DYNEGY ANNOUNCES 2017 FINANCIAL RESULTS
Summary of Fourth Quarter and Full-Year 2017 Financial Results (in millions):
|
| Three Months Ended |
| Twelve Months Ended |
| ||||||||
|
| 2017 |
| 2016 |
| 2017 |
| 2016 |
| ||||
Operating Revenues |
| $ | 994 |
| $ | 1,107 |
| $ | 4,842 |
| $ | 4,318 |
|
Net Income (loss) |
| $ | (95 | ) | $ | (182 | ) | $ | 72 |
| $ | (1,244 | ) |
Adjusted EBITDA (1) |
| $ | 293 |
| $ | 219 |
| $ | 1,160 |
| $ | 1,007 |
|
|
|
|
|
|
|
|
|
|
| ||||
Operating Cash Flow |
|
|
|
|
| $ | 585 |
| $ | 645 |
| ||
Adjusted Free Cash Flow (1) |
|
|
|
|
| $ | 374 |
| $ | 263 |
| ||
2017 Highlights:
· Announced strategic combination with Vistra Energy on October 30
· Completed acquisition of ENGIE’s U.S. portfolio on February 7; acquisition included more than 9,000 megawatts of predominately gas-fueled generating capacity in the ERCOT, ISO-NE, and PJM markets
· Completed sales of five power generation facilities for approximately $780 million in cash, which, together with cash on hand, was used to repay $900 million in debt
· Simplified Ohio joint operating unit structure by securing 100% ownership of Miami Fort and Zimmer facilities and divesting ownership share of Conesville facility
· Reduced 2019 debt maturity from $2.1 billion to $850 million through a combination of repayments and refinancing
· Completed Genco restructuring on February 2, eliminating $825 million of unsecured bonds in exchange for approximately $122 million in cash, $188 million of seven-year unsecured notes, and 9 million Dynegy common stock warrants
· Achieved $89 million and $141 million, respectively, in EBITDA and balance sheet improvements through employee-driven PRIDE program; separately, launched Earnings and Cost Improvement (ECI) initiative with a target of more than $100 million in sustainable earnings improvements
· Achieved top decile safety performance across the entire Company for the full year, Dynegy’s top performance since 2010
(1) Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures, see “Regulation G Reconciliations” for further details.
HOUSTON (February 21, 2018) - Dynegy Inc. (NYSE: DYN) reported net income for 2017 of $72 million, compared to a net loss of $1.24 billion for 2016. The year-over-year increase was primarily driven by (i) a $228 million lower operating loss primarily attributable to lower impairments, (ii) a $590 million increase related to the extinguishment of debt associated with the Genco bankruptcy, and (iii) a $565 million increase in tax benefits, partially offset by a $79 million loss on the early extinguishment of debt.
The Company reported 2017 consolidated Adjusted EBITDA of $1.16 billion, compared to $1.01 billion for 2016. The $153 million increase was attributable to contributions from the newly acquired ENGIE plants,
higher capacity revenues across most of Dynegy’s business segments, and lower O&M costs as a result of unit shutdowns and fewer planned outages. Partially offsetting this were lower energy margins, net of hedges, as a result of decreased spark spreads at the PJM and NY/NE segments, decreased dark spreads at the MISO segment, and lower retail contribution at the PJM and MISO segments, all driven by milder weather. Full-year results versus guidance reflect an approximately $70 million unfavorable impact from asset sales and M&A timing during the year.
The Company reported a fourth quarter 2017 net loss of $95 million, compared to a net loss of $182 million for 2016. The quarter-over-quarter change was primarily driven by an increase in our income tax benefit due to the partial release of our valuation allowance as a result of the ENGIE acquisition and recognition of the benefit of AMT credits that had previously been subject to a valuation allowance. This change was partially offset by a loss attributable to the newly acquired ENGIE plants.
The Company reported fourth quarter 2017 consolidated Adjusted EBITDA of $293 million, compared to $219 million for the fourth quarter 2016 as the newly acquired ENGIE plants and higher capacity revenues in the NY/NE and PJM segments benefited results. Adjusted EBITDA during the quarter was negatively impacted by weaker than expected commodity prices in November and the first half of December, as well as higher accruals related to cash-settled incentive compensation tied to Dynegy’s common stock price, which increased over 20% during the quarter, and approximately 40% versus the prior year.
“Dynegy has a long list of accomplishments during 2017, including our best safety performance since 2010. Over the course of the year, we made substantial and dramatic changes to our portfolio in addition to announcing our combination with Vistra. In addition to our portfolio activities, we simultaneously strengthened our balance sheet over the course of the year by utilizing asset sale proceeds, refinancing debt, and restructuring our Genco subsidiary. Despite the loss of financial contributions from the plants that were sold, we finished the year with Adjusted Free Cash Flow comfortably within the guidance range which was raised in May 2017 due to our disciplined focus on controlling costs and agility to adapt to the changing portfolio and market place,” said Dynegy President and Chief Executive Officer Robert C. Flexon.
“In terms of our 2017 operational results, our fleet responded to the challenging market conditions by operating safely and reliably serving our customers and communities,” Flexon continued. “Further, we advanced our position of being the most efficient and lowest-cost platform in the industry. Our PRIDE initiative is on track to exceed our three-year EBITDA target of $250 million in 2018, with additional contributions expected to follow through the Company’s Earnings and Cost Improvement initiative, which was launched in October 2017.”
Full-Year Comparative Results
|
| Year Ended December 31, |
| ||||||||||
|
| 2017 |
| 2016 |
| ||||||||
(in millions) |
| Operating |
| Adjusted EBITDA |
| Operating |
| Adjusted EBITDA |
| ||||
PJM |
| $ | 192 |
| $ | 818 |
| $ | 414 |
| $ | 757 |
|
NY/NE |
| (113 | ) | 293 |
| (29 | ) | 171 |
| ||||
ERCOT |
| (147 | ) | 26 |
| — |
| — |
| ||||
MISO |
| (44 | ) | 152 |
| (832 | ) | 129 |
| ||||
CAISO |
| (45 | ) | 19 |
| (5 | ) | 59 |
| ||||
Other |
| (255 | ) | (148 | ) | (188 | ) | (109 | ) | ||||
Total |
| $ | (412 | ) | $ | 1,160 |
| $ | (640 | ) | $ | 1,007 |
|
Segment Review of Results Year-over-Year
PJM - Operating income in 2017 totaled $192 million compared to operating income of $414 million in 2016. Factors that led to the decrease in operating income included a change in the mark-to-market value of derivative transactions, lower spark spreads as a result of higher gas costs and milder weather, the loss on the sale of assets, and a lower retail contribution as a result of higher supply costs and milder weather. Partially offsetting this were higher capacity revenues and income attributable to the newly acquired ENGIE plants.
Adjusted EBITDA totaled $818 million during 2017 compared to $757 million in 2016. The increase was primarily due to the contribution from the newly acquired ENGIE plants, higher capacity revenues, and lower O&M costs, partially offset by lower generation volumes due to milder weather.
NY/NE - The 2017 operating loss was $113 million compared to an operating loss of $29 million for 2016. Factors that led to the higher operating loss included a change in the mark-to-market value of derivative transactions and a loss on the sale of the Dighton and Milford facilities in Massachusetts, partially offset by higher capacity revenues, lower depreciation costs, and income from the newly acquired ENGIE plants.
Adjusted EBITDA totaled $293 million in 2017 compared to $171 million in 2016 primarily due to the contribution from the newly acquired ENGIE plants.
ERCOT - Dynegy’s ERCOT segment was initiated in February 2017 with the acquisition of ENGIE plants in Texas. The 2017 operating loss of $147 million was primarily driven by mark-to-market losses on derivative transactions and depreciation expenses.
Adjusted EBITDA totaled $26 million, with energy margin, net of hedges, partially offset by O&M costs.
MISO - The 2017 operating loss was $44 million compared to an operating loss of $832 million in 2016. The previous year results were primarily driven by approximately $790 million in impairment charges.
Adjusted EBITDA totaled $152 million in 2017 compared to $129 million in 2016 due to higher capacity revenues that resulted from favorable pricing and volumes.
CAISO - The 2017 operating loss was $45 million compared to an operating loss of $5 million for 2016. The higher operating loss resulted from lower capacity revenues due to lower contracted volumes and prices and lower tolling revenue due to the expiration of a tolling contract, partially offset by higher energy margin, net of hedges, as a result of warmer weather.
Adjusted EBITDA totaled $19 million in 2017 compared to $59 million in 2016 as lower volumes and prices for capacity and the expiration of tolling agreements impacted results.
Fourth Quarter Comparative Results
|
| Quarter Ended December 31, |
| ||||||||||
|
| 2017 |
| 2016 |
| ||||||||
(in millions) |
| Operating |
| Adjusted EBITDA |
| Operating |
| Adjusted EBITDA |
| ||||
PJM |
| $ | 14 |
| $ | 216 |
| $ | 137 |
| $ | 181 |
|
NY/NE |
| (41 | ) | 99 |
| (7 | ) | 29 |
| ||||
ERCOT |
| (139 | ) | (12 | ) | — |
| — |
| ||||
MISO |
| 6 |
| 28 |
| (42 | ) | 28 |
| ||||
CAISO |
| (12 | ) | 5 |
| (5 | ) | 14 |
| ||||
Other |
| (67 | ) | (43 | ) | (49 | ) | (33 | ) | ||||
Total |
| $ | (239 | ) | $ | 293 |
| $ | 34 |
| $ | 219 |
|
Segment Review of Results Quarter-over-Quarter
PJM - Operating income for the fourth quarter 2017 totaled $14 million compared to $137 million for the fourth quarter 2016. The decrease was primarily due to a change in the mark-to-market value of derivative transactions.
Adjusted EBITDA totaled $216 million in 2017 versus $181 million in 2016 as the contribution from the newly acquired ENGIE plants and higher capacity revenues were partially offset by a lower retail contribution due to higher supply costs and milder weather.
NY/NE - The fourth quarter 2017 operating loss was $41 million compared to an operating loss of $7 million for the fourth quarter 2016. The decrease was primarily due to a change in the mark-to-market value of derivative transactions.
Adjusted EBITDA totaled $99 million in 2017 compared to $29 million in 2016. The increase was primarily due to the contribution from the newly acquired ENGIE plants, higher capacity revenues, and lower O&M expenses.
ERCOT- The fourth quarter 2017 operating loss of $139 million was primarily driven by mark-to-market losses on derivative transactions and depreciation expenses, which more than offset positive energy margin.
Adjusted EBITDA totaled $(12) million as a result of O&M expenses associated with plant outages, which more than offset positive energy margin.
MISO - Operating income for the fourth quarter 2017 totaled $6 million compared to an operating loss of $42 million for the fourth quarter 2016 as lower O&M and depreciation expenses benefited results.
Adjusted EBITDA remained unchanged at $28 million in 2017 and in 2016.
CAISO - The fourth quarter 2017 operating loss was $12 million compared to a $5 million operating loss for the fourth quarter 2016 as lower capacity and tolling revenue impacted results.
Adjusted EBITDA in 2017 was $5 million versus $14 million in 2016 primarily due to lower capacity and tolling revenue in the most recent period.
Liquidity
Dynegy’s total available liquidity is reflected in the table below.
|
| December 31, 2017 |
| |
(amounts in millions) |
| Dynegy Inc. |
| |
Revolving facilities and LC capacity (1) |
| $ | 1,650 |
|
Less: |
|
|
| |
Outstanding revolver draws |
| — |
| |
Outstanding LCs |
| (438 | ) | |
Revolving facilities and LC availability |
| 1,212 |
| |
Cash and cash equivalents |
| 365 |
| |
Total available liquidity |
| $ | 1,577 |
|
(1) Includes $1.545 billion in senior secured revolving credit facilities and $105 million related to letter of credit facilities (“LCs”).
Consolidated Cash Flow
Cash provided by operations totaled $585 million for the full year of 2017. During the period, our power generation facilities and retail operations provided cash of $1.25 billion. Corporate activities, primarily related to general and administrative, interest, and acquisition-related expenses, as well as other working capital changes, used cash of $669 million during the period.
Cash used in investing activities totaled $2.76 billion for the full year of 2017 as Dynegy used $3.25 billion at the ENGIE acquisition closing, $70 million, including $20 million in working capital, for the purchase of interest in Miami Fort and Zimmer from AES, and invested $224 million in capital expenditures, offset by $773 million in proceeds received from asset sales, in addition to $12 million in distributions received from our unconsolidated investments in the Bellingham NEA and Sayreville facilities.
Cash used in financing activities totaled $1.3 billion for the full year of 2017 primarily as a result of the remaining payment obligations relating to the purchase of Energy Capital Partners’ (ECP) interest in Atlas Power, payments related to our Illinois Power Generating Company subsidiary’s (Genco) emergence from bankruptcy, and the repayment of the outstanding revolving credit facility, as well as various other financing activities.
Capital Structure
During 2017 numerous steps were taken to streamline and strengthen Dynegy’s capital structure including:
· Used asset sale proceeds, cash on hand, and proceeds from an $850 million bond offering to repay/refinance $1.75 billion in debt;
· Restructuring the Genco subsidiary, eliminated $825 million of Genco senior notes in exchange for approximately $122 million in cash, $188 million of seven-year unsecured notes, and 9 million Dynegy common stock warrants; and
· Added more flexibility and improved the terms of our Credit Agreement by executing amendments to increase its capacity, extend its maturity date, and reduce the interest rate margin by 125 basis points.
Commodity Pricing and Impact of Hedges
Throughout the fourth quarter of 2017, Dynegy continued to actively hedge its fleet for 2018 and 2019, taking advantage of a rise in forward commodity prices experienced in late 2017. In the fourth quarter of 2017, forward pricing for 2018 and 2019 improved in many of Dynegy’s key markets as both spark and dark spreads expanded. This improved outlook has resulted in an increase in forecasted run times as plants are now more
deeply in the money. Gross margin is expected to increase as Dynegy’s generation facilities are now projected to run more hours at higher prices.
As of February 8, 2018, Dynegy’s 2018 generation volumes hedged in the key markets of PJM, NY/NE, ERCOT, and MISO stood at 78%, 64%, 74%, and 75%, respectively. In 2019, hedging in the same markets is at 40%, 19%, 26%, and 39%, respectively.
As we move forward, we will continue to look for opportunities to hedge future generation at advantageous levels.
Recent Developments
Vistra Merger
On October 29, 2017, Dynegy and Vistra Energy Corp. entered into a Merger Agreement that 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.
We expect the transaction to close in the second quarter of 2018 after meeting the remaining customary conditions including stockholder approval and receiving the required regulatory approvals, including the Federal Energy Regulatory Commission, the Public Utility Commission of Texas, and the New York Public Service Commission.
Tax Reform Act
The Tax Cuts and Jobs Act (TCJA), enacted on December 22, 2017, reduces the U.S. federal corporate tax rate from 35% to 21%. This resulted in a reduction to our net deferred tax assets with a corresponding reduction to our valuation allowance. The TCJA also repealed the corporate Alternative Minimum Tax (AMT), which resulted in a $223 million tax benefit for Dynegy. As prescribed by the TCJA, and unless used to offset a cash tax liability, Dynegy will receive the cash refunds of our existing AMT credits beginning in 2019, for the 2018 tax year, through 2022. Estimated cash refunds by year: 2019 - $112 million; 2020 - $56 million; 2021 - $28 million; 2022 - $27 million.
ENGIE Acquisition
On February 7, 2017, Dynegy completed its acquisition of ENGIE’s US portfolio, which included more than 9,000 megawatts of generation facilities for a base purchase price of approximately $3.3 billion. The plants acquired included 15 natural gas-fueled facilities in Illinois, Massachusetts, New Jersey, Ohio, Pennsylvania, Texas, Virginia, and West Virginia, as well as one coal-fueled facility in Texas and a waste-coal-fueled facility in Pennsylvania.
Portfolio Changes
During 2017, Dynegy sold its Armstrong (Pennsylvania), Dighton (Massachusetts), Lee (Illinois), Milford (Massachusetts), and Troy (Ohio) facilities. In addition, Dynegy sold its 40 percent ownership interest in the Conesville facility in Ohio and, through separate transactions with AEP and AES, raised its ownership in the Miami Fort and Zimmer facilities in Ohio to 100%.
PRIDE Update and Earnings and Cost Improvement Project
Dynegy’s PRIDE (Producing Results through Innovation by Dynegy Employees) program was launched in 2011 with a focus on optimizing our cost structure, implementing company-wide process and operating improvements, and improving balance sheet efficiency. In 2017 the program exceeded its balance sheet target of $100 million by $41 million and its EBITDA target of $65 million by $24 million.
Dynegy introduced its Earnings and Cost Improvement (ECI) project in the fourth quarter 2017 to identify and implement practices that promote leading practices across key areas of our power generation fleet. The initiative is driven by employees with assistance from a third-party consultant. ECI’s target is more than $100 million in sustainable earnings improvements.
Retail Business Expansion
The retail business continued its effort to expand into new markets during 2017 by serving new municipal aggregation customers in Massachusetts and through commercial and industrial sales in the Pennsylvania market for 2018 delivery. Retail now serves customers in Illinois, Massachusetts, Ohio, and Pennsylvania. Retail delivered volumes in 2017 were 26,000 gigawatt-hours to its approximately 1.2 million residential and business customers.
Safety
Dynegy’s safety performance for the full-year 2017 was in the top decile for the industry. Both coal and gas facilities are focused on intensive safety initiatives that help drive safety culture. A total of seven Dynegy plants have achieved STAR Program status through the Occupational Safety and Health Administration’s Voluntary Protection Program (VPP). Dynegy is committed to having all of its plants go through the VPP auditing process in the next several years.
About Dynegy
Throughout the Northeast, Mid-Atlantic, Midwest, Texas and California, Dynegy operates nearly 28,000 megawatts (MW) of power generating facilities capable of producing enough energy to supply more than 23 million American homes. Through our retail business, we serve 1.2 million customers who depend on reliable, affordable energy to grow and thrive.
Forward-Looking Statement
This news release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements,” particularly those statements concerning Dynegy’s beliefs and expectations regarding its platform position in the industry; execution of Dynegy’s PRIDE Energized targets and its Earnings and Cost Improvement initiative in 2018; anticipated earnings and cash flows; Dynegy’s proposed merger into Vistra Energy, including stockholder and regulatory approvals and timing of closing; and achievement of OSHAs VPP auditing process of all Dynegy plants within the next several years. Historically, Dynegy’s performance has deviated, in some cases materially, from its cash flow and earnings guidance. Discussion of risks and uncertainties that could cause actual results to differ materially from current projections, forecasts, estimates and expectations of Dynegy is contained in Dynegy’s filings with the Securities and Exchange Commission (SEC). Specifically, Dynegy makes reference to, and incorporates herein by reference, the section entitled “Risk Factors” in its 2017 Form 10-K (when filed). Any or all of Dynegy’s forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond Dynegy’s control. In addition to the risks and uncertainties set forth in Dynegy’s SEC filings, the forward-looking statements described in this press release could be affected by, among other things, (i) expectations regarding the Merger, including beliefs concerning stockholder and regulatory approvals; (ii) 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; (iii) expectations regarding anticipated benefits of the Merger; (iv) beliefs and assumptions about weather and general economic conditions; (v) 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; (vi) 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; (vii) sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof; (viii) the effects of, or changes to the power and capacity procurement processes in the markets in which we operate; (ix) 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; (x) beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters; (xi) projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; (xii) our focus on safety and our ability to operate our assets efficiently so as to capture revenue generating opportunities and operating margins; (xiii) our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; (xiv) our ability to optimize our assets through targeted investment in cost effective technology enhancements; (xv) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (xvi) efforts to secure retail sales and the ability to grow the retail business; (xvii) efforts to identify opportunities to reduce congestion and improve busbar power prices; (xviii) ability to mitigate impacts associated with expiring reliability must run “RMR” and/or capacity contracts; (xix) expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments; (xx) expectations regarding performance standards and capital and maintenance expenditures; (xxi) the timing and anticipated benefits to be achieved through our PRIDE and ECI initiatives; (xxii) expectations regarding strengthening the balance sheet, managing debt and improving Dynegy’s leverage profile; (xxiii) anticipated timing, outcome, and impact of our expected retirements; and (xxiv) beliefs about the costs and scope of ongoing demolition and site remediation efforts. Any or all of Dynegy’s forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties, and other factors, many of which are beyond Dynegy’s control.
Dynegy Inc. Contacts: Media: Dean Ellis, 713.767.5800; Analysts: 713.507.6466
DYNEGY INC.
REPORTED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS, EXCEPT PER SHARE DATA)
|
| Twelve Months Ended |
| ||||
|
| 2017 |
| 2016 |
| ||
Revenues |
| $ | 4,842 |
| $ | 4,318 |
|
Cost of sales, excluding depreciation expense |
| (2,932 | ) | (2,281 | ) | ||
Gross margin |
| 1,910 |
| 2,037 |
| ||
Operating and maintenance expense |
| (995 | ) | (940 | ) | ||
Depreciation expense |
| (811 | ) | (689 | ) | ||
Impairments |
| (148 | ) | (858 | ) | ||
Loss on sale of assets, net |
| (122 | ) | (1 | ) | ||
General and administrative expense |
| (189 | ) | (161 | ) | ||
Acquisition and integration costs |
| (57 | ) | (11 | ) | ||
Other |
| — |
| (17 | ) | ||
Operating loss |
| (412 | ) | (640 | ) | ||
Bankruptcy reorganization items |
| 494 |
| (96 | ) | ||
Earnings from unconsolidated investments |
| 8 |
| 7 |
| ||
Interest expense |
| (616 | ) | (625 | ) | ||
Loss on early extinguishment of debt |
| (79 | ) | — |
| ||
Other income and expense, net |
| 67 |
| 65 |
| ||
Loss before income taxes |
| (538 | ) | (1,289 | ) | ||
Income tax benefit |
| 610 |
| 45 |
| ||
Net income (loss) |
| 72 |
| (1,244 | ) | ||
Less: Net loss attributable to noncontrolling interest |
| (4 | ) | (4 | ) | ||
Net income (loss) attributable to Dynegy Inc. |
| 76 |
| (1,240 | ) | ||
Less: Dividends on preferred stock |
| 18 |
| 22 |
| ||
Net income (loss) attributable to Dynegy Inc. common stockholders |
| $ | 58 |
| $ | (1,262 | ) |
|
|
|
|
|
| ||
Earnings (Loss) Per Share: |
|
|
|
|
| ||
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders |
| $ | 0.37 |
| $ | (9.78 | ) |
Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders |
| $ | 0.36 |
| $ | (9.78 | ) |
|
|
|
|
|
| ||
Basic shares outstanding |
| 155 |
| 129 |
| ||
Diluted shares outstanding |
| 162 |
| 129 |
| ||
The following table reflects the significant components of our weighted average shares outstanding used in basic and diluted loss per share calculations for the twelve months ended December 31, 2017 and 2016:
|
| Twelve Months Ended |
| ||
(in millions, except per share amounts) |
| 2017 |
| 2016 |
|
Shares outstanding at the beginning of the period |
| 140 |
| 117 |
|
Weighted-average shares during the period of: |
|
|
|
|
|
Shares issuances |
| 13 |
| — |
|
Shares converted from preferred stock |
| 2 |
| — |
|
Prepaid stock purchase contract (TEUs) (1) |
| — |
| 12 |
|
Basic weighted-average shares |
| 155 |
| 129 |
|
Dilution from potentially dilutive shares (2) |
| 7 |
| — |
|
Diluted weighted-average shares (3) |
| 162 |
| 129 |
|
(1) The minimum settlement amount, or 23.1 million shares, are considered to be outstanding since June 21, 2016 and are included in the computation of basic earnings (loss) per share.
(2) Shares included in the computation of diluted earnings per share for the year ended December 31, 2017 consist of:
· 5.4 million 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 (28.5 million shares); and
· 1.9 million 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 twelve months ended December 31, 2016.
DYNEGY INC.
OPERATING DATA
The following table provides summary financial data regarding our PJM, NY/NE, ERCOT, MISO, and CAISO segment results of operations for the three and twelve months ended December 31, 2017 and 2016, respectively.
|
| Three Months |
| Twelve Months |
| ||||||||
|
| 2017 |
| 2016 |
| 2017 |
| 2016 |
| ||||
PJM |
|
|
|
|
|
|
|
|
| ||||
Million Megawatt Hours Generated (1) |
| 14.0 |
| 13.5 |
| 52.8 |
| 52.8 |
| ||||
IMA (1)(2): |
|
|
|
|
|
|
|
|
| ||||
Combined Cycle Facilities |
| 98 | % | 97 | % | 95 | % | 97 | % | ||||
Coal-Fueled Facilities |
| 73 | % | 78 | % | 75 | % | 80 | % | ||||
Average Capacity Factor (1)(3): |
|
|
|
|
|
|
|
|
| ||||
Combined Cycle Facilities |
| 66 | % | 73 | % | 64 | % | 74 | % | ||||
Coal-Fueled Facilities |
| 65 | % | 58 | % | 56 | % | 53 | % | ||||
CDDs (4) |
| 57 |
| 40 |
| 1,143 |
| 1,417 |
| ||||
HDDs (4) |
| 1,798 |
| 1,663 |
| 4,403 |
| 4,719 |
| ||||
Average Market On-Peak Spark Spreads ($/MWh) (5): |
|
|
|
|
|
|
|
|
| ||||
PJM West |
| $ | 17.22 |
| $ | 19.11 |
| $ | 16.90 |
| $ | 22.62 |
|
AD Hub |
| $ | 22.69 |
| $ | 20.18 |
| $ | 19.22 |
| $ | 22.52 |
|
Average Market On-Peak Power Prices ($/MWh) (6): |
|
|
|
|
|
|
|
|
| ||||
PJM West |
| $ | 36.65 |
| $ | 34.31 |
| $ | 34.38 |
| $ | 34.65 |
|
AD Hub |
| $ | 34.74 |
| $ | 33.76 |
| $ | 34.00 |
| $ | 32.93 |
|
Average natural gas price—TetcoM3 ($/MMBtu) (7) |
| $ | 2.78 |
| $ | 2.17 |
| $ | 2.50 |
| $ | 1.72 |
|
|
|
|
|
|
|
|
|
|
| ||||
NY/NE |
|
|
|
|
|
|
|
|
| ||||
Million Megawatt Hours Generated (1) |
| 4.6 |
| 3.8 |
| 19.2 |
| 16.9 |
| ||||
IMA for Combined Cycle Facilities (1)(2) |
| 96 | % | 97 | % | 96 | % | 96 | % | ||||
Average Capacity Factor for Combined Cycle Facilities (1)(3) |
| 45 | % | 43 | % | 43 | % | 48 | % | ||||
CDDs (4) |
| 35 |
| 10 |
| 721 |
| 884 |
| ||||
HDDs (4) |
| 1,951 |
| 1,935 |
| 5,495 |
| 5,593 |
| ||||
Average Market On-Peak Spark Spreads ($/MWh) (5): |
|
|
|
|
|
|
|
|
| ||||
New York—Zone C |
| $ | 19.18 |
| $ | 13.74 |
| $ | 14.78 |
| $ | 16.46 |
|
Mass Hub |
| $ | 13.49 |
| $ | 11.72 |
| $ | 12.09 |
| $ | 13.80 |
|
Average Market On-Peak Power Prices ($/MWh) (6): |
|
|
|
|
|
|
|
|
| ||||
New York—Zone C |
| $ | 31.22 |
| $ | 27.32 |
| $ | 29.56 |
| $ | 26.88 |
|
Mass Hub |
| $ | 49.41 |
| $ | 38.74 |
| $ | 37.83 |
| $ | 35.52 |
|
Average natural gas price—Algonquin Citygates ($/MMBtu) (7) |
| $ | 5.13 |
| $ | 3.86 |
| $ | 3.68 |
| $ | 3.10 |
|
|
|
|
|
|
|
|
|
|
| ||||
ERCOT |
|
|
|
|
|
|
|
|
| ||||
Million Megawatt Hours Generated (1) |
| 2.2 |
| — |
| 11.0 |
| — |
| ||||
IMA (1)(2): |
|
|
|
|
|
|
|
|
| ||||
Combined-Cycle Facilities |
| 96 | % | — | % | 94 | % | — | % | ||||
Coal-Fired Facility |
| 100 | % | — | % | 96 | % | — | % | ||||
Average Capacity Factor (1)(3): |
|
|
|
|
|
|
|
|
| ||||
Combined-Cycle Facilities |
| 11 | % | — | % | 25 | % | — | % | ||||
Coal-Fired Facility |
| 77 | % | — | % | 67 | % | — | % | ||||
CDDs (4) |
| 364 |
| 446 |
| 3,390 |
| 3,355 |
| ||||
HDDs (4) |
| 581 |
| 435 |
| 1,090 |
| 1,222 |
| ||||
Average Market On-Peak Spark Spreads ($/MWh) (5): |
|
|
|
|
|
|
|
|
| ||||
ERCOT North |
| $ | 6.65 |
| $ | 7.38 |
| $ | 7.79 |
| $ | 9.79 |
|
Average Market On-Peak Power Prices ($/MWh) (6): |
|
|
|
|
|
|
|
|
| ||||
ERCOT North |
| $ | 24.28 |
| $ | 26.91 |
| $ | 26.45 |
| $ | 26.02 |
|
Average natural gas price—Waha Hub ($/MMBtu) (7) |
| $ | 2.52 |
| $ | 2.79 |
| $ | 2.67 |
| $ | 2.32 |
|
|
|
|
|
|
|
|
|
|
| ||||
MISO |
|
|
|
|
|
|
|
|
| ||||
Million Megawatt Hours Generated |
| 7.7 |
| 7.0 |
| 29.1 |
| 29.8 |
| ||||
IMA for Coal-Fueled Facilities (2) |
| 90 | % | 88 | % | 89 | % | 89 | % | ||||
Average Capacity Factor for Coal-Fueled Facilities (3) |
| 66 | % | 60 | % | 63 | % | 53 | % | ||||
CDDs (4) |
| 105 |
| 123 |
| 1,272 |
| 1,652 |
| ||||
HDDs (4) |
| 1,924 |
| 1,656 |
| 4,534 |
| 4,662 |
| ||||
Average Market On-Peak Power Prices ($/MWh) (6): |
|
|
|
|
|
|
|
|
| ||||
Indiana (Indy Hub) |
| $ | 32.71 |
| $ | 37.89 |
| $ | 34.36 |
| $ | 33.71 |
|
Commonwealth Edison (NI Hub) |
| $ | 31.65 |
| $ | 33.28 |
| $ | 32.28 |
| $ | 31.98 |
|
|
|
|
|
|
|
|
|
|
| ||||
CAISO |
|
|
|
|
|
|
|
|
| ||||
Million Megawatt Hours Generated |
| 0.8 |
| 0.6 |
| 2.3 |
| 2.6 |
| ||||
IMA for Combined Cycle Facilities (2) |
| 93 | % | 95 | % | 92 | % | 96 | % | ||||
Average Capacity Factor for Combined Cycle Facilities (3) |
| 37 | % | 26 | % | 26 | % | 27 | % | ||||
CDDs (4) |
| 211 |
| 160 |
| 1,337 |
| 1,211 |
| ||||
HDDs (4) |
| 400 |
| 481 |
| 1,233 |
| 1,218 |
| ||||
Average Market On-Peak Spark Spreads ($/MWh) (5): |
|
|
|
|
|
|
|
|
| ||||
North of Path 15 (NP 15) |
| $ | 19.82 |
| $ | 13.71 |
| $ | 15.38 |
| $ | 12.67 |
|
Average Market On-Peak Spark Spreads ($/MWh) (6): |
|
|
|
|
|
|
|
|
| ||||
North of Path 15 (NP 15) |
| $ | 41.22 |
| $ | 36.61 |
| $ | 38.02 |
| $ | 31.60 |
|
Average natural gas price—PG&E Citygate ($/MMBtu) (7) |
| $ | 3.06 |
| $ | 3.27 |
| $ | 3.23 |
| $ | 2.70 |
|
(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 Brayton Point and CTs.
(3) Reflects actual production as a percentage of available capacity. The calculation excludes Brayton Point and CTs.
(4) Reflects CDDs or HDDs for the PJM, ISO-NE, ERCOT, MISO, and CAISO Regions 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 quoted 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.
DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED EBITDA
TWELVE MONTHS ENDED DECEMBER 31, 2017
(UNAUDITED) (IN MILLIONS)
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2017:
|
| Twelve Months Ended December 31, 2017 |
| |||||||||||||||||||
|
| PJM |
| NY/NE |
| ERCOT |
| MISO |
| CAISO |
| Other |
| Total |
| |||||||
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | 72 |
| ||||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Income tax benefit |
|
|
|
|
|
|
|
|
|
|
|
|
| (610 | ) | |||||||
Other income and expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
| (67 | ) | |||||||
Loss on early extinguishment of debt |
|
|
|
|
|
|
|
|
|
|
|
|
| 79 |
| |||||||
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
| 616 |
| |||||||
Earnings from unconsolidated investments |
|
|
|
|
|
|
|
|
|
|
|
|
| (8 | ) | |||||||
Bankruptcy reorganization items |
|
|
|
|
|
|
|
|
|
|
|
|
| (494 | ) | |||||||
Operating income (loss) |
| $ | 192 |
| $ | (113 | ) | $ | (147 | ) | $ | (44 | ) | $ | (45 | ) | $ | (255 | ) | $ | (412 | ) |
Depreciation and amortization expense |
| 390 |
| 232 |
| 74 |
| 91 |
| 57 |
| 7 |
| 851 |
| |||||||
Bankruptcy reorganization items |
| — |
| — |
| — |
| 494 |
| — |
| — |
| 494 |
| |||||||
Earnings from unconsolidated investments |
| 3 |
| 5 |
| — |
| — |
| — |
| — |
| 8 |
| |||||||
Loss on early extinguishment of debt |
| — |
| — |
| — |
| — |
| — |
| (79 | ) | (79 | ) | |||||||
Other income and expense, net |
| 16 |
| — |
| — |
| 26 |
| — |
| 25 |
| 67 |
| |||||||
EBITDA (1) |
| 601 |
| 124 |
| (73 | ) | 567 |
| 12 |
| (302 | ) | 929 |
| |||||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest |
| 5 |
| 2 |
| — |
| 2 |
| — |
| — |
| 9 |
| |||||||
Acquisition, integration and restructuring costs |
| — |
| — |
| — |
| — |
| — |
| 74 |
| 74 |
| |||||||
Bankruptcy reorganization items |
| — |
| — |
| — |
| (494 | ) | — |
| — |
| (494 | ) | |||||||
Mark-to-market adjustments, including warrants |
| 125 |
| 75 |
| 99 |
| (21 | ) | 7 |
| (16 | ) | 269 |
| |||||||
Impairments |
| 49 |
| — |
| — |
| 99 |
| — |
| — |
| 148 |
| |||||||
Loss (gain) on sale of assets, net |
| 36 |
| 90 |
| — |
| (1 | ) | — |
| — |
| 125 |
| |||||||
Loss on early extinguishment of debt |
| — |
| — |
| — |
| — |
| — |
| 79 |
| 79 |
| |||||||
Non-cash compensation expense |
| — |
| — |
| — |
| 1 |
| — |
| 20 |
| 21 |
| |||||||
Other |
| 2 |
| 2 |
| — |
| (1 | ) | — |
| (3 | ) | — |
| |||||||
Adjusted EBITDA (1) |
| $ | 818 |
| $ | 293 |
| $ | 26 |
| $ | 152 |
| $ | 19 |
| $ | (148 | ) | $ | 1,160 |
|
(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED EBITDA
TWELVE MONTHS ENDED DECEMBER 31, 2016
(UNAUDITED) (IN MILLIONS)
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2016:
|
| Twelve Months Ended December 31, 2016 |
| ||||||||||||||||
|
| PJM |
| NY/NE |
| MISO |
| CAISO |
| Other |
| Total |
| ||||||
Net loss |
|
|
|
|
|
|
|
|
|
|
| $ | (1,244 | ) | |||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income tax benefit |
|
|
|
|
|
|
|
|
|
|
| (45 | ) | ||||||
Other income and expense, net |
|
|
|
|
|
|
|
|
|
|
| (65 | ) | ||||||
Interest expense |
|
|
|
|
|
|
|
|
|
|
| 625 |
| ||||||
Earnings from unconsolidated investments |
|
|
|
|
|
|
|
|
|
|
| (7 | ) | ||||||
Bankruptcy reorganization items |
|
|
|
|
|
|
|
|
|
|
| 96 |
| ||||||
Operating income (loss) |
| $ | 414 |
| $ | (29 | ) | $ | (832 | ) | $ | (5 | ) | $ | (188 | ) | $ | (640 | ) |
Depreciation and amortization expense |
| 349 |
| 243 |
| 87 |
| 53 |
| 5 |
| 737 |
| ||||||
Bankruptcy reorganization items |
| — |
| — |
| (96 | ) | — |
| — |
| (96 | ) | ||||||
Earnings from unconsolidated investments |
| 7 |
| — |
| — |
| — |
| — |
| 7 |
| ||||||
Other income and expense, net |
| 9 |
| 1 |
| 15 |
| 12 |
| 28 |
| 65 |
| ||||||
EBITDA (1) |
| 779 |
| 215 |
| (826 | ) | 60 |
| (155 | ) | 73 |
| ||||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest |
| — |
| — |
| 2 |
| — |
| — |
| 2 |
| ||||||
Acquisition, integration and restructuring costs |
| — |
| — |
| (8 | ) | — |
| 29 |
| 21 |
| ||||||
Bankruptcy reorganization items |
| — |
| — |
| 96 |
| — |
| — |
| 96 |
| ||||||
Mark-to-market adjustments, including warrants |
| (92 | ) | (44 | ) | 47 |
| — |
| (6 | ) | (95 | ) | ||||||
Impairments |
| 65 |
| — |
| 793 |
| — |
| — |
| 858 |
| ||||||
Loss (gain) on sale of assets, net |
| — |
| — |
| (1 | ) | — |
| 2 |
| 1 |
| ||||||
Non-cash compensation expense |
| — |
| — |
| 6 |
| — |
| 22 |
| 28 |
| ||||||
Other (2) |
| 5 |
| — |
| 20 |
| (1 | ) | (1 | ) | 23 |
| ||||||
Adjusted EBITDA (1) |
| $ | 757 |
| $ | 171 |
| $ | 129 |
| $ | 59 |
| $ | (109 | ) | $ | 1,007 |
|
(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
(2) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.
DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED EBITDA
THREE MONTHS ENDED DECEMBER 31, 2017
(UNAUDITED) (IN MILLIONS)
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2017:
|
| Three Months Ended December 31, 2017 |
| |||||||||||||||||||
|
| PJM |
| NY/NE |
| ERCOT |
| MISO |
| CAISO |
| Other |
| Total |
| |||||||
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
| $ | (95 | ) | ||||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Income tax benefit |
|
|
|
|
|
|
|
|
|
|
|
|
| (280 | ) | |||||||
Loss on early extinguishment of debt |
|
|
|
|
|
|
|
|
|
|
|
|
| 4 |
| |||||||
Other income and expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
| (2 | ) | |||||||
Interest expense |
|
|
|
|
|
|
|
|
|
|
|
|
| 138 |
| |||||||
Earnings from unconsolidated investments |
|
|
|
|
|
|
|
|
|
|
|
|
| (4 | ) | |||||||
Operating income (loss) |
| $ | 14 |
| $ | (41 | ) | $ | (139 | ) | $ | 6 |
| $ | (12 | ) | $ | (67 | ) | $ | (239 | ) |
Depreciation and amortization expense |
| 97 |
| 53 |
| 19 |
| 19 |
| 13 |
| 1 |
| 202 |
| |||||||
Earnings from unconsolidated investments |
| 1 |
| 3 |
| — |
| — |
| — |
| — |
| 4 |
| |||||||
Loss on early extinguishment of debt |
| — |
| — |
| — |
| — |
| — |
| (4 | ) | (4 | ) | |||||||
Other income and expense, net |
| — |
| — |
| — |
| — |
| — |
| 2 |
| 2 |
| |||||||
EBITDA (1) |
| 112 |
| 15 |
| (120 | ) | 25 |
| 1 |
| (68 | ) | (35 | ) | |||||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |||||||
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude noncontrolling interest |
| 1 |
| — |
| — |
| 3 |
| — |
| — |
| 4 |
| |||||||
Acquisition, integration and restructuring costs |
| — |
| — |
| — |
| — |
| — |
| 19 |
| 19 |
| |||||||
Mark-to-market adjustments, including warrants |
| 97 |
| 69 |
| 108 |
| (1 | ) | 4 |
| — |
| 277 |
| |||||||
Loss on sale of assets, net |
| 5 |
| 13 |
| — |
| — |
| — |
| — |
| 18 |
| |||||||
Loss on early extinguishment of debt |
| — |
| — |
| — |
| — |
| — |
| 4 |
| 4 |
| |||||||
Non-cash compensation expense |
| — |
| — |
| — |
| 1 |
| — |
| 4 |
| 5 |
| |||||||
Other |
| 1 |
| 2 |
| — |
| — |
| — |
| (2 | ) | 1 |
| |||||||
Adjusted EBITDA (1) |
| $ | 216 |
| $ | 99 |
| $ | (12 | ) | $ | 28 |
| $ | 5 |
| $ | (43 | ) | $ | 293 |
|
(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED EBITDA
THREE MONTHS ENDED DECEMBER 31, 2016
(UNAUDITED) (IN MILLIONS)
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2016:
|
| Three Months Ended December 31, 2016 |
| ||||||||||||||||
|
| PJM |
| NY/NE |
| MISO |
| CAISO |
| Other |
| Total |
| ||||||
Net loss |
|
|
|
|
|
|
|
|
|
|
| $ | (182 | ) | |||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Income tax benefit |
|
|
|
|
|
|
|
|
|
|
| (51 | ) | ||||||
Other income and expense, net |
|
|
|
|
|
|
|
|
|
|
| (5 | ) | ||||||
Interest expense |
|
|
|
|
|
|
|
|
|
|
| 176 |
| ||||||
Earnings from unconsolidated investments |
|
|
|
|
|
|
|
|
|
|
| — |
| ||||||
Bankruptcy reorganization items |
|
|
|
|
|
|
|
|
|
|
| 96 |
| ||||||
Operating income (loss) |
| $ | 137 |
| $ | (7 | ) | $ | (42 | ) | $ | (5 | ) | $ | (49 | ) | $ | 34 |
|
Depreciation and amortization expense |
| 90 |
| 53 |
| 44 |
| 19 |
| 2 |
| 208 |
| ||||||
Bankruptcy reorganization items |
| — |
| — |
| (96 | ) | — |
| — |
| (96 | ) | ||||||
Earnings from unconsolidated investments |
| — |
| — |
| — |
| — |
| — |
| — |
| ||||||
Other income and expense, net |
| — |
| 1 |
| — |
| — |
| 4 |
| 5 |
| ||||||
EBITDA (1) |
| 227 |
| 47 |
| (94 | ) | 14 |
| (43 | ) | 151 |
| ||||||
Plus / (Less): |
|
|
|
|
|
|
|
|
|
|
|
|
| ||||||
Adjustment to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest |
| — |
| — |
| 2 |
| — |
| — |
| 2 |
| ||||||
Acquisition and integration costs |
| — |
| — |
| — |
| — |
| 8 |
| 8 |
| ||||||
Bankruptcy reorganization items |
| — |
| — |
| 96 |
| — |
| — |
| 96 |
| ||||||
Mark-to-market adjustments, including warrants |
| (49 | ) | (17 | ) | 17 |
| 1 |
| (1 | ) | (49 | ) | ||||||
Impairments |
| 1 |
| — |
| — |
| — |
| — |
| 1 |
| ||||||
Loss on sale of assets, net |
| — |
| — |
| — |
| — |
| 2 |
| 2 |
| ||||||
Non-cash compensation expense |
| — |
| — |
| 6 |
| — |
| 4 |
| 10 |
| ||||||
Other (2) |
| 2 |
| (1 | ) | 1 |
| (1 | ) | (3 | ) | (2 | ) | ||||||
Adjusted EBITDA (1) |
| $ | 181 |
| $ | 29 |
| $ | 28 |
| $ | 14 |
| $ | (33 | ) | $ | 219 |
|
(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
(2) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $2 million.
DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED FREE CASH FLOW (1)
TWELVE MONTHS ENDED DECEMBER 31, 2017
(UNAUDITED) (IN MILLIONS)
Adjusted EBITDA (2) |
| $ | 1,160 |
|
Interest payments |
| (567 | ) | |
Acquisition and integration payments |
| (55 | ) | |
Adjustment related to acquired derivatives |
| (42 | ) | |
Collateral, working capital and other |
| 89 |
| |
Net cash provided by operating activities |
| 585 |
| |
Capital expenditures |
| (249 | ) | |
Acquisition and integration payments |
| 55 |
| |
Adjustment related to acquired derivatives |
| 42 |
| |
Interest rate swap settlement payments |
| (20 | ) | |
Collateral, working capital and other |
| (39 | ) | |
Adjusted Free Cash Flow (2) |
| $ | 374 |
|
|
|
|
| |
Capital expenditures |
| $ | (224 | ) |
Acquisitions, net of cash acquired |
| (3,319 | ) | |
Distributions from unconsolidated investments |
| 12 |
| |
Proceeds from asset sales, net |
| 772 |
| |
Net cash used in investing activities |
| $ | (2,759 | ) |
|
|
|
| |
Proceeds from long-term borrowings, net of debt issuance costs |
| $ | 1,743 |
|
Repayments of borrowings |
| (2,589 | ) | |
Proceeds from issuance of equity, net of issuance costs |
| 150 |
| |
Payments of debt extinguishment costs |
| (50 | ) | |
Preferred stock dividends paid |
| (22 | ) | |
Interest rate swap settlement payments |
| (20 | ) | |
Acquisition of noncontrolling interest |
| (375 | ) | |
Payments related to bankruptcy settlement |
| (133 | ) | |
Other financing |
| (3 | ) | |
Net cash used in financing activities |
| $ | (1,299 | ) |
(1) This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of Adjusted Free Cash Flow. We believe it is useful to our analysts and investors to understand this relationship because it demonstrates how the cash generated by our operations is used to satisfy various liquidity requirements. A reconciliation of Adjusted Free Cash Flow from Net cash provided by operating activities is presented above. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures.
(2) Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures. See Regulation G Reconciliations - Adjusted EBITDA for the twelve months ended December 31, 2017 for a reconciliation of Adjusted EBITDA to Net income.
DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED FREE CASH FLOW (1)
TWELVE MONTHS ENDED DECEMBER 31, 2016
(UNAUDITED) (IN MILLIONS)
Adjusted EBITDA (2) |
| $ | 1,007 |
|
Interest payments |
| (558 | ) | |
Acquisition and integration payments |
| (19 | ) | |
Adjustment related to acquired derivatives |
| (47 | ) | |
Collateral, working capital and other |
| 262 |
| |
Net cash provided by operating activities |
| 645 |
| |
Capital expenditures |
| (228 | ) | |
Acquisition related payments |
| 73 |
| |
Adjustment related to acquired derivatives |
| 47 |
| |
Interest rate swap settlement payments |
| (17 | ) | |
Collateral, working capital and other |
| (257 | ) | |
Adjusted Free Cash Flow (2) |
| $ | 263 |
|
|
|
|
| |
Capital expenditures |
| $ | (293 | ) |
Distributions from unconsolidated affiliates |
| 14 |
| |
Proceeds from asset sales, net |
| 176 |
| |
Other investing |
| 10 |
| |
Net cash used in investing activities |
| $ | (93 | ) |
|
|
|
| |
Proceeds from long-term borrowings, net of debt issuance costs |
| $ | 3,014 |
|
Repayments of borrowings |
| (589 | ) | |
Proceeds from issuance of equity, net of issuance costs |
| 359 |
| |
Preferred stock dividends paid |
| (22 | ) | |
Interest rate swap settlement payments |
| (17 | ) | |
Other financing |
| (3 | ) | |
Net cash provided by financing activities |
| $ | 2,742 |
|
(1) This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of Adjusted Free Cash Flow. We believe it is useful to our analysts and investors to understand this relationship because it demonstrates how the cash generated by our operations is used to satisfy various liquidity requirements. A reconciliation of Adjusted Free Cash Flow from Net cash provided by operating activities is presented above. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures.
(2) Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 21, 2018, for definitions, utility and uses of such non-GAAP financial measures. See Regulation G Reconciliations - Adjusted EBITDA for the twelve months ended December 31, 2016 for a reconciliation of Adjusted EBITDA to Net loss.