News Release

Dynegy Announces 2017 Third Quarter Results

HOUSTON--(BUSINESS WIRE)--Nov. 1, 2017--

Dynegy Inc. (NYSE: DYN):

Summary of Third Quarter 2017 Financial Results (in millions):

   

Three Months Ended
September 30,

   

Nine Months Ended
September 30,

2017   2016 2017   2016
Operating Revenues $ 1,437 $ 1,184 $ 3,848 $ 3,211
Net Income (loss) $ (133 ) $ (249 ) $ 167 $ (1,062 )
Adjusted EBITDA (1) $ 397 $ 350 $ 867 $ 788
 

Reaffirming 2017 Guidance Ranges (in millions):

Adjusted EBITDA (1)           $1,200 - $1,400
Adjusted Free Cash Flow (1) $300 - $500
 

Recent Highlights:

  • Generated more than 34 million megawatt hours during the third quarter of 2017
  • Approximately $1.6 billion in liquidity at September 30, 2017
  • Completed sales of four power generation facilities during the third quarter of 2017 and one facility during October 2017; received approximately $785 million in aggregate cash proceeds
  • Reduced 2019 unsecured debt maturity by $1.25 billion and repaid $200 million of the existing Term Loan C using proceeds from asset sales, an $850 million bond offering, and cash-on-hand
  • Repaid the outstanding revolving credit facility balance of $300 million during October 2017
  • Achieved top decile safety performance across the entire Company for the second consecutive quarter

(1) Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures, see “Regulation G Reconciliations” for further details.

Dynegy Inc. (NYSE: DYN) reported a net loss of $133 million for the third quarter of 2017, compared to a net loss of $249 million for the third quarter of 2016. Results for the most recent quarter benefited from $86 million in contributions from assets acquired from ENGIE in February 2017 and lower impairment charges, partially offset by losses of $78 million related to the sale of assets and $66 million associated with the early extinguishment of debt.

The Company reported consolidated Adjusted EBITDA of $397 million for the 2017 third quarter compared to $350 million for the 2016 third quarter. Contributions from the ENGIE assets were partially offset by lower energy margin as a result of milder weather.

Net income for the first nine months of 2017 was $167 million compared to a net loss of $1,062 million for the first nine months of 2016. The year-to-date increase was primarily driven by contributions from the ENGIE assets, income from a deferred tax valuation allowance release in 2017, a gain primarily due to the extinguishment of debt associated with the Genco bankruptcy reorganization, and lower impairment charges, partially offset by non-cash mark-to-market losses associated with hedging transactions, acquisition and integration costs related to the ENGIE acquisition, a loss on the sale of assets, and a loss on the early extinguishment of debt.

For the first nine months of 2017, the Company reported consolidated Adjusted EBITDA of $867 million compared to $788 million for the first nine months of 2016. The $79 million increase in Adjusted EBITDA was primarily driven by contributions from the ENGIE assets, partially offset by lower energy margin largely driven by milder weather.

“During the third quarter, Dynegy’s power generation fleet produced the highest generation volumes in the Company’s history while simultaneously achieving top decile safety performance for the second quarter in a row,” said Robert C. Flexon, Dynegy’s President and Chief Executive Officer. “In addition to our operational achievements, we made significant improvements to our balance sheet, reducing our outstanding 2019 maturity by $1.25 billion, with approximately half of that repaid with asset sale proceeds and cash on hand.”

Third Quarter Comparative Results

    Quarter Ended September 30,
2017   2016
(in millions)

Operating
Income (Loss)

  Adjusted EBITDA (1)

Operating
Income (Loss)

  Adjusted EBITDA (1)
PJM $ 86 $ 243 $ 29 $ 215
NY/NE (30 ) 92 (15 ) 55
ERCOT 50 46
MISO (9 ) 12 13 16
IPH 11 21 (104 ) 50
CAISO 18 10 24
Other (50 ) (35 ) (50 ) (10 )
Total $ 58   $ 397   $ (117 ) $ 350  
__________________________________________

(1)

 

Adjusted EBITDA is a non-GAAP financial measure. See “Regulation G Reconciliations” for further details.

Segment Review of Results Quarter-over-Quarter

PJM - Operating income for the 2017 third quarter totaled $86 million, compared to operating income of $29 million for the same period of 2016. The increase was primarily due to income from the ENGIE assets, higher capacity revenues as a result of higher pricing, an increase in the mark-to-market value of derivative transactions and lower asset impairments, partially offset by lower energy margin. Adjusted EBITDA totaled $243 million during the 2017 third quarter compared to $215 million during the same period in 2016 primarily due to higher capacity revenues and contributions from the ENGIE assets, partially offset by lower energy margins.

NY/NE - Operating loss for the 2017 third quarter totaled $30 million, compared to operating loss of $15 million for the same period in 2016. The increase was primarily due to a $77 million loss related to the sale of the Dighton and Milford facilities in Massachusetts, partially offset by income from the ENGIE assets, higher capacity revenues as a result of higher pricing, and the change in the mark-to-market value of derivative transactions. Adjusted EBITDA totaled $92 million during the 2017 third quarter, compared to $55 million during the same period in 2016, primarily due to the contributions from the ENGIE assets.

ERCOT - Operating income for the 2017 third quarter totaled $50 million. Energy margin of $68 million and a mark-to-market gain of $23 million were partially offset by $23 million of O&M costs. Adjusted EBITDA was $46 million.

MISO - Operating loss for the 2017 third quarter totaled $9 million, compared to an operating income of $13 million for the same period in 2016. Contributing to the operating loss were lower dark spreads as a result of milder weather, lower generation volumes as a result of shutdowns in 2016, and higher depreciation expense. Adjusted EBITDA totaled $12 million during the 2017 third quarter compared to $16 million during the same period in 2016. The decrease was primarily due to lower dark spreads as a result of milder weather and lower generation volumes due to shutdowns in 2016.

IPH - Operating income for the 2017 third quarter totaled $11 million, compared to operating loss of $104 million for the same period of 2016. The year-over-year increase was primarily due to a $148 million impairment charge on the Newton facility in the third quarter 2016, partially offset by lower energy margin due to milder weather. Adjusted EBITDA totaled $21 million during the 2017 third quarter compared to $50 million during the same period in 2016, primarily due to lower energy margin as a result of milder weather.

CAISO - Operating income for the 2017 third quarter totaled $0 million, compared to operating income of $10 million for the same period in 2016. The decrease in operating income was primarily due to lower tolling revenue due to the expiration of a tolling agreement and lower capacity revenues due to lower contracted volumes and prices, partially offset by higher energy margin as a result of warmer weather. Adjusted EBITDA totaled $18 million during the 2017 third quarter compared to Adjusted EBITDA of $24 million during the same period in 2016.

Liquidity

As of September 30, 2017, Dynegy’s total available liquidity was approximately $1.6 billion as reflected in the table below.

(amounts in millions)      
Revolving facilities and LC capacity (1) $ 1,650
Less:
Outstanding revolver draw (300 )
Outstanding LCs (405 )
Revolving facilities and LC availability 945
Cash and cash equivalents 613  
Total available liquidity $ 1,558  
__________________________________________

(1)

 

Dynegy Inc. includes $1.5 billion in senior secured revolving credit facilities and $105 million related to LCs.

Consolidated Cash Flow

Cash provided by operations totaled $501 million for the first nine months of 2017. During the period, our power generation facilities and retail operations provided cash of $932 million. Corporate activities, primarily related to general and administrative, interest and acquisition-related expenses, as well as other working capital changes, used cash of $431 million during the period.

Cash used in investing activities totaled $2,771 million during the first nine months of 2017 as Dynegy used $3,249 million at the ENGIE acquisition closing and invested $129 million in capital expenditures, offset by $600 million proceeds received primarily related to the Troy and Armstrong, and Milford-MA and Dighton sales, in addition to $7 million distributions received from our unconsolidated investment in NELP.

Cash used in financing activities totaled $955 million for the first nine months of 2017 primarily as a result of the remaining payment obligation relating to the purchase of ECP’s interest in Atlas Power, payments related to our Genco subsidiary’s emergence from bankruptcy as well as various other financing activities.

2017 Guidance

Dynegy’s full-year 2017 Adjusted EBITDA guidance range remains unchanged at $1,200-1,400 million. The Company’s Adjusted free cash flow range is affirmed at $300 - $500 million.

The sale of Armstrong, Troy, Milford (MA), Dighton and Lee, together with the later than expected closing of the ENGIE acquisition, has impacted Adjusted EBITDA by approximately $70 million this year. As a result we currently expect to be near the bottom of the Adjusted EBITDA guidance range for the year.

PRIDE Update

Dynegy’s PRIDE Energized (Producing Results through Innovation by Dynegy Employees) program is on track to meet or exceed its 2017 target of $65 million in EBITDA by the end of the fourth quarter. The Company has already exceeded its three-year goal of $400 million in balance sheet improvements with $422 million in improvements accomplished in 2016. For 2017, Dynegy has identified more than $100 million of incremental balance sheet opportunities that will add to its aggregate total.

Safety

Dynegy’s safety performance for the third quarter 2017 was in the top decile for the industry for the second consecutive quarter. Both coal and gas facilities are focused on intensive safety initiatives helping to drive safety culture. Dynegy expects that all of its plants will complete the Voluntary Protection Program (VPP) process, a rigorous evaluation conducted by the Occupational Safety and Health Administration (OSHA), within the next three years. The Milford, Connecticut facility went through the VPP certification renewal process and was recommended for VPP recertification during the third quarter.

Retail Growth

Dynegy’s business has grown to serve approximately 1.2 million residential and commercial accounts. The retail business expanded to New England this summer with its municipal aggregation contracts in the greater Boston area. The Company now provides electricity to more than 500 communities in Illinois, Massachusetts and Ohio.

Asset Portfolio Updates

PJM and ISO-NE Asset Sales

Since June 30, Dynegy has completed the sale of five generating facilities, providing approximately $785 million in proceeds which were used for debt reduction. In July, Dynegy completed the sales of the Armstrong and Troy peaking units in Pennsylvania and Ohio, respectively, to an affiliate of LS Power for approximately $480 million in cash. In September, Dynegy completed the sale of the Dighton and Milford intermediate gas-fueled plants in Massachusetts to an affiliate of Starwood Energy Group Global for $125 million in cash including approximately $6 million in working capital adjustments. In October, Dynegy completed the sale of the Lee Energy Facility, a gas-fueled peaking asset in the PJM ComEd region, to an affiliate of Rockland Capital for $180 million in cash.

Earnings Presentation and Management Comments

Dynegy’s earnings presentation and management comments on the earnings presentation will be available on the “Investor Relations” section of www.dynegy.com later today. The Company will not be holding an investor conference call and webcast.

About Dynegy

Throughout the Northeast, Mid-Atlantic, Midwest, and Texas, Dynegy operates 27,000 megawatts (MW) of power generating facilities capable of producing enough energy to supply more than 22 million American homes. We generate power safely and responsibly for 1.2 million electricity customers who depend on that energy to grow and thrive.

Forward-Looking Statements

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 execution of Dynegy’s PRIDE Energized target in balance sheet and operating improvements program; anticipated earnings and cash flows, and Dynegy’s 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance. 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 2016 Form 10-K and subsequent Form 10-Qs. 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) beliefs and assumptions about weather and general economic conditions; (ii) 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; (iii) 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; (iv) sufficiency of, access to, and costs associated with coal, fuel oil, and natural gas inventories and transportation thereof; (v) the effects of, or changes to the power and capacity procurement processes in the markets in which we operate; (vi) 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; (vii) beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters; (viii) projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; (ix) our focus on safety and our ability to operate our assets efficiently so as to capture revenue generating opportunities and operating margins; (x) our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; (xi) our ability to optimize our assets through targeted investment in cost effective technology enhancements; (xii) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (xiii) efforts to secure retail sales and the ability to grow the retail business; (xiv) efforts to identify opportunities to reduce congestion and improve busbar power prices; (xv) ability to mitigate impacts associated with expiring reliability must run “RMR” and/or capacity contracts; (xvi) expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments; (xvii) expectations regarding performance standards and capital and maintenance expenditures; (xviii) the timing and anticipated benefits to be achieved through our Company-wide improvement programs; (xix) expectations regarding strengthening the balance sheet, managing debt maturities and improving Dynegy’s leverage profile; (xx) expectations, timing and benefits of the AES transaction; (xxi) efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures; (xxii) anticipated timing, outcome and impact of expected retirements; (xxiii) beliefs about the costs and scope of the ongoing demolition and site remediation efforts; and (xxiv) expectations regarding the synergies and anticipated benefits resulting from the ENGIE Acquisition. 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.

REPORTED UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(IN MILLIONS, EXCEPT PER SHARE DATA)

 

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 12 494
Earnings from unconsolidated investments 4 4 4 7
Interest expense (161 ) (166 ) (478 ) (449 )
Loss on early extinguishment of debt (66 ) (75 )
Other income and expense, net 19   29   65   60  
Loss before income taxes (134 ) (250 ) (163 ) (1,056 )
Income tax benefit (expense) 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:
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
       

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:

 
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.
(2) Shares included in the computation of diluted earnings (loss) per share for the nine months ended September 30, 2017 primarily consist of approximately 5.4 million shares related to our TEUs.
(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.
     

DYNEGY INC.

OPERATING DATA

 
The following table provides summary financial data regarding our PJM, NY/NE, ERCOT, MISO, IPH and CAISO segment
results of operations for the three and nine months ended September 30, 2017 and 2016, respectively.
 

Three Months Ended
September 30,

Nine Months Ended
September 30,

2017   2016 2017   2016
PJM
Million Megawatt Hours Generated (1) 14.5 15.1 38.8 39.3
IMA (1)(2):
Combined Cycle Facilities 98 % 97 % 93 % 97 %
Coal-Fueled Facilities 75 % 83 % 71 % 81 %
Average Capacity Factor (1)(3):
Combined Cycle Facilities 70 % 79 % 63 % 75 %
Coal-Fueled Facilities 62 % 65 % 54 % 51 %
CDDs (4) 787 1,044 1,085 1,377
HDDs (4) 34 17 2,606 3,056
Average Market On-Peak Spark Spreads ($/MWh) (5):
PJM West $ 23.21 $ 31.48 $ 16.79 $ 23.79
AD Hub $ 24.95 $ 27.27 $ 18.05 $ 28.88
Average Market On-Peak Power Prices ($/MWh) (6):
PJM West $ 35.10 $ 40.74 $ 33.62 $ 34.77
AD Hub $ 36.30 $ 38.75 $ 33.76 $ 32.66
Average natural gas price—TetcoM3 ($/MMBtu) (7) $ 1.70 $ 1.32 $ 2.40 $ 1.57
 
NY/NE
Million Megawatt Hours Generated (1)

5.7

5.4 14.6 13.1
IMA for Combined Cycle Facilities (1)(2) 87 % 98 % 91 % 95 %
Average Capacity Factor for Combined Cycle Facilities (1)(3) 52 % 63 % 42 % 50 %
CDDs (4) 519 724 687 874
HDDs (4) 62 100 3,543 3,658
Average Market On-Peak Spark Spreads ($/MWh) (5):
New York—Zone C $ 18.52 $ 26.04 $ 13.30 $ 17.37
Mass Hub $ 16.17 $ 21.58 $ 11.63 $ 14.49
Average Market On-Peak Power Prices ($/MWh) (6):
New York—Zone C $ 29.86 $ 34.79 $ 29.01 $ 26.74
Mass Hub $ 31.94 $ 41.31 $ 33.97 $ 34.44
Average natural gas price—Algonquin Citygates ($/MMBtu) (7) $ 2.25 $ 2.82 $ 3.19 $ 2.85
 
ERCOT
Million Megawatt Hours Generated (1) 5.0

8.8
IMA (1)(2):
Combined-Cycle Facilities 86 %

%

89 % %
Coal-Fueled Facility 93 % % 95 % %
Average Capacity Factor (1)(3):
Combined-Cycle Facilities 47 % % 30 %

%

Coal-Fueled Facility 75 % % 63 % %
CDDs (4) 1,701 1,808 3,026 2,909
HDDs (4) 509 788
Average Market On-Peak Spark Spreads ($/MWh) (5):
ERCOT North $ 12.65 $ 14.51 $ 8.16 $ 10.60
Average Market On-Peak Power Prices ($/MWh) (6):
ERCOT North $ 31.21 $ 33.25 $ 27.17 $ 25.72
Average natural gas price—Waha Hub ($/MMBtu) (7) $ 2.65 $ 2.68 $ 2.72 $ 2.16
 
MISO
Million Megawatt Hours Generated

3.4

4.2

8.8

11.2
IMA for Coal-Fueled Facilities (2) 94 % 90 % 90 % 89 %
Average Capacity Factor for Coal-Fueled Facilities (3) 82 % 76 % 71 % 61 %
CDDs (4) 786 1,029 1,167 1,529
HDDs (4) 11 46 2,610 3,006
Average Market On-Peak Power Prices ($/MWh) (6):
Indiana (Indy Hub) $ 37.04 $ 40.19 $ 34.91 $ 32.32
Commonwealth Edison (NI Hub) $ 34.03 $ 38.41 $ 32.49 $ 31.54
 
IPH
Million Megawatt Hours Generated 4.6 5.0 12.6 11.6
IMA for IPH Facilities (2) 85 % 88 % 87 % 88 %
Average Capacity Factor for IPH Facilities (3) 62 % 59 % 57 % 45 %
CDDs (4) 786 1,029 1,167 1,529
HDDs (4) 11 46 2,610 3,006
Average Market On-Peak Power Prices ($/MWh) ($/MWh) (6):
Indiana (Indy Hub) $ 37.04 $ 40.19 $ 34.91 $ 32.32
Commonwealth Edison (NI Hub) $ 34.03 $ 38.41 $ 32.49 $ 31.54
 
CAISO
Million Megawatt Hours Generated 1.0

0.5

1.5 2.0
IMA for Combined Cycle Facilities (2) 86 % 92 % 85 % 96 %
Average Capacity Factor for Combined Cycle Facilities (3) 43 % 20 % 23 % 27 %
CDDs (4) 874 723 1,126 1,051
HDDs (4) 6 22 834 737
Average Market On-Peak Spark Spreads ($/MWh) (5):
North of Path 15 (NP 15) $ 23.84 $ 15.44 $ 13.89 $ 12.32
Average natural gas price—PG&E Citygate ($/MMBtu) (7) $ 3.27 $ 3.18 $ 3.29 $ 2.52
__________________________________________
(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 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 and CTs.
(3) Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility and CTs.
(4) Reflects CDDs or HDDs for the region based on NOAA data.
(5) Reflects the simple 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.
 

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

THREE MONTHS ENDED SEPTEMBER 30, 2017

(UNAUDITED) (IN MILLIONS)

   

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended September 30, 2017:

 
Three Months Ended September 30, 2017
PJM   NY/NE   ERCOT   MISO   IPH   CAISO   Other   Total
Net loss $ (133 )
Plus / (Less):
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 (1) 199 24 70 10 34 15 (111 ) 241
Plus / (Less):
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 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 (1)(2) $ 243   $ 92   $ 46   $ 12   $ 21   $ 18   $ (35 ) $ 397  

__________________________________________

(1)   EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 1, 2017, 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) Not adjusted to exclude Wood River’s energy margin and O&M costs.
 

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

THREE MONTHS ENDED SEPTEMBER 30, 2016

(UNAUDITED) (IN MILLIONS)

   

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended September 30, 2016:

 
Three Months Ended September 30, 2016
PJM   NY/NE   MISO   IPH   CAISO   Other   Total
Net loss $ (249 )
Plus / (Less):
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 (1) 128 40 18 (96 ) 25 (24 ) 91
Plus / (Less):
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 (2) 2     2   (3 ) 1   1   3  
Adjusted EBITDA (1) $ 215   $ 55   $ 16   $ 50   $ 24   $ (10 ) $ 350  

__________________________________________

(1)   EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 1, 2017, 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 $3 million.
 

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

NINE MONTHS ENDED SEPTEMBER 30, 2017

(UNAUDITED) (IN MILLIONS)

   

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the nine months ended September 30, 2017:

 
Nine Months Ended September 30, 2017
PJM   NY/NE   ERCOT   MISO   IPH   CAISO   Other   Total
Net income $ 167
Plus / (Less):
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 (1) 489 109 47 (56 ) 598 11 (234 ) 964
Plus / (Less):
Adjustments to reflect Adjusted EBITDA from unconsolidated investments and exclude 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 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 (1)(2) $ 602   $ 194   $ 38   $ 25   $ 99   $ 14   $ (105 ) $ 867  

__________________________________________

(1)   EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 1, 2017, 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) Not adjusted to exclude Wood River’s energy margin and O&M costs.
   

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

NINE MONTHS ENDED SEPTEMBER 30, 2016

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the nine months ended September 30, 2016:

 
Nine Months Ended September 30, 2016
PJM   NY/NE   MISO   IPH   CAISO   Other   Total
Net loss $ (1,062 )
Plus / (Less):
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 (1) 552 168 (680 ) (52 ) 45 (111 ) (78 )
Plus / (Less):
Acquisition and integration 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 (2) 2     21   (3 ) 1   3   24  
Adjusted EBITDA (1) $ 576   $ 142   $ 19   $ 82   $ 45   $ (76 ) $ 788  

__________________________________________

(1)   EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 1, 2017, 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 for the nine months ended September 30, 2016.
 

DYNEGY INC.

REG G RECONCILIATIONS - 2017 GUIDANCE

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance:

       
Dynegy Consolidated
Low       High
Net income (1) $ 152 $ 342
Plus / (Less):
Interest expense 625 630
Tax benefit (325 ) (330 )
Depreciation and amortization expense 845   855  
EBITDA (2) 1,297 1,497
Plus / (Less):
Acquisition, integration and restructuring costs 55 55
Bankruptcy reorganization items (494 ) (494 )
Impairments 148 148
Loss on sale of assets 107 107
Loss on early extinguishment of debt 75 75
Other adjustments, net 12   12  
Adjusted EBITDA (2) $ 1,200 $ 1,400
Cash interest payments (600 ) (600 )
Acquisition, integration and restructuring costs (55 ) (55 )
Other cash items (90 ) (90 )
Cash Flow from Operations 455 655
Maintenance capital expenditures (200 ) (200 )
Environmental capital expenditures (10 ) (10 )
Acquisition, integration and restructuring costs 55   55  
Adjusted Free Cash Flow (2) $ 300   $ 500  

__________________________________________

(1)   For purposes of our 2017 guidance, fair value adjustments related to derivatives and our common stock warrants are assumed to be zero.
(2) EBITDA, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures. Please refer to Item 2.02 of our Form 8-K filed on November 1, 2017, for definitions, utility and uses of such non-GAAP financial measures.

Source: Dynegy Inc.

Dynegy Inc.
Media: Dean Ellis, 713.767.5800
Analysts: 713.507.6466