | 186 | (2,502 | ) | 2,987 | |||||||||||||
Property, plant and equipment, net | — | 6,772 | 349 | — | 7,121 | ||||||||||||||
Investment in affiliates | 12,175 | — | — | (12,175 | ) | — | |||||||||||||
Restricted cash | 2,000 | — | — | — | 2,000 | ||||||||||||||
Goodwill | — | 799 | — | — | 799 | ||||||||||||||
Other long-term assets | 2 | 109 | 35 | — | 146 | ||||||||||||||
Intercompany note receivable | — | 8 | — | (8 | ) | — | |||||||||||||
Total Assets | $ | 15,880 | $ | 11,288 | $ | 570 | $ | (14,685 | ) | $ | 13,053 | ||||||||
Current Liabilities | |||||||||||||||||||
Accounts payable | $ | 1,990 | $ | 443 | $ | 297 | $ | (2,398 | ) | $ | 332 | ||||||||
Other current liabilities | 143 | 377 | 168 | (104 | ) | 584 | |||||||||||||
Total Current Liabilities | 2,133 | 820 | 465 | (2,502 | ) | 916 | |||||||||||||
Liabilities subject to compromise | — | 832 | — | — | 832 | ||||||||||||||
Debt, long-term portion, net | 8,531 | 216 | 31 | — | 8,778 | ||||||||||||||
Intercompany note payable | 3,042 | — | — | (3,042 | ) | — | |||||||||||||
Other long-term liabilities | 132 | 313 | 51 | (8 | ) | 488 | |||||||||||||
Total Liabilities | 13,838 | 2,181 | 547 | (5,552 | ) | 11,014 | |||||||||||||
Stockholders’ Equity | |||||||||||||||||||
Dynegy Stockholders’ Equity | 2,042 | 12,152 | 23 | (12,175 | ) | 2,042 | |||||||||||||
Intercompany note receivable | — | (3,042 | ) | — | 3,042 | — | |||||||||||||
Total Dynegy Stockholders’ Equity | 2,042 | 9,110 | 23 | (9,133 | ) | 2,042 | |||||||||||||
Noncontrolling interest | — | (3 | ) | — | — | (3 | ) | ||||||||||||
Total Equity | 2,042 | 9,107 | 23 | (9,133 | ) | 2,039 | |||||||||||||
Total Liabilities and Equity | $ | 15,880 | $ | 11,288 | $ | 570 | $ | (14,685 | ) | $ | 13,053 |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues | $ | — | $ | 1,380 | $ | 84 | $ | (27 | ) | $ | 1,437 | ||||||||
Cost of sales, excluding depreciation expense | — | (760 | ) | (54 | ) | 27 | (787 | ) | |||||||||||
Gross margin | — | 620 | 30 | — | 650 | ||||||||||||||
Operating and maintenance expense | — | (209 | ) | (27 | ) | — | (236 | ) | |||||||||||
Depreciation expense | — | (193 | ) | (9 | ) | — | (202 | ) | |||||||||||
Impairments | — | (29 | ) | — | — | (29 | ) | ||||||||||||
Loss on sale of assets, net | — | (78 | ) | — | — | (78 | ) | ||||||||||||
General and administrative expense | 8 | (50 | ) | (2 | ) | — | (44 | ) | |||||||||||
Acquisition and integration costs | — | (3 | ) | — | — | (3 | ) | ||||||||||||
Other | — | — | — | — | — | ||||||||||||||
Operating income (loss) | 8 | 58 | (8 | ) | — | 58 | |||||||||||||
Bankruptcy reorganization items | — | 12 | — | — | 12 | ||||||||||||||
Earnings from unconsolidated investments | — | 4 | — | — | 4 | ||||||||||||||
Equity in losses from investments in affiliates | 78 | — | — | (78 | ) | — | |||||||||||||
Interest expense | (155 | ) | (6 | ) | (3 | ) | 3 | (161 | ) | ||||||||||
Loss on early extinguishment of debt | (66 | ) | — | — | — | (66 | ) | ||||||||||||
Other income and expense, net | 3 | 19 | — | (3 | ) | 19 | |||||||||||||
Income (loss) before income taxes | (132 | ) | 87 | (11 | ) | (78 | ) | (134 | ) | ||||||||||
Income tax benefit | — | 1 | — | — | 1 | ||||||||||||||
Net income (loss) | (132 | ) | 88 | (11 | ) | (78 | ) | (133 | ) | ||||||||||
Less: Net loss attributable to noncontrolling interest | — | (1 | ) | — | — | (1 | ) | ||||||||||||
Net Income (loss) attributable to Dynegy Inc. | $ | (132 | ) | $ | 89 | $ | (11 | ) | $ | (78 | ) | $ | (132 | ) |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues | $ | — | $ | 3,616 | $ | 342 | $ | (110 | ) | $ | 3,848 | ||||||||
Cost of sales, excluding depreciation expense | — | (2,108 | ) | (227 | ) | 110 | (2,225 | ) | |||||||||||
Gross margin | — | 1,508 | 115 | — | 1,623 | ||||||||||||||
Operating and maintenance expense | — | (660 | ) | (90 | ) | — | (750 | ) | |||||||||||
Depreciation expense | — | (567 | ) | (44 | ) | — | (611 | ) | |||||||||||
Impairments | — | (148 | ) | — | — | (148 | ) | ||||||||||||
Gain (loss) on sale of assets, net | — | (108 | ) | 1 | — | (107 | ) | ||||||||||||
General and administrative expense | — | (121 | ) | (5 | ) | — | (126 | ) | |||||||||||
Acquisition and integration costs | (51 | ) | (4 | ) | — | — | (55 | ) | |||||||||||
Other | — | 1 | — | — | 1 | ||||||||||||||
Operating loss | (51 | ) | (99 | ) | (23 | ) | — | (173 | ) | ||||||||||
Bankruptcy reorganization items | — | 494 | — | — | 494 | ||||||||||||||
Earnings from unconsolidated investments | — | 4 | — | — | 4 | ||||||||||||||
Equity in earnings from investments in affiliates | 730 | — | — | (730 | ) | — | |||||||||||||
Interest expense | (461 | ) | (18 | ) | (9 | ) | 10 | (478 | ) | ||||||||||
Loss on early extinguishment of debt | (75 | ) | — | — | — | (75 | ) | ||||||||||||
Other income and expense, net | 26 | 49 | — | (10 | ) | 65 | |||||||||||||
Income (loss) before income taxes | 169 | 430 | (32 | ) | (730 | ) | (163 | ) | |||||||||||
Income tax benefit | — | 330 | — | — | 330 | ||||||||||||||
Net income (loss) | 169 | 760 | (32 | ) | (730 | ) | 167 | ||||||||||||
Less: Net loss attributable to noncontrolling interest | — | (2 | ) | — | — | (2 | ) | ||||||||||||
Net income (loss) attributable to Dynegy Inc. | $ | 169 | $ | 762 | $ | (32 | ) | $ | (730 | ) | $ | 169 |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues | $ | — | $ | 1,082 | $ | 128 | $ | (26 | ) | $ | 1,184 | ||||||||
Cost of sales, excluding depreciation expense | — | (609 | ) | (77 | ) | 26 | (660 | ) | |||||||||||
Gross margin | — | 473 | 51 | — | 524 | ||||||||||||||
Operating and maintenance expense | — | (189 | ) | (29 | ) | — | (218 | ) | |||||||||||
Depreciation expense | — | (146 | ) | (17 | ) | — | (163 | ) | |||||||||||
Impairments | — | (212 | ) | — | — | (212 | ) | ||||||||||||
General and administrative expense | (2 | ) | (38 | ) | (1 | ) | — | (41 | ) | ||||||||||
Acquisition and integration costs | (5 | ) | (2 | ) | — | — | (7 | ) | |||||||||||
Other | — | (1 | ) | 1 | — | — | |||||||||||||
Operating income (loss) | (7 | ) | (115 | ) | 5 | — | (117 | ) | |||||||||||
Earnings from unconsolidated investments | — | 4 | — | — | 4 | ||||||||||||||
Equity in losses from investments in affiliates | (136 | ) | — | — | 136 | — | |||||||||||||
Interest expense | (138 | ) | (27 | ) | (2 | ) | 1 | (166 | ) | ||||||||||
Other income and expense, net | 25 | 5 | — | (1 | ) | 29 | |||||||||||||
Income (loss) before income taxes | (256 | ) | (133 | ) | 3 | 136 | (250 | ) | |||||||||||
Income tax benefit (expense) | 7 | (6 | ) | — | — | 1 | |||||||||||||
Net income (loss) attributable to Dynegy Inc. | $ | (249 | ) | $ | (139 | ) | $ | 3 | $ | 136 | $ | (249 | ) |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Revenues | $ | — | $ | 2,921 | $ | 355 | $ | (65 | ) | $ | 3,211 | ||||||||
Cost of sales, excluding depreciation expense | — | (1,570 | ) | (193 | ) | 65 | (1,698 | ) | |||||||||||
Gross margin | — | 1,351 | 162 | — | 1,513 | ||||||||||||||
Operating and maintenance expense | — | (595 | ) | (100 | ) | — | (695 | ) | |||||||||||
Depreciation expense | — | (436 | ) | (58 | ) | — | (494 | ) | |||||||||||
Impairments | — | (857 | ) | — | — | (857 | ) | ||||||||||||
General and administrative expense | (5 | ) | (108 | ) | (4 | ) | — | (117 | ) | ||||||||||
Acquisition and integration costs | (8 | ) | — | — | — | (8 | ) | ||||||||||||
Other | — | (9 | ) | (7 | ) | — | (16 | ) | |||||||||||
Operating loss | (13 | ) | (654 | ) | (7 | ) | — | (674 | ) | ||||||||||
Earnings from unconsolidated investments | — | 7 | — | — | 7 | ||||||||||||||
Equity in losses from investments in affiliates | (693 | ) | — | — | 693 | — | |||||||||||||
Interest expense | (382 | ) | (65 | ) | (6 | ) | 4 | (449 | ) | ||||||||||
Other income and expense, net | 28 | 36 | — | (4 | ) | 60 | |||||||||||||
Loss before income taxes | (1,060 | ) | (676 | ) | (13 | ) | 693 | (1,056 | ) | ||||||||||
Income tax expense | — | (6 | ) | — | — | (6 | ) | ||||||||||||
Net loss | (1,060 | ) | (682 | ) | (13 | ) | 693 | (1,062 | ) | ||||||||||
Less: Net loss attributable to noncontrolling interest | — | (2 | ) | — | — | (2 | ) | ||||||||||||
Net loss attributable to Dynegy Inc. | $ | (1,060 | ) | $ | (680 | ) | $ | (13 | ) | $ | 693 | $ | (1,060 | ) |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net income (loss) | $ | (132 | ) | $ | 88 | $ | (11 | ) | $ | (78 | ) | $ | (133 | ) | |||||
Other comprehensive income before reclassifications: | |||||||||||||||||||
Actuarial gain and plan amendments, net of tax of zero | — | — | — | — | — | ||||||||||||||
Amounts reclassified from accumulated other comprehensive income: | |||||||||||||||||||
Amortization of unrecognized prior service credit, net of tax of zero | (2 | ) | — | — | — | (2 | ) | ||||||||||||
Other comprehensive loss, net of tax | (2 | ) | — | — | — | (2 | ) | ||||||||||||
Comprehensive income (loss) | (134 | ) | 88 | (11 | ) | (78 | ) | (135 | ) | ||||||||||
Less: Comprehensive loss attributable to noncontrolling interest | — | (1 | ) | — | — | (1 | ) | ||||||||||||
Total comprehensive income (loss) attributable to Dynegy Inc. | $ | (134 | ) | $ | 89 | $ | (11 | ) | $ | (78 | ) | $ | (134 | ) |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net income (loss) | $ | 169 | $ | 760 | $ | (32 | ) | $ | (730 | ) | $ | 167 | |||||||
Other comprehensive income before reclassifications: | |||||||||||||||||||
Actuarial gain and plan amendments, net of tax of $4 | 11 | — | — | — | 11 | ||||||||||||||
Amounts reclassified from accumulated other comprehensive income: | |||||||||||||||||||
Amortization of unrecognized prior service credit, net of tax of zero | (5 | ) | — | (1 | ) | — | (6 | ) | |||||||||||
Other comprehensive loss from investment in affiliates | (1 | ) | — | — | 1 | — | |||||||||||||
Other comprehensive income (loss), net of tax | 5 | — | (1 | ) | 1 | 5 | |||||||||||||
Comprehensive income (loss) | 174 | 760 | (33 | ) | (729 | ) | 172 | ||||||||||||
Less: Comprehensive loss attributable to noncontrolling interest | — | (2 | ) | — | — | (2 | ) | ||||||||||||
Total comprehensive income (loss) attributable to Dynegy Inc. | $ | 174 | $ | 762 | $ | (33 | ) | $ | (729 | ) | $ | 174 |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net income (loss) | $ | (249 | ) | $ | (139 | ) | $ | 3 | $ | 136 | $ | (249 | ) | ||||||
Amounts reclassified from accumulated other comprehensive income: | |||||||||||||||||||
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero | (1 | ) | (1 | ) | — | — | (2 | ) | |||||||||||
Other comprehensive loss from investment in affiliates | (1 | ) | — | — | 1 | — | |||||||||||||
Other comprehensive loss, net of tax | (2 | ) | (1 | ) | — | 1 | (2 | ) | |||||||||||
Comprehensive income (loss) | (251 | ) | (140 | ) | 3 | 137 | (251 | ) | |||||||||||
Less: Comprehensive income attributable to noncontrolling interest | — | — | — | — | — | ||||||||||||||
Total comprehensive income (loss) attributable to Dynegy Inc. | $ | (251 | ) | $ | (140 | ) | $ | 3 | $ | 137 | $ | (251 | ) |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
Net loss | $ | (1,060 | ) | $ | (682 | ) | $ | (13 | ) | $ | 693 | $ | (1,062 | ) | |||||
Amounts reclassified from accumulated other comprehensive income: | |||||||||||||||||||
Amortization of unrecognized prior service credit and actuarial gain, net of tax of zero | (3 | ) | (1 | ) | — | — | (4 | ) | |||||||||||
Other comprehensive loss from investment in affiliates | (1 | ) | — | — | 1 | — | |||||||||||||
Other comprehensive loss, net of tax | (4 | ) | (1 | ) | — | 1 | (4 | ) | |||||||||||
Comprehensive loss | (1,064 | ) | (683 | ) | (13 | ) | 694 | (1,066 | ) | ||||||||||
Less: Comprehensive loss attributable to noncontrolling interest | — | (2 | ) | — | — | (2 | ) | ||||||||||||
Total comprehensive loss attributable to Dynegy Inc. | $ | (1,064 | ) | $ | (681 | ) | $ | (13 | ) | $ | 694 | $ | (1,064 | ) |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||||||||||
Net cash provided by (used in) operating activities | $ | (455 | ) | $ | 877 | $ | 79 | $ | — | $ | 501 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||
Capital expenditures | — | (123 | ) | (6 | ) | — | (129 | ) | |||||||||||
Acquisitions, net of cash acquired | (3,244 | ) | (5 | ) | — | — | (3,249 | ) | |||||||||||
Distributions from unconsolidated investments | — | 7 | — | — | 7 | ||||||||||||||
Net intercompany transfers | 726 | — | — | (726 | ) | — | |||||||||||||
Proceeds received from asset sales, net | 599 | — | 1 | — | 600 | ||||||||||||||
Net cash used in investing activities | (1,919 | ) | (121 | ) | (5 | ) | (726 | ) | (2,771 | ) | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||
Proceeds from long-term borrowings, net of debt issuance costs | 1,747 | — | — | — | 1,747 | ||||||||||||||
Repayments of borrowings | (2,180 | ) | (30 | ) | (51 | ) | — | (2,261 | ) | ||||||||||
Proceeds from issuance of equity, net of issuance costs | 150 | — | — | — | 150 | ||||||||||||||
Payments of debt extinguishment costs | (50 | ) | — | — | — | (50 | ) | ||||||||||||
Preferred stock dividends paid | (16 | ) | — | — | — | (16 | ) | ||||||||||||
Interest rate swap settlement payments | (15 | ) | — | — | — | (15 | ) | ||||||||||||
Acquisition of noncontrolling interest | (375 | ) | — | — | — | (375 | ) | ||||||||||||
Payments related to bankruptcy settlement | (126 | ) | (7 | ) | — | — | (133 | ) | |||||||||||
Net intercompany transfers | — | (684 | ) | (42 | ) | 726 | — | ||||||||||||
Intercompany borrowings, net of repayments | 45 | (45 | ) | — | — | — | |||||||||||||
Other financing | (2 | ) | — | — | — | (2 | ) | ||||||||||||
Net cash used in financing activities | (822 | ) | (766 | ) | (93 | ) | 726 | (955 | ) | ||||||||||
Net decrease in cash, cash equivalents and restricted cash | (3,196 | ) | (10 | ) | (19 | ) | — | (3,225 | ) | ||||||||||
Cash, cash equivalents, and restricted cash beginning of period | 3,550 | 262 | 26 | — | 3,838 | ||||||||||||||
Cash, cash equivalents, and restricted cash end of period | $ | 354 | $ | 252 | $ | 7 | $ | — | $ | 613 |
Parent | Guarantor Subsidiaries | Non-Guarantor Subsidiaries | Eliminations | Consolidated | |||||||||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | |||||||||||||||||||
Net cash provided by (used in) operating activities | $ | (236 | ) | $ | 977 | $ | (13 | ) | $ | — | $ | 728 | |||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | |||||||||||||||||||
Capital expenditures | — | (271 | ) | (66 | ) | — | (337 | ) | |||||||||||
Distributions from unconsolidated investments | — | 14 | — | — | 14 | ||||||||||||||
Net intercompany transfers | 801 | — | — | (801 | ) | — | |||||||||||||
Other investing | — | 10 | — | — | 10 | ||||||||||||||
Net cash provided by (used in) investing activities | 801 | (247 | ) | (66 | ) | (801 | ) | (313 | ) | ||||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | |||||||||||||||||||
Proceeds from long-term borrowings, net of debt issuance costs | 2,079 | 198 | — | — | 2,277 | ||||||||||||||
Repayments of borrowings | (6 | ) | (15 | ) | — | — | (21 | ) | |||||||||||
Proceeds from issuance of equity, net of issuance costs | 359 | — | — | — | 359 | ||||||||||||||
Preferred stock dividends paid | (16 | ) | — | — | — | (16 | ) | ||||||||||||
Interest rate swap settlement payments | (13 | ) | — | — | — | (13 | ) | ||||||||||||
Net intercompany transfers | — | (837 | ) | 36 | 801 | — | |||||||||||||
Other financing | (2 | ) | — | — | — | (2 | ) | ||||||||||||
Net cash provided by (used in) financing activities | 2,401 | (654 | ) | 36 | 801 | 2,584 | |||||||||||||
Net increase (decrease) in cash, cash equivalents and restricted cash | 2,966 | 76 | (43 | ) | — | 2,999 | |||||||||||||
Cash, cash equivalents and restricted cash, beginning of period | 327 | 133 | 84 | — | 544 | ||||||||||||||
Cash, cash equivalents and restricted cash, end of period | $ | 3,293 | $ | 209 | $ | 41 | $ | — | $ | 3,543 |
• | On the Emergence Date, approximately $113 million of cash, $182 million of new Dynegy seven-year unsecured notes, and warrants (the “2017 Warrants”) to purchase up to 8.7 million shares of common stock with a fair value of $17 million. |
• | On April 18, 2017, approximately $3 million of cash, $3 million of new Dynegy seven-year unsecured notes, and 0.1 million 2017 Warrants with a fair value of less than $1 million. |
• | On August 1, 2017, approximately $6 million of cash, $4 million of new Dynegy seven-year unsecured notes, and 0.2 million 2017 Warrants with a fair value of less than $1 million were issued to remaining eligible holders of Genco senior notes and represented the final payment in the Genco restructuring. |
(amounts in millions) | ||||
Liabilities subject to compromise, which were terminated | $ | 832 | ||
Less: | ||||
Seven-year unsecured notes | 188 | |||
Cash consideration | 122 | |||
2017 Warrants, at fair value | 17 | |||
Legal and consulting fees | 11 | |||
Bankruptcy reorganization items | $ | 494 |
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other and Eliminations | Total | ||||||||||||||||||||||||
Domestic: | ||||||||||||||||||||||||||||||||
Unaffiliated revenues | $ | 628 | $ | 269 | $ | 210 | $ | 98 | $ | 182 | $ | 50 | $ | — | $ | 1,437 | ||||||||||||||||
Intercompany and affiliate revenues | (25 | ) | (1 | ) | (1 | ) | 6 | 21 | — | — | — | |||||||||||||||||||||
Total revenues | $ | 603 | $ | 268 | $ | 209 | $ | 104 | $ | 203 | $ | 50 | $ | — | $ | 1,437 | ||||||||||||||||
Depreciation expense | $ | (94 | ) | $ | (52 | ) | $ | (20 | ) | $ | (9 | ) | $ | (11 | ) | $ | (14 | ) | $ | (2 | ) | $ | (202 | ) | ||||||||
Impairments | (29 | ) | — | — | — | — | — | — | (29 | ) | ||||||||||||||||||||||
Loss on sale of assets, net | (1 | ) | (77 | ) | — | — | — | — | — | (78 | ) | |||||||||||||||||||||
General and administrative expense | — | — | — | — | — | — | (44 | ) | (44 | ) | ||||||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | — | (3 | ) | (3 | ) | ||||||||||||||||||||||
Operating income (loss) | $ | 86 | $ | (30 | ) | $ | 50 | $ | (9 | ) | $ | 11 | $ | — | $ | (50 | ) | $ | 58 | |||||||||||||
Bankruptcy reorganization items | — | — | — | — | 12 | — | — | 12 | ||||||||||||||||||||||||
Earnings from unconsolidated investments | 2 | 2 | — | — | — | — | — | 4 | ||||||||||||||||||||||||
Interest expense | — | — | — | — | — | — | (161 | ) | (161 | ) | ||||||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | — | — | — | (66 | ) | (66 | ) | ||||||||||||||||||||||
Other income and expense, net | 16 | — | — | — | — | — | 3 | 19 | ||||||||||||||||||||||||
Loss before income taxes | (134 | ) | ||||||||||||||||||||||||||||||
Income tax benefit | — | — | — | — | — | — | 1 | 1 | ||||||||||||||||||||||||
Net loss | (133 | ) | ||||||||||||||||||||||||||||||
Less: Net loss attributable to noncontrolling interest | (1 | ) | ||||||||||||||||||||||||||||||
Net loss attributable to Dynegy Inc. | $ | (132 | ) | |||||||||||||||||||||||||||||
Total assets—domestic | $ | 5,158 | $ | 3,401 | $ | 1,564 | $ | 232 | $ | 581 | $ | 461 | $ | 610 | $ | 12,007 | ||||||||||||||||
Investment in unconsolidated affiliate | $ | 77 | $ | 77 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 154 | ||||||||||||||||
Capital expenditures | $ | (6 | ) | $ | (6 | ) | $ | (3 | ) | $ | — | $ | (4 | ) | $ | (3 | ) | $ | (2 | ) | $ | (24 | ) |
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other and Eliminations | Total | ||||||||||||||||||||||||
Domestic: | ||||||||||||||||||||||||||||||||
Unaffiliated revenues | $ | 1,806 | $ | 817 | $ | 322 | $ | 276 | $ | 538 | $ | 89 | $ | — | $ | 3,848 | ||||||||||||||||
Intercompany and affiliate revenues | (47 | ) | (2 | ) | (1 | ) | 16 | 34 | — | — | — | |||||||||||||||||||||
Total revenues | $ | 1,759 | $ | 815 | $ | 321 | $ | 292 | $ | 572 | $ | 89 | $ | — | $ | 3,848 | ||||||||||||||||
Depreciation expense | $ | (283 | ) | $ | (171 | ) | $ | (54 | ) | $ | (22 | ) | $ | (35 | ) | $ | (40 | ) | $ | (6 | ) | $ | (611 | ) | ||||||||
Impairments | (49 | ) | — | — | (99 | ) | — | — | — | (148 | ) | |||||||||||||||||||||
Gain (loss) on sale of assets, net | (31 | ) | (77 | ) | — | — | 1 | — | — | (107 | ) | |||||||||||||||||||||
General and administrative expense | — | — | — | — | — | — | (126 | ) | (126 | ) | ||||||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | — | (55 | ) | (55 | ) | ||||||||||||||||||||||
Operating income (loss) | $ | 178 | $ | (72 | ) | $ | (8 | ) | $ | (90 | ) | $ | 40 | $ | (33 | ) | $ | (188 | ) | $ | (173 | ) | ||||||||||
Bankruptcy reorganization items | — | — | — | — | 494 | — | — | 494 | ||||||||||||||||||||||||
Earnings from unconsolidated investments | 2 | 2 | — | — | — | — | — | 4 | ||||||||||||||||||||||||
Interest expense | — | — | — | — | — | — | (478 | ) | (478 | ) | ||||||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | — | — | — | (75 | ) | (75 | ) | ||||||||||||||||||||||
Other income and expense, net | 16 | — | — | — | 26 | — | 23 | 65 | ||||||||||||||||||||||||
Loss before income taxes | 0 | — | 0 | — | — | — | 0 | (163 | ) | |||||||||||||||||||||||
Income tax benefit | — | — | — | — | — | — | 330 | 330 | ||||||||||||||||||||||||
Net income | 167 | |||||||||||||||||||||||||||||||
Less: Net loss attributable to noncontrolling interest | (2 | ) | ||||||||||||||||||||||||||||||
Net income attributable to Dynegy Inc. | $ | 169 | ||||||||||||||||||||||||||||||
Total assets—domestic | $ | 5,158 | $ | 3,401 | $ | 1,564 | $ | 232 | $ | 581 | $ | 461 | $ | 610 | $ | 12,007 | ||||||||||||||||
Investment in unconsolidated affiliate | $ | 77 | $ | 77 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 154 | ||||||||||||||||
Capital expenditures | $ | (74 | ) | $ | (46 | ) | $ | (20 | ) | $ | (3 | ) | $ | (10 | ) | $ | (34 | ) | $ | (5 | ) | $ | (192 | ) |
(amounts in millions) | PJM | NY/NE | MISO | IPH | CAISO | Other and Eliminations | Total | |||||||||||||||||||||
Domestic: | ||||||||||||||||||||||||||||
Unaffiliated revenues | $ | 551 | $ | 200 | $ | 130 | $ | 241 | $ | 46 | $ | — | $ | 1,168 | ||||||||||||||
Intercompany revenues | 17 | (5 | ) | 3 | 1 | — | — | 16 | ||||||||||||||||||||
Total revenues | $ | 568 | $ | 195 | $ | 133 | $ | 242 | $ | 46 | $ | — | $ | 1,184 | ||||||||||||||
Depreciation expense | $ | (88 | ) | $ | (53 | ) | $ | (3 | ) | $ | (7 | ) | $ | (11 | ) | $ | (1 | ) | $ | (163 | ) | |||||||
Impairments | (64 | ) | — | — | (148 | ) | — | — | (212 | ) | ||||||||||||||||||
General and administrative expense | — | — | — | — | — | (41 | ) | (41 | ) | |||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | (7 | ) | (7 | ) | |||||||||||||||||||
Operating income (loss) | $ | 29 | $ | (15 | ) | $ | 13 | $ | (104 | ) | $ | 10 | $ | (50 | ) | $ | (117 | ) | ||||||||||
Earnings from unconsolidated investments | 4 | — | — | — | — | — | 4 | |||||||||||||||||||||
Interest expense | — | — | — | — | — | (166 | ) | (166 | ) | |||||||||||||||||||
Other income and expense, net | 3 | — | — | 1 | — | 25 | 29 | |||||||||||||||||||||
Loss before income taxes | (250 | ) | ||||||||||||||||||||||||||
Income tax benefit | — | — | — | — | — | 1 | 1 | |||||||||||||||||||||
Net loss | (249 | ) | ||||||||||||||||||||||||||
Less: Net loss attributable to noncontrolling interest | — | |||||||||||||||||||||||||||
Net loss attributable to Dynegy Inc. | $ | (249 | ) | |||||||||||||||||||||||||
Total assets—domestic | $ | 5,208 | $ | 2,807 | $ | 371 | $ | 746 | $ | 499 | $ | 3,393 | $ | 13,024 | ||||||||||||||
Investment in unconsolidated affiliate | $ | 173 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 173 | ||||||||||||||
Capital expenditures | $ | (13 | ) | $ | (10 | ) | $ | (1 | ) | $ | (9 | ) | $ | (1 | ) | $ | (1 | ) | $ | (35 | ) |
(amounts in millions) | PJM | NY/NE | MISO | IPH | CAISO | Other and Eliminations | Total | |||||||||||||||||||||
Domestic: | ||||||||||||||||||||||||||||
Unaffiliated revenues | $ | 1,559 | $ | 630 | $ | 315 | $ | 575 | $ | 105 | $ | — | $ | 3,184 | ||||||||||||||
Intercompany revenues | 45 | (2 | ) | (15 | ) | (1 | ) | — | — | 27 | ||||||||||||||||||
Total revenues | $ | 1,604 | $ | 628 | $ | 300 | $ | 574 | $ | 105 | $ | — | $ | 3,211 | ||||||||||||||
Depreciation expense | $ | (257 | ) | $ | (167 | ) | $ | (19 | ) | $ | (21 | ) | $ | (26 | ) | $ | (4 | ) | $ | (494 | ) | |||||||
Impairments | (64 | ) | — | (645 | ) | (148 | ) | — | — | (857 | ) | |||||||||||||||||
General and administrative expense | — | — | — | — | — | (117 | ) | (117 | ) | |||||||||||||||||||
Acquisition and integration costs | — | — | — | 8 | — | (16 | ) | (8 | ) | |||||||||||||||||||
Operating income (loss) | $ | 277 | $ | (22 | ) | $ | (703 | ) | $ | (87 | ) | $ | — | $ | (139 | ) | $ | (674 | ) | |||||||||
Earnings from unconsolidated investments | 7 | — | — | — | — | — | 7 | |||||||||||||||||||||
Interest expense | — | — | — | — | — | (449 | ) | (449 | ) | |||||||||||||||||||
Other income and expense, net | 9 | — | — | 15 | 12 | 24 | 60 | |||||||||||||||||||||
Loss before income taxes | (1,056 | ) | ||||||||||||||||||||||||||
Income tax expense | — | — | — | — | — | (6 | ) | (6 | ) | |||||||||||||||||||
Net loss | (1,062 | ) | ||||||||||||||||||||||||||
Less: Net loss attributable to noncontrolling interest | (2 | ) | ||||||||||||||||||||||||||
Net loss attributable to Dynegy Inc. | $ | (1,060 | ) | |||||||||||||||||||||||||
Total assets—domestic | $ | 5,208 | $ | 2,807 | $ | 371 | $ | 746 | $ | 499 | $ | 3,393 | $ | 13,024 | ||||||||||||||
Investment in unconsolidated affiliate | $ | 173 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | 173 | ||||||||||||||
Capital expenditures | $ | (124 | ) | $ | (84 | ) | $ | (9 | ) | $ | (30 | ) | $ | (4 | ) | $ | (9 | ) | $ | (260 | ) |
Revolving facilities and LC capacity (1) | $ | 1,650 | ||
Less: | ||||
Outstanding revolver draws | (300 | ) | ||
Outstanding LCs | (405 | ) | ||
Revolving facilities and LC availability | 945 | |||
Cash and cash equivalents | 613 | |||
Total available liquidity | $ | 1,558 |
(1) | Includes $1.545 billion in senior secured revolving credit facilities and $105 million related to LCs. Please read Note 12—Debt for further discussion. |
• | July 2017 - We received approximately $480 million in proceeds from the Troy and Armstrong Sale. |
• | July 2017 - Refinanced previously monetized capacity under our Forward Capacity Sales Agreement by 24 months. |
• | July 2017 - Extended a $55 million LC for an additional year. |
• | August 2017 - We exchanged $25 million of the Genco senior notes for approximately $6 million cash, $4 million in Dynegy senior notes, and 0.2 million 2017 Warrants. This was the final payment related to the Genco restructuring. |
• | August 2017 - We issued $850 million of 2026 Senior Notes. We used the proceeds of the offering, together with proceeds from asset sales, and cash-on-hand to repurchase $1.25 billion of our 6.75 percent senior notes due 2019 and repay $200 million of our Tranche C-1 term loan. |
• | September 2017 - We received approximately $125 million in proceeds, including $6 million in working capital adjustments, from the sale of our Dighton and Milford-MA facilities. |
• | October 2017 - We received approximately $180 million in proceeds from the Lee Sale Agreement. |
• | October 2017 - We repaid the outstanding Revolving Facility balance of $300 million. |
Nine Months Ended September 30, | ||||||||||||
(amounts in millions) | 2017 | 2016 | Change | |||||||||
Net cash provided by operating activities | $ | 501 | $ | 728 | $ | (227 | ) | |||||
Net cash used in investing activities | $ | (2,771 | ) | $ | (313 | ) | $ | (2,458 | ) | |||
Net cash provided by (used in) financing activities | $ | (955 | ) | $ | 2,584 | $ | (3,539 | ) |
(in millions) | ||||
Increase in cash provided by operation of our power generation facilities and retail operations | $ | 159 | ||
Increase in interest payments on our various debt agreements | (85 | ) | ||
Increase in payments for acquisition-related costs | (39 | ) | ||
Decrease in cash provided by changes in working capital and other | (262 | ) | ||
$ | (227 | ) |
(amounts in millions) | September 30, 2017 | December 31, 2016 | ||||||
Cash (1) | $ | 55 | $ | 124 | ||||
LCs | 405 | 382 | ||||||
Total | $ | 460 | $ | 506 |
(1) | Includes broker margin as well as other collateral postings included in Prepayments and other current assets in our unaudited consolidated balance sheets. At September 30, 2017 and December 31, 2016, $22 million and $54 million, respectively, of cash posted as collateral were netted against Liabilities from risk management activities in our unaudited consolidated balance sheets. |
(in millions) | ||||
Cash paid, net of cash acquired for the ENGIE Acquisition | $ | (3,249 | ) | |
Decrease in capital expenditures | 208 | |||
Net proceeds received from asset sales in 2017 | 600 | |||
Decrease in other investing inflows | (17 | ) | ||
$ | (2,458 | ) |
Nine Months Ended September 30, | Estimated Remaining | ||||||||||||
(amounts in millions) | 2017 | 2016 | 2017 | ||||||||||
PJM | $ | 74 | $ | 124 | $ | 31 | |||||||
NY/NE | 46 | 84 | 15 | ||||||||||
ERCOT | 20 | — | 10 | ||||||||||
MISO | 3 | 9 | 2 | ||||||||||
IPH | 10 | 30 | 14 | ||||||||||
CAISO | 34 | 4 | 1 | ||||||||||
Other | 5 | 9 | 3 | ||||||||||
Total capital expenditures incurred (1) | $ | 192 | $ | 260 | $ | 76 | |||||||
Non-cash investing activities (2) | (39 | ) | (1 | ) | N/A | ||||||||
Capital work performed under prepaid long-term service agreement | (31 | ) | — | N/A | |||||||||
Prepaid cash for long-term service agreements (3) | 7 | 78 | N/A | ||||||||||
Capital Expenditures - Statement of Cash Flows | $ | 129 | $ | 337 | N/A |
(1) | Includes capitalized interest of $2 million and $9 million for the nine months ended September 30, 2017 and 2016, respectively. |
(2) | Please read Note 7—Cash Flow Information for further details. |
(3) | Prepaid cash reclassified into Investing Activities on the consolidated statements of cash flows. |
(in millions) | ||||
Decrease in proceeds from long-term borrowings, net of issuance costs | $ | (332 | ) | |
Proceeds related to the SPC TEUs in 2016 | (359 | ) | ||
Proceeds from issuance of equity related to the PIPE Transaction in 2017 | 150 | |||
Proceeds related to the Forward Capacity Agreement in 2016 | (198 | ) | ||
Cash paid related to the ECP Buyout in 2017 | (375 | ) | ||
Cash paid related to the Genco Bankruptcy in 2017 | (133 | ) | ||
Increase in repayment of borrowings | (2,240 | ) | ||
Cash paid for debt extinguishment costs in 2017 | (50 | ) | ||
Increase in other financing activity | (2 | ) | ||
$ | (3,539 | ) |
Dividend Payment Dates and Amounts Paid | ||||||||
(amounts in millions) | 2017 | 2016 | ||||||
February 1 | $ | 5.4 | $ | 5.4 | ||||
May 1 | $ | 5.4 | $ | 5.4 | ||||
August 1 | $ | 5.4 | $ | 5.4 | ||||
November 1 | $ | 5.4 | $ | 5.4 |
Moody’s | S&P | |||
Dynegy Inc.: | ||||
Corporate Family Rating | B2 | B+ | ||
Senior Secured | Ba3 | BB | ||
Senior Unsecured | B3 | B+ |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(amounts in millions) | 2017 | 2016 | ||||||||||
Revenues | ||||||||||||
Energy | $ | 1,105 | $ | 992 | $ | 113 | ||||||
Capacity | 278 | 193 | 85 | |||||||||
Mark-to-market income (loss), net | 32 | (18 | ) | 50 | ||||||||
Contract amortization | (5 | ) | (23 | ) | 18 | |||||||
Other | 27 | 40 | (13 | ) | ||||||||
Total revenues | 1,437 | 1,184 | 253 | |||||||||
Cost of sales, excluding depreciation expense | (787 | ) | (660 | ) | (127 | ) | ||||||
Gross margin | 650 | 524 | 126 | |||||||||
Operating and maintenance expense | (236 | ) | (218 | ) | (18 | ) | ||||||
Depreciation expense | (202 | ) | (163 | ) | (39 | ) | ||||||
Impairments | (29 | ) | (212 | ) | 183 | |||||||
Loss on sale of assets | (78 | ) | — | (78 | ) | |||||||
General and administrative expense | (44 | ) | (41 | ) | (3 | ) | ||||||
Acquisition and integration costs | (3 | ) | (7 | ) | 4 | |||||||
Operating income (loss) | 58 | (117 | ) | 175 | ||||||||
Bankruptcy reorganization items | 12 | — | 12 | |||||||||
Earnings from unconsolidated investment | 4 | 4 | — | |||||||||
Interest expense | (161 | ) | (166 | ) | 5 | |||||||
Loss on early extinguishment of debt | (66 | ) | — | (66 | ) | |||||||
Other income and expense, net | 19 | 29 | (10 | ) | ||||||||
Loss before income taxes | (134 | ) | (250 | ) | 116 | |||||||
Income tax benefit | 1 | 1 | — | |||||||||
Net loss | (133 | ) | (249 | ) | 116 | |||||||
Less: Net loss attributable to noncontrolling interest | (1 | ) | — | (1 | ) | |||||||
Net loss attributable to Dynegy Inc. | $ | (132 | ) | $ | (249 | ) | $ | 117 |
Three Months Ended September 30, 2017 | ||||||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||
Revenues | $ | 603 | $ | 268 | $ | 209 | $ | 104 | $ | 203 | $ | 50 | $ | — | $ | 1,437 | ||||||||||||||||
Cost of sales, excluding depreciation expense | (303 | ) | (131 | ) | (116 | ) | (70 | ) | (136 | ) | (31 | ) | — | (787 | ) | |||||||||||||||||
Gross margin | 300 | 137 | 93 | 34 | 67 | 19 | — | 650 | ||||||||||||||||||||||||
Operating and maintenance expense | (90 | ) | (38 | ) | (23 | ) | (34 | ) | (45 | ) | (5 | ) | (1 | ) | (236 | ) | ||||||||||||||||
Depreciation expense | (94 | ) | (52 | ) | (20 | ) | (9 | ) | (11 | ) | (14 | ) | (2 | ) | (202 | ) | ||||||||||||||||
Impairments | (29 | ) | — | — | — | — | — | — | (29 | ) | ||||||||||||||||||||||
Loss on sale of assets | (1 | ) | (77 | ) | — | — | — | — | — | (78 | ) | |||||||||||||||||||||
General and administrative expense | — | — | — | — | — | — | (44 | ) | (44 | ) | ||||||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | — | (3 | ) | (3 | ) | ||||||||||||||||||||||
Operating income (loss) | $ | 86 | $ | (30 | ) | $ | 50 | $ | (9 | ) | $ | 11 | $ | — | $ | (50 | ) | $ | 58 |
Three Months Ended September 30, 2016 | ||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | MISO | IPH | CAISO | Other | Total | |||||||||||||||||||||
Revenues | $ | 568 | $ | 195 | $ | 133 | $ | 242 | $ | 46 | $ | — | $ | 1,184 | ||||||||||||||
Cost of sales, excluding depreciation expense | (296 | ) | (122 | ) | (84 | ) | (142 | ) | (16 | ) | — | (660 | ) | |||||||||||||||
Gross margin | 272 | 73 | 49 | 100 | 30 | — | 524 | |||||||||||||||||||||
Operating and maintenance expense | (91 | ) | (35 | ) | (33 | ) | (50 | ) | (9 | ) | — | (218 | ) | |||||||||||||||
Depreciation expense | (88 | ) | (53 | ) | (3 | ) | (7 | ) | (11 | ) | (1 | ) | (163 | ) | ||||||||||||||
Impairments | (64 | ) | — | — | (148 | ) | — | — | (212 | ) | ||||||||||||||||||
General and administrative expense | — | — | — | — | — | (41 | ) | (41 | ) | |||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | (7 | ) | (7 | ) | |||||||||||||||||||
Other | — | — | — | 1 | — | (1 | ) | — | ||||||||||||||||||||
Operating income (loss) | $ | 29 | $ | (15 | ) | $ | 13 | $ | (104 | ) | $ | 10 | $ | (50 | ) | $ | (117 | ) |
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Total | |||||||||||||||||||||
Revenues, net of hedges, attributable to newly acquired ENGIE plants | $ | 61 | $ | 75 | $ | 209 | $ | — | $ | — | $ | — | $ | 345 | ||||||||||||||
Higher (lower) realized power prices | (32 | ) | 3 | — | (5 | ) | (24 | ) | 12 | (46 | ) | |||||||||||||||||
Higher (lower) generation volumes (1) | (38 | ) | (32 | ) | — | (24 | ) | (25 | ) | 14 | (105 | ) | ||||||||||||||||
Higher (lower) capacity revenues | 30 | 14 | — | 4 | 7 | (9 | ) | 46 | ||||||||||||||||||||
Change in MTM value of derivative transactions | 22 | 14 | — | (5 | ) | 1 | (5 | ) | 27 | |||||||||||||||||||
Lower contract amortization | 10 | 3 | — | — | 1 | 4 | 18 | |||||||||||||||||||||
Other (2) | (18 | ) | (4 | ) | — | 1 | 1 | (12 | ) | (32 | ) | |||||||||||||||||
Total change in revenues | $ | 35 | $ | 73 | $ | 209 | $ | (29 | ) | $ | (39 | ) | $ | 4 | $ | 253 |
(1) | Decrease primarily due to milder weather at our PJM, NY/NE, MISO and IPH segments, unit shutdowns primarily at our MISO and IPH segments, and a plant retirement at our NY/NE segment; offsetting increase primarily due to warmer weather at our CAISO segment. |
(2) | Other primarily consists of ancillary, tolling, transmission and gas revenues. |
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Total | |||||||||||||||||||||
Cost of sales attributable to newly acquired ENGIE plants | $ | 34 | $ | 34 | $ | 116 | $ | — | $ | — | $ | — | $ | 184 | ||||||||||||||
Higher (lower) prices | (10 | ) | 9 | — | 3 | 2 | 3 | 7 | ||||||||||||||||||||
Higher (lower) burn volumes (1) | (31 | ) | (36 | ) | — | (17 | ) | (5 | ) | 12 | (77 | ) | ||||||||||||||||
Lower (higher) contract amortization | 10 | (1 | ) | — | — | 2 | — | 11 | ||||||||||||||||||||
Other (2) | 4 | 3 | — | — | (5 | ) | — | 2 | ||||||||||||||||||||
Total change in cost of sales | $ | 7 | $ | 9 | $ | 116 | $ | (14 | ) | $ | (6 | ) | $ | 15 | $ | 127 |
(1) | Lower burn volumes primarily due to milder weather at our PJM, NY/NE, MISO and IPH segments, unit shutdowns primarily at our MISO and IPH segments, and a plant retirement at our NY/NE segment; offsetting increase primarily due to warmer weather at our CAISO segment. |
(2) | Other primarily consists of transmission expenses. |
Three Months Ended September 30, | ||||||||
Description | 2017 | 2016 | ||||||
Materials and supplies inventory | $ | 14 | $ | — | ||||
Property, plant and equipment, net | — | 203 | ||||||
Equity investment | — | 9 | ||||||
Assets held-for-sale (Lee) | 15 | — | ||||||
Total | $ | 29 | $ | 212 |
Three Months Ended September 30, 2017 | ||||||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||
Net loss | $ | (133 | ) | |||||||||||||||||||||||||||||
Income tax benefit | (1 | ) | ||||||||||||||||||||||||||||||
Other income and expense, net | (19 | ) | ||||||||||||||||||||||||||||||
Loss on early extinguishment of debt | 66 | |||||||||||||||||||||||||||||||
Interest expense | 161 | |||||||||||||||||||||||||||||||
Earnings from unconsolidated investments | (4 | ) | ||||||||||||||||||||||||||||||
Bankruptcy reorganization items | (12 | ) | ||||||||||||||||||||||||||||||
Operating income (loss) | $ | 86 | $ | (30 | ) | $ | 50 | $ | (9 | ) | $ | 11 | $ | — | $ | (50 | ) | $ | 58 | |||||||||||||
Depreciation and amortization expense | 95 | 52 | 20 | 19 | 11 | 15 | 2 | 214 | ||||||||||||||||||||||||
Bankruptcy reorganization items | — | — | — | — | 12 | — | — | 12 | ||||||||||||||||||||||||
Earnings from unconsolidated investments | 2 | 2 | — | — | — | — | — | 4 | ||||||||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | — | — | — | (66 | ) | (66 | ) | ||||||||||||||||||||||
Other income and expense, net | 16 | — | — | — | — | — | 3 | 19 | ||||||||||||||||||||||||
EBITDA | 199 | 24 | 70 | 10 | 34 | 15 | (111 | ) | 241 | |||||||||||||||||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest | 2 | 1 | — | — | — | — | — | 3 | ||||||||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||
Bankruptcy reorganization items | — | — | — | — | (12 | ) | — | — | (12 | ) | ||||||||||||||||||||||
Mark-to-market adjustments, including warrants | 12 | (11 | ) | (23 | ) | 1 | (1 | ) | 3 | (1 | ) | (20 | ) | |||||||||||||||||||
Impairments | 29 | — | — | — | — | — | — | 29 | ||||||||||||||||||||||||
Loss on sale of assets, net | 1 | 77 | — | — | — | — | — | 78 | ||||||||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | — | — | — | 66 | 66 | ||||||||||||||||||||||||
Non-cash compensation expense | — | — | — | — | — | — | 6 | 6 | ||||||||||||||||||||||||
Other | — | 1 | (1 | ) | 1 | — | — | 2 | 3 | |||||||||||||||||||||||
Adjusted EBITDA | $ | 243 | $ | 92 | $ | 46 | $ | 12 | $ | 21 | $ | 18 | $ | (35 | ) | $ | 397 |
Three Months Ended September 30, 2016 | ||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | MISO | IPH | CAISO | Other | Total | |||||||||||||||||||||
Net loss | $ | (249 | ) | |||||||||||||||||||||||||
Income tax benefit | (1 | ) | ||||||||||||||||||||||||||
Other income and expense, net | (29 | ) | ||||||||||||||||||||||||||
Interest expense | 166 | |||||||||||||||||||||||||||
Earnings from unconsolidated investments | (4 | ) | ||||||||||||||||||||||||||
Operating income (loss) | $ | 29 | $ | (15 | ) | $ | 13 | $ | (104 | ) | $ | 10 | $ | (50 | ) | $ | (117 | ) | ||||||||||
Depreciation and amortization expense | 92 | 55 | 5 | 7 | 15 | 1 | 175 | |||||||||||||||||||||
Earnings from unconsolidated investments | 4 | — | — | — | — | — | 4 | |||||||||||||||||||||
Other income and expense, net | 3 | — | — | 1 | — | 25 | 29 | |||||||||||||||||||||
EBITDA | 128 | 40 | 18 | (96 | ) | 25 | (24 | ) | 91 | |||||||||||||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest | (4 | ) | — | — | (1 | ) | — | — | (5 | ) | ||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | 12 | 12 | |||||||||||||||||||||
Mark-to-market adjustments, including warrants | 25 | 14 | (4 | ) | 2 | (2 | ) | (4 | ) | 31 | ||||||||||||||||||
Impairments | 64 | — | — | 148 | — | — | 212 | |||||||||||||||||||||
Non-cash compensation expense | — | 1 | — | — | — | 5 | 6 | |||||||||||||||||||||
Other (1) | 2 | — | 2 | (3 | ) | 1 | 1 | 3 | ||||||||||||||||||||
Adjusted EBITDA | $ | 215 | $ | 55 | $ | 16 | $ | 50 | $ | 24 | $ | (10 | ) | $ | 350 |
(1) | Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $3 million for the three months ended September 30, 2016. Adjusted EBITDA did not include this adjustment for the three months ended September 30, 2017. |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 (1) | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 458 | $ | 499 | $ | (41 | ) | |||||
Capacity | 133 | 86 | 47 | |||||||||
Mark-to-market income (loss), net | 1 | (17 | ) | 18 | ||||||||
Contract amortization | (3 | ) | (14 | ) | 11 | |||||||
Other | 14 | 14 | — | |||||||||
Total operating revenues | 603 | 568 | 35 | |||||||||
Operating costs | ||||||||||||
Cost of sales | (306 | ) | (307 | ) | 1 | |||||||
Contract amortization | 3 | 11 | (8 | ) | ||||||||
Total operating costs | (303 | ) | (296 | ) | (7 | ) | ||||||
Gross margin | 300 | 272 | 28 | |||||||||
Operating and maintenance expense | (90 | ) | (91 | ) | 1 | |||||||
Depreciation expense | (94 | ) | (88 | ) | (6 | ) | ||||||
Impairments | (29 | ) | (64 | ) | 35 | |||||||
Loss on sale of assets, net | (1 | ) | — | (1 | ) | |||||||
Operating income | 86 | 29 | 57 | |||||||||
Depreciation and amortization expense | 95 | 92 | 3 | |||||||||
Earnings from unconsolidated investments | 2 | 4 | (2 | ) | ||||||||
Other income and expense, net | 16 | 3 | 13 | |||||||||
EBITDA | 199 | 128 | 71 | |||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments | 2 | (4 | ) | 6 | ||||||||
Mark-to-market adjustments | 12 | 25 | (13 | ) | ||||||||
Loss on sale of assets | 1 | — | 1 | |||||||||
Impairments | 29 | 64 | (35 | ) | ||||||||
Other | — | 2 | (2 | ) | ||||||||
Adjusted EBITDA | $ | 243 | $ | 215 | $ | 28 | ||||||
Million Megawatt Hours Generated | 14.5 | 15.1 | (0.6 | ) | ||||||||
IMA (2): | ||||||||||||
Combined-Cycle Facilities | 98 | % | 97 | % | ||||||||
Coal-Fired Facilities | 75 | % | 83 | % | ||||||||
Average Capacity Factor (3): | ||||||||||||
Combined-Cycle Facilities | 70 | % | 79 | % | ||||||||
Coal-Fired Facilities | 62 | % | 65 | % | ||||||||
CDDs (4) | 787 | 1,044 | (257 | ) | ||||||||
HDDs (4) | 34 | 17 | 17 | |||||||||
Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||
PJM West | $ | 23.21 | $ | 31.48 | $ | (8.27 | ) | |||||
AD Hub | $ | 24.95 | $ | 27.27 | $ | (2.32 | ) | |||||
Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||
PJM West | $ | 35.10 | $ | 40.74 | $ | (5.64 | ) | |||||
AD Hub | $ | 36.30 | $ | 38.75 | $ | (2.45 | ) | |||||
Average natural gas price—TetcoM3 ($/MMBtu) (7) | $ | 1.70 | $ | 1.32 | $ | 0.38 |
(1) | Includes the activity of the assets acquired in the ENGIE Acquisition. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(3) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(4) | Reflects CDDs or HDDs for the PJM Region based on National Oceanic and Atmospheric Association (“NOAA”) data. |
(5) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(6) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Income attributable to newly acquired plants | $ | 13 | ||
Lower energy margin due to the following: | ||||
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather | $ | (18 | ) | |
Lower generation volumes primarily due to lower demand as a result of milder weather | $ | (16 | ) | |
Lower retail contribution as a result of higher supply costs and milder weather | $ | (13 | ) | |
Higher capacity revenues as a result of higher pricing and performance penalties in 2016 | $ | 30 | ||
Change in MTM value of derivative transactions | $ | 22 | ||
Lower asset impairments | $ | 35 | ||
Lower O&M costs due to lower costs from long-term service agreements | $ | 9 |
(in millions) | ||||
Contribution from newly acquired plants | $ | 26 | ||
Lower energy margin due to the following: | ||||
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather | $ | (13 | ) | |
Lower generation volumes primarily due to lower demand as a result of milder weather | $ | (18 | ) | |
Lower retail contribution as a result of higher supply costs and milder weather | $ | (13 | ) | |
Higher capacity revenues as a result of higher pricing and performance penalties in 2016 | $ | 30 | ||
Lower O&M costs due to lower costs from long-term service agreements | $ | 7 | ||
Net casualty loss insurance reimbursement | $ | 13 |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 (1) | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 173 | $ | 152 | $ | 21 | ||||||
Capacity | 77 | 41 | 36 | |||||||||
Mark-to-market income (loss), net | 11 | (7 | ) | 18 | ||||||||
Contract amortization | (1 | ) | (3 | ) | 2 | |||||||
Other | 8 | 12 | (4 | ) | ||||||||
Total operating revenues | 268 | 195 | 73 | |||||||||
Operating costs | ||||||||||||
Cost of sales | (132 | ) | (122 | ) | (10 | ) | ||||||
Contract amortization | 1 | — | 1 | |||||||||
Total operating costs | (131 | ) | (122 | ) | (9 | ) | ||||||
Gross margin | 137 | 73 | 64 | |||||||||
Operating and maintenance expense | (38 | ) | (35 | ) | (3 | ) | ||||||
Depreciation expense | (52 | ) | (53 | ) | 1 | |||||||
Loss on sale of assets | (77 | ) | — | (77 | ) | |||||||
Operating loss | (30 | ) | (15 | ) | (15 | ) | ||||||
Depreciation and amortization expense | 52 | 55 | (3 | ) | ||||||||
Earnings from unconsolidated investments | 2 | — | 2 | |||||||||
EBITDA | 24 | 40 | (16 | ) | ||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments | 1 | — | 1 | |||||||||
Mark-to-market adjustments | (11 | ) | 14 | (25 | ) | |||||||
Loss on sale of assets | 77 | — | 77 | |||||||||
Non-cash compensation expense | — | 1 | (1 | ) | ||||||||
Other | 1 | — | 1 | |||||||||
Adjusted EBITDA | $ | 92 | $ | 55 | $ | 37 | ||||||
Million Megawatt Hours Generated | 5.7 | 5.4 | 0.3 | |||||||||
IMA for Combined-Cycle Facilities (2) | 87 | % | 98 | % | ||||||||
Average Capacity Factor for Combined-Cycle Facilities (3) | 52 | % | 63 | % | ||||||||
CDDs (4) | 519 | 724 | (205 | ) | ||||||||
HDDs (4) | 62 | 100 | (38 | ) | ||||||||
Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||
New York—Zone C | $ | 18.52 | $ | 26.04 | $ | (7.52 | ) | |||||
Mass Hub | $ | 16.17 | $ | 21.58 | $ | (5.41 | ) | |||||
Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||
New York—Zone C | $ | 29.86 | $ | 34.79 | $ | (4.93 | ) | |||||
Mass Hub | $ | 31.94 | $ | 41.31 | $ | (9.37 | ) | |||||
Average natural gas price—Algonquin Citygates ($/MMBtu) (7) | $ | 2.25 | $ | 2.82 | $ | (0.57 | ) |
(1) | Includes the activity of the assets acquired in the ENGIE Acquisition. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility. |
(3) | Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility. |
(4) | Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data. |
(5) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(6) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Income attributable to newly acquired plants | $ | 21 | ||
Lower energy margin due to the following: | ||||
Lower generation volumes as a result of milder weather and the retirement of Brayton Point | $ | (9 | ) | |
Higher price impact due to favorable hedge settlements partially offset by lower spark spreads, net of hedges as a result of milder weather | $ | 2 | ||
Higher capacity revenues as a result of higher pricing, partially offset by capacity lost due to the retirement of Brayton Point | $ | 14 | ||
Change in MTM value of derivative transactions | $ | 14 | ||
Lower contract amortization | $ | 4 | ||
Loss on sale of our Dighton and Milford-MA facilities | $ | (77 | ) | |
Lower O&M due to the retirement of Brayton Point | $ | 3 | ||
Lower depreciation primarily due to the retirement of Brayton Point | $ | 14 |
(in millions) | ||||
Contribution from newly acquired plants | $ | 36 | ||
Lower energy margin due to the following: | ||||
Lower spark spreads, net of hedges as a result of milder weather | $ | (6 | ) | |
Lower generation volumes as a result of milder weather and the retirement of Brayton Point | $ | (9 | ) | |
Higher capacity revenues as a result of higher pricing, partially offset by capacity lost due to the retirement of Brayton Point | $ | 14 | ||
Lower O&M due to the retirement of Brayton Point | $ | 3 |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 182 | $ | — | N/A | |||||||
Mark-to-market income, net | 23 | — | N/A | |||||||||
Other | 4 | — | N/A | |||||||||
Total operating revenues | 209 | — | N/A | |||||||||
Operating costs | ||||||||||||
Cost of sales | (117 | ) | — | N/A | ||||||||
Contract amortization | 1 | — | N/A | |||||||||
Total operating costs | (116 | ) | — | N/A | ||||||||
Gross margin | 93 | — | N/A | |||||||||
Operating and maintenance expense | (23 | ) | — | N/A | ||||||||
Depreciation expense | (20 | ) | — | N/A | ||||||||
Operating income | 50 | — | N/A | |||||||||
Depreciation and amortization expense | 20 | — | N/A | |||||||||
EBITDA | 70 | — | N/A | |||||||||
Mark-to-market adjustments | (23 | ) | — | N/A | ||||||||
Other | (1 | ) | — | N/A | ||||||||
Adjusted EBITDA | $ | 46 | $ | — | N/A | |||||||
Million Megawatt Hours Generated | 5.0 | — | N/A | |||||||||
IMA (1): | ||||||||||||
Combined-Cycle Facilities | 86 | % | — | % | ||||||||
Coal-Fired Facility | 93 | % | — | % | ||||||||
Average Capacity Factor (2): | ||||||||||||
Combined-Cycle Facilities | 47 | % | — | % | ||||||||
Coal-Fired Facility | 75 | % | — | % | ||||||||
CDDs (3) | 1,701 | 1,808 | (107 | ) | ||||||||
HDDs (3) | — | — | — | |||||||||
Average Market On-Peak Spark Spreads ($/MWh) (4): | ||||||||||||
ERCOT North | $ | 12.65 | $ | 14.51 | $ | (1.86 | ) | |||||
Average Market On-Peak Power Prices ($/MWh) (5): | ||||||||||||
ERCOT North | $ | 31.21 | $ | 33.25 | $ | (2.04 | ) | |||||
Average natural gas price—Waha Hub ($/MMBtu) (6) | $ | 2.65 | $ | 2.68 | $ | (0.03 | ) |
(1) | IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(2) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(3) | Reflects CDDs or HDDs for the ERCOT Region based on NOAA data. |
(4) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(5) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(6) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Energy margin, net of hedges | $ | 68 | ||
MTM gain | $ | 23 | ||
O&M costs | $ | (23 | ) | |
Depreciation and amortization expense | $ | (19 | ) |
(in millions) | ||||
Energy margin, net of hedges | $ | 68 | ||
O&M costs | $ | (23 | ) |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 94 | $ | 122 | $ | (28 | ) | |||||
Capacity | 11 | 7 | 4 | |||||||||
Mark-to-market income (loss), net | (1 | ) | 4 | (5 | ) | |||||||
Total operating revenues | 104 | 133 | (29 | ) | ||||||||
Operating costs | ||||||||||||
Cost of sales | (70 | ) | (84 | ) | 14 | |||||||
Total operating costs | (70 | ) | (84 | ) | 14 | |||||||
Gross margin | 34 | 49 | (15 | ) | ||||||||
Operating and maintenance expense | (34 | ) | (33 | ) | (1 | ) | ||||||
Depreciation expense | (9 | ) | (3 | ) | (6 | ) | ||||||
Operating income (loss) | (9 | ) | 13 | (22 | ) | |||||||
Depreciation and amortization expense | 19 | 5 | 14 | |||||||||
EBITDA | 10 | 18 | (8 | ) | ||||||||
Mark-to-market adjustments | 1 | (4 | ) | 5 | ||||||||
Other (1) | 1 | 2 | (1 | ) | ||||||||
Adjusted EBITDA | $ | 12 | $ | 16 | $ | (4 | ) | |||||
Million Megawatt Hours Generated | 3.4 | 4.2 | (0.8 | ) | ||||||||
IMA for Coal-Fired Facilities (2) | 94 | % | 90 | % | ||||||||
Average Capacity Factor for Coal-Fired Facilities (3) | 82 | % | 76 | % | ||||||||
CDDs (4) | 786 | 1,029 | (243 | ) | ||||||||
HDDs (4) | 11 | 46 | (35 | ) | ||||||||
Average Market On-Peak Power Prices ($/MWh) (5): | ||||||||||||
Indiana (Indy Hub) | $ | 37.04 | $ | 40.19 | $ | (3.15 | ) | |||||
Commonwealth Edison (NI Hub) | $ | 34.03 | $ | 38.41 | $ | (4.38 | ) |
(1) | Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $3 million for the three months ended September 30, 2016. Adjusted EBITDA did not include this adjustment for the three months ended September 30, 2017. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. |
(3) | Reflects actual production as a percentage of available capacity. |
(4) | Reflects CDDs or HDDs for the MISO Region based on NOAA data. |
(5) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (8 | ) | |
Lower generation volumes as a result of shutdowns in 2016 | $ | (6 | ) | |
Higher capacity revenues due to favorable pricing and volumes | $ | 4 | ||
Change in MTM value of derivative transactions | $ | (5 | ) | |
Higher O&M costs due to ARO accretion partially offset by shutdowns in 2016 | $ | (1 | ) | |
Higher depreciation expense | $ | (6 | ) |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (8 | ) | |
Lower generation volumes as a result of shutdowns in 2016 | $ | (6 | ) | |
Higher capacity revenues due to favorable pricing and volumes | $ | 4 | ||
Lower O&M costs due to shutdowns in 2016 | $ | 5 |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 152 | $ | 200 | $ | (48 | ) | |||||
Capacity | 49 | 42 | 7 | |||||||||
Mark-to-market income, net | 1 | — | 1 | |||||||||
Contract amortization | (1 | ) | (2 | ) | 1 | |||||||
Other | 2 | 2 | — | |||||||||
Total operating revenues | 203 | 242 | (39 | ) | ||||||||
Operating costs | ||||||||||||
Cost of sales | (138 | ) | (146 | ) | 8 | |||||||
Contract amortization | 2 | 4 | (2 | ) | ||||||||
Total operating costs | (136 | ) | (142 | ) | 6 | |||||||
Gross margin | 67 | 100 | (33 | ) | ||||||||
Operating and maintenance expense | (45 | ) | (50 | ) | 5 | |||||||
Depreciation expense | (11 | ) | (7 | ) | (4 | ) | ||||||
Impairments | — | (148 | ) | 148 | ||||||||
Other | — | 1 | (1 | ) | ||||||||
Operating income (loss) | 11 | (104 | ) | 115 | ||||||||
Depreciation and amortization expense | 11 | 7 | 4 | |||||||||
Bankruptcy reorganization items | 12 | — | 12 | |||||||||
Other income and expense, net | — | 1 | (1 | ) | ||||||||
EBITDA | 34 | (96 | ) | 130 | ||||||||
Adjustment to exclude noncontrolling interest | — | (1 | ) | 1 | ||||||||
Bankruptcy reorganization items | (12 | ) | — | (12 | ) | |||||||
Mark-to-market adjustments | (1 | ) | 2 | (3 | ) | |||||||
Impairments | — | 148 | (148 | ) | ||||||||
Other | — | (3 | ) | 3 | ||||||||
Adjusted EBITDA | $ | 21 | $ | 50 | $ | (29 | ) | |||||
Million Megawatt Hours Generated | 4.6 | 5.0 | (0.4 | ) | ||||||||
IMA (1) | 85 | % | 88 | % | ||||||||
Average Capacity Factor for IPH Facilities (2) | 62 | % | 59 | % | ||||||||
CDDs (3) | 786 | 1,029 | (243 | ) | ||||||||
HDDs (3) | 11 | 46 | (35 | ) | ||||||||
Average Market On-Peak Power Prices ($/MWh) (4): | ||||||||||||
Indiana (Indy Hub) | $ | 37.04 | $ | 40.19 | $ | (3.15 | ) | |||||
Commonwealth Edison (NI Hub) | $ | 34.03 | $ | 38.41 | $ | (4.38 | ) |
(1) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(2) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(3) | Reflects CDDs or HDDs for the MISO Region based on NOAA data. |
(4) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (6 | ) | |
Lower generation as a result of milder weather and 2016 shutdowns | $ | (7 | ) | |
Lower retail contribution as a result of milder weather | $ | (28 | ) | |
Higher capacity revenues due to higher pricing | $ | 7 | ||
Change in MTM value of derivative transactions | $ | 1 | ||
Lower O&M costs due to lower ARO accretion and shutdowns in 2016 | $ | 5 | ||
Higher depreciation expense | $ | (4 | ) | |
Lower impairment charges in 2017 | $ | 148 |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (6 | ) | |
Lower generation as a result of milder weather and 2016 shutdowns | $ | (7 | ) | |
Lower retail contribution as a result of milder weather | $ | (28 | ) | |
Higher capacity revenues due to higher pricing | $ | 7 | ||
Lower O&M costs due to shutdowns in 2016 | $ | 5 |
Three Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 46 | $ | 19 | $ | 27 | ||||||
Capacity | 8 | 17 | (9 | ) | ||||||||
Mark-to-market income (loss), net | (3 | ) | 2 | (5 | ) | |||||||
Contract amortization | — | (4 | ) | 4 | ||||||||
Other | (1 | ) | 12 | (13 | ) | |||||||
Total operating revenues | 50 | 46 | 4 | |||||||||
Operating costs | ||||||||||||
Cost of sales | (31 | ) | (16 | ) | (15 | ) | ||||||
Total operating costs | (31 | ) | (16 | ) | (15 | ) | ||||||
Gross margin | 19 | 30 | (11 | ) | ||||||||
Operating and maintenance expense | (5 | ) | (9 | ) | 4 | |||||||
Depreciation expense | (14 | ) | (11 | ) | (3 | ) | ||||||
Operating income | — | 10 | (10 | ) | ||||||||
Depreciation and amortization expense | 15 | 15 | — | |||||||||
EBITDA | 15 | 25 | (10 | ) | ||||||||
Mark-to-market adjustments | 3 | (2 | ) | 5 | ||||||||
Other | — | 1 | (1 | ) | ||||||||
Adjusted EBITDA | $ | 18 | $ | 24 | $ | (6 | ) | |||||
Million Megawatt Hours Generated | 1.0 | 0.5 | 0.5 | |||||||||
IMA for Combined-Cycle Facilities (1) | 86 | % | 92 | % | ||||||||
Average Capacity Factor for Combined-Cycle Facilities (2) | 43 | % | 20 | % | ||||||||
CDDs (3) | 874 | 723 | 151 | |||||||||
HDDs (3) | 6 | 22 | (16 | ) | ||||||||
Average Market On-Peak Spark Spreads ($/MWh) (4): | ||||||||||||
North of Path 15 (NP 15) | $ | 23.84 | $ | 15.44 | $ | 8.40 | ||||||
Average natural gas price—PG&E Citygate ($/MMBtu) (5) | $ | 3.27 | $ | 3.18 | $ | 0.09 |
(1) | IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(2) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(3) | Reflects CDDs or HDDs for the CAISO Region based on NOAA data. |
(4) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(5) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Higher energy margin, net of hedges due to higher spark spreads as a result of warmer weather | $ | 11 | ||
Lower capacity revenues due to lower contracted volumes and prices | $ | (9 | ) | |
Change in MTM value of derivative transactions | $ | (5 | ) | |
Lower tolling revenue due to expiration of tolling agreement | $ | (11 | ) | |
Lower O&M costs due to shutdowns | $ | 3 |
(in millions) | ||||
Higher energy margin, net of hedges due to higher spark spreads as a result of warmer weather | $ | 11 | ||
Lower capacity revenues due to lower contracted volumes and prices | $ | (9 | ) | |
Lower tolling revenue due to expiration of tolling agreement | $ | (11 | ) | |
Lower O&M costs due to shutdowns | $ | 3 |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(amounts in millions) | 2017 | 2016 | ||||||||||
Revenues | ||||||||||||
Energy | $ | 3,036 | $ | 2,526 | $ | 510 | ||||||
Capacity | 722 | 573 | 149 | |||||||||
Mark-to-market income, net | 20 | 73 | (53 | ) | ||||||||
Contract amortization | (29 | ) | (58 | ) | 29 | |||||||
Other | 99 | 97 | 2 | |||||||||
Total revenues | 3,848 | 3,211 | 637 | |||||||||
Cost of sales, excluding depreciation expense | (2,225 | ) | (1,698 | ) | (527 | ) | ||||||
Gross margin | 1,623 | 1,513 | 110 | |||||||||
Operating and maintenance expense | (750 | ) | (695 | ) | (55 | ) | ||||||
Depreciation expense | (611 | ) | (494 | ) | (117 | ) | ||||||
Impairments | (148 | ) | (857 | ) | 709 | |||||||
Loss on sale of assets, net | (107 | ) | — | (107 | ) | |||||||
General and administrative expense | (126 | ) | (117 | ) | (9 | ) | ||||||
Acquisition and integration costs | (55 | ) | (8 | ) | (47 | ) | ||||||
Other | 1 | (16 | ) | 17 | ||||||||
Operating loss | (173 | ) | (674 | ) | 501 | |||||||
Bankruptcy reorganization items | 494 | — | 494 | |||||||||
Earnings from unconsolidated investments | 4 | 7 | (3 | ) | ||||||||
Interest expense | (478 | ) | (449 | ) | (29 | ) | ||||||
Loss on early extinguishment of debt | (75 | ) | — | (75 | ) | |||||||
Other income and expense, net | 65 | 60 | 5 | |||||||||
Loss before income taxes | (163 | ) | (1,056 | ) | 893 | |||||||
Income tax benefit (expense) | 330 | (6 | ) | 336 | ||||||||
Net income (loss) | 167 | (1,062 | ) | 1,229 | ||||||||
Less: Net loss attributable to noncontrolling interest | (2 | ) | (2 | ) | — | |||||||
Net income (loss) attributable to Dynegy Inc. | $ | 169 | $ | (1,060 | ) | $ | 1,229 |
Nine Months Ended September 30, 2017 | ||||||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||
Revenues | $ | 1,759 | $ | 815 | $ | 321 | $ | 292 | $ | 572 | $ | 89 | $ | — | $ | 3,848 | ||||||||||||||||
Cost of sales, excluding depreciation expense | (922 | ) | (504 | ) | (209 | ) | (175 | ) | (365 | ) | (50 | ) | — | (2,225 | ) | |||||||||||||||||
Gross margin | 837 | 311 | 112 | 117 | 207 | 39 | — | 1,623 | ||||||||||||||||||||||||
Operating and maintenance expense | (296 | ) | (135 | ) | (66 | ) | (86 | ) | (133 | ) | (32 | ) | (2 | ) | (750 | ) | ||||||||||||||||
Depreciation expense | (283 | ) | (171 | ) | (54 | ) | (22 | ) | (35 | ) | (40 | ) | (6 | ) | (611 | ) | ||||||||||||||||
Impairments | (49 | ) | — | — | (99 | ) | — | — | — | (148 | ) | |||||||||||||||||||||
Gain (loss) on sale of assets | (31 | ) | (77 | ) | — | — | 1 | — | — | (107 | ) | |||||||||||||||||||||
General and administrative expense | — | — | — | — | — | — | (126 | ) | (126 | ) | ||||||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | — | (55 | ) | (55 | ) | ||||||||||||||||||||||
Other | — | — | — | — | — | — | 1 | 1 | ||||||||||||||||||||||||
Operating income (loss) | $ | 178 | $ | (72 | ) | $ | (8 | ) | $ | (90 | ) | $ | 40 | $ | (33 | ) | $ | (188 | ) | $ | (173 | ) |
Nine Months Ended September 30, 2016 | ||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | MISO | IPH | CAISO | Other | Total | |||||||||||||||||||||
Revenues | $ | 1,604 | $ | 628 | $ | 300 | $ | 574 | $ | 105 | $ | — | $ | 3,211 | ||||||||||||||
Cost of sales, excluding depreciation expense | (712 | ) | (361 | ) | (232 | ) | (342 | ) | (51 | ) | — | (1,698 | ) | |||||||||||||||
Gross margin | 892 | 267 | 68 | 232 | 54 | — | 1,513 | |||||||||||||||||||||
Operating and maintenance expense | (294 | ) | (122 | ) | (107 | ) | (143 | ) | (28 | ) | (1 | ) | (695 | ) | ||||||||||||||
Depreciation expense | (257 | ) | (167 | ) | (19 | ) | (21 | ) | (26 | ) | (4 | ) | (494 | ) | ||||||||||||||
Impairments | (64 | ) | — | (645 | ) | (148 | ) | — | — | (857 | ) | |||||||||||||||||
General and administrative expense | — | — | — | — | — | (117 | ) | (117 | ) | |||||||||||||||||||
Acquisition and integration costs | — | — | — | 8 | — | (16 | ) | (8 | ) | |||||||||||||||||||
Other | — | — | — | (15 | ) | — | (1 | ) | (16 | ) | ||||||||||||||||||
Operating income (loss) | $ | 277 | $ | (22 | ) | $ | (703 | ) | $ | (87 | ) | $ | — | $ | (139 | ) | $ | (674 | ) |
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Total | |||||||||||||||||||||
Revenues, net of hedges, attributable to newly acquired ENGIE plants for the first quarter of 2017 | $ | 180 | $ | 167 | $ | 321 | $ | — | $ | — | $ | — | $ | 668 | ||||||||||||||
Higher (lower) realized power prices | 51 | 94 | — | (9 | ) | (42 | ) | 27 | 121 | |||||||||||||||||||
Lower generation volumes (1) | (39 | ) | (40 | ) | — | (59 | ) | — | (15 | ) | (153 | ) | ||||||||||||||||
Higher (lower) capacity revenues | 9 | 12 | — | 7 | 37 | (14 | ) | 51 | ||||||||||||||||||||
Change in MTM value of derivative transactions | (66 | ) | (52 | ) | — | 51 | (1 | ) | (4 | ) | (72 | ) | ||||||||||||||||
Lower contract amortization | 14 | 1 | — | — | 5 | 7 | 27 | |||||||||||||||||||||
Other (2) | 6 | 5 | — | 2 | (1 | ) | (17 | ) | (5 | ) | ||||||||||||||||||
Total change in revenues | $ | 155 | $ | 187 | $ | 321 | $ | (8 | ) | $ | (2 | ) | $ | (16 | ) | $ | 637 |
(1) | Decrease primarily due to unit shutdowns at our MISO and IPH segments, higher outages at our PJM and CAISO segments, milder weather at our PJM, NY/NE, MISO and IPH segments, and a plant retirement at our NY/NE segment. |
(2) | Other primarily consists of ancillary, tolling, transmission and gas revenues. |
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Total | |||||||||||||||||||||
Cost of sales attributable to newly acquired ENGIE plants for the first quarter of 2017 | $ | 80 | $ | 79 | $ | 209 | $ | — | $ | — | $ | — | $ | 368 | ||||||||||||||
Higher (lower) prices | 124 | 129 | — | (9 | ) | (5 | ) | 12 | 251 | |||||||||||||||||||
Higher (lower) burn volumes (1) | (38 | ) | (51 | ) | — | (49 | ) | 31 | (13 | ) | (120 | ) | ||||||||||||||||
Lower (higher) contract amortization | 31 | (17 | ) | — | — | 12 | — | 26 | ||||||||||||||||||||
Other (2) | 13 | 3 | — | 1 | (15 | ) | — | 2 | ||||||||||||||||||||
Total change in cost of sales | $ | 210 | $ | 143 | $ | 209 | $ | (57 | ) | $ | 23 | $ | (1 | ) | $ | 527 |
(1) | Lower burn volumes primarily due to unit shutdowns at our MISO and IPH segments, higher outages at our PJM and CAISO segments, milder weather at our PJM, NY/NE, MISO and IPH segments, and a plant retirement at our NY/NE segment; offsetting increase primarily due to higher market prices at our IPH segment. |
(2) | Other primarily consists of transmission expenses. |
Nine Months Ended September 30, | ||||||||
Description | 2017 | 2016 | ||||||
Materials and supplies inventory | $ | 14 | $ | — | ||||
Property, plant and equipment, net | 119 | 848 | ||||||
Equity investment | — | 9 | ||||||
Assets held-for-sale (Lee) | 15 | — | ||||||
Total | $ | 148 | $ | 857 |
Nine Months Ended September 30, 2017 | ||||||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | ERCOT | MISO | IPH | CAISO | Other | Total | ||||||||||||||||||||||||
Net income | $ | 167 | ||||||||||||||||||||||||||||||
Income tax benefit | (330 | ) | ||||||||||||||||||||||||||||||
Other income and expense, net | (65 | ) | ||||||||||||||||||||||||||||||
Loss on early extinguishment of debt | 75 | |||||||||||||||||||||||||||||||
Interest expense | 478 | |||||||||||||||||||||||||||||||
Earnings from unconsolidated investments | (4 | ) | ||||||||||||||||||||||||||||||
Bankruptcy reorganization items | (494 | ) | ||||||||||||||||||||||||||||||
Operating income (loss) | $ | 178 | $ | (72 | ) | $ | (8 | ) | $ | (90 | ) | $ | 40 | $ | (33 | ) | $ | (188 | ) | $ | (173 | ) | ||||||||||
Depreciation and amortization expense | 293 | 179 | 55 | 34 | 38 | 44 | 6 | 649 | ||||||||||||||||||||||||
Bankruptcy reorganization items | — | — | — | — | 494 | — | — | 494 | ||||||||||||||||||||||||
Earnings from unconsolidated investments | 2 | 2 | — | — | — | — | — | 4 | ||||||||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | — | — | — | (75 | ) | (75 | ) | ||||||||||||||||||||||
Other income and expense, net | 16 | — | — | — | 26 | — | 23 | 65 | ||||||||||||||||||||||||
EBITDA | 489 | 109 | 47 | (56 | ) | 598 | 11 | (234 | ) | 964 | ||||||||||||||||||||||
Adjustments to reflect Adjusted EBITDA to exclude earnings from unconsolidated investments and noncontrolling interest | 4 | 2 | — | — | (1 | ) | — | — | 5 | |||||||||||||||||||||||
Acquisition and integration costs | — | — | — | — | — | — | 55 | 55 | ||||||||||||||||||||||||
Bankruptcy reorganization items | — | — | — | — | (494 | ) | — | — | (494 | ) | ||||||||||||||||||||||
Mark-to-market adjustments, including warrants | 28 | 6 | (9 | ) | (18 | ) | (2 | ) | 3 | (16 | ) | (8 | ) | |||||||||||||||||||
Impairments | 49 | — | — | 99 | — | — | — | 148 | ||||||||||||||||||||||||
Loss (gain) on sale of assets, net | 31 | 77 | — | — | (1 | ) | — | — | 107 | |||||||||||||||||||||||
Loss on early extinguishment of debt | — | — | — | — | — | — | 75 | 75 | ||||||||||||||||||||||||
Non-cash compensation expense | — | — | — | — | — | — | 16 | 16 | ||||||||||||||||||||||||
Other | 1 | — | — | — | (1 | ) | — | (1 | ) | (1 | ) | |||||||||||||||||||||
Adjusted EBITDA | $ | 602 | $ | 194 | $ | 38 | $ | 25 | $ | 99 | $ | 14 | $ | (105 | ) | $ | 867 |
Nine Months Ended September 30, 2016 | ||||||||||||||||||||||||||||
(amounts in millions) | PJM | NY/NE | MISO | IPH | CAISO | Other | Total | |||||||||||||||||||||
Net loss | $ | (1,062 | ) | |||||||||||||||||||||||||
Income tax expense | 6 | |||||||||||||||||||||||||||
Other income and expense, net | (60 | ) | ||||||||||||||||||||||||||
Interest expense | 449 | |||||||||||||||||||||||||||
Earnings from unconsolidated investments | (7 | ) | ||||||||||||||||||||||||||
Operating income (loss) | $ | 277 | $ | (22 | ) | $ | (703 | ) | $ | (87 | ) | $ | — | $ | (139 | ) | $ | (674 | ) | |||||||||
Depreciation and amortization expense | 259 | 190 | 23 | 20 | 33 | 4 | 529 | |||||||||||||||||||||
Earnings from unconsolidated investments | 7 | — | — | — | — | — | 7 | |||||||||||||||||||||
Other income and expense, net | 9 | — | — | 15 | 12 | 24 | 60 | |||||||||||||||||||||
EBITDA | 552 | 168 | (680 | ) | (52 | ) | 45 | (111 | ) | (78 | ) | |||||||||||||||||
Acquisition, integration and restructuring costs | — | — | — | (8 | ) | — | 21 | 13 | ||||||||||||||||||||
Mark-to-market adjustments, including warrants | (43 | ) | (27 | ) | 33 | (3 | ) | (1 | ) | (5 | ) | (46 | ) | |||||||||||||||
Impairments | 64 | — | 645 | 148 | — | — | 857 | |||||||||||||||||||||
Non-cash compensation expense | 1 | 1 | — | — | — | 16 | 18 | |||||||||||||||||||||
Other (1) | 2 | — | 21 | (3 | ) | 1 | 3 | 24 | ||||||||||||||||||||
Adjusted EBITDA | $ | 576 | $ | 142 | $ | 19 | $ | 82 | $ | 45 | $ | (76 | ) | $ | 788 |
(1) | Other primarily includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the nine months ended September 30, 2016. Adjusted EBITDA did not include this adjustment for the nine months ended September 30, 2017. |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 (1) | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 1,351 | $ | 1,239 | $ | 112 | ||||||
Capacity | 367 | 302 | 65 | |||||||||
Mark-to-market income, net | — | 61 | (61 | ) | ||||||||
Contract amortization | (16 | ) | (35 | ) | 19 | |||||||
Other | 57 | 37 | 20 | |||||||||
Total operating revenues | 1,759 | 1,604 | 155 | |||||||||
Operating costs | ||||||||||||
Cost of sales | (931 | ) | (748 | ) | (183 | ) | ||||||
Contract amortization | 9 | 36 | (27 | ) | ||||||||
Total operating costs | (922 | ) | (712 | ) | (210 | ) | ||||||
Gross margin | 837 | 892 | (55 | ) | ||||||||
Operating and maintenance expense | (296 | ) | (294 | ) | (2 | ) | ||||||
Depreciation expense | (283 | ) | (257 | ) | (26 | ) | ||||||
Impairments | (49 | ) | (64 | ) | 15 | |||||||
Loss on sale of assets | (31 | ) | — | (31 | ) | |||||||
Operating income | 178 | 277 | (99 | ) | ||||||||
Depreciation and amortization expense | 293 | 259 | 34 | |||||||||
Earnings from unconsolidated investments | 2 | 7 | (5 | ) | ||||||||
Other income and expense, net | 16 | 9 | 7 | |||||||||
EBITDA | 489 | 552 | (63 | ) | ||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments | 4 | — | 4 | |||||||||
Mark-to-market adjustments | 28 | (43 | ) | 71 | ||||||||
Impairments | 49 | 64 | (15 | ) | ||||||||
Loss on sale of assets | 31 | — | 31 | |||||||||
Non-cash compensation expense | — | 1 | (1 | ) | ||||||||
Other | 1 | 2 | (1 | ) | ||||||||
Adjusted EBITDA | $ | 602 | $ | 576 | $ | 26 | ||||||
Million Megawatt Hours Generated | 38.8 | 39.3 | (0.5 | ) | ||||||||
IMA (2): | ||||||||||||
Combined-Cycle Facilities | 93 | % | 97 | % | ||||||||
Coal-Fired Facilities | 71 | % | 81 | % | ||||||||
Average Capacity Factor (3): | ||||||||||||
Combined-Cycle Facilities | 63 | % | 75 | % | ||||||||
Coal-Fired Facilities | 54 | % | 51 | % | ||||||||
CDDs (4) | 1,085 | 1,377 | (292 | ) | ||||||||
HDDs (4) | 2,606 | 3,056 | (450 | ) | ||||||||
Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||
PJM West | $ | 16.79 | $ | 23.79 | $ | (7.00 | ) | |||||
AD Hub | $ | 18.05 | $ | 28.88 | $ | (10.83 | ) | |||||
Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||
PJM West | $ | 33.62 | $ | 34.77 | $ | (1.15 | ) | |||||
AD Hub | $ | 33.76 | $ | 32.66 | $ | 1.10 | ||||||
Average natural gas price—TetcoM3 ($/MMBtu) (7) | $ | 2.40 | $ | 1.57 | $ | 0.83 |
(1) | Includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(3) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(4) | Reflects CDDs or HDDs for the PJM Region based on NOAA data. |
(5) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(6) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Income attributable to newly acquired plants | $ | 62 | ||
Lower energy margin primarily due to the following: | ||||
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather | $ | (51 | ) | |
Lower generation volumes primarily due to higher outages and milder weather | $ | (30 | ) | |
Lower retail contribution as a result of higher supply costs and milder weather | $ | (8 | ) | |
Higher capacity revenues as a result of higher pricing and performance penalties in 2016 | $ | 9 | ||
Change in MTM value of derivative transactions | $ | (66 | ) | |
Lower contract amortization | $ | (17 | ) | |
Lower O&M costs associated with outages in 2016 and lower costs from long-term service agreements | $ | 17 | ||
Lower impairment charges | $ | 15 | ||
Loss on sale of assets due to the Conesville and Zimmer ownership interest exchange | $ | (31 | ) |
(in millions) | ||||
Contribution from newly acquired plants | $ | 75 | ||
Lower energy margin primarily due to the following: | ||||
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather | $ | (38 | ) | |
Lower generation volumes primarily due to higher outages and milder weather | $ | (35 | ) | |
Lower retail contribution as a result of higher supply costs and milder weather | $ | (8 | ) | |
Higher capacity revenues as a result of higher pricing and performance penalties in 2016 | $ | 9 | ||
Lower O&M costs associated with outages in 2016 and lower costs from long-term service agreements | $ | 15 | ||
Net casualty loss insurance reimbursement | $ | 7 |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 (1) | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 619 | $ | 430 | $ | 189 | ||||||
Capacity | 182 | 128 | 54 | |||||||||
Mark-to-market income (loss), net | (6 | ) | 41 | (47 | ) | |||||||
Contract amortization | (8 | ) | (6 | ) | (2 | ) | ||||||
Other | 28 | 35 | (7 | ) | ||||||||
Total operating revenues | 815 | 628 | 187 | |||||||||
Operating costs | ||||||||||||
Cost of sales | (505 | ) | (345 | ) | (160 | ) | ||||||
Contract amortization | 1 | (16 | ) | 17 | ||||||||
Total operating costs | (504 | ) | (361 | ) | (143 | ) | ||||||
Gross margin | 311 | 267 | 44 | |||||||||
Operating and maintenance expense | (135 | ) | (122 | ) | (13 | ) | ||||||
Depreciation expense | (171 | ) | (167 | ) | (4 | ) | ||||||
Loss on sale of assets | (77 | ) | — | (77 | ) | |||||||
Operating loss | (72 | ) | (22 | ) | (50 | ) | ||||||
Depreciation and amortization expense | 179 | 190 | (11 | ) | ||||||||
Earnings from unconsolidated investments | 2 | — | 2 | |||||||||
EBITDA | 109 | 168 | (59 | ) | ||||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments | 2 | — | 2 | |||||||||
Mark-to-market adjustments | 6 | (27 | ) | 33 | ||||||||
Loss on sale of assets | 77 | — | 77 | |||||||||
Non-cash compensation expense | — | 1 | (1 | ) | ||||||||
Adjusted EBITDA | $ | 194 | $ | 142 | $ | 52 | ||||||
Million Megawatt Hours Generated | 14.6 | 13.1 | 1.5 | |||||||||
IMA for Combined-Cycle Facilities (2) | 91 | % | 95 | % | ||||||||
Average Capacity Factor for Combined-Cycle Facilities (3) | 42 | % | 50 | % | ||||||||
CDDs (4) | 687 | 874 | (187 | ) | ||||||||
HDDs (4) | 3,543 | 3,658 | (115 | ) | ||||||||
Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||
New York—Zone C | $ | 13.30 | $ | 17.37 | $ | (4.07 | ) | |||||
Mass Hub | $ | 11.63 | $ | 14.49 | $ | (2.86 | ) | |||||
Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||
New York—Zone C | $ | 29.01 | $ | 26.74 | $ | 2.27 | ||||||
Mass Hub | $ | 33.97 | $ | 34.44 | $ | (0.47 | ) | |||||
Average natural gas price—Algonquin Citygates ($/MMBtu) (7) | $ | 3.19 | $ | 2.85 | $ | 0.34 |
(1) | Adjusted EBITDA includes the activity of the assets acquired in the ENGIE Acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility. |
(3) | Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility. |
(4) | Reflects CDDs or HDDs for the ISO-NE Region based on NOAA data. |
(5) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(6) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Income attributable to newly acquired plants in 2017 | $ | 27 | ||
Lower energy margin due to the following: | ||||
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather | $ | (8 | ) | |
Lower generation volumes as a result of milder weather and the retirement of our Brayton Point facility | $ | (11 | ) | |
Higher capacity revenues as a result of higher pricing, offset by capacity lost due to the retirement of our Brayton Point facility | $ | 12 | ||
Change in MTM value of derivative transactions | $ | (52 | ) | |
Lower contract amortization | $ | 18 | ||
Lower depreciation primarily due to the retirement of our Brayton Point facility | $ | 37 | ||
Loss on sale of our Dighton and Milford-MA facilities | $ | (77 | ) |
(in millions) | ||||
Contribution from newly acquired plants in 2017 | $ | 70 | ||
Lower energy margin due to the following: | ||||
Lower spark spreads, net of hedges as a result of higher gas costs and milder weather | $ | (24 | ) | |
Lower generation volumes as a result of milder weather and the retirement of our Brayton Point facility | $ | (12 | ) | |
Higher capacity revenues as a result of higher pricing, offset by capacity lost due to the retirement of our Brayton Point facility | $ | 12 |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 305 | $ | — | N/A | |||||||
Mark-to-market income, net | 9 | — | N/A | |||||||||
Other | 7 | — | N/A | |||||||||
Total operating revenues | 321 | — | N/A | |||||||||
Operating costs | ||||||||||||
Cost of sales | (209 | ) | — | N/A | ||||||||
Total operating costs | (209 | ) | — | N/A | ||||||||
Gross margin | 112 | — | N/A | |||||||||
Operating and maintenance expense | (66 | ) | — | N/A | ||||||||
Depreciation expense | (54 | ) | — | N/A | ||||||||
Impairments | — | — | — | |||||||||
Operating loss | (8 | ) | — | N/A | ||||||||
Depreciation and amortization expense | 55 | — | N/A | |||||||||
EBITDA | 47 | — | N/A | |||||||||
Mark-to-market adjustments | (9 | ) | — | N/A | ||||||||
Adjusted EBITDA | $ | 38 | $ | — | N/A | |||||||
Million Megawatt Hours Generated (1) | 8.8 | — | N/A | |||||||||
IMA (1)(2): | ||||||||||||
Combined-Cycle Facilities | 89 | % | — | % | ||||||||
Coal-Fired Facility | 95 | % | — | % | ||||||||
Average Capacity Factor (1)(3): | ||||||||||||
Combined-Cycle Facilities | 30 | % | — | % | ||||||||
Coal-Fired Facility | 63 | % | — | % | ||||||||
CDDs (4) | 3,026 | 2,909 | 117 | |||||||||
HDDs (4) | 509 | 788 | (279 | ) | ||||||||
Average Market On-Peak Spark Spreads ($/MWh) (5): | ||||||||||||
ERCOT North | $ | 8.16 | $ | 10.60 | $ | (2.44 | ) | |||||
Average Market On-Peak Power Prices ($/MWh) (6): | ||||||||||||
ERCOT North | $ | 27.17 | $ | 25.72 | $ | 1.45 | ||||||
Average natural gas price—Waha Hub ($/MMBtu) (7) | $ | 2.72 | $ | 2.16 | $ | 0.56 |
(1) | Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA excludes such activity for our period of ownership in February. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(3) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(4) | Reflects CDDs or HDDs for the ERCOT Region based on NOAA data. |
(5) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(6) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(7) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Energy margin, net of hedges | $ | 103 | ||
MTM gain | $ | 9 | ||
O&M costs | $ | (66 | ) | |
Depreciation expense | $ | (54 | ) |
(in millions) | ||||
Energy margin, net of hedges | $ | 103 | ||
O&M costs | $ | (65 | ) |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 246 | $ | 313 | $ | (67 | ) | |||||
Capacity | 27 | 20 | 7 | |||||||||
Mark-to-market income (loss), net | 18 | (33 | ) | 51 | ||||||||
Other | 1 | — | 1 | |||||||||
Total operating revenues | 292 | 300 | (8 | ) | ||||||||
Operating costs | ||||||||||||
Cost of sales | (175 | ) | (232 | ) | 57 | |||||||
Total operating costs | (175 | ) | (232 | ) | 57 | |||||||
Gross margin | 117 | 68 | 49 | |||||||||
Operating and maintenance expense | (86 | ) | (107 | ) | 21 | |||||||
Depreciation expense | (22 | ) | (19 | ) | (3 | ) | ||||||
Impairments | (99 | ) | (645 | ) | 546 | |||||||
Operating loss | (90 | ) | (703 | ) | 613 | |||||||
Depreciation and amortization expense | 34 | 23 | 11 | |||||||||
EBITDA | (56 | ) | (680 | ) | 624 | |||||||
Mark-to-market adjustments | (18 | ) | 33 | (51 | ) | |||||||
Impairments | 99 | 645 | (546 | ) | ||||||||
Other (1) | — | 21 | (21 | ) | ||||||||
Adjusted EBITDA | $ | 25 | $ | 19 | $ | 6 | ||||||
Million Megawatt Hours Generated | 8.8 | 11.2 | (2.4 | ) | ||||||||
IMA for Coal-Fired Facilities (2) | 90 | % | 89 | % | ||||||||
Average Capacity Factor for Coal-Fired Facilities (3) | 71 | % | 61 | % | ||||||||
CDDs (4) | 1,167 | 1,529 | (362 | ) | ||||||||
HDDs (4) | 2,610 | 3,006 | (396 | ) | ||||||||
Average Market On-Peak Power Prices ($/MWh) (5): | ||||||||||||
Indiana (Indy Hub) | $ | 34.91 | $ | 32.32 | $ | 2.59 | ||||||
Commonwealth Edison (NI Hub) | $ | 32.49 | $ | 31.54 | $ | 0.95 |
(1) | Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million for the nine months ended September 30, 2016. Adjusted EBITDA did not include this adjustment for the nine months ended September 30, 2017. |
(2) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. |
(3) | Reflects actual production as a percentage of available capacity. |
(4) | Reflects CDDs or HDDs for the MISO Region based on NOAA data. |
(5) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (13 | ) | |
Lower generation volumes as a result of shutdowns in 2016 | $ | (10 | ) | |
Change in fuel and transportation costs related to Wood River | $ | 14 | ||
Higher capacity revenues due to favorable pricing and volumes | $ | 7 | ||
Change in MTM value of derivative transactions | $ | 51 | ||
Lower O&M costs primarily due to shutdowns in 2016 | $ | 21 | ||
Higher depreciation expense | $ | (3 | ) | |
Lower impairment charges primarily due to our Baldwin facility in 2016 | $ | 546 |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (15 | ) | |
Lower generation volumes as a result of shutdowns in 2016 | $ | (5 | ) | |
Higher capacity revenues due to favorable pricing and volumes | $ | 7 | ||
Lower O&M costs primarily due to shutdowns in 2016 | $ | 18 |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 440 | $ | 482 | $ | (42 | ) | |||||
Capacity | 131 | 94 | 37 | |||||||||
Mark-to-market income, net | 2 | 3 | (1 | ) | ||||||||
Contract amortization | (5 | ) | (10 | ) | 5 | |||||||
Other | 4 | 5 | (1 | ) | ||||||||
Total operating revenues | 572 | 574 | (2 | ) | ||||||||
Operating costs | ||||||||||||
Cost of sales | (371 | ) | (360 | ) | (11 | ) | ||||||
Contract amortization | 6 | 18 | (12 | ) | ||||||||
Total operating costs | (365 | ) | (342 | ) | (23 | ) | ||||||
Gross margin | 207 | 232 | (25 | ) | ||||||||
Operating and maintenance expense | (133 | ) | (143 | ) | 10 | |||||||
Depreciation expense | (35 | ) | (21 | ) | (14 | ) | ||||||
Impairments | — | (148 | ) | 148 | ||||||||
Acquisition and integration costs | — | 8 | (8 | ) | ||||||||
Other | 1 | (15 | ) | 16 | ||||||||
Operating income (loss) | 40 | (87 | ) | 127 | ||||||||
Depreciation and amortization expense | 38 | 20 | 18 | |||||||||
Bankruptcy reorganization items | 494 | — | 494 | |||||||||
Other income and expense, net | 26 | 15 | 11 | |||||||||
EBITDA | 598 | (52 | ) | 650 | ||||||||
Adjustment to exclude noncontrolling interest | (1 | ) | — | (1 | ) | |||||||
Acquisition and integration costs | — | (8 | ) | 8 | ||||||||
Bankruptcy reorganization items | (494 | ) | — | (494 | ) | |||||||
Mark-to-market adjustments | (2 | ) | (3 | ) | 1 | |||||||
Impairments | — | 148 | (148 | ) | ||||||||
Gain on sale of assets, net | (1 | ) | — | (1 | ) | |||||||
Other | (1 | ) | (3 | ) | 2 | |||||||
Adjusted EBITDA | $ | 99 | $ | 82 | $ | 17 | ||||||
Million Megawatt Hours Generated | 12.6 | 11.6 | 1.0 | |||||||||
IMA (1) | 87 | % | 88 | % | ||||||||
Average Capacity Factor for IPH Facilities (2) | 57 | % | 45 | % | ||||||||
CDDs (3) | 1,167 | 1,529 | (362 | ) | ||||||||
HDDs (3) | 2,610 | 3,006 | (396 | ) | ||||||||
Average Market On-Peak Power Prices ($/MWh) (4): | ||||||||||||
Indiana (Indy Hub) | $ | 34.91 | $ | 32.32 | $ | 2.59 | ||||||
Commonwealth Edison (NI Hub) | $ | 32.49 | $ | 31.54 | $ | 0.95 |
(1) | IMA is an internal measurement calculation that reflects the percentage of generation available during periods when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(2) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(3) | Reflects CDDs or HDDs for the MISO Region based on NOAA data. |
(4) | Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (12 | ) | |
Lower retail contribution as a result of milder weather | $ | (41 | ) | |
Higher capacity revenues due to favorable pricing and volumes | $ | 37 | ||
Change in MTM value of derivative transactions | $ | (1 | ) | |
Termination of an above market coal supply contract in 2016 | $ | 15 | ||
Lower O&M costs due to lower ARO accretion, property taxes, and outage costs | $ | 10 | ||
Higher depreciation and amortization | $ | (21 | ) | |
Absence of impairment charges due to our Newton facility in 2016 | $ | 148 |
(in millions) | ||||
Lower energy margin due to the following: | ||||
Lower dark spreads, net of hedges as a result of milder weather | $ | (12 | ) | |
Lower retail contribution as a result of milder weather | $ | (41 | ) | |
Higher capacity revenues due to favorable pricing and volumes | $ | 37 | ||
AER proceeds | $ | 25 | ||
Lower O&M costs due to lower property taxes, and outage costs | $ | 8 |
Nine Months Ended September 30, | Favorable (Unfavorable) $ Change | |||||||||||
(dollars in millions, except for price information) | 2017 | 2016 | ||||||||||
Operating revenues | ||||||||||||
Energy | $ | 75 | $ | 62 | $ | 13 | ||||||
Capacity | 15 | 29 | (14 | ) | ||||||||
Mark-to-market income (loss), net | (3 | ) | 1 | (4 | ) | |||||||
Contract amortization | — | (7 | ) | 7 | ||||||||
Other | 2 | 20 | (18 | ) | ||||||||
Total operating revenues | 89 | 105 | (16 | ) | ||||||||
Operating costs | ||||||||||||
Cost of sales | (50 | ) | (51 | ) | 1 | |||||||
Total operating costs | (50 | ) | (51 | ) | 1 | |||||||
Gross margin | 39 | 54 | (15 | ) | ||||||||
Operating and maintenance expense | (32 | ) | (28 | ) | (4 | ) | ||||||
Depreciation expense | (40 | ) | (26 | ) | (14 | ) | ||||||
Operating loss | (33 | ) | — | (33 | ) | |||||||
Depreciation and amortization expense | 44 | 33 | 11 | |||||||||
Other income and expense, net | — | 12 | (12 | ) | ||||||||
EBITDA | 11 | 45 | (34 | ) | ||||||||
Mark-to-market adjustments | 3 | (1 | ) | 4 | ||||||||
Other | — | 1 | (1 | ) | ||||||||
Adjusted EBITDA | $ | 14 | $ | 45 | $ | (31 | ) | |||||
Million Megawatt Hours Generated | 1.5 | 2.0 | (0.5 | ) | ||||||||
IMA for Combined-Cycle Facilities (1) | 85 | % | 96 | % | ||||||||
Average Capacity Factor for Combined-Cycle Facilities (2) | 23 | % | 27 | % | ||||||||
CDDs (3) | 1,126 | 1,051 | 75 | |||||||||
HDDs (3) | 834 | 737 | 97 | |||||||||
Average Market On-Peak Spark Spreads ($/MWh) (4): | ||||||||||||
North of Path 15 (NP 15) | $ | 13.89 | $ | 12.32 | $ | 1.57 | ||||||
Average natural gas price—PG&E Citygate ($/MMBtu) (5) | $ | 3.29 | $ | 2.52 | $ | 0.77 |
(1) | IMA is an internal measurement calculation that reflects the percentage of generation available when market prices are such that these units could be profitably dispatched. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes CTs. |
(2) | Reflects actual production as a percentage of available capacity. The calculation excludes CTs. |
(3) | Reflects CDDs or HDDs for the CAISO Region based on NOAA data. |
(4) | Reflects the average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. |
(5) | Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us. |
(in millions) | ||||
Higher energy margin, net of hedges due to higher spark spreads as a result of warmer weather, offset by lower generation volumes for a portion of the year | $ | 13 | ||
Lower capacity revenues due to lower contracted volumes and prices | $ | (14 | ) | |
Lower tolling revenue due to expiration of tolling agreement | $ | (16 | ) | |
Change in MTM value of derivative transactions | $ | (4 | ) | |
Higher O&M costs due to higher ARO accretion | $ | (4 | ) | |
Higher depreciation and amortization | $ | (7 | ) |
(in millions) | ||||
Higher energy margin, net of hedges due to higher spark spreads as a result of warmer weather, offset by lower generation volumes for a portion of the year | $ | 13 | ||
Lower capacity revenues due to lower contracted volumes and prices | $ | (14 | ) | |
Lower tolling revenue due to expiration of tolling agreement | $ | (16 | ) | |
Supplier settlement in 2016 | $ | (12 | ) |
2017 | 2018 | 2019 to 2021 | ||||
Generation volumes hedged | 87% | 71% | 12% | |||
Coal requirements contracted (1) | 100% | 93% | 33% | |||
Coal requirements priced (1) | 100% | 93% | 21% | |||
Coal transportation requirements contracted (1) | 100% | 100% | 100% |
(1) | Excludes non-operated jointly-owned generating units. |
2017-2018 | 2018-2019 | 2019-2020 | 2020-2021 | |||||||||||||||||||||||||
(price per MW-day) | Legacy Capacity | CP | Base | CP | Base | CP | CP | |||||||||||||||||||||
RTO zone (1) | $ | 120.00 | $ | 151.50 | $ | 149.98 | $ | 164.77 | $ | 80.00 | $ | 100.00 | $ | 88.32 | ||||||||||||||
MAAC zone | $ | 120.00 | $ | 151.50 | $ | 149.98 | $ | 164.77 | $ | 80.00 | $ | 100.00 | $ | 86.04 | ||||||||||||||
EMAAC zone | $ | 120.00 | $ | 151.50 | $ | 210.63 | $ | 225.42 | $ | 99.77 | $ | 119.77 | $ | 187.87 | ||||||||||||||
COMED zone | $ | 120.00 | $ | 151.50 | $ | 200.21 | $ | 215.00 | $ | 182.77 | $ | 202.77 | $ | 188.12 | ||||||||||||||
ATSI zone | $ | 120.00 | $ | 151.50 | $ | 149.98 | $ | 164.77 | $ | 80.00 | $ | 100.00 | $ | 76.53 | ||||||||||||||
PPL zone | $ | 120.00 | $ | 151.50 | $ | 75.00 | $ | 164.77 | $ | 80.00 | $ | 100.00 | $ | 86.04 |
(1) | Planning Year 2020-2021 includes DEOK zone which broke out from RTO zone at $130.00 per MW-day. |
2017-2018 | 2018-2019 | 2019-2020 | 2020-2021 | |||||
Legacy/Base auction capacity sold, net (MW) | 2,871 | 1,910 | 1,413 | — | ||||
CP auction capacity sold, net (MW) | 6,666 | 7,142 | 7,500 | 7,862 | ||||
Bilateral capacity sold, net (MW) | 2 | 270 | 200 | 200 | ||||
Total segment capacity sold, net (MW) | 9,539 | 9,322 | 9,113 | 8,062 | ||||
Average price per MW-day | $143.63 | $181.86 | $130.79 | $130.14 |
2017 | 2018 | 2019 to 2021 | ||||
Generation volumes hedged (1) | 100% | 60% | 9% |
(1) | Excludes volumes subject to tolling agreements. |
Summer 2017 | Winter 2017-2018 | |||
Price per kW-month | $3.00 | $0.37 |
Summer 2017 | Winter 2017-2018 | Summer 2018 | Winter 2018-2019 | Summer 2019 | Winter 2019-2020 | Summer 2020 | ||||||||
Auction capacity sold (MW) | 83 | — | — | — | — | — | — | |||||||
Bilateral capacity sold (MW) | 870 | 1,021 | 745 | 430 | 255 | 160 | 75 | |||||||
Total capacity sold (MW) | 953 | 1,021 | 745 | 430 | 255 | 160 | 75 | |||||||
Average price per kW-month | $3.36 | $2.08 | $3.34 | $2.75 | $3.39 | $2.94 | $3.15 |
2016-2017 | 2017-2018 | 2018-2019 | 2019-2020 | 2020-2021 | ||||||
Price per kW-month | $3.15 | $7.03 | $9.55 | $7.03 | $5.30 |
2017-2018 | 2018-2019 | 2019-2020 | 2020-2021 | |||||
Auction capacity sold (MW) | 3,129 | 3,167 | 3,203 | 3,229 | ||||
Bilateral capacity sold (MW) | 148 | 77 | 30 | — | ||||
Total capacity sold (MW) | 3,277 | 3,244 | 3,233 | 3,229 | ||||
Average price per kW-month | $6.97 | $9.99 | $7.02 | $5.39 |
2017 | 2018 | 2019 to 2021 | ||||
Generation volumes hedged | 100% | 79% | 8% | |||
Coal requirements contracted | 100% | 100% | —% | |||
Coal requirements priced | 100% | 100% | —% | |||
Coal transportation requirements contracted | 100% | 100% | —% |
2017 | 2018 | 2019 to 2021 | ||||
Generation volumes hedged | 77% | 64% | 6% | |||
Coal requirements contracted | 100% | 76% | 40% | |||
Coal requirements priced | 100% | 76% | —% | |||
Coal transportation requirements contracted | 100% | 98% | 96% |
2017 | 2018 | 2019 to 2021 | ||||
Generation volumes hedged | 70% | 56% | 23% | |||
Coal requirements contracted | 100% | 47% | 27% | |||
Coal requirements priced | 91% | 43% | —% | |||
Coal transportation requirements contracted | 100% | 100% | 100% |
2017-2018 | ||
Price per MW-day | $1.50 |
2017-2018 | 2018-2019 | 2019-2020 | 2020-2021 | |||||
MISO Segment: | ||||||||
Bilateral capacity sold in MISO (MW) | 1,075 | 342 | 185 | 385 | ||||
Legacy/Base auction capacity sold in PJM (MW) | 207 | — | — | — | ||||
CP auction capacity sold in PJM (MW) | — | — | — | 38 | ||||
Total MISO segment capacity sold (MW) | 1,282 | 342 | 185 | 423 | ||||
Average price per kW-month | $2.97 | $2.69 | $2.60 | $3.03 | ||||
IPH Segment: | ||||||||
Bilateral capacity sold in MISO (MW) | 2,431 | 1,971 | 930 | 674 | ||||
Legacy/Base auction capacity sold in PJM (MW) | 365 | — | 260 | — | ||||
CP auction capacity sold in PJM (MW) | 472 | 835 | 356 | 406 | ||||
Total IPH segment capacity sold (MW) | 3,268 | 2,806 | 1,546 | 1,080 | ||||
Average price per kW-month | $4.32 | $4.85 | $3.95 | $4.12 |
2017 | 2018 | 2019 to 2021 | ||||
Generation volumes hedged | 65% | 86% | 10% |
Remainder of 2017 | 2018 | 2019 | ||||
Bilateral capacity sold (Avg. MW) | 737 | 444 | 850 |
(amounts in millions) | Less than 1 Year | 1 - 3 Years | 3 - 5 Years | More than 5 Years | Total | |||||||||||||||
ELG expenditures (1) | $ | — | $ | 52 | $ | 155 | $ | 38 | $ | 245 |
(1) | Projections have not been adjusted to reflect the pending AES transaction. Please read Note 10—Joint Ownership of Generating Facilities for further discussion. |
(amounts in millions) | As of and for the Nine Months Ended September 30, 2017 | |||
Fair value of portfolio at December 31, 2016 | $ | 6 | ||
Risk management gains recognized through the statement of operations in the period, net | 35 | |||
Contracts realized or otherwise settled during the period | 3 | |||
Acquired derivatives | 9 | |||
Change in collateral/margin netting | (32 | ) | ||
Fair value of portfolio at September 30, 2017 | $ | 21 |
(amounts in millions) | Total | 2017 | 2018 | 2019 | 2020 | 2021 | Thereafter | |||||||||||||||||||||
Market quotations (1)(2) | $ | (3 | ) | $ | 4 | $ | (11 | ) | $ | (7 | ) | $ | — | $ | 2 | $ | 9 | |||||||||||
Prices based on models (2) | 2 | (2 | ) | (2 | ) | 3 | 3 | — | — | |||||||||||||||||||
Total (3) | $ | (1 | ) | $ | 2 | $ | (13 | ) | $ | (4 | ) | $ | 3 | $ | 2 | $ | 9 |
(3) | Excludes $22 million of broker margin that has been netted against Risk management liabilities in our unaudited consolidated balance sheets. Please read Note 5—Risk Management Activities, Derivatives and Financial Instruments for further discussion. |
• | expectations regarding the Merger, including beliefs concerning stockholder and regulatory approvals; |
• | the occurrence of any event that could give rise to the termination of the Merger Agreement, including a termination of the Merger Agreement under circumstances that could require us to pay a termination fee; |
• | beliefs and assumptions about weather and general economic conditions; |
• | beliefs, assumptions, and projections regarding the demand for power, generation volumes, and commodity pricing, including natural gas prices and the timing of a recovery in power market prices, if any; |
• | beliefs and assumptions about market competition, generation capacity, and regional supply and demand characteristics of the wholesale and retail power markets, including the anticipation of plant retirements and higher market pricing over the longer term; |
• | sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof; |
• | the effects of, or changes to the power and capacity procurement processes in the markets in which we operate; |
• | expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect; |
• | beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters; |
• | projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; |
• | our focus on safety and our ability to operate our assets efficiently so as to capture revenue generating opportunities and operating margins; |
• | our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; |
• | our ability to optimize our assets through targeted investment in cost effective technology enhancements; |
• | the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; |
• | efforts to secure retail sales and the ability to grow the retail business; |
• | efforts to identify opportunities to reduce congestion and improve busbar power prices; |
• | ability to mitigate impacts associated with expiring RMR and/or capacity contracts; |
• | expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments; |
• | expectations regarding performance standards and capital and maintenance expenditures; |
• | the timing and anticipated benefits to be achieved through our company-wide improvement programs; |
• | expectations regarding strengthening the balance sheet, managing debt maturities and improving Dynegy’s leverage profile; |
• | expectations, timing and benefits of the AES transaction; |
• | efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures; |
• | anticipated timing, outcome, and impact of expected retirements; |
• | beliefs about the costs and scope of the ongoing demolition and site remediation efforts; and |
• | expectations regarding the synergies and anticipated benefits resulting from the ENGIE Acquisition. |
(amounts in millions) | September 30, 2017 | December 31, 2016 | ||||||
One day VaR—95 percent confidence level | $ | 9 | $ | 38 | ||||
One day VaR—99 percent confidence level | $ | 12 | $ | 53 | ||||
Average VaR—95 percent confidence level for the rolling twelve months ended | $ | 16 | $ | 14 |
(amounts in millions) | Investment Grade Quality | Non-Investment Grade Quality | Total | |||||||||
Type of Business: | ||||||||||||
Financial institutions | $ | 42 | $ | 1 | $ | 43 | ||||||
Oil and gas producers | 8 | — | 8 | |||||||||
Utility and power generators | 14 | — | 14 | |||||||||
Commercial/industrial/end users | 1 | — | 1 | |||||||||
Total | $ | 65 | $ | 1 | $ | 66 |
September 30, 2017 | December 31, 2016 | |||||||
Interest rate swaps (in millions of U.S. dollars) | $ | 1,963 | $ | 769 | ||||
Fixed interest rate paid (percent) | 2.38 | % | 3.19 | % |
Exhibit Number | Description | ||
2.1 | Agreement and Plan of Merger, dated as of October 29, 2017, by and between Dynegy Inc. and Vistra Energy Corp.* (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443). | ||
4.1 | Indenture, dated August 21, 2017, by and among Dynegy Inc., the Guarantors and Wilmington Trust, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K of Dynegy Inc. filed on August 21, 2017 File No. 001-33443). | ||
4.2 | Registration Rights Agreement, dated August 21, 2017, by and among Dynegy Inc., the Guarantors and Goldman Sachs & Co. LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K of Dynegy Inc. filed on August 21, 2017 File No. 001-33443). | ||
10.1 | Amendment No. 1 to the Investor Rights Agreement by and between Dynegy Inc. and Terawatt Holdings, LP (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on September 6, 2017 File No. 001-33443). | ||
10.2 | Merger Support Agreement, dated as of October 29, 2017, by and between Dynegy Inc. and Stockholders of Vistra Energy Corp. Party Thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443). | ||
10.3 | First Amendment to Amended and Restated Employment Agreement, dated as of October 29, 2017, by and between Dynegy Operating Company and Robert Flexon (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on October 30, 2017 File No. 001-33443). | ||
**31.1 | |||
**31.2 | |||
†32.1 | |||
†32.2 | |||
**101.INS | XBRL Instance Document | ||
**101.SCH | XBRL Taxonomy Extension Schema Document | ||
**101.CAL | XBRL Taxonomy Extension Calculation Linkbase Document | ||
**101.DEF | XBRL Taxonomy Extension Definition Linkbase Document | ||
**101.LAB | XBRL Taxonomy Extension Label Linkbase Document | ||
**101.PRE | XBRL Taxonomy Extension Presentation Linkbase Document |
** | Filed herewith. |
* | Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Dynegy will furnish the omitted schedules and exhibits to the Securities and Exchange Commission upon request by the Commission. |
† | Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act. |
DYNEGY INC. | |||
Date: | November 1, 2017 | By: | /s/ CLINT C. FREELAND |
Clint C. Freeland Executive Vice President and Chief Financial Officer |
1. | I have reviewed this report on Form 10-Q of Dynegy Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this quarterly report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | November 1, 2017 | By: | /s/ ROBERT C. FLEXON |
Robert C. Flexon President and Chief Executive Officer |
1. | I have reviewed this report on Form 10-Q of Dynegy Inc.; |
2. | Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; |
3. | Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; |
4. | The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have: |
(a) | Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; |
(b) | Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; |
(c) | Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and |
(d) | Disclosed in this quarterly report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and |
5. | The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions): |
(a) | All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and |
(b) | Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting. |
Date: | November 1, 2017 | By: | /s/ CLINT C. FREELAND |
Clint C. Freeland Executive Vice President and Chief Financial Officer |
(1) | the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. |
Date: | November 1, 2017 | By: | /s/ ROBERT C. FLEXON |
Robert C. Flexon President and Chief Executive Officer |
(1) | the Report fully complies with the requirements of Section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934, and |
(2) | the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company at the dates and for the periods indicated. |
Date: | November 1, 2017 | By: | /s/ CLINT C. FREELAND |
Clint C. Freeland Executive Vice President and Chief Financial Officer |
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end
Document and Entity Information - shares |
9 Months Ended | |
---|---|---|
Sep. 30, 2017 |
Oct. 31, 2017 |
|
Document and Entity Information [Abstract] | ||
Entity Registrant Name | DYNEGY INC. | |
Entity Central Index Key | 0001379895 | |
Document Type | 10-Q | |
Document Period End Date | Sep. 30, 2017 | |
Amendment Flag | false | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Large Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 131,378,891 | |
Document Fiscal Year Focus | 2017 | |
Document Fiscal Period Focus | Q3 |
CONSOLIDATED BALANCE SHEETS (PARENTHETICAL) - USD ($) $ in Millions |
9 Months Ended | 12 Months Ended |
---|---|---|
Sep. 30, 2017 |
Dec. 31, 2016 |
|
Allowance for doubtful accounts | $ 1 | $ 1 |
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized (in shares) | 420,000,000 | 420,000,000 |
Common stock, shares issued (in shares) | 142,699,979 | 128,626,740 |
Common stock, shares outstanding (in shares) | 131,373,857 | 117,300,618 |
Series A 5.375% mandatory convertible preferred stock | ||
Preferred stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Preferred stock, series A 5.375% | 5.375% | 5.375% |
Preferred stock, shares authorized (in shares) | 20,000,000 | 20,000,000 |
Preferred stock, shares issued (in shares) | 4,000,000 | 4,000,000 |
Preferred stock, shares outstanding (in shares) | 4,000,000 | 4,000,000 |
CONSOLIDATED STATEMENTS OF OPERATIONS - USD ($) shares in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Income Statement [Abstract] | ||||
Revenues | $ 1,437,000,000 | $ 1,184,000,000 | $ 3,848,000,000 | $ 3,211,000,000 |
Cost of sales, excluding depreciation expense | (787,000,000) | (660,000,000) | (2,225,000,000) | (1,698,000,000) |
Gross margin | 650,000,000 | 524,000,000 | 1,623,000,000 | 1,513,000,000 |
Operating and maintenance expense | (236,000,000) | (218,000,000) | (750,000,000) | (695,000,000) |
Depreciation expense | (202,000,000) | (163,000,000) | (611,000,000) | (494,000,000) |
Impairments | (29,000,000) | (212,000,000) | (148,000,000) | (857,000,000) |
Loss on sale of assets, net | (78,000,000) | 0 | (107,000,000) | 0 |
General and administrative expense | (44,000,000) | (41,000,000) | (126,000,000) | (117,000,000) |
Acquisition and integration costs | (3,000,000) | (7,000,000) | (55,000,000) | (8,000,000) |
Other | 0 | 0 | 1,000,000 | (16,000,000) |
Operating income (loss) | 58,000,000 | (117,000,000) | (173,000,000) | (674,000,000) |
Bankruptcy reorganization items (Note 18) | 12,000,000 | 0 | 494,000,000 | 0 |
Earnings from unconsolidated investments | 4,000,000 | 4,000,000 | 4,000,000 | 7,000,000 |
Interest expense | (161,000,000) | (166,000,000) | (478,000,000) | (449,000,000) |
Loss on early extinguishment of debt (Note 12) | (66,000,000) | 0 | (75,000,000) | 0 |
Other income and expense, net | 19,000,000 | 29,000,000 | 65,000,000 | 60,000,000 |
Loss before income taxes | (134,000,000) | (250,000,000) | (163,000,000) | (1,056,000,000) |
Income tax benefit (expense) (Note 14) | 1,000,000 | 1,000,000 | 330,000,000 | (6,000,000) |
Net income (loss) | (133,000,000) | (249,000,000) | 167,000,000 | (1,062,000,000) |
Less: Net loss attributable to noncontrolling interest | (1,000,000) | 0 | (2,000,000) | (2,000,000) |
Net income (loss) attributable to Dynegy Inc. | (132,000,000) | (249,000,000) | 169,000,000 | (1,060,000,000) |
Less: Dividends on preferred stock | 5,000,000 | 5,000,000 | 16,000,000 | 16,000,000 |
Net income (loss) attributable to Dynegy Inc. common stockholders | $ (137,000,000) | $ (254,000,000) | $ 153,000,000 | $ (1,076,000,000) |
Earnings (Loss) Per Share (Note 16): | ||||
Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share) | $ (0.89) | $ (1.81) | $ 1.01 | $ (8.54) |
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders (in dollars per share) | $ (0.89) | $ (1.81) | $ 0.96 | $ (8.54) |
Basic shares outstanding (in shares) | 154 | 140 | 152 | 126 |
Diluted shares outstanding (in shares) | 154 | 140 | 159 | 126 |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Statement of Comprehensive Income [Abstract] | ||||
Net income (loss) | $ (133) | $ (249) | $ 167 | $ (1,062) |
Other comprehensive income before reclassifications: | ||||
Actuarial gain and plan amendment (net of tax of zero, zero, $4, and zero for each respective period) | 0 | 0 | 11 | 0 |
Amounts reclassified from accumulated other comprehensive income: | ||||
Amortization of unrecognized prior service credit (net of tax of zero for each respective period) | (2) | (2) | (6) | (4) |
Other comprehensive income (loss), net of tax | (2) | (2) | 5 | (4) |
Comprehensive income (loss) | (135) | (251) | 172 | (1,066) |
Less: Comprehensive loss attributable to noncontrolling interest | (1) | 0 | (2) | (2) |
Total comprehensive income (loss) attributable to Dynegy Inc. | $ (134) | $ (251) | $ 174 | $ (1,064) |
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (PARENTHETICAL) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Statement of Comprehensive Income [Abstract] | ||||
Tax on actuarial loss | $ 0 | $ 0 | $ 4 | $ 0 |
Tax on amortization of unrecognized prior service cost (credit) and actuarial loss (gain) | $ 0 | $ 0 | $ 0 | $ 0 |
Basis of Presentation and Organization |
9 Months Ended |
---|---|
Sep. 30, 2017 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Basis of Presentation and Organization | Note 1—Basis of Presentation and Organization The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements, but does not include all disclosures required by the Generally Accepted Accounting Principles of the United States of America (“GAAP”). The unaudited consolidated financial statements contained in this report include all material adjustments of a normal recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Certain prior period amounts in our unaudited consolidated financial statements have been reclassified to conform to current year presentation. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 24, 2017, which we refer to as our “Form 10-K.” Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. We sell electric energy, capacity and ancillary services primarily on a wholesale basis from our power generation facilities. We also serve residential, municipal, commercial and industrial customers primarily in MISO, PJM and NY/NE through our Homefield Energy and Dynegy Energy Services retail businesses. We report the results of our power generation business as six segments in our unaudited consolidated financial statements: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 19—Segment Information for further discussion. On February 2, 2017 (the “Emergence Date”), Illinois Power Generating Company (“Genco”) emerged from bankruptcy. Please read Note 18—Genco Chapter 11 Bankruptcy and Emergence for further discussion. |
Accounting Policies |
9 Months Ended |
---|---|
Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Accounting Policies | Note 2—Accounting Policies The accounting policies followed by the Company are set forth in Note 2—Summary of Significant Accounting Policies in our Form 10-K. The accompanying unaudited consolidated financial statements include our accounts and the accounts of our majority-owned or controlled subsidiaries. Accounting policies for all of our operations are in accordance with GAAP. Except for the adoption of new policies as described below, there have been no significant changes to our accounting policies during the nine months ended September 30, 2017. Use of Estimates. The preparation of unaudited consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures, and other factors. Accounting Standards Adopted Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. We adopted this ASU on January 1, 2017 and applied the amendments on a retrospective basis. The adoption of this ASU affected the classification of prepayments for future planned outage work performed under long-term service agreements. The majority of the cash prepayments required under these agreements will now be reflected as cash outflows from investing activities and the remainder will be classified as cash outflows from operating activities, based on whether they are anticipated to be expensed or capitalized. As a result of the retrospective application of this ASU, we reclassified approximately $80 million of cash prepayments from operating activities to investing activities in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016. In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explains the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted this ASU as of January 1, 2017 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, changes in restricted cash of $1 million and $2.045 billion previously reflected as cash flows from operating activities and investing activities, respectively, are now reflected in Net increase (decrease) in cash, cash equivalents, and restricted cash in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016. Additionally, restricted cash of $39 million and $2.085 billion are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016. Please read Note 7—Cash Flow Information for further discussion. Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. We adopted this ASU on January 1, 2017 with no material impact on our unaudited consolidated financial statements. Goodwill. In January 2017, the FASB issued ASU 2017-04-Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. To simplify the subsequent measure of goodwill, the amendments in this ASU eliminate step two from the goodwill impairment test. An entity will no longer be required to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination to determine the impairment of goodwill. The amendments in this ASU will now require goodwill impairment to be measured by the amount by which the carrying value of the reporting unit exceeds its fair value. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Upon adoption, an entity shall apply the guidance in this ASU prospectively with early adoption permitted for annual goodwill tests performed after January 1, 2017. We adopted this ASU on January 1, 2017 with no material impact on our unaudited consolidated financial statements. Accounting Standards Not Yet Adopted Business Combinations. In January 2017, the FASB issued ASU 2017-01-Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this ASU clarify the definition of a business. The amendments affect all companies and other reporting organizations that must determine whether they have acquired or sold a business. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our unaudited consolidated financial statements. Pensions. In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments of this ASU require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and below the subtotal of operating income. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The adoption of this standard must be applied on a retrospective basis for the amendments concerning income statement presentation and on a prospective basis for the amendments regarding the capitalization of the service cost component. We are currently evaluating this ASU and any potential impacts the adoption will have on our unaudited consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The provisions in this ASU will require lessees to recognize lease assets and lease liabilities, for all leases, including operating leases, on the balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets or lease liabilities for leases with a term of 12 months or less. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our unaudited consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements and industry specific guidance and develops a common revenue recognition standard whereby an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenues and cash flows from contracts with customers. The guidance in this ASU and its amendments are effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We have established an implementation team to assess the impact the new accounting standard will have on our financial statements upon adoption and have not currently identified any material changes to the timing of our revenue recognition. We continue to assess the impact of the standard by reviewing our revenue contracts to determine if changes in our recognition policies or controls are necessary. We believe changes to our disclosures will primarily include a regional presentation of our revenues disaggregated by revenue type - energy, capacity, and ancillary services. |
Acquisitions and Divestitures |
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Business Combinations [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Acquisitions and Divestitures | Note 3—Acquisitions and Divestitures Acquisition ENGIE Acquisition. On February 7, 2017 (the “ENGIE Acquisition Closing Date”), pursuant to the terms of the stock purchase agreement, as amended and restated on June 27, 2016, (the “ENGIE Acquisition Stock Purchase Agreement”), Dynegy acquired approximately 9,017 MW of generation from GDF SUEZ Energy North America, Inc. (“GSENA”) and International Power, S.A. (the “Seller”), including (i) 15 natural gas-fired facilities located in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, (ii) one coal-fired facility in Texas, and (iii) one waste coal-fired facility in Pennsylvania for a base purchase price of approximately $3.3 billion in cash, subject to certain adjustments (the “ENGIE Acquisition”). Business Combination Accounting. The ENGIE Acquisition has been accounted for in accordance with ASC 805, Business Combinations, with identifiable assets acquired and liabilities assumed recorded at their estimated fair values on the acquisition date, February 7, 2017. A summary of the various techniques used to fair value the identifiable assets and liabilities, as well as their classification within the fair value hierarchy are listed below.
We also used management’s forecasts of operations and maintenance expense, general and administrative expense, as well as capital expenditures for the years 2017 through 2021, and for years thereafter assumed a 2.5 percent growth rate. These cash flows were discounted using discount rates of approximately 9 percent to 13 percent for gas-fired, and approximately 13 percent to 14 percent for coal-fired, generation facilities, based upon the plant’s age, efficiency, region, and years until retirement.
The accounting for the ENGIE Acquisition is not complete because certain information and analysis that may impact our initial valuation is still being obtained or reviewed. Dynegy expects to finalize these amounts during the first quarter of 2018. The significant assets and liabilities for which provisional amounts are recognized are PP&E, deferred income taxes, and taxes other than deferred income taxes. Additionally, some taxes have not yet been finalized with the associated taxing jurisdictions, resulting in a potential change to their fair value at acquisition. These changes may also impact the fair value of the acquired PP&E or deferred tax liability. As such, the provisional amounts recognized are subject to revision until our valuation is completed, not to exceed one year from the ENGIE Acquisition Closing Date, and any material adjustments identified that existed as of the acquisition date will be recognized in the period in which they are identified. The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the ENGIE Acquisition, as of the acquisition date, February 7, 2017:
The following table summarizes certain information related to the ENGIE Acquisition, which is included in our unaudited consolidated statements of operations:
Pro Forma Results. The unaudited pro forma financial results for the nine months ended September 30, 2017 and 2016 assume the ENGIE Acquisition occurred on January 1, 2016. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed as of January 1, 2016, nor are they indicative of future results of operations. The unaudited pro forma financial results for the nine months ended September 30, 2017 and 2016 include adjustments of $35 million and $5 million, respectively, for non-recurring acquisition costs attributable to the ENGIE Acquisition.
AER Acquisition. On April 12, 2017, we received approximately $25 million of cash related to the 2013 AER Acquisition. As a result, we have recorded $25 million in Other income and expense, net in our unaudited consolidated statement of operations for the nine months ended September 30, 2017. Divestitures Troy and Armstrong. On July 11, 2017, Dynegy completed the sale of its equity ownership interests in two peaking facilities in PJM to LS Power (the “Troy and Armstrong Sale”) for approximately $480 million in cash, including adjustments for capital expenditures and working capital. The facilities sold were recently acquired in the ENGIE Acquisition and total 1,269 MW. Lee. On July 10, 2017, Dynegy signed a membership interest purchase agreement (the “Lee Sale Agreement”) with an affiliate of Rockland Capital for the sale of its equity ownership interest in the Lee facility, a natural gas-fueled peaking facility in PJM, for $180 million in cash, plus adjustments for working capital. On October 4, 2017, the FERC approved our sale of Lee, and we completed the sale on October 12, 2017. Our Lee facility, associated inventory, and allocated goodwill of $9 million are classified as long-term assets held-for-sale as of September 30, 2017. Goodwill was allocated based on the relative fair values of the assets sold to the reporting unit. For the three and nine months ended September 30, 2017, we wrote down the carrying value of the assets held-for-sale to the sales price and recognized an impairment of $15 million, which was recorded in Impairments in our unaudited consolidated statements of operations. Dighton and Milford-MA. On September 22, 2017, Dynegy completed the sale of its equity ownership interests in two intermediate natural gas-fueled facilities in NY/NE to Starwood Energy Group for approximately $125 million in cash, including $6 million in working capital adjustments. This sale has fulfilled the mitigation plan approved by FERC regarding the Company’s purchase of ENGIE’s US-based asset portfolio. For the three and nine months ended September 30, 2017, we recognized a loss on sale of assets on our Dighton and Milford-MA facilities of $77 million, which includes $18 million of allocated goodwill. Goodwill was allocated based on the relative fair values of the assets sold to the reporting unit. |
Unconsolidated Investments |
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Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Unconsolidated Investments | Note 4—Unconsolidated Investments Equity Method Investments NELP. In connection with the ENGIE Acquisition, we acquired a 50 percent interest in Northeast Energy, LP (“NELP”), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At September 30, 2017, our equity method investment in NELP included in our unaudited consolidated balance sheets was $154 million. Upon the acquisition, we recognized basis differences in the net assets of approximately $14 million primarily related to PP&E. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. For the three and nine months ended September 30, 2017, we recorded $4 million and $4 million, respectively, in equity earnings related to our investment in NELP which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statements of operations. For the nine months ended September 30, 2017, we received distributions of $9 million, of which $7 million was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our unaudited consolidated statements of cash flows. Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in Elwood Energy, LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (and together with Elwood Energy “Elwood”), to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). As a result, we recorded an impairment charge of $9 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016, to write down our investment in Elwood to the sales price. For the three and nine months ended September 30, 2016, we recorded $4 million and $7 million, respectively, in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statements of operations. For the nine months ended September 30, 2016, we received distributions of $15 million, of which $14 million was considered to be a return of investment using the accumulated earnings approach and reflected as Distributions from unconsolidated investments in our unaudited consolidated statements of cash flows. Note 10—Joint Ownership of Generating Facilities We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases, and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to additional costs. Our share of revenues and operating costs of the jointly owned generating facilities is included within the corresponding financial statement line items in our unaudited consolidated statements of operations. The following tables present the ownership interests of the jointly owned facilities as of September 30, 2017 and December 31, 2016 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies.
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On May 9, 2017, Dynegy finalized the sale of its 40 percent ownership interest in Conesville to American Electric Power (“AEP”) in exchange for AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy now owns 71.9 percent of the Zimmer facility and no longer has an ownership interest in the Conesville facility. No cash was exchanged in the transaction and no additional debt was incurred by either party. AEP returned a previously issued letter of credit totaling $58 million to Dynegy. The acquisition of the additional interest in Zimmer has been accounted for as a business combination using similar fair value methodologies as described in Note 3—Acquisitions and Divestitures. The fair value of the additional Zimmer interest is $27 million and was allocated $14 million to Property, plant and equipment, $14 million to Inventory, and $1 million to ARO liability in our unaudited consolidated balance sheets. As a result of the Conesville sale, we recognized a loss of $31 million for the nine months ended September 30, 2017, representing the difference between the $58 million book value of our transferred interest in Conesville and the $27 million fair value of the acquired interest in Zimmer. On April 21, 2017, Dynegy reached an agreement with AES Ohio Generation, LLC and The Dayton Power and Light Company (collectively, “AES”) under which Dynegy will purchase AES’ 28.1 percent interest in Zimmer and 36 percent interest in Miami Fort for $50 million in cash and the assumption of certain liabilities, subject to customary adjustments. The transaction is expected to close by the end of 2017. |
Risk Management Activities, Derivatives and Financial Instruments |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Risk Management Activities, Derivatives and Financial Instruments | Note 5—Risk Management Activities, Derivatives and Financial Instruments The nature of our business involves commodity market and financial risks. Specifically, we are exposed to commodity price variability related to our power generation business. Our commercial team manages these commodity price risks with financially and physically settled contracts consistent with our commodity risk management policy. Our treasury team manages our interest rate risk. Our commodity risk management policy gives us the flexibility to sell energy and capacity and purchase fuel through a combination of spot market sales and near-term contractual arrangements (generally over a rolling one- to three-year time frame). Our commodity risk management goal is to protect cash flow in the near-term while keeping the ability to capture value longer-term. Many of our contractual arrangements are derivative instruments and are accounted for at fair value as part of Revenues in our unaudited consolidated statements of operations. We have other contractual arrangements such as capacity forward sales arrangements, tolling arrangements, fixed price coal purchases, and retail power sales, which do not receive recurring fair value accounting treatment because these arrangements do not meet the definition of a derivative or are designated as “normal purchase, normal sale,” in accordance with ASC 815, Derivatives and Hedging. As a result, the gains and losses with respect to these arrangements are not reflected in the unaudited consolidated statements of operations until the delivery occurs. Quantitative Disclosures Related to Financial Instruments and Derivatives As of September 30, 2017, we had net purchases and sales of derivative contracts outstanding in the following quantities:
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Derivatives on the Balance Sheet. The following tables present the fair value and balance sheet classification of derivatives in our unaudited consolidated balance sheets as of September 30, 2017 and December 31, 2016. As of September 30, 2017 and December 31, 2016, there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets.
Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to worsen, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. As of September 30, 2017, the aggregate fair value of all commodity derivative instruments containing credit-risk-related contingent features, in a liability position and not fully collateralized, is $9 million for which we have posted no collateral. Transactions with our clearing brokers are excluded as they are fully collateralized. Our remaining derivative instruments do not have credit-related collateral contingencies as they are included within our first-lien collateral program. The following table summarizes our cash collateral posted as of September 30, 2017 and December 31, 2016, within Prepayments and other current assets in our unaudited consolidated balance sheets and the amount applied against short-term risk management activities:
Impact of Derivatives on the Unaudited Consolidated Statements of Operations We elect not to designate derivatives related to our power generation business and interest rate instruments as cash flow or fair value hedges. Thus, we account for changes in the fair value of these derivatives within our unaudited consolidated statements of operations. Our unaudited consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 include the impact of derivative financial instruments as presented below:
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Fair Value Measurements |
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Fair Value Disclosures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Measurements | Note 6—Fair Value Measurements We apply the market approach for recurring fair value measurements, employing valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We have consistently used the same valuation techniques for all periods presented. Please read Note 2—Summary of Significant Accounting Policies—Fair Value Measurements in our Form 10-K for further discussion. The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid:
Level 3 Valuation Methods. The electricity derivatives classified within Level 3 include financial swaps executed in illiquid trading locations or on long dated contracts, capacity contracts and FTRs. The curves used to generate the fair value of the financial swaps are based on basis adjustments applied to forward curves for liquid trading points, while the curves for the capacity deals are based upon auction results in the marketplace, which are infrequently executed. The forward market price of FTRs is derived using historical congestion patterns within the marketplace and heat rate derivative valuations are derived using a DCF model, which uses modeled forward natural gas and power prices. The natural gas derivatives classified within Level 3 include financial swaps, basis swaps, and physical purchases executed in illiquid trading locations or on long dated contracts. Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations. The significant unobservable inputs used in the fair value measurement of our commodity instruments categorized within Level 3 of the fair value hierarchy include estimates of forward congestion, power price spreads, and natural gas pricing, and the difference between our plant locational prices to liquid hub prices. Power price spreads, and natural gas pricing, and the difference between our plant locational prices to liquid hub prices are generally based on observable markets where available, or derived from historical prices and forward market prices from similar observable markets when not available. Increases in the price of the spread on a buy or sell position in isolation would result in a higher/lower fair value measurement. The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of September 30, 2017 are as follows:
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The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:
Gains and losses recognized for Level 3 recurring items are included in Revenues in our unaudited consolidated statements of operations for commodity derivatives. We believe an analysis of commodity instruments classified as Level 3 should be undertaken with the understanding that these items generally serve as economic hedges of our power generation portfolio. Nonfinancial Assets and Liabilities. Nonfinancial assets and liabilities that are measured at fair value on a nonrecurring basis are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of such assets and liabilities and their placement within the fair value hierarchy. Impairments. During the three and nine months ended September 30, 2017 and 2016, we recorded impairment charges related to certain of our facilities, materials and supplies inventory and assets held-for-sale using fair value measurements. See Note 3—Acquisitions and Divestitures, Note 8—Inventory and Note 9—Property, Plant and Equipment for further discussion. Acquisitions. We fair valued the ENGIE Acquisition and our acquisition of additional joint ownership interest in the Zimmer facility using fair value measurements. See Note 3—Acquisitions and Divestitures and Note 10—Joint Ownership of Generating Facilities for further discussion of the fair value hierarchy classifications of valuations of acquired identifiable assets and liabilities. Fair Value of Financial Instruments. The following table discloses the fair value of financial instruments which are not recognized at fair value in our unaudited consolidated balance sheets. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of September 30, 2017 and December 31, 2016, respectively.
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Cash Flow Information |
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Cash and Cash Equivalents [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash Flow Information | Note 7—Cash Flow Information The supplemental disclosures of our non-cash investing and financing information are as follows:
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our unaudited consolidated balance sheets that sum to the total of the same such amounts shown in our unaudited consolidated statements of cash flows:
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Inventory |
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Inventory Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventory | Note 8—Inventory A summary of our inventories is as follows:
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As discussed in Note 10—Joint Ownership of Generating Facilities, Stuart Unit 1 was retired early on September 30, 2017, with remaining Stuart and Killen units scheduled to be retired by mid-2018. We determined that we would not be able to recover the carrying value of our Materials and supplies inventory at these facilities and, as a result, recognized a charge of $14 million in Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2017. |
Property, Plant and Equipment |
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Property, Plant and Equipment | Note 9—Property, Plant and Equipment A summary of our property, plant and equipment is as follows:
Impairments For the three and nine months ended September 30, 2017 and 2016, we recognized the following PP&E impairments in our unaudited consolidated statements of operations (amounts in millions). Each valuation is classified as Level 3 within the fair value hierarchy and is presented as of the date of its impairment.
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Brayton Point Retirement The Brayton Point facility officially retired on June 1, 2017. During the three and nine months ended September 30, 2017, we recognized approximately $7 million and $12 million of severance costs, respectively, which were classified within Operating and maintenance expense in our unaudited consolidated statement of operations. |
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Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Joint Ownership of Generating Facilities | Note 4—Unconsolidated Investments Equity Method Investments NELP. In connection with the ENGIE Acquisition, we acquired a 50 percent interest in Northeast Energy, LP (“NELP”), a joint venture with NextEra Energy, Inc., which indirectly owns the Bellingham NEA facility and the Sayreville facility. At September 30, 2017, our equity method investment in NELP included in our unaudited consolidated balance sheets was $154 million. Upon the acquisition, we recognized basis differences in the net assets of approximately $14 million primarily related to PP&E. These basis differences are being amortized over their respective useful lives. Our risk of loss related to our equity method investment is limited to our investment balance. For the three and nine months ended September 30, 2017, we recorded $4 million and $4 million, respectively, in equity earnings related to our investment in NELP which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statements of operations. For the nine months ended September 30, 2017, we received distributions of $9 million, of which $7 million was considered to be a return of investment using the cumulative earnings approach and reflected as Distributions from unconsolidated investments in our unaudited consolidated statements of cash flows. Elwood. On November 21, 2016, Dynegy sold its 50 percent equity interest in Elwood Energy, LLC, a limited liability company (“Elwood Energy”) and Elwood Expansion LLC, a limited liability company (and together with Elwood Energy “Elwood”), to J-Power USA Development Co. Ltd. for approximately $173 million (the “Elwood Sale”). As a result, we recorded an impairment charge of $9 million to Impairments in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2016, to write down our investment in Elwood to the sales price. For the three and nine months ended September 30, 2016, we recorded $4 million and $7 million, respectively, in equity earnings related to our investment in Elwood, which is reflected in Earnings from unconsolidated investments in our unaudited consolidated statements of operations. For the nine months ended September 30, 2016, we received distributions of $15 million, of which $14 million was considered to be a return of investment using the accumulated earnings approach and reflected as Distributions from unconsolidated investments in our unaudited consolidated statements of cash flows. Note 10—Joint Ownership of Generating Facilities We hold ownership interests in certain jointly owned generating facilities. We are entitled to the proportional share of the generating capacity and the output of each unit equal to our ownership interests. We pay our share of capital expenditures, fuel inventory purchases, and operating expenses, except in certain instances where agreements have been executed to limit certain joint owners’ maximum exposure to additional costs. Our share of revenues and operating costs of the jointly owned generating facilities is included within the corresponding financial statement line items in our unaudited consolidated statements of operations. The following tables present the ownership interests of the jointly owned facilities as of September 30, 2017 and December 31, 2016 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies.
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On May 9, 2017, Dynegy finalized the sale of its 40 percent ownership interest in Conesville to American Electric Power (“AEP”) in exchange for AEP’s 25.4 percent ownership interest in Zimmer. As a result, Dynegy now owns 71.9 percent of the Zimmer facility and no longer has an ownership interest in the Conesville facility. No cash was exchanged in the transaction and no additional debt was incurred by either party. AEP returned a previously issued letter of credit totaling $58 million to Dynegy. The acquisition of the additional interest in Zimmer has been accounted for as a business combination using similar fair value methodologies as described in Note 3—Acquisitions and Divestitures. The fair value of the additional Zimmer interest is $27 million and was allocated $14 million to Property, plant and equipment, $14 million to Inventory, and $1 million to ARO liability in our unaudited consolidated balance sheets. As a result of the Conesville sale, we recognized a loss of $31 million for the nine months ended September 30, 2017, representing the difference between the $58 million book value of our transferred interest in Conesville and the $27 million fair value of the acquired interest in Zimmer. On April 21, 2017, Dynegy reached an agreement with AES Ohio Generation, LLC and The Dayton Power and Light Company (collectively, “AES”) under which Dynegy will purchase AES’ 28.1 percent interest in Zimmer and 36 percent interest in Miami Fort for $50 million in cash and the assumption of certain liabilities, subject to customary adjustments. The transaction is expected to close by the end of 2017. |
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Intangible Assets, Net (Excluding Goodwill) [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangible Assets and Liabilities | Note 11—Intangible Assets and Liabilities The following table summarizes the components of our intangible assets and liabilities as of September 30, 2017 and December 31, 2016:
The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three and nine months ended September 30, 2017 and 2016:
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The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the ENGIE Acquisition in February 2017:
Amortization expense (revenue), net related to intangible assets and liabilities recorded in connection with the ENGIE Acquisition for the next five years as of September 30, 2017 is as follows: 2017—$(3) million, 2018—$11 million, 2019—$17 million, 2020—$4 million and 2021—$(1) million. |
Debt |
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Debt | Note 12—Debt A summary of our long-term debt is as follows:
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Credit Agreement As of September 30, 2017, we had a $3.769 billion credit agreement, as amended, that consisted of (i) a $2.224 billion seven-year senior secured term loan facility (the “Tranche C-1 Term Loan”) and (ii) $1.545 billion in senior secured revolving credit facilities (the “Revolving Facility,” and collectively with the Tranche C-1 Term Loan the “Credit Agreement”). During the nine months ended September 30, 2017, we made the following changes to the Credit Agreement:
At September 30, 2017, there was $300 million drawn on the Revolving Facility. We also had outstanding letters of credit (“LCs”) of approximately $310 million, which reduce the amount available under the Revolving Facility. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a Senior Secured Leverage Ratio (as defined in the Credit Agreement) calculated on a rolling four quarters basis. Under the Credit Agreement, if Dynegy utilizes 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio of 4.00:1.00. Our revolver usage at September 30, 2017 was 39 percent of the aggregate revolver commitment due to outstanding LCs and revolver draws. Based on the calculation outlined in the Credit Agreement, we were in compliance with these covenants as of September 30, 2017. In October 2017, we repaid the outstanding Revolving Facility balance of $300 million. Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Consolidated Senior Secured Net Debt, as defined in the Credit Agreement. Interest Rate Swaps. In March 2017, we amended our existing interest rate swaps to more closely match the terms of our Tranche C-1 Term Loan. The swaps have an aggregate notional value of approximately $763 million at an average fixed rate of 3.03 percent and expire between the second quarter of 2018 and the second quarter of 2020. In a previous extension to the existing interest rate swaps, in lieu of paying the breakage fees related to terminating the old swaps and issuing the new swaps, the costs were incorporated into the terms of the new swaps. As a result, any cash flows related to the settlement of the swaps are reflected as a financing activity in our unaudited consolidated statements of cash flows. Additionally, in May 2017, we entered into new interest rate swap agreements. The swaps have an aggregate notional value of approximately $1.2 billion at an average fixed rate of 1.97 percent, and expire in the first quarter of 2024. Any cash flows related to the settlement of these swaps are reflected as an operating activity in our unaudited consolidated statements of cash flows. Senior Notes The senior notes are unsecured and unsubordinated obligations of the Company and are guaranteed by each of the Company’s current and future wholly-owned domestic subsidiaries that from time to time are a borrower or guarantor under the Credit Agreement. The senior notes indentures limit, among other things, the ability of the Company or any of the guarantors to create liens upon any principal property to secure debt for borrowed money in excess of, among other limitations, 30 percent of total assets. On August 21, 2017, we issued $850 million of 8.125 percent senior notes due 2026 (the “2026 Senior Notes”) in a private placement transaction. Interest is payable semiannually in arrears on January 30 and July 30 of each year, beginning January 30, 2018. Dynegy used the proceeds of the offering, together with proceeds from the sale of certain facilities, and cash-on-hand to repurchase $1.25 billion of its 6.75 percent senior notes due 2019 and repay $200 million of its Tranche C-1 term loan, as noted above. In connection with the extinguishment of a portion of our 2019 senior notes, we recorded a loss on early extinguishment of debt of approximately $58 million in our unaudited consolidated statements of operations for the three and nine months ended September 30, 2017, of which approximately $44 million related to a premium paid in excess of debt principal, approximately $8 million related to the write-off of unamortized deferred financing costs, and approximately $6 million related to fees. The Company, pursuant to a Registration Rights Agreement, has agreed to use commercially reasonable efforts to register the 2026 Senior Notes by August 16, 2018. Otherwise, the 2026 Senior Notes are generally identical in all material respects to Dynegy’s other outstanding senior notes. Amortizing Notes On June 21, 2016, in connection with the issuance of the tangible equity units (“TEUs”), Dynegy issued the Amortizing Notes with a principal amount of approximately $87 million. The Amortizing Notes mature on July 1, 2019. Each installment payment per Amortizing Note will be paid in cash and will constitute a partial repayment of principal and a payment of interest, computed at an annual rate of 7 percent. Interest will be calculated on the basis of a 360 day year consisting of twelve 30 day months. Payments will be applied first to the interest due and payable and then to the reduction of the unpaid principal amount, allocated as set forth in the Indenture. The indenture limits, among other things, the ability of Dynegy to consolidate, merge, sell, or dispose all or substantially all of its assets. If a fundamental change occurs, or if Dynegy elects to settle the prepaid stock contracts (“SPCs”) early, then the holders of the Amortizing Notes will have the right to require Dynegy to repurchase the Amortizing Notes at a repurchase price equal to the principal amount of the Amortizing Notes as of the repurchase date (as described in the supplemental indenture) plus accrued and unpaid interest. The indenture also contains customary events of default which would permit the holders of the Amortizing Notes to declare those Amortizing Notes to be immediately due and payable if not cured within applicable grace periods, including the failure to make timely installment payments on the Amortizing Notes or other material indebtedness, the failure to satisfy covenants, and specified events of bankruptcy and insolvency. Letter of Credit Facilities Dynegy has a Letter of Credit Reimbursement Agreement with an issuing bank, for an LC in an amount not to exceed $55 million. In July 2017, the expiry date of the facility was extended one year, to September 19, 2018. As of September 30, 2017, there was $55 million outstanding under this LC. Following the ENGIE Acquisition Closing Date, Dynegy entered into a Letter of Credit Reimbursement Agreement with an issuing bank, pursuant to which the issuing bank agreed to provide LCs in an amount not to exceed $50 million. The facility matures February 7, 2018 and may be extended at the Lender’s discretion for up to four additional one-year terms. As of September 30, 2017, there was $40 million outstanding under this facility. Forward Capacity Agreement As of September 30, 2017, we have sold a portion of our PJM capacity that cleared for Planning Years 2018-2019, 2019-2020 and 2020-2021 to a financial institution. Dynegy will continue to be subject to the performance obligations as well as any associated performance penalties and bonus payments for those planning years. As a result, this transaction is accounted for as a debt issuance of $241 million with an implied interest rate of 4.9 percent. On March 29, 2017, we replaced an existing Planning Year 2017-2018 contract in the amount of $110 million, with a Planning Year 2019-2020 contract in the amount of $121 million. On July 7, 2017, we replaced $99 million of $109 million of an existing Planning Year 2018-2019 contract with a Planning Year 2020-2021 contract in the amount of $110 million. Inventory Financing Agreements Brayton Point Inventory Financing. On May 31, 2017, the Brayton Point inventory financing agreement terminated and the remaining obligation was paid. The Brayton Point facility officially retired on June 1, 2017. Emissions Repurchase Agreements. In August 2015, we entered into two repurchase transactions with a third party in which we sold approximately $78 million of RGGI inventory and received cash. In February 2017, we repurchased approximately $30 million of the previously sold RGGI inventory. We are obligated to repurchase the remaining inventory in February 2018 at a specified price with an annualized carry cost of approximately 3.49 percent. As of September 30, 2017, there was $48 million, in aggregate, outstanding under these agreements. Equipment Financing Agreements Under certain of our contractual service agreements in which we receive maintenance and capital improvements for our gas-fueled generation fleet, we have obtained parts and equipment intended to increase the output, efficiency, and availability of our generation units. We have financed these parts and equipment under agreements with maturities ranging from 2017 to 2025. The portion of future payments attributable to principal will be classified as cash outflows from financing activities, and the portion of future payments attributable to interest will be classified as cash outflows from operating activities in our unaudited consolidated statements of cash flows. The related assets were recorded at the net present value of the payments of $112 million. The $27 million discount is currently being amortized as interest expense over the life of the payments. |
Commitments and Contingencies |
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Commitments and Contingencies Disclosure [Abstract] | |
Commitments and Contingencies | Note 13—Commitments and Contingencies Legal Proceedings Set forth below is a summary of our material ongoing legal proceedings. We record accruals for estimated losses from contingencies when available information indicates that a loss is probable and the amount of the loss, or range of loss, can be reasonably estimated. In addition, we disclose matters for which management believes a material loss is reasonably possible. In all instances, management has assessed the matters below based on current information and made judgments concerning their potential outcome, giving consideration to the nature of the claim, the amount, if any, the nature of damages sought, and the probability of success. Management regularly reviews all new information with respect to such contingencies and adjusts its assessments and estimates of such contingencies accordingly. Because litigation is subject to inherent uncertainties including unfavorable rulings or developments, it is possible that the ultimate resolution of our legal proceedings could involve amounts that are different from our currently recorded accruals, and that such differences could be material. In addition to the matters discussed below, we are party to other routine proceedings arising in the ordinary course of business. Any accruals or estimated losses related to these matters are not material. In management’s judgment, the ultimate resolution of these matters will not have a material effect on our financial condition, results of operations, or cash flows. Gas Index Pricing Litigation. We, through our subsidiaries, and other energy companies are named as defendants in several lawsuits claiming damages resulting from alleged price manipulation and false reporting of natural gas prices to various index publications from 2000-2002. The cases allege that the defendants engaged in an antitrust conspiracy to inflate natural gas prices in three states (Kansas, Missouri, and Wisconsin) during the relevant time period. The cases are consolidated in a multi-district litigation proceeding pending in the United States District Court for Nevada. On March 30, 2017, the court denied Plaintiffs’ motion to certify a class action, which will be subject to an interlocutory appeal granted by the Ninth Circuit on June 13, 2017. At this time we cannot reasonably estimate a potential loss. Advatech Dispute. On September 2, 2016, our Genco subsidiary terminated its Second Amended and Restated Newton Flue Gas Desulfurization System Engineering, Procurement, Construction and Commissioning Services Contract dated as of December 15, 2014 with Advatech, LLC. Advatech issued Genco its final invoice on September 30, 2016 totaling $81 million. Genco contested the invoice on October 3, 2016 and believes the proper amount is less than $1 million. On October 27, 2016, Advatech initiated the dispute resolution process under the Contract and filed for arbitration on March 16, 2017. Settlement discussions required under the dispute resolution process have been unsuccessful. We believe the risk of a material loss related to this dispute to be remote. We dispute the allegations and will defend our position vigorously. Other Contingencies MISO 2015-2016 Planning Resource Auction. In May 2015, three complaints were filed at FERC regarding the Zone 4 results for the 2015-2016 Planning Resource Auction (“PRA”) conducted by MISO. Dynegy is a named party in one of the complaints. The complainants, Public Citizen, Inc., the Illinois Attorney General, and Southwestern Electric Cooperative, Inc., have challenged the results of the PRA as unjust and unreasonable, requested rate relief/refunds, and requested changes to the MISO PRA structure going forward. Complainants have also alleged that Dynegy may have engaged in economic or physical withholding in Zone 4 constituting market manipulation in the 2015-2016 PRA. The Independent Market Monitor for MISO (“MISO IMM”), which was responsible for monitoring the MISO 2015-2016 PRA, determined that all offers were competitive and that no physical or economic withholding occurred. The MISO IMM also stated, in a filing responding to the complaints, that there is no basis for the proposed remedies. We filed our Answer to these complaints and believe that we complied fully with the terms of the MISO tariff in connection with the 2015-2016 PRA, disputed the allegations, and will defend our actions vigorously. In addition, the Illinois Industrial Energy Consumers filed a complaint at FERC against MISO on June 30, 2015 requesting prospective changes to the MISO tariff. Dynegy also responded to this complaint. On October 1, 2015, FERC issued an order of non-public, formal investigation, stating that shortly after the conclusion of the 2015-2016 PRA, FERC’s Office of Enforcement began a non-public informal investigation into whether market manipulation or other potential violations of FERC orders, rules, and regulations occurred before or during the PRA (the “Order”). The Order noted that the investigation is ongoing, and that the order converting the informal, non-public investigation to a formal, non-public investigation does not indicate that FERC has determined that any entity has engaged in market manipulation or otherwise violated any FERC order, rule, or regulation. Dynegy is participating in the investigation. We believe the risk of a material loss related to the investigation to be remote. On December 31, 2015, FERC issued an order on the complaints requiring a number of prospective changes to the MISO tariff provisions associated with calculating Initial Reference Levels and Local Clearing Requirements, effective as of the 2016-2017 PRA. The order did not address the arguments of the complainants regarding the 2015-2016 PRA, and stated that those issues remain under consideration and will be addressed in a future order. New Source Review and CAA Matters. New Source Review. Since 1999, the EPA has been engaged in a nationwide enforcement initiative to determine whether coal-fired power plants failed to comply with the requirements of the New Source Review and New Source Performance Standard provisions under the CAA when the plants implemented modifications. The EPA’s initiative focuses on whether projects performed at power plants triggered various permitting requirements, including the need to install pollution control equipment. In August 2012, the EPA issued a Notice of Violation (“NOV”) alleging that projects performed in 1997, 2006, and 2007 at the Newton facility violated Prevention of Significant Deterioration, Title V permitting, and other requirements. The NOV remains unresolved. We believe our defenses to the allegations described in the NOV are meritorious. A decision by the U.S. Court of Appeals for the Seventh Circuit in 2013 held that similar claims older than five years were barred by the statute of limitations. This decision may provide an additional defense to the allegations in the Newton facility NOV. In September 2016, we retired Newton Unit 2. Zimmer NOVs. In December 2014, the EPA issued an NOV alleging violation of opacity standards at the Zimmer facility, which we co-own and operate. The EPA previously had issued NOVs to Zimmer in 2008 and 2010 alleging violations of the CAA, the Ohio State Implementation Plan, and the station’s air permits involving standards applicable to opacity, sulfur dioxide, sulfuric acid mist, and heat input. The NOVs remain unresolved. We are unable to predict the outcome of these matters. Killen and Stuart NOVs/ Notices of Intent to Sue. The EPA issued NOVs in December 2014 for Killen and Stuart, and in February 2017 for Stuart, alleging violations of opacity standards. In May and June 2017, we received two letters from the Sierra Club providing notice of its intent to sue various Dynegy entities and the owner and operator of the Killen and Stuart facilities, respectively, alleging violations of opacity standards under the CAA. The Dayton Power and Light Company, the operator of Killen and Stuart, is expected to act on behalf of itself and the co-owners with respect to these matters. We are unable to predict the outcome of these matters. Edwards CAA Citizen Suit. In April 2013, environmental groups filed a CAA citizen suit in the U.S. District Court for the Central District of Illinois alleging violations of opacity and particulate matter limits at our IPH segment’s Edwards facility. In August 2016, the District Court granted the plaintiffs’ motion for summary judgment on certain liability issues. We filed a motion seeking interlocutory appeal of the court’s summary judgment ruling. In February 2017, the appellate court denied our motion for interlocutory appeal. The District Court has scheduled the remedy phase trial for October 2018. We dispute the allegations and will defend the case vigorously. Ultimate resolution of any of these CAA matters could have a material adverse impact on our future financial condition, results of operations, and cash flows. A resolution could result in increased capital expenditures for the installation of pollution control equipment, increased operations and maintenance expenses, and penalties. At this time we are unable to make a reasonable estimate of the possible costs, or range of costs, that might be incurred to resolve these matters. Coal Combustion Residuals/ Groundwater. MISO Segment. In 2012, the Illinois EPA (“IEPA”) issued violation notices alleging violations of groundwater standards onsite at our Baldwin and Vermilion facilities’ Coal Combustion Residuals (“CCR”) surface impoundments. In 2016, the IEPA approved our closure and post-closure care plans for the Baldwin old east, east, and west fly ash CCR surface impoundments. We are working towards implementation of those closure plans. At our retired Vermilion facility, which is not subject to the CCR rule, we submitted proposed corrective action plans involving closure of two CCR surface impoundments (i.e., the old east and the north impoundments) to the IEPA in 2012, with revised plans submitted in 2014. In May 2017, in response to a request from the IEPA for additional information regarding the closure of these Vermilion surface impoundments, we agreed to perform additional groundwater sampling and further analysis of closure options and riverbank stabilization options. IPH Segment. In 2012, the IEPA issued violation notices alleging violations of groundwater standards at the Newton and Coffeen facilities’ CCR surface impoundments. We are addressing these CCR surface impoundments in accordance with the CCR rule. If remediation measures concerning groundwater are necessary at any of our coal-fired MISO or IPH Segment facilities, we may incur significant costs that could have a material adverse effect on our financial condition, results of operations, and cash flows. At this time, we cannot reasonably estimate the costs, or range of costs, of remediation, if any, that ultimately may be required. CCR surface impoundment and landfill closure costs are reflected in our AROs. Dam Safety Assessment Reports. The EPA initiated a nationwide investigation of the structural integrity of CCR surface impoundments in 2009. The EPA assessments found all of our surface impoundments to be in satisfactory or fair condition, with the exception of the surface impoundments at the Baldwin and Hennepin facilities. In response to the Hennepin report, we made capital improvements to the Hennepin east CCR surface impoundment berms and notified the EPA of our intent to close the Hennepin west CCR surface impoundment, which is reflected in our AROs. We performed further studies needed to support closure of the west CCR surface impoundment, submitted those studies to the IEPA in 2014 and await IEPA action. In response to the Baldwin report, we notified the EPA of our action plan, which included implementation of recommended operating practices, remedial measures and studies. At this time, to resolve the concerns raised in the EPA’s assessment report and as a result of the CCR rule, we plan to initiate closure of the Baldwin west fly ash CCR surface impoundment in the fourth quarter of 2017, which is reflected in our AROs. Other Commitments In conducting our operations, we routinely enter into long-term commodity purchase and sale commitments, as well as agreements that commit future cash flow to the lease or acquisition of assets used in our businesses. These commitments have been typically associated with commodity supply arrangements, capital projects, reservation charges associated with firm transmission, transportation, storage and leases for office space, equipment, design and construction, plant sites, and power generation assets. Indemnifications and Guarantees In the ordinary course of business, we routinely enter into contractual agreements that contain various representations, warranties, indemnifications and guarantees. Examples of such agreements include, but are not limited to, service agreements, equipment purchase agreements, engineering and technical service agreements, asset sales agreements, and procurement and construction contracts. Some agreements contain indemnities that cover the other party’s negligence or limit the other party’s liability with respect to third party claims, in which event we will effectively be indemnifying the other party. Virtually all such agreements contain representations or warranties that are covered by indemnifications against the losses incurred by the other parties in the event such representations and warranties are false. While there is always the possibility of a loss related to such representations, warranties, indemnifications, and guarantees in our contractual agreements, and such loss could be significant, in most cases management considers the probability of loss to be remote. We have accrued no amounts with respect to the indemnifications as of September 30, 2017 because none were probable of occurring, nor could they be reasonably estimated. |
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Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Taxes | Note 14—Income Taxes Income Tax Benefit. We compute our quarterly taxes under the effective tax rate method based on applying an anticipated annual effective rate to our year-to-date income or loss, except for significant, unusual, or extraordinary transactions. Income taxes for significant, unusual, or extraordinary transactions are computed and recorded in the period that the specific transaction occurs. The income taxes related to income (loss) from continuing operations were as follows:
As of September 30, 2017, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more-likely-than-not our net deferred tax assets can be realized in the future. Unrecognized Tax Benefits. During the first quarter of 2017, we increased our unrecognized tax benefits by $66 million as a result of the ENGIE Acquisition for uncertain tax positions included in GSENA’s tax returns prior to our ownership. The entire $66 million would impact our effective tax rate if recognized. |
Pension and Other Post-Employment Benefit Plans |
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Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Pension and Other Post-Employment Benefit Plans | Note 15—Pension and Other Post-Employment Benefit Plans We sponsor and administer defined benefit plans and defined contribution plans for the benefit of our employees and also provide other post-employment benefits to retirees who meet age and service requirements, which are further described in Note 19—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans in our Form 10-K. In the first quarter of 2017, the Dynegy pension and other post-employment plans were amended as a result of negotiations with former Duke Midwest union participants, IBEW Local 1347. As part of these amendments, the participants’ previous pension plan accrued benefits will be frozen as of December 31, 2017 and will begin accruing on January 1, 2018 with a minimum interest crediting rate of 4 percent. Other post-employment plans were amended to provide retiree medical plan benefits to only certain participants as of January 1, 2018. As a result of these amendments, we remeasured our benefit obligations and funded status of the affected plans and recorded a net-of-tax gain of approximately $15 million through accumulated other comprehensive income during the first quarter of 2017. Components of Net Periodic Benefit Cost (Gain). The components of net periodic benefit cost (gain) were as follows:
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Stockholders' Equity |
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Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stockholders' Equity | Note 16—Stockholders' Equity Preferred Stock We pay quarterly dividends on our mandatory convertible preferred stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors. For each of the nine months ended September 30, 2017 and 2016, we paid $16 million in dividends. On October 2, 2017, our Board of Directors declared a dividend on our mandatory convertible preferred stock of $1.34 per share, or approximately $5 million in the aggregate. The dividend is for the period beginning on August 1, 2017 and ending on October 31, 2017. Such dividends were paid on November 1, 2017, to stockholders of record as of October 15, 2017. In addition, on November 1, 2017 (the “Mandatory Conversion Date”), each share of Preferred Stock converted at 3.2258 shares of Common Stock for a total issuance of approximately 12.9 million shares of Common Stock. Stock Purchase Agreement-Terawatt On February 24, 2016, Dynegy entered into a Stock Purchase Agreement with Terawatt Holdings, LP (“Terawatt”), an affiliate of the ECP Funds, pursuant to which, at the ENGIE Acquisition Closing Date, Dynegy issued to Terawatt 13,711,152 shares of Dynegy common stock for $150 million (the “PIPE Transaction”). ECP Buyout Dynegy settled its payment obligation to Energy Capital Partners (“ECP”) of $375 million on the ENGIE Acquisition Closing Date. This payment is recorded as a reduction in additional paid-in capital in our unaudited consolidated balance sheet and is reflected as a purchase of a noncontrolling interest in financing activities in our unaudited consolidated statement of cash flows as of September 30, 2017. Warrants On October 2, 2017, the warrants to purchase up to 15.6 million shares of Common Stock for an exercise price of $40 per share expired. These warrants were issued to Legacy Dynegy stockholders upon our emergence from bankruptcy on October 1, 2012 and had a five-year term. Earnings (Loss) Per Share Basic earnings (loss) per share is based on the weighted average number of common shares outstanding during the period. Diluted earnings (loss) is based on the weighted average number of common shares used for the basic earnings (loss) per share computation, adjusted for the incremental issuance of shares of common stock assuming (i) our stock options and warrants are exercised under the treasury stock method, (ii) our restricted stock units and performance stock units are fully vested under the treasury stock method, and (iii) our mandatory convertible preferred stock and the SPCs are converted into common stock under the if-converted method. Please read Note 18—Capital Stock and Note 13—Tangible Equity Units in our Form 10-K for further discussion. The following table reflects significant components of our weighted-average shares outstanding used in the basic and diluted loss per share calculations for the three and nine months ended September 30, 2017 and 2016:
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For the three and nine months ended September 30, 2017 and 2016, the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive:
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Accumulated Other Comprehensive Income Changes in accumulated other comprehensive income, net of tax, by component, are as follows:
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Condensed Consolidating Financial Information |
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Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Condensed Consolidating Financial Information | Note 17—Condensed Consolidating Financial Information Dynegy’s senior notes are guaranteed by certain, but not all, of our wholly owned subsidiaries. The following condensed consolidating financial statements present the financial information of (i) Dynegy (“Parent”), which is the parent and issuer of the senior notes, on a stand-alone, unconsolidated basis, (ii) the guarantor subsidiaries of Dynegy, (iii) the non-guarantor subsidiaries of Dynegy, and (iv) the eliminations necessary to arrive at the information for Dynegy on a consolidated basis. The 100 percent owned subsidiary guarantors, jointly, severally, fully, and unconditionally, guarantee the payment obligations under the senior notes. Please read Note 12—Debt for further discussion. These statements should be read in conjunction with the unaudited consolidated financial statements and notes thereto of Dynegy. The supplemental condensed consolidating financial information has been prepared pursuant to the rules and regulations for condensed financial information and does not include all disclosures included in annual financial statements. The inclusion of Dynegy’s subsidiaries as either guarantor subsidiaries or non-guarantor subsidiaries in the condensed consolidating financial information is determined as of the most recent balance sheet date presented. On February 2, 2017, upon Genco’s emergence from bankruptcy, IPH (excluding Electric Energy, Inc.) became a guarantor to the senior notes. Accordingly, condensed consolidating financial information previously reported has been retroactively adjusted to reflect the status of Dynegy’s subsidiaries as either guarantor subsidiaries or non-guarantor subsidiaries as of September 30, 2017. For purposes of the unaudited condensed consolidating financial statements, a portion of our intercompany receivable, which we do not consider to be likely of settlement, has been classified as equity as of September 30, 2017 and December 31, 2016. Condensed Consolidating Balance Sheet as of September 30, 2017 (amounts in millions)
Condensed Consolidating Balance Sheet as of December 31, 2016 (amounts in millions)
Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2016 (amounts in millions)
Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2016 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2016 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2016 (amounts in millions)
Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2016 (amounts in millions)
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Genco Chapter 11 Bankruptcy and Emergence |
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Reorganizations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Genco Chapter 11 Bankruptcy and Emergence | Note 18—Genco Chapter 11 Bankruptcy and Emergence On December 9, 2016, Genco filed a petition (the “Bankruptcy Petition”) under title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (the “Bankruptcy Court”). On January 25, 2017, the Bankruptcy Court confirmed the Genco Plan and Genco emerged from bankruptcy on February 2, 2017. As a result, we eliminated $825 million of Genco senior notes and $7 million of accrued interest in exchange for:
The 2017 Warrants, which have an exercise price of $35 per share of common stock, have a seven-year term expiring on February 2, 2024 and are recorded as Other long-term liabilities in our unaudited consolidated balance sheet as of September 30, 2017. The following table summarizes the Company’s gain from the termination of the Genco senior notes, which is recognized in Bankruptcy reorganization items in our unaudited consolidated statement of operations for the nine months ended September 30, 2017:
Included in the table above is an approximate $12 million gain to Bankruptcy reorganization items recognized for the three months ended September 30, 2017 upon the final payment under the Genco restructuring. For income tax purposes, the income from cancellation of debt is excluded from taxable income in the current year and will instead reduce Genco’s tax attributes. |
Segment Information |
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Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Information | Note 19—Segment Information We report the results of our operations in six segments: (i) PJM, (ii) NY/NE, (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. PJM also includes our Dynegy Energy Services retail business in Ohio and Pennsylvania. NY/NE also includes our Dynegy Energy Services retail business in Massachusetts. IPH also includes our Homefield Energy retail business in Illinois. Our unaudited consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2017 and 2016 is presented below: Segment Data as of and for the Three Months Ended September 30, 2017
Segment Data as of and for the Nine Months Ended September 30, 2017
Segment Data as of and for the Three Months Ended September 30, 2016
Segment Data as of and for the Nine Months Ended September 30, 2016
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Subsequent Events |
9 Months Ended |
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Sep. 30, 2017 | |
Subsequent Events [Abstract] | |
Subsequent Events | Note 20—Subsequent Events On October 29, 2017, Dynegy and Vistra Energy Corp., a Delaware corporation (“Vistra Energy”), entered into an Agreement and Plan of Merger (the “Merger Agreement”). Under the Merger Agreement, which has been approved by the boards of directors of both companies, Dynegy will merge with and into Vistra Energy in a tax-free, all-stock transaction, with Vistra Energy continuing as the surviving corporation (the “Merger”). Under the terms of the agreement, Dynegy stockholders will receive 0.652 shares of Vistra Energy common stock for each share of Dynegy common stock they own, resulting in Vistra Energy stockholders and Dynegy stockholders owning approximately 79 percent and 21 percent, respectively, of the combined company. Completion of the Merger is subject to various customary conditions, including, among others, (a) approval by Vistra Energy’s stockholders of the issuance of the Vistra Energy common stock in the Merger, (b) adoption of the Merger Agreement by Dynegy’s stockholders and Vistra Energy’s stockholders, (c) receipt of all requisite regulatory approvals, which includes, among others, approvals of the FERC, the Public Utility Commission of Texas and the New York Public Service Commission, and the expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, and (d) effectiveness of the registration statement for the shares of Vistra Energy common stock to be issued in the Merger, and the approval of the listing of such shares on the New York Stock Exchange. Each party’s obligation to consummate the Merger is also subject to certain additional customary conditions. The Merger Agreement contains customary representations, warranties and covenants of Dynegy and Vistra Energy, and contains certain termination rights for both Dynegy and Vistra Energy. |
Accounting Policies (Policies) |
9 Months Ended |
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Sep. 30, 2017 | |
Accounting Policies [Abstract] | |
Basis of Presentation | The accompanying unaudited consolidated financial statements have been prepared in accordance with the instructions to interim financial reporting as prescribed by the SEC. The year-end consolidated balance sheet data was derived from audited consolidated financial statements, but does not include all disclosures required by the Generally Accepted Accounting Principles of the United States of America (“GAAP”). The unaudited consolidated financial statements contained in this report include all material adjustments of a normal recurring nature that, in the opinion of management, are necessary for a fair presentation of the results for the interim periods. Certain prior period amounts in our unaudited consolidated financial statements have been reclassified to conform to current year presentation. These interim financial statements should be read together with the consolidated financial statements and notes thereto included in our annual report on Form 10-K for the year ended December 31, 2016, filed with the SEC on February 24, 2017, which we refer to as our “Form 10-K.” Unless the context indicates otherwise, throughout this report, the terms “Dynegy,” “the Company,” “we,” “us,” “our,” and “ours” are used to refer to Dynegy Inc. and its direct and indirect subsidiaries. We sell electric energy, capacity and ancillary services primarily on a wholesale basis from our power generation facilities. We also serve residential, municipal, commercial and industrial customers primarily in MISO, PJM and NY/NE through our Homefield Energy and Dynegy Energy Services retail businesses. We report the results of our power generation business as six segments in our unaudited consolidated financial statements: (i) PJM, (ii) ISO-NE/NYISO (“NY/NE”), (iii) ERCOT, (iv) MISO, (v) IPH, and (vi) CAISO. Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense, and income tax benefit (expense). All significant intercompany transactions have been eliminated. Please read Note 19—Segment Information for further discussion. On February 2, 2017 (the “Emergence Date”), Illinois Power Generating Company (“Genco”) emerged from bankruptcy. Please read Note 18—Genco Chapter 11 Bankruptcy and Emergence for further discussion. |
Use of Estimates | Use of Estimates. The preparation of unaudited consolidated financial statements in conformity with GAAP requires management to make informed estimates and judgments that affect our reported financial position and results of operations based on currently available information. Actual results could differ materially from our estimates. The results of operations for the interim periods presented in this Form 10-Q are not necessarily indicative of the results to be expected for the full year or any other interim period due to seasonal fluctuations in demand for our energy products and services, changes in commodity prices, timing of maintenance and other expenditures, and other factors. |
Accounting Standards Adopted During the Current Period | Accounting Standards Adopted Statement of Cash Flows. In August 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2016-15-Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments. To reduce current and future diversity in practice, the amendments in this ASU provide guidance for several cash flow classification issues identified where current GAAP is either unclear or does not include specific guidance. We adopted this ASU on January 1, 2017 and applied the amendments on a retrospective basis. The adoption of this ASU affected the classification of prepayments for future planned outage work performed under long-term service agreements. The majority of the cash prepayments required under these agreements will now be reflected as cash outflows from investing activities and the remainder will be classified as cash outflows from operating activities, based on whether they are anticipated to be expensed or capitalized. As a result of the retrospective application of this ASU, we reclassified approximately $80 million of cash prepayments from operating activities to investing activities in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016. In November 2016, the FASB issued ASU 2016-18-Statement of Cash Flows (Topic 230): Restricted Cash. The amendments in this ASU require that a statement of cash flows explains the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. We adopted this ASU as of January 1, 2017 and applied the amendments on a retrospective basis. As a result of the retrospective application of this ASU, changes in restricted cash of $1 million and $2.045 billion previously reflected as cash flows from operating activities and investing activities, respectively, are now reflected in Net increase (decrease) in cash, cash equivalents, and restricted cash in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016. Additionally, restricted cash of $39 million and $2.085 billion are now reflected in the beginning of period and end of period cash, cash equivalents and restricted cash line items, respectively, in our unaudited consolidated statement of cash flows for the nine months ended September 30, 2016. Please read Note 7—Cash Flow Information for further discussion. Compensation. In March 2016, the FASB issued ASU 2016-09-Compensation-Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting. The amendments in this ASU simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities and classification on the statement of cash flows. We adopted this ASU on January 1, 2017 with no material impact on our unaudited consolidated financial statements. Goodwill. In January 2017, the FASB issued ASU 2017-04-Intangibles-Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. To simplify the subsequent measure of goodwill, the amendments in this ASU eliminate step two from the goodwill impairment test. An entity will no longer be required to calculate the implied fair value of goodwill by assigning the fair value of a reporting unit to all of its assets and liabilities as if the reporting unit had been acquired in a business combination to determine the impairment of goodwill. The amendments in this ASU will now require goodwill impairment to be measured by the amount by which the carrying value of the reporting unit exceeds its fair value. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Upon adoption, an entity shall apply the guidance in this ASU prospectively with early adoption permitted for annual goodwill tests performed after January 1, 2017. We adopted this ASU on January 1, 2017 with no material impact on our unaudited consolidated financial statements. Accounting Standards Not Yet Adopted Business Combinations. In January 2017, the FASB issued ASU 2017-01-Business Combinations (Topic 805): Clarifying the Definition of a Business. The amendments in this ASU clarify the definition of a business. The amendments affect all companies and other reporting organizations that must determine whether they have acquired or sold a business. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our unaudited consolidated financial statements. Pensions. In March 2017, the FASB issued ASU No. 2017-07, Compensation-Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments of this ASU require an entity to report the service cost component of net benefit costs in the same line item as other compensation costs arising from services rendered by the related employees during the applicable service period. The other components of net benefit cost are required to be presented separately from the service cost component and below the subtotal of operating income. Additionally, only the service cost component of net benefit costs is eligible for capitalization. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2017, with early adoption permitted. The adoption of this standard must be applied on a retrospective basis for the amendments concerning income statement presentation and on a prospective basis for the amendments regarding the capitalization of the service cost component. We are currently evaluating this ASU and any potential impacts the adoption will have on our unaudited consolidated financial statements. Leases. In February 2016, the FASB issued ASU 2016-02-Leases (Topic 842). The provisions in this ASU will require lessees to recognize lease assets and lease liabilities, for all leases, including operating leases, on the balance sheet. The lease assets recognized in the balance sheet will represent a right-of-use asset, which is an asset that represents the lessee’s right to use, or control the use of, a specified asset for the lease term. The lease liability recognized in the balance sheet will represent the lessee’s obligation to make lease payments arising from a lease, measured based on the present value of the minimum rental payments. Entities may make an accounting policy election to not recognize lease assets or lease liabilities for leases with a term of 12 months or less. The guidance in this ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. We are currently evaluating this ASU and any potential impacts the adoption will have on our unaudited consolidated financial statements. Revenue from Contracts with Customers. In May 2014, the FASB issued ASU 2014-09-Revenue from Contracts with Customers (Topic 606). This ASU supersedes current revenue recognition requirements and industry specific guidance and develops a common revenue recognition standard whereby an entity will recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. Additional disclosures will be required to describe the nature, amount, timing, and uncertainty of revenues and cash flows from contracts with customers. The guidance in this ASU and its amendments are effective for interim and annual periods beginning after December 15, 2017, with early adoption permitted for interim and annual periods beginning after December 15, 2016. We have established an implementation team to assess the impact the new accounting standard will have on our financial statements upon adoption and have not currently identified any material changes to the timing of our revenue recognition. We continue to assess the impact of the standard by reviewing our revenue contracts to determine if changes in our recognition policies or controls are necessary. We believe changes to our disclosures will primarily include a regional presentation of our revenues disaggregated by revenue type - energy, capacity, and ancillary services. |
Acquisitions and Divestitures (Tables) |
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Schedule of Recognized Identified Assets Acquired and Liabilities Assumed | The following table summarizes the consideration paid and the provisional fair value amounts recognized for the assets acquired and liabilities assumed related to the ENGIE Acquisition, as of the acquisition date, February 7, 2017:
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Business Acquisition, Pro Forma Information | The unaudited pro forma financial results for the nine months ended September 30, 2017 and 2016 assume the ENGIE Acquisition occurred on January 1, 2016. The unaudited pro forma financial results may not be indicative of the results that would have occurred had the acquisition been completed as of January 1, 2016, nor are they indicative of future results of operations. The unaudited pro forma financial results for the nine months ended September 30, 2017 and 2016 include adjustments of $35 million and $5 million, respectively, for non-recurring acquisition costs attributable to the ENGIE Acquisition.
The following table summarizes certain information related to the ENGIE Acquisition, which is included in our unaudited consolidated statements of operations:
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Risk Management Activities, Derivatives and Financial Instruments (Tables) |
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Derivative Instruments and Hedging Activities Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Derivative Contracts and Interest Rate Swaps | As of September 30, 2017, we had net purchases and sales of derivative contracts outstanding in the following quantities:
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Schedule of Derivative Instruments in the Balance Sheet, Fair Value | The following tables present the fair value and balance sheet classification of derivatives in our unaudited consolidated balance sheets as of September 30, 2017 and December 31, 2016. As of September 30, 2017 and December 31, 2016, there were no gross amounts available to be offset that were not offset in our unaudited consolidated balance sheets.
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Schedule of Derivative Collateral Posted and Location on Balance Sheet | The following table summarizes our cash collateral posted as of September 30, 2017 and December 31, 2016, within Prepayments and other current assets in our unaudited consolidated balance sheets and the amount applied against short-term risk management activities:
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Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations | Our unaudited consolidated statements of operations for the three and nine months ended September 30, 2017 and 2016 include the impact of derivative financial instruments as presented below:
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Fair Value Measurements (Tables) |
9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Fair Value Disclosures [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis | The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2017 and December 31, 2016, and are presented on a gross basis before consideration of amounts netted under master netting agreements and the application of collateral and margin paid:
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Sensitivity to Changes in Significant Unobservable Inputs for Level 3 Valuations | The significant unobservable inputs used in the valuation of Dynegy’s contracts classified as Level 3 as of September 30, 2017 are as follows:
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Schedule of Changes in Fair Value of Financial Instruments | The following tables set forth a reconciliation of changes in the fair value of financial instruments classified as Level 3 in the fair value hierarchy:
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Fair Value of Financial Assets and Liabilities | The following table discloses the fair value of financial instruments which are not recognized at fair value in our unaudited consolidated balance sheets. Unless otherwise noted, the fair value of debt as reflected in the table has been calculated based on the average of certain available broker quotes as of September 30, 2017 and December 31, 2016, respectively.
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Cash Flow Information (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cash and Cash Equivalents [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Cash Flow, Supplemental Disclosures | The supplemental disclosures of our non-cash investing and financing information are as follows:
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Schedule of Cash and Cash Equivalents | The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within our unaudited consolidated balance sheets that sum to the total of the same such amounts shown in our unaudited consolidated statements of cash flows:
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Inventory (Tables) |
9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Inventory Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Summary of Inventories | A summary of our inventories is as follows:
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Property, Plant and Equipment (Tables) |
9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Property, Plant and Equipment [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Property, Plant and Equipment | A summary of our property, plant and equipment is as follows:
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Property, Plant and Equipment Impairment | For the three and nine months ended September 30, 2017 and 2016, we recognized the following PP&E impairments in our unaudited consolidated statements of operations (amounts in millions). Each valuation is classified as Level 3 within the fair value hierarchy and is presented as of the date of its impairment.
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Joint Ownership of Generating Facilities (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments and Joint Ventures [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity Method Investments | The following tables present the ownership interests of the jointly owned facilities as of September 30, 2017 and December 31, 2016 included in our unaudited consolidated balance sheets. Each facility is co-owned with one or more other generation companies.
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Intangible Assets and Liabilities (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangible Assets, Net (Excluding Goodwill) [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Intangible Assets and Liabilities | The following table summarizes the components of our intangible assets and liabilities as of September 30, 2017 and December 31, 2016:
The following table presents our amortization expense (revenue) of intangible assets and liabilities for the three and nine months ended September 30, 2017 and 2016:
__________________________________________
The following table summarizes the components of our contract based intangible assets and liabilities recorded in connection with the ENGIE Acquisition in February 2017:
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Debt (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Debt Disclosure [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Long-term Debt Instruments | A summary of our long-term debt is as follows:
__________________________________________
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Income Taxes Income Taxes (Tables) |
9 Months Ended | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Income Tax Disclosure [Abstract] | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Components of Income Tax Expense (Benefit) | The income taxes related to income (loss) from continuing operations were as follows:
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Pension and Other Post-Employment Benefit Plans (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Retirement Benefits [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Net Benefit Costs | The components of net periodic benefit cost (gain) were as follows:
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Stockholders' Equity (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Earnings Per Share, Basic and Diluted | The following table reflects significant components of our weighted-average shares outstanding used in the basic and diluted loss per share calculations for the three and nine months ended September 30, 2017 and 2016:
_________________________________________
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Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share | For the three and nine months ended September 30, 2017 and 2016, the following potentially dilutive securities were not included in the computation of diluted per share amounts because the effect would be anti-dilutive:
_________________________________________
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Schedule of Accumulated Other Comprehensive Income (Loss) | Changes in accumulated other comprehensive income, net of tax, by component, are as follows:
__________________________________________
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Condensed Consolidating Financial Information (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Condensed Consolidating Balance Sheets | Condensed Consolidating Balance Sheet as of September 30, 2017 (amounts in millions)
Condensed Consolidating Balance Sheet as of December 31, 2016 (amounts in millions)
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Condensed Consolidating Statements of Operations | Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Operations for the Three Months Ended September 30, 2016 (amounts in millions)
Condensed Consolidating Statements of Operations for the Nine Months Ended September 30, 2016 (amounts in millions)
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Condensed Consolidating Statements of Comprehensive Income (Loss) | Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Three Months Ended September 30, 2016 (amounts in millions)
Condensed Consolidating Statements of Comprehensive Income (Loss) for the Nine Months Ended September 30, 2016 (amounts in millions)
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Condensed Consolidating Statements of Cash Flow | Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2017 (amounts in millions)
Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2016 (amounts in millions)
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Genco Chapter 11 Bankruptcy and Emergence (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|---|
Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||
Reorganizations [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Reorganization Items | The following table summarizes the Company’s gain from the termination of the Genco senior notes, which is recognized in Bankruptcy reorganization items in our unaudited consolidated statement of operations for the nine months ended September 30, 2017:
|
Segment Information (Tables) |
9 Months Ended | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Sep. 30, 2017 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Segment Reporting [Abstract] | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Schedule of Segment Reporting Information, by Segment | Reportable segment information, including intercompany transactions accounted for at prevailing market rates, for the three and nine months ended September 30, 2017 and 2016 is presented below: Segment Data as of and for the Three Months Ended September 30, 2017
Segment Data as of and for the Nine Months Ended September 30, 2017
Segment Data as of and for the Three Months Ended September 30, 2016
Segment Data as of and for the Nine Months Ended September 30, 2016
|
Basis of Presentation and Organization (Details) |
9 Months Ended |
---|---|
Sep. 30, 2017
segment
| |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Number of reportable segments | 6 |
Accounting Policies (Details) - USD ($) $ in Millions |
9 Months Ended | ||
---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Dec. 31, 2015 |
|
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net cash provided by (used in) operating activities | $ 501 | $ 728 | |
Net cash provided by (used in) investing activities | $ 2,771 | 313 | |
Accounting Standards Update 2016-15 | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net cash provided by (used in) operating activities | 80 | ||
Net cash provided by (used in) investing activities | 80 | ||
Accounting Standards Update 2016-18 | |||
New Accounting Pronouncements or Change in Accounting Principle [Line Items] | |||
Net cash provided by (used in) operating activities | (1) | ||
Net cash provided by (used in) investing activities | 2,045 | ||
Restricted cash | $ 2,085 | $ 39 |
Acquisitions and Divestitures - Engie Acquisition (Details) - Engie Acquisition $ in Millions |
Feb. 07, 2017
USD ($)
facility
MW
|
---|---|
Business Acquisition [Line Items] | |
Capacity of power facilities acquired (in MW) | MW | 9,017 |
Number of natural gas power facilities acquired | 15 |
Base purchase price | $ | $ 3,300 |
TEXAS | |
Business Acquisition [Line Items] | |
Number of coal-fired power facilities | 1 |
PENNSYLVANIA | |
Business Acquisition [Line Items] | |
Number of coal-fired power facilities | 1 |
Acquisitions and Divestitures - Business Combination Accounting (Details) - Engie Acquisition |
9 Months Ended | 12 Months Ended |
---|---|---|
Sep. 30, 2017 |
Dec. 31, 2027 |
|
Business Acquisition [Line Items] | ||
Operations, maintenance and capital expenditures, growth rate after year five | 2.50% | |
Minimum | Gas | ||
Business Acquisition [Line Items] | ||
Discount rate | 9.00% | |
Minimum | Coal | ||
Business Acquisition [Line Items] | ||
Discount rate | 13.00% | |
Maximum | Gas | ||
Business Acquisition [Line Items] | ||
Discount rate | 13.00% | |
Maximum | Coal | ||
Business Acquisition [Line Items] | ||
Discount rate | 14.00% | |
Scenario, Forecast | ||
Business Acquisition [Line Items] | ||
Long-term growth rate | 2.50% |
Acquisitions and Divestitures - Results Since Acquisition (Details) - Engie Acquisition - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Business Acquisition [Line Items] | ||||
Acquisition costs | $ 0 | $ 3 | $ 35 | $ 5 |
Revenues | 345 | 669 | ||
Operating loss | $ (36) | $ (32) |
Acquisitions and Divestitures - Pro Forma Results (Details) - Engie Acquisition - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Business Acquisition [Line Items] | ||||
Acquisition costs | $ 0 | $ 3 | $ 35 | $ 5 |
Revenue | 3,905 | 3,942 | ||
Net income (loss) | 169 | (1,090) | ||
Parent | ||||
Business Acquisition [Line Items] | ||||
Net income (loss) | $ 171 | $ (1,088) |
Acquisitions and Divestitures - AER Acquisition (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | |||
---|---|---|---|---|---|
Apr. 12, 2017 |
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Business Acquisition [Line Items] | |||||
Other income and expense, net | $ 19 | $ 29 | $ 65 | $ 60 | |
AER Acquisition | |||||
Business Acquisition [Line Items] | |||||
Contingent consideration, liability | $ 25 | ||||
Other income and expense, net | $ 25 |
Risk Management Activities, Derivatives and Financial Instruments - Narratives (Details) |
9 Months Ended |
---|---|
Sep. 30, 2017
USD ($)
| |
Commodity Contract | |
Derivative [Line Items] | |
Credit risk derivative liabilities at fair value | $ 9,000,000 |
Fair value of collateral | $ 0 |
Minimum | |
Derivative [Line Items] | |
Rolling time period over which the entity can sell energy and capacity through near-term contractual arrangements | 1 year |
Maximum | |
Derivative [Line Items] | |
Rolling time period over which the entity can sell energy and capacity through near-term contractual arrangements | 3 years |
Risk Management Activities, Derivatives and Financial Instruments - Schedule of Collateral Posted and Balance Sheet Location (Details) - Commodity Contract - Prepayments and Other Current Assets - USD ($) $ in Millions |
Sep. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Derivative [Line Items] | ||
Gross collateral posted with counterparties | $ 54 | $ 116 |
Less: Collateral netted against risk management liabilities | 22 | 54 |
Net collateral within Prepayments and other current assets | $ 32 | $ 62 |
Risk Management Activities, Derivatives and Financial Instruments - Schedule of Derivative Instruments, Gain (Loss) in the Statement of Operations (Details) - Not Designated as Hedging Instrument - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Commodity Contract | Revenues | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Recognized gain (loss) on derivatives | $ 29 | $ (27) | $ 242 | $ 188 |
Interest Rate Contracts | Interest Expense | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Recognized gain (loss) on derivatives | 1 | 1 | 4 | (11) |
Warrants | Other Income and (Expense), Net | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Recognized gain (loss) on derivatives | $ 1 | $ 4 | $ 16 | $ 5 |
Cash Flow Information - Supplemental Disclosures of Non-cash Investing and Financing Information (Details) - USD ($) $ in Millions |
9 Months Ended | |
---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Cash and Cash Equivalents [Abstract] | ||
Change in capital expenditures included in accounts payable | $ 5 | $ (10) |
Change in capital expenditures pursuant to an equipment financing agreement | 34 | 11 |
Issuance of 2017 Warrants | 17 | 0 |
Issuance of senior notes related to the Genco restructuring | 188 | 0 |
Sale of interest in Conesville facility | (58) | 0 |
Acquisition of interest in Zimmer facility | $ 27 | $ 0 |
Cash Flow Information - Reconciliation of Cash and Cash Equivalents (Details) - USD ($) $ in Millions |
Sep. 30, 2017 |
Dec. 31, 2016 |
Sep. 30, 2016 |
Dec. 31, 2015 |
---|---|---|---|---|
Cash and Cash Equivalents [Abstract] | ||||
Cash and cash equivalents | $ 613 | $ 1,776 | $ 1,458 | |
Restricted cash included in current assets | 0 | 62 | 85 | |
Restricted cash included in long-term assets | 0 | 2,000 | 2,000 | |
Total cash, cash equivalents and restricted cash | $ 613 | $ 3,838 | 3,543 | $ 544 |
Escrow | 45 | |||
Escrow, pre-funded interest | 25 | |||
Escrow, pre-funded original issue discount | 20 | |||
Cash collateral for borrowed securities | $ 40 |
Inventory - Summary of Inventories (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | |
---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2017 |
Dec. 31, 2016 |
|
Inventory Disclosure [Abstract] | |||
Materials and supplies | $ 236 | $ 236 | $ 182 |
Coal | 165 | 165 | 238 |
Fuel oil | 14 | 14 | 17 |
Natural gas | 12 | 12 | 0 |
Emissions allowances | 2 | 2 | 8 |
Total | 429 | 429 | $ 445 |
Inventory impairment | $ 14 | $ 14 |
Property, Plant and Equipment - Summary of Property, Plant, and Equipment (Details) - USD ($) $ in Millions |
Sep. 30, 2017 |
Dec. 31, 2016 |
---|---|---|
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Property, plant and equipment | $ 10,918 | $ 8,579 |
Accumulated depreciation | (1,989) | (1,458) |
Property, plant and equipment, net | 8,929 | 7,121 |
Power generation | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Property, plant and equipment | 9,845 | 7,537 |
Buildings and improvements | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Property, plant and equipment | 958 | 944 |
Office and other equipment | ||
Property, Plant and Equipment, Net, by Type [Abstract] | ||
Property, plant and equipment | $ 115 | $ 98 |
Property, Plant and Equipment - Schedule of Property, Plant and Equipment Impairment (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Property, Plant and Equipment [Line Items] | ||||
Impairments | $ 0 | $ 203 | $ 119 | $ 848 |
Baldwin | ||||
Property, Plant and Equipment [Line Items] | ||||
Fair Value | 97 | 97 | ||
Impairments | 0 | 0 | 0 | 645 |
Stuart Facility | ||||
Property, Plant and Equipment [Line Items] | ||||
Fair Value | 0 | 0 | ||
Impairments | 0 | 55 | 0 | 55 |
Newton FGD Facility | ||||
Property, Plant and Equipment [Line Items] | ||||
Fair Value | 0 | 0 | ||
Impairments | 0 | 148 | 0 | 148 |
Killen | ||||
Property, Plant and Equipment [Line Items] | ||||
Fair Value | 0 | 0 | ||
Impairments | 0 | 0 | 20 | 0 |
Hennepin | ||||
Property, Plant and Equipment [Line Items] | ||||
Fair Value | 16 | 16 | ||
Impairments | 0 | 0 | 10 | 0 |
Havana | ||||
Property, Plant and Equipment [Line Items] | ||||
Fair Value | 37 | 37 | ||
Impairments | $ 0 | $ 0 | $ 89 | $ 0 |
Property, Plant and Equipment - Narrative (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended |
---|---|---|
Sep. 30, 2017 |
Sep. 30, 2017 |
|
Brayton Point Facility | ||
Property, Plant and Equipment [Line Items] | ||
Severance costs | $ 7 | $ 12 |
Intangible Assets and Liabilities - Amortization of Intangible Assets and Liabilities (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Intangible Assets and Liabilities [Line Items] | ||||
Amortization of intangibles | $ (1) | $ 4 | $ 13 | $ 17 |
Electricity derivatives | ||||
Intangible Assets and Liabilities [Line Items] | ||||
Amortization of intangibles | 5 | 19 | 29 | 52 |
Coal contracts | ||||
Intangible Assets and Liabilities [Line Items] | ||||
Amortization of intangibles | (1) | (9) | (4) | (32) |
Coal transport contracts | ||||
Intangible Assets and Liabilities [Line Items] | ||||
Amortization of intangibles | (2) | (7) | (7) | (21) |
Gas transport contracts | ||||
Intangible Assets and Liabilities [Line Items] | ||||
Amortization of intangibles | (3) | 1 | (4) | 18 |
Gas storage contracts | ||||
Intangible Assets and Liabilities [Line Items] | ||||
Amortization of intangibles | $ 0 | $ 0 | $ (1) | $ 0 |
Intangible Assets and Liabilities - Additional Information (Details) $ in Millions |
Sep. 30, 2017
USD ($)
|
---|---|
Goodwill and Intangible Assets Disclosure [Abstract] | |
Amortization expense (revenue), 2017 | $ (3) |
Amortization expense (revenue), 2018 | 11 |
Amortization expense (revenue), 2019 | 17 |
Amortization expense (revenue), 2020 | 4 |
Amortization expense (revenue), 2021 | $ (1) |
Commitments and Contingencies - Legal Proceedings (Details) - Pending Litigation $ in Millions |
Sep. 30, 2017
state
|
Sep. 30, 2016
USD ($)
|
---|---|---|
Gas Index Pricing Litigation | ||
Loss Contingencies [Line Items] | ||
Number of States with pending litigation | state | 3 | |
Advatech Dispute | ||
Loss Contingencies [Line Items] | ||
Estimate of possible loss | $ 81 | |
Contested invoice amount (less than) | $ 1 |
Commitments and Contingencies - Other Commitments and Contingencies (Details) |
12 Months Ended | |
---|---|---|
Dec. 31, 2012
surface_impoundment
|
May 31, 2015
complaint
|
|
Vermillion Facility, Old East and North Sites | ||
Loss Contingencies [Line Items] | ||
Number of localized areas where groundwater standards were exceeded | surface_impoundment | 2 | |
MISO 2015-2016 Planning Resource Auction | ||
Loss Contingencies [Line Items] | ||
Number of complaints | 3 | |
MISO 2015-2016 Planning Resource Auction | Pending Litigation | ||
Loss Contingencies [Line Items] | ||
Number of complaints | 1 |
Commitments and Contingencies - Indemnifications and Guarantees (Details) |
Sep. 30, 2017
USD ($)
|
---|---|
LS Power Indemnities | |
Loss Contingencies [Line Items] | |
Number of claims and amount of accrued indemnifications, if any | $ 0 |
Income Taxes (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | |||
---|---|---|---|---|---|
Sep. 30, 2017 |
Mar. 31, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Operating Loss Carryforwards [Line Items] | |||||
Expected refund of AMT credits previously subject to a valuation allowance | $ 2 | $ 0 | $ 9 | $ 0 | |
Release of valuation allowance for OCI transactions that impacted deferred income taxes | (1) | 0 | 4 | 0 | |
Valuation allowance release as a result of the 2017 ENGIE Acquisition and the 2016 EquiPower Acquisition | 0 | 0 | 317 | 3 | |
Other state taxes | 0 | 1 | 0 | (9) | |
Income tax benefit (expense) | $ 1 | $ 1 | $ 330 | $ (6) | |
Engie Acquisition | |||||
Operating Loss Carryforwards [Line Items] | |||||
Unrecognized tax benefits, increase resulting from acquisition | $ 66 | ||||
Unrecognized tax benefits | $ 66 |
Pension and Other Post-Employment Benefit Plans (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | |||
---|---|---|---|---|---|
Sep. 30, 2017 |
Mar. 31, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Defined Benefit Plan Disclosure [Line Items] | |||||
Interest crediting rate | 4.00% | ||||
Gain recognized in OCI from remeasurement | $ 15 | ||||
Pension Benefits | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost benefits earned during period | $ 4 | $ 4 | $ 13 | $ 12 | |
Interest cost on projected benefit obligation | 5 | 5 | 15 | 15 | |
Expected return on plan assets | (6) | (5) | (19) | (17) | |
Amortization of prior service credit | (1) | (1) | (2) | (1) | |
Net periodic benefit cost (gain) | 2 | 3 | 7 | 9 | |
Other Benefits | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Service cost benefits earned during period | 0 | 0 | 0 | 0 | |
Interest cost on projected benefit obligation | 0 | 1 | 1 | 3 | |
Expected return on plan assets | 0 | (1) | (1) | (3) | |
Amortization of prior service credit | (1) | (1) | (4) | (3) | |
Net periodic benefit cost (gain) | $ (1) | $ (1) | $ (4) | $ (3) |
Condensed Consolidating Financial Information - Operations (Details) - USD ($) |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Condensed Financial Statements, Captions [Line Items] | ||||
Revenues | $ 1,437,000,000 | $ 1,184,000,000 | $ 3,848,000,000 | $ 3,211,000,000 |
Cost of sales, excluding depreciation expense | (787,000,000) | (660,000,000) | (2,225,000,000) | (1,698,000,000) |
Gross margin | 650,000,000 | 524,000,000 | 1,623,000,000 | 1,513,000,000 |
Operating and maintenance expense | (236,000,000) | (218,000,000) | (750,000,000) | (695,000,000) |
Depreciation expense | (202,000,000) | (163,000,000) | (611,000,000) | (494,000,000) |
Impairments | (29,000,000) | (212,000,000) | (148,000,000) | (857,000,000) |
Loss on sale of assets, net | (78,000,000) | 0 | (107,000,000) | 0 |
General and administrative expense | (44,000,000) | (41,000,000) | (126,000,000) | (117,000,000) |
Acquisition and integration costs | (3,000,000) | (7,000,000) | (55,000,000) | (8,000,000) |
Other | 0 | 0 | 1,000,000 | (16,000,000) |
Operating income (loss) | 58,000,000 | (117,000,000) | (173,000,000) | (674,000,000) |
Bankruptcy reorganization items (Note 18) | 12,000,000 | 0 | 494,000,000 | 0 |
Earnings from unconsolidated investments | 4,000,000 | 4,000,000 | 4,000,000 | 7,000,000 |
Equity in earnings from investments in affiliates | 0 | 0 | 0 | 0 |
Interest expense | (161,000,000) | (166,000,000) | (478,000,000) | (449,000,000) |
Loss on early extinguishment of debt | (66,000,000) | 0 | (75,000,000) | 0 |
Other income and expense, net | 19,000,000 | 29,000,000 | 65,000,000 | 60,000,000 |
Loss before income taxes | (134,000,000) | (250,000,000) | (163,000,000) | (1,056,000,000) |
Income tax benefit | 1,000,000 | 1,000,000 | 330,000,000 | (6,000,000) |
Net income (loss) | (133,000,000) | (249,000,000) | 167,000,000 | (1,062,000,000) |
Less: Net loss attributable to noncontrolling interest | (1,000,000) | 0 | (2,000,000) | (2,000,000) |
Net income (loss) attributable to Dynegy Inc. | (132,000,000) | (249,000,000) | 169,000,000 | (1,060,000,000) |
Eliminations | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Revenues | (27,000,000) | (26,000,000) | (110,000,000) | (65,000,000) |
Cost of sales, excluding depreciation expense | 27,000,000 | 26,000,000 | 110,000,000 | 65,000,000 |
Gross margin | 0 | 0 | 0 | 0 |
Operating and maintenance expense | 0 | 0 | 0 | 0 |
Depreciation expense | 0 | 0 | 0 | 0 |
Impairments | 0 | 0 | 0 | 0 |
Loss on sale of assets, net | 0 | 0 | ||
General and administrative expense | 0 | 0 | 0 | 0 |
Acquisition and integration costs | 0 | 0 | 0 | 0 |
Other | 0 | 0 | 0 | 0 |
Operating income (loss) | 0 | 0 | 0 | 0 |
Bankruptcy reorganization items (Note 18) | 0 | 0 | ||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 |
Equity in earnings from investments in affiliates | (78,000,000) | 136,000,000 | (730,000,000) | 693,000,000 |
Interest expense | 3,000,000 | 1,000,000 | 10,000,000 | 4,000,000 |
Loss on early extinguishment of debt | 0 | 0 | ||
Other income and expense, net | (3,000,000) | (1,000,000) | (10,000,000) | (4,000,000) |
Loss before income taxes | (78,000,000) | 136,000,000 | (730,000,000) | 693,000,000 |
Income tax benefit | 0 | 0 | 0 | 0 |
Net income (loss) | (78,000,000) | 136,000,000 | (730,000,000) | 693,000,000 |
Less: Net loss attributable to noncontrolling interest | 0 | 0 | 0 | |
Net income (loss) attributable to Dynegy Inc. | (78,000,000) | 136,000,000 | (730,000,000) | 693,000,000 |
Parent | Reportable Legal Entities | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Revenues | 0 | 0 | 0 | 0 |
Cost of sales, excluding depreciation expense | 0 | 0 | 0 | 0 |
Gross margin | 0 | 0 | 0 | 0 |
Operating and maintenance expense | 0 | 0 | 0 | 0 |
Depreciation expense | 0 | 0 | 0 | 0 |
Impairments | 0 | 0 | 0 | 0 |
Loss on sale of assets, net | 0 | 0 | ||
General and administrative expense | 8,000,000 | (2,000,000) | 0 | (5,000,000) |
Acquisition and integration costs | 0 | (5,000,000) | (51,000,000) | (8,000,000) |
Other | 0 | 0 | 0 | 0 |
Operating income (loss) | 8,000,000 | (7,000,000) | (51,000,000) | (13,000,000) |
Bankruptcy reorganization items (Note 18) | 0 | 0 | ||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 |
Equity in earnings from investments in affiliates | 78,000,000 | (136,000,000) | 730,000,000 | (693,000,000) |
Interest expense | (155,000,000) | (138,000,000) | (461,000,000) | (382,000,000) |
Loss on early extinguishment of debt | (66,000,000) | (75,000,000) | ||
Other income and expense, net | 3,000,000 | 25,000,000 | 26,000,000 | 28,000,000 |
Loss before income taxes | (132,000,000) | (256,000,000) | 169,000,000 | (1,060,000,000) |
Income tax benefit | 0 | 7,000,000 | 0 | 0 |
Net income (loss) | (132,000,000) | (249,000,000) | 169,000,000 | (1,060,000,000) |
Less: Net loss attributable to noncontrolling interest | 0 | 0 | 0 | |
Net income (loss) attributable to Dynegy Inc. | (132,000,000) | (249,000,000) | 169,000,000 | (1,060,000,000) |
Guarantor Subsidiaries | Reportable Legal Entities | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Revenues | 1,380,000,000 | 1,082,000,000 | 3,616,000,000 | 2,921,000,000 |
Cost of sales, excluding depreciation expense | (760,000,000) | (609,000,000) | (2,108,000,000) | (1,570,000,000) |
Gross margin | 620,000,000 | 473,000,000 | 1,508,000,000 | 1,351,000,000 |
Operating and maintenance expense | (209,000,000) | (189,000,000) | (660,000,000) | (595,000,000) |
Depreciation expense | (193,000,000) | (146,000,000) | (567,000,000) | (436,000,000) |
Impairments | (29,000,000) | (212,000,000) | (148,000,000) | (857,000,000) |
Loss on sale of assets, net | (78,000,000) | (108,000,000) | ||
General and administrative expense | (50,000,000) | (38,000,000) | (121,000,000) | (108,000,000) |
Acquisition and integration costs | (3,000,000) | (2,000,000) | (4,000,000) | 0 |
Other | 0 | (1,000,000) | 1,000,000 | (9,000,000) |
Operating income (loss) | 58,000,000 | (115,000,000) | (99,000,000) | (654,000,000) |
Bankruptcy reorganization items (Note 18) | 12,000,000 | 494,000,000 | ||
Earnings from unconsolidated investments | 4,000,000 | 4,000,000 | 4,000,000 | 7,000,000 |
Equity in earnings from investments in affiliates | 0 | 0 | 0 | 0 |
Interest expense | (6,000,000) | (27,000,000) | (18,000,000) | (65,000,000) |
Loss on early extinguishment of debt | 0 | 0 | ||
Other income and expense, net | 19,000,000 | 5,000,000 | 49,000,000 | 36,000,000 |
Loss before income taxes | 87,000,000 | (133,000,000) | 430,000,000 | (676,000,000) |
Income tax benefit | 1,000,000 | (6,000,000) | 330,000,000 | (6,000,000) |
Net income (loss) | 88,000,000 | (139,000,000) | 760,000,000 | (682,000,000) |
Less: Net loss attributable to noncontrolling interest | (1,000,000) | (2,000,000) | (2,000,000) | |
Net income (loss) attributable to Dynegy Inc. | 89,000,000 | (139,000,000) | 762,000,000 | (680,000,000) |
Non-Guarantor Subsidiaries | Reportable Legal Entities | ||||
Condensed Financial Statements, Captions [Line Items] | ||||
Revenues | 84,000,000 | 128,000,000 | 342,000,000 | 355,000,000 |
Cost of sales, excluding depreciation expense | (54,000,000) | (77,000,000) | (227,000,000) | (193,000,000) |
Gross margin | 30,000,000 | 51,000,000 | 115,000,000 | 162,000,000 |
Operating and maintenance expense | (27,000,000) | (29,000,000) | (90,000,000) | (100,000,000) |
Depreciation expense | (9,000,000) | (17,000,000) | (44,000,000) | (58,000,000) |
Impairments | 0 | 0 | 0 | 0 |
Loss on sale of assets, net | 0 | 1,000,000 | ||
General and administrative expense | (2,000,000) | (1,000,000) | (5,000,000) | (4,000,000) |
Acquisition and integration costs | 0 | 0 | 0 | 0 |
Other | 0 | 1,000,000 | 0 | (7,000,000) |
Operating income (loss) | (8,000,000) | 5,000,000 | (23,000,000) | (7,000,000) |
Bankruptcy reorganization items (Note 18) | 0 | 0 | ||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 |
Equity in earnings from investments in affiliates | 0 | 0 | 0 | 0 |
Interest expense | (3,000,000) | (2,000,000) | (9,000,000) | (6,000,000) |
Loss on early extinguishment of debt | 0 | 0 | ||
Other income and expense, net | 0 | 0 | 0 | 0 |
Loss before income taxes | (11,000,000) | 3,000,000 | (32,000,000) | (13,000,000) |
Income tax benefit | 0 | 0 | 0 | 0 |
Net income (loss) | (11,000,000) | 3,000,000 | (32,000,000) | (13,000,000) |
Less: Net loss attributable to noncontrolling interest | 0 | 0 | 0 | |
Net income (loss) attributable to Dynegy Inc. | $ (11,000,000) | $ 3,000,000 | $ (32,000,000) | $ (13,000,000) |
Genco Chapter 11 Bankruptcy and Emergence - Schedule of Reorganization Items (Details) - USD ($) $ in Millions |
3 Months Ended | 9 Months Ended | ||
---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
|
Reorganizations [Abstract] | ||||
Liabilities subject to compromise, which were terminated | $ 832 | |||
Seven-year unsecured notes | 188 | |||
Cash consideration | 122 | |||
2017 Warrants, at fair value | 17 | |||
Legal and consulting fees | 11 | |||
Bankruptcy reorganization items | $ 12 | $ 0 | $ 494 | $ 0 |
Segment Information - Narrative (Details) |
9 Months Ended |
---|---|
Sep. 30, 2017
segment
| |
Segment Reporting [Abstract] | |
Number of reportable segments | 6 |
Segment Information - Reportable Segment Information (Details) - USD ($) |
3 Months Ended | 9 Months Ended | |||
---|---|---|---|---|---|
Sep. 30, 2017 |
Sep. 30, 2016 |
Sep. 30, 2017 |
Sep. 30, 2016 |
Dec. 31, 2016 |
|
Segment Information | |||||
Unaffiliated revenues | $ 1,437,000,000 | $ 1,168,000,000 | $ 3,848,000,000 | $ 3,184,000,000 | |
Intercompany and affiliate revenues | 0 | 16,000,000 | 0 | 27,000,000 | |
Revenues | 1,437,000,000 | 1,184,000,000 | 3,848,000,000 | 3,211,000,000 | |
Depreciation expense | (202,000,000) | (163,000,000) | (611,000,000) | (494,000,000) | |
Impairments | (29,000,000) | (212,000,000) | (148,000,000) | (857,000,000) | |
Loss on sale of assets, net | (78,000,000) | 0 | (107,000,000) | 0 | |
General and administrative expense | (44,000,000) | (41,000,000) | (126,000,000) | (117,000,000) | |
Acquisition and integration costs | (3,000,000) | (7,000,000) | (55,000,000) | (8,000,000) | |
Operating income (loss) | 58,000,000 | (117,000,000) | (173,000,000) | (674,000,000) | |
Bankruptcy reorganization items (Note 18) | 12,000,000 | 0 | 494,000,000 | 0 | |
Earnings from unconsolidated investments | 4,000,000 | 4,000,000 | 4,000,000 | 7,000,000 | |
Interest expense | (161,000,000) | (166,000,000) | (478,000,000) | (449,000,000) | |
Loss on early extinguishment of debt | (66,000,000) | 0 | (75,000,000) | 0 | |
Other items, net | 19,000,000 | 29,000,000 | 65,000,000 | 60,000,000 | |
Loss before income taxes | (134,000,000) | (250,000,000) | (163,000,000) | (1,056,000,000) | |
Income tax benefit | 1,000,000 | 1,000,000 | 330,000,000 | (6,000,000) | |
Net income (loss) | (133,000,000) | (249,000,000) | 167,000,000 | (1,062,000,000) | |
Less: Net loss attributable to noncontrolling interest | (1,000,000) | 0 | (2,000,000) | (2,000,000) | |
Net income (loss) attributable to Dynegy Inc. | (132,000,000) | (249,000,000) | 169,000,000 | (1,060,000,000) | |
Identifiable assets (domestic) | 12,007,000,000 | 13,024,000,000 | 12,007,000,000 | 13,024,000,000 | $ 13,053,000,000 |
Investment in unconsolidated affiliate | 154,000,000 | 173,000,000 | 154,000,000 | 173,000,000 | |
Capital expenditures | (24,000,000) | (35,000,000) | (192,000,000) | (260,000,000) | |
Operating segments | PJM | |||||
Segment Information | |||||
Unaffiliated revenues | 628,000,000 | 551,000,000 | 1,806,000,000 | 1,559,000,000 | |
Intercompany and affiliate revenues | (25,000,000) | 17,000,000 | (47,000,000) | 45,000,000 | |
Revenues | 603,000,000 | 568,000,000 | 1,759,000,000 | 1,604,000,000 | |
Depreciation expense | (94,000,000) | (88,000,000) | (283,000,000) | (257,000,000) | |
Impairments | (29,000,000) | (64,000,000) | (49,000,000) | (64,000,000) | |
Loss on sale of assets, net | (1,000,000) | (31,000,000) | |||
General and administrative expense | 0 | 0 | 0 | 0 | |
Acquisition and integration costs | 0 | 0 | 0 | 0 | |
Operating income (loss) | 86,000,000 | 29,000,000 | 178,000,000 | 277,000,000 | |
Bankruptcy reorganization items (Note 18) | 0 | 0 | |||
Earnings from unconsolidated investments | 2,000,000 | 4,000,000 | 2,000,000 | 7,000,000 | |
Interest expense | 0 | 0 | 0 | 0 | |
Loss on early extinguishment of debt | 0 | 0 | |||
Other items, net | 16,000,000 | 3,000,000 | 16,000,000 | 9,000,000 | |
Income tax benefit | 0 | 0 | 0 | 0 | |
Identifiable assets (domestic) | 5,158,000,000 | 5,208,000,000 | 5,158,000,000 | 5,208,000,000 | |
Investment in unconsolidated affiliate | 77,000,000 | 173,000,000 | 77,000,000 | 173,000,000 | |
Capital expenditures | (6,000,000) | (13,000,000) | (74,000,000) | (124,000,000) | |
Operating segments | NY/NE | |||||
Segment Information | |||||
Unaffiliated revenues | 269,000,000 | 200,000,000 | 817,000,000 | 630,000,000 | |
Intercompany and affiliate revenues | (1,000,000) | (5,000,000) | (2,000,000) | (2,000,000) | |
Revenues | 268,000,000 | 195,000,000 | 815,000,000 | 628,000,000 | |
Depreciation expense | (52,000,000) | (53,000,000) | (171,000,000) | (167,000,000) | |
Impairments | 0 | 0 | 0 | 0 | |
Loss on sale of assets, net | (77,000,000) | (77,000,000) | |||
General and administrative expense | 0 | 0 | 0 | 0 | |
Acquisition and integration costs | 0 | 0 | 0 | 0 | |
Operating income (loss) | (30,000,000) | (15,000,000) | (72,000,000) | (22,000,000) | |
Bankruptcy reorganization items (Note 18) | 0 | 0 | |||
Earnings from unconsolidated investments | 2,000,000 | 0 | 2,000,000 | 0 | |
Interest expense | 0 | 0 | 0 | 0 | |
Loss on early extinguishment of debt | 0 | 0 | |||
Other items, net | 0 | 0 | 0 | 0 | |
Income tax benefit | 0 | 0 | 0 | 0 | |
Identifiable assets (domestic) | 3,401,000,000 | 2,807,000,000 | 3,401,000,000 | 2,807,000,000 | |
Investment in unconsolidated affiliate | 77,000,000 | 0 | 77,000,000 | 0 | |
Capital expenditures | (6,000,000) | (10,000,000) | (46,000,000) | (84,000,000) | |
Operating segments | ERCOT | |||||
Segment Information | |||||
Unaffiliated revenues | 210,000,000 | 322,000,000 | |||
Intercompany and affiliate revenues | (1,000,000) | (1,000,000) | |||
Revenues | 209,000,000 | 321,000,000 | |||
Depreciation expense | (20,000,000) | (54,000,000) | |||
Impairments | 0 | 0 | |||
Loss on sale of assets, net | 0 | 0 | |||
General and administrative expense | 0 | 0 | |||
Acquisition and integration costs | 0 | 0 | |||
Operating income (loss) | 50,000,000 | (8,000,000) | |||
Bankruptcy reorganization items (Note 18) | 0 | 0 | |||
Earnings from unconsolidated investments | 0 | 0 | |||
Interest expense | 0 | 0 | |||
Loss on early extinguishment of debt | 0 | 0 | |||
Other items, net | 0 | 0 | |||
Income tax benefit | 0 | 0 | |||
Identifiable assets (domestic) | 1,564,000,000 | 1,564,000,000 | |||
Investment in unconsolidated affiliate | 0 | 0 | |||
Capital expenditures | (3,000,000) | (20,000,000) | |||
Operating segments | MISO | |||||
Segment Information | |||||
Unaffiliated revenues | 98,000,000 | 130,000,000 | 276,000,000 | 315,000,000 | |
Intercompany and affiliate revenues | 6,000,000 | 3,000,000 | 16,000,000 | (15,000,000) | |
Revenues | 104,000,000 | 133,000,000 | 292,000,000 | 300,000,000 | |
Depreciation expense | (9,000,000) | (3,000,000) | (22,000,000) | (19,000,000) | |
Impairments | 0 | 0 | (99,000,000) | (645,000,000) | |
Loss on sale of assets, net | 0 | 0 | |||
General and administrative expense | 0 | 0 | 0 | 0 | |
Acquisition and integration costs | 0 | 0 | 0 | 0 | |
Operating income (loss) | (9,000,000) | 13,000,000 | (90,000,000) | (703,000,000) | |
Bankruptcy reorganization items (Note 18) | 0 | 0 | |||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 | |
Interest expense | 0 | 0 | 0 | 0 | |
Loss on early extinguishment of debt | 0 | 0 | |||
Other items, net | 0 | 0 | 0 | 0 | |
Income tax benefit | 0 | 0 | 0 | 0 | |
Identifiable assets (domestic) | 232,000,000 | 371,000,000 | 232,000,000 | 371,000,000 | |
Investment in unconsolidated affiliate | 0 | 0 | 0 | 0 | |
Capital expenditures | 0 | (1,000,000) | (3,000,000) | (9,000,000) | |
Operating segments | IPH | |||||
Segment Information | |||||
Unaffiliated revenues | 182,000,000 | 241,000,000 | 538,000,000 | 575,000,000 | |
Intercompany and affiliate revenues | 21,000,000 | 1,000,000 | 34,000,000 | (1,000,000) | |
Revenues | 203,000,000 | 242,000,000 | 572,000,000 | 574,000,000 | |
Depreciation expense | (11,000,000) | (7,000,000) | (35,000,000) | (21,000,000) | |
Impairments | 0 | (148,000,000) | 0 | (148,000,000) | |
Loss on sale of assets, net | 0 | 1,000,000 | |||
General and administrative expense | 0 | 0 | 0 | 0 | |
Acquisition and integration costs | 0 | 0 | 0 | 8,000,000 | |
Operating income (loss) | 11,000,000 | (104,000,000) | 40,000,000 | (87,000,000) | |
Bankruptcy reorganization items (Note 18) | 12,000,000 | 494,000,000 | |||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 | |
Interest expense | 0 | 0 | 0 | 0 | |
Loss on early extinguishment of debt | 0 | 0 | |||
Other items, net | 0 | 1,000,000 | 26,000,000 | 15,000,000 | |
Income tax benefit | 0 | 0 | 0 | 0 | |
Identifiable assets (domestic) | 581,000,000 | 746,000,000 | 581,000,000 | 746,000,000 | |
Investment in unconsolidated affiliate | 0 | 0 | 0 | 0 | |
Capital expenditures | (4,000,000) | (9,000,000) | (10,000,000) | (30,000,000) | |
Operating segments | CAISO | |||||
Segment Information | |||||
Unaffiliated revenues | 50,000,000 | 46,000,000 | 89,000,000 | 105,000,000 | |
Intercompany and affiliate revenues | 0 | 0 | 0 | 0 | |
Revenues | 50,000,000 | 46,000,000 | 89,000,000 | 105,000,000 | |
Depreciation expense | (14,000,000) | (11,000,000) | (40,000,000) | (26,000,000) | |
Impairments | 0 | 0 | 0 | 0 | |
Loss on sale of assets, net | 0 | 0 | |||
General and administrative expense | 0 | 0 | 0 | 0 | |
Acquisition and integration costs | 0 | 0 | 0 | 0 | |
Operating income (loss) | 0 | 10,000,000 | (33,000,000) | 0 | |
Bankruptcy reorganization items (Note 18) | 0 | 0 | |||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 | |
Interest expense | 0 | 0 | 0 | 0 | |
Loss on early extinguishment of debt | 0 | 0 | |||
Other items, net | 0 | 0 | 0 | 12,000,000 | |
Income tax benefit | 0 | 0 | 0 | 0 | |
Identifiable assets (domestic) | 461,000,000 | 499,000,000 | 461,000,000 | 499,000,000 | |
Investment in unconsolidated affiliate | 0 | 0 | 0 | 0 | |
Capital expenditures | (3,000,000) | (1,000,000) | (34,000,000) | (4,000,000) | |
Other and Eliminations | |||||
Segment Information | |||||
Unaffiliated revenues | 0 | 0 | 0 | 0 | |
Intercompany and affiliate revenues | 0 | 0 | 0 | 0 | |
Revenues | 0 | 0 | 0 | 0 | |
Depreciation expense | (2,000,000) | (1,000,000) | (6,000,000) | (4,000,000) | |
Impairments | 0 | 0 | 0 | 0 | |
Loss on sale of assets, net | 0 | 0 | |||
General and administrative expense | (44,000,000) | (41,000,000) | (126,000,000) | (117,000,000) | |
Acquisition and integration costs | (3,000,000) | (7,000,000) | (55,000,000) | (16,000,000) | |
Operating income (loss) | (50,000,000) | (50,000,000) | (188,000,000) | (139,000,000) | |
Bankruptcy reorganization items (Note 18) | 0 | 0 | |||
Earnings from unconsolidated investments | 0 | 0 | 0 | 0 | |
Interest expense | (161,000,000) | 166,000,000 | (478,000,000) | (449,000,000) | |
Loss on early extinguishment of debt | (66,000,000) | (75,000,000) | |||
Other items, net | 3,000,000 | 25,000,000 | 23,000,000 | 24,000,000 | |
Income tax benefit | 1,000,000 | 1,000,000 | 330,000,000 | (6,000,000) | |
Identifiable assets (domestic) | 610,000,000 | 3,393,000,000 | 610,000,000 | 3,393,000,000 | |
Investment in unconsolidated affiliate | 0 | 0 | 0 | 0 | |
Capital expenditures | $ (2,000,000) | $ (1,000,000) | $ (5,000,000) | $ (9,000,000) |
Subsequent Events (Details) - Subsequent Event - Vistra Energy Merger |
Oct. 29, 2017 |
---|---|
Subsequent Event [Line Items] | |
Ratio of acquiring entity shares to be received | 0.652 |
Vistra Energy Corp. | Vistra Energy Shareholders | |
Subsequent Event [Line Items] | |
Percentage of ownership after transaction | 79.00% |
Vistra Energy Corp. | Dynegy Shareholders | |
Subsequent Event [Line Items] | |
Percentage of ownership after transaction | 21.00% |
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