Dynegy Announces 2016 Third Quarter Results Affirms 2016 Guidance; Initiates 2017 Guidance

Dynegy Inc. (NYSE: DYN):

Summary of Third Quarter 2016 Financial Results (in millions):
     

Three Months Ended September 30

Nine Months Ended September 30
2016   2015 2016   2015
Operating Revenues $ 1,184 $ 1,232 $ 3,211 $ 2,854
Net Income (loss) $ (249 ) $ (24 ) $ (1,060 ) $ 184
Adjusted EBITDA $ 350 $ 350 $ 788 $ 628
 
  • $2,570 million in consolidated liquidity, including $121 million at IPH as of September 30, 2016

2016 and 2017 Guidance
  • Affirming 2016 Adjusted EBITDA guidance range at $1,000 to $1,100 million and 2016 Free Cash Flow guidance at $200 to $300 million
  • Initiating 2017 Adjusted EBITDA guidance range at $1,200 to $1,400 million and 2017 Free Cash Flow guidance at $150 to $350 million

Business Developments
  • Restructuring support agreement (RSA) reached with Illinois Power Generating Company (Genco) and an ad hoc group of Genco bondholders to restructure $825 million in unsecured debt at Genco
  • Baldwin unit 1 to remain online through Planning Year 2017/2018 to support bilateral capacity sales
  • 90-day notice filed earlier today with the California Independent System Operator to retire Moss Landing units 6 and 7

Other
  • Closed $750 million offering of 8.00% senior notes due in 2025; secures financing needed to complete the ECP buyout obligation and improves overall financial flexibility
  • J.D. Power named Dynegy "Highest in Residential Customer Satisfaction with Retail Electric Service in Ohio"

Dynegy Inc. (NYSE: DYN) reported net loss for the 2016 third quarter of $249 million, compared to a net loss of $24 million for the 2015 third quarter. The quarter-over-quarter decrease is mainly due to a $138 million increase in non-cash asset impairment charges and a $74 million increase in non-cash mark-to-market losses associated with hedging transactions.

The Company reported consolidated Adjusted EBITDA of $350 million, compared to $350 million for the 2015 third quarter. Higher realized energy margin at the Gas and IPH segments offset a reduction in capacity revenues at the Gas and Coal segments resulting primarily from lower capacity pricing in PJM.

The net loss for the first nine months of 2016 was $1,060 million, compared to net income of $184 million for the first nine months of 2015. The year-over-year decrease was primarily driven by asset impairments at the Company's Baldwin, Newton and Stuart plants in 2016 and a second quarter 2015 deferred tax valuation allowance reversal which benefitted 2015 results but did not reoccur in 2016. This decrease was partially offset by the first quarter 2016 contribution from the Duke Midwest and EquiPower plants which were acquired in April 2015.

For the first nine months of 2016, the Company reported consolidated Adjusted EBITDA of $788 million, compared to $628 million for the first nine months of 2015. The $160 million increase in Adjusted EBITDA was primarily due to the first quarter 2016 contribution from the Duke Midwest and EquiPower plants which were acquired in April 2015. Partially offsetting this benefit were lower energy margins, net of hedges, in all segments primarily due to lower power prices and generation volumes at the Coal segment, lower generation volumes at the IPH segment, and lower spark spreads and generation volumes at the Gas segment, as a result of mild winter weather across our markets. Higher O&M costs, primarily associated with planned major maintenance outages at the Gas segment, which coincided with plant capacity uprates, also provided an offset.

"We remain on track to achieve our 2016 Adjusted EBITDA and Free Cash Flow guidance," said Dynegy President and Chief Executive Officer Robert C. Flexon. "As we wait for FERC approval on our ENGIE North American power acquisition we have completed all of the necessary financings to close the transaction and are prepared for full integration on Day 1. Our debt reduction efforts remain a priority and, as part of this effort, the successful restructuring of Genco eliminates over $600 million in consolidated debt by the first quarter of 2017. In light of the low commodity price environment, we will continue to conservatively manage our balance sheet into and beyond 2017."

Third Quarter Comparative Results

 
          Quarter Ended September 30, 2016
(in millions)
Coal       IPH     Gas       Other    

 
Total
Net loss attributable to Dynegy Inc. $ (249 )
Plus / (Less):
Income tax benefit (1 )
Other income and expense, net (29 )
Interest expense 166
Earnings from unconsolidated investment (4 )
Operating income (loss) $ (33 ) $ (104 ) $ 69 $ (49 ) $ (117 )
Plus / (Less):
Depreciation and amortization expense 30 7 137 1 175
Earnings from unconsolidated investment 4 4
Other income and expense, net 3   1     25   29  
EBITDA (1) (96 ) 210 (23 ) 91
Plus / (Less):

Adjustments to reflect Adjusted EBITDA from

unconsolidated investment and exclude

noncontrolling interest
(1 ) (4 ) (5 )
Acquisition, integration and restructuring costs 12 12
Mark-to-market adjustments, including warrants (20 ) 2 53 (4 ) 31
Impairments 55 148 9 212
Wood River energy margin and O&M 3 3
Non-cash compensation expense 1 5 6
Other 1   (3)   2      

Adjusted EBITDA (1)

$39
 

$50
 

$271
 

$(10)
 

$350
 
 
Quarter Ended September 30, 2015
(in millions)
Coal IPH Gas Other   Total
Net loss attributable to Dynegy Inc. $ (24 )
Plus / (Less):
Income tax expense 28
Other income and expense, net (46 )
Interest expense 145
Losses from unconsolidated investment 4  
Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) $ 107
Plus / (Less):
Depreciation and amortization expense 30 6 139 1 176
Losses from unconsolidated investment (4 ) (4 )
Other income and expense, net       46   46  
EBITDA (1) (6 ) 37 287 7 325
Plus / (Less):

Adjustment to reflect Adjusted EBITDA from

unconsolidated investment
8 8
Acquisition and integration costs 8 8
Mark-to-market adjustments, including warrants (14 ) (3 ) (6 ) (45 ) (68 )
Impairments 74 74
Other     2   1   3  
Adjusted EBITDA (1)(2) $ 54   $ 34   $ 291   $ (29 ) $ 350  

__________________________________________
 
(1)   EBITDA and Adjusted EBITDA are non-GAAP financial measures and are used by management to evaluate Dynegy's business on an ongoing basis. Please refer to Item 2.02 of Dynegy's Form 8-K which is available on the Company's website: www.dynegy.com and filed on November 1, 2016, for definitions, purposes and uses of such non-GAAP financial measures. General and administrative expenses are not allocated to each segment and are included in the Other segment. Management does not allocate 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 for these items which are excluded in 2016: (i) non-cash compensation expense of $6 million, and (ii) Wood River's energy margin and O&M costs of $1 million.
 

Segment Review of Results Quarter-over-Quarter

Gas - The 2016 third quarter operating income was $69 million, compared to $152 million for the same period in 2015. The decrease was due to non-cash mark-to-market losses on hedging transactions and lower capacity revenues in PJM, partially offset by higher realized energy margin. Adjusted EBITDA totaled $271 million during the 2016 third quarter compared to $291 million during the same period in 2015. The decrease was driven by lower capacity revenues due to lower pricing and higher O&M costs primarily due to an increase in property tax assessments at our Ohio combined cycle plants. This decrease was partially offset by higher energy margin, net of hedges, primarily due to higher spark spreads as a result of warmer weather conditions and lower delivered fuel costs.

Coal - The 2016 third quarter operating loss was $33 million, compared to an operating loss of $36 million for the same period in 2015. Lower energy margin, net of hedges, and lower capacity revenues in 2016 were more than offset by lower impairment charges and O&M costs. Adjusted EBITDA, excluding Wood River, totaled $39 million during the 2016 third quarter as compared to $54 million during the same period in 2015. This decrease of $15 million was driven by lower PJM capacity revenues as a result of performance penalties during the period and lower energy margin, net of hedges, due to lower realized power prices. These items more than offset the benefit of higher generation volumes during the quarter and lower O&M costs resulting from a reduction in property tax assessments at our Ohio coal-fueled generating facilities.

IPH - The 2016 third quarter operating loss was $104 million, compared to operating income of $31 million for the same period in 2015. The decrease was primarily due to a non-cash asset impairment at the Newton facility. Adjusted EBITDA totaled $50 million during the 2016 third quarter compared to $34 million during the same period in 2015. The quarter-over-quarter increase in Adjusted EBITDA was due to higher energy margin, net of hedges, as a result of higher power prices due to warmer weather and higher capacity revenues.

Liquidity

As of September 30, 2016, Dynegy's total available liquidity was $2.6 billion as reflected in the table below and excludes amounts classified as restricted cash in our unaudited consolidated balance sheet.
   
September 30, 2016
(amounts in millions) Dynegy Inc.   IPH (1)   Total
Revolving facilities and LC capacity $ 1,480 $ 44 $ 1,524
Less: Outstanding LCs (382 ) (30 ) (412 )
Revolving facilities and LC availability 1,098 14 1,112
Cash and cash equivalents 1,351   107   1,458  
Total available liquidity (2) $ 2,449   $ 121   $ 2,570  

__________________________________________
(1)   Includes cash and cash equivalents of $84 million related to Genco.
(2) On December 2, 2013, Dynegy and Illinois Power Resources, LLC entered into an intercompany revolving promissory note of $25 million. At September 30, 2016, there was approximately $5 million outstanding on the note, which is not reflected in the table above.
 

Consolidated Cash Flow

Cash provided by operations totaled $649 million for the first nine months of 2016. During the period, our power generation facilities and retail operations provided cash of $773 million. Corporate and other activities used cash of $293 million primarily for interest payments on various debt agreements of $277 million and acquisition-related costs of $16 million. In addition, changes in working capital and other, net of general and administrative expenses, provided cash of $169 million during the period.

Cash used in investing activities totaled $2.280 billion during the first nine months of 2016. During the period, restricted cash increased by $2.0 billion from proceeds from the Tranche C Term Loan being held in escrow for the ENGIE acquisition and $71 million in related pre-funded interest, original issuance discount and interest income, offset by $26 million released from escrow for interest payments. Additionally, during the nine months ended September 30, 2016, we paid $259 million in capital expenditures, received a $14 million cash inflow related to distributions from our unconsolidated investment in Elwood, and received $10 million in proceeds from an insurance claim.

Cash provided by financing activities totaled $2.584 billion for the first nine months of 2016 primarily due to (i) $2.0 billion in proceeds related to the Tranche C Term Loan, (ii) $443 million in net proceeds from our tangible equity units, and (iii) $198 million of proceeds related to our forward capacity agreement, partially offset by (iv) $21 million in repayments associated with our equipment financing agreements and Tranche B-2 Term Loan, (v) $16 million in dividend payments on our preferred stock, and (vi) $13 million in interest rate swap settlement payments.

2017 Guidance

Dynegy initiated 2017 guidance with an Adjusted EBITDA range of $1,200 to $1,400 million and a Free Cash Flow range of $150 to $350 million. The ranges assume that the ENGIE and Elwood transactions close in 2016, and that the Genco restructuring is completed in the first quarter of 2017. Additionally, the guidance ranges contemplate the significant major outage schedule, particularly for the ENGIE fleet.

Genco Restructuring

In October, Dynegy reached a restructuring support agreement (RSA) with Illinois Power Generating Company (Genco) and an ad hoc group of Genco bondholders representing approximately 70% of the $825 million in outstanding unsecured debt at Genco. The existing 2018, 2020 and 2032 Genco notes are to be exchanged for up to $210 million in new 7-year Dynegy Inc. unsecured notes, up to $130 million cash consideration, and warrants for up to 10 million shares of Dynegy Inc. common stock. An additional $9 million in cash consideration will be paid to GENCO bondholders who previously participated in the RSA. Dynegy intends to launch the exchange offer in the fourth quarter of 2016 for the restructuring. If less than 97% of outstanding bonds are tendered in the exchange, the restructuring will be consummated through a prepackaged chapter 11 filing of Genco. In the event of a pre-packaged Chapter 11 process, non-accredited investors participating (expected to be less than 20% of noteholders) will receive cash in lieu of unsecured notes and warrants. The amount of notes and warrants issued by Dynegy at that time will be reduced by a like amount so there is no change in total consideration.

$750 Million Senior Notes Offering

Dynegy closed its offering of $750 million in aggregate principal amount of 8.00% senior notes due 2025 in a private placement. Dynegy intends to use the net proceeds of the offering, together with the proceeds from the Elwood sale, and cash-on-hand, to fund the ECP buyout and repayment of debt.

PRIDE Energized

Dynegy's PRIDE initiative, Producing Results through Innovation by Dynegy Employees program, celebrated its five-year anniversary in August. The current incarnation, PRIDE Energized, aims to deliver an incremental $250 million in EBITDA and $400 million in balance sheet improvements by the end of 2018. The Company is on track to achieve the targeted $135 million in Adjusted EBITDA for 2016, with $104 million secured to date, and exceed the $200 million in balance sheet improvement targets for the year.

Safety

Casco Bay Energy Facility in Veazie, Maine became the seventh and latest Dynegy asset to achieve OSHA Voluntary Protection Program (VPP) status, OSHA's stringent safety certification. 70% of Dynegy's operated plants have achieved or are in the process of pursuing OSHA VPP status. The VPP approach has been shown to save lives and reduce injuries, serving as a model for others. Four additional facilities have submitted applications and are awaiting review, with two more facilities scheduled to submit VPP applications by the end of this year.

Asset Portfolio Changes

Newton unit 2 retired on September 15 and Baldwin unit 3 shut down on October 17 after failing to clear the most recent MISO capacity auction. Baldwin unit 1 is to remain online through Planning Year 2017/2018 to support incremental bilateral capacity sales. Newton unit 1 and Baldwin unit 2 remain in operation as well.

Earlier today, Dynegy filed its 90-day notice with the California Independent System Operator that the Company intends to retire Moss Landing units 6 and 7 by the end of January 2017. The units failed to secure a Resource Adequacy transaction leaving them unable to recover basic operating costs.

ENGIE and Elwood Transactions Update

Dynegy continues to await regulatory approval from the Federal Energy Regulatory Commission (FERC) to purchase ENGIE's U.S. fossil portfolio. FERC approval of the sale of the Company's 50% interest in Elwood Energy to J-Power USA Development Co. Ltd. is also pending.

Investor Conference Call/Webcast

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. Dynegy will answer questions about its 2016 third quarter financial results during an investor conference call and webcast tomorrow, November 2, 2016 at 9 a.m. ET/8 a.m. CT. Participants may access the webcast from the Company's website.

About Dynegy

At Dynegy, we generate more than just power for our customers. We are committed to being a leader in the electricity sector. Throughout the Midwest and Northeast, Dynegy operates power generating facilities capable of producing more than 25,000 megawatts of electricity - or enough energy to power the homes of 21 million U.S. families. We're proud of what we do, but it's about much more than just output. We're always striving to generate power safely and responsibly for our wholesale and retail electricity customers who depend on that 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: expectations and beliefs related to Genco's RSA and timing, terms and execution of the exchange offer and potential subsequent Chapter 11 filing; execution of its PRIDE Energized target in balance sheet and operating improvements by year-end 2016; the shutdown of certain Illinois coal-fueled units; ability to obtain FERC approval and to close the ENGIE and Elwood transactions; anticipated earnings and cash flows and Dynegy's 2016 and 2017 Adjusted EBITDA and 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 (the SEC). Specifically, Dynegy makes reference to, and incorporates herein by reference, the section entitled "Risk Factors" in its 2015 Form 10-K and subsequent Form 10-Qs. 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, MISO, PJM, CAISO, NYISO, or ISO-NE power and capacity procurement processes; (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 Dynegy's costs, result in an impairment of Dynegy's assets, cause Dynegy to limit or terminate the operation of certain of its facilities, or otherwise have a negative financial effect; (vii) beliefs about the outcome of legal, administrative, legislative, and regulatory matters; (viii) projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; (ix) Dynegy's focus on safety and Dynegy's ability to efficiently operate its assets so as to capture revenue generating opportunities and operating margins; (x) Dynegy's ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; (xi) Dynegy's ability to optimize its assets through targeted investment in cost effective technology enhancements; (xii) the effectiveness of Dynegy's strategies to capture opportunities presented by changes in commodity prices and to manage Dynegy's 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 RMR and/or capacity contracts; (xvi) expectations regarding Dynegy's 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) beliefs concerning the restructuring of Genco, including the RSA; (xix) the timing and anticipated benefits to be achieved through Dynegy's companywide improvement programs, including its PRIDE initiative; (xx) anticipated timing, outcome, and impact of the expected retirement of Brayton Point and the shutdown of Baldwin Units 1 and 3, and Moss Landing 6 and 7; (xxi) beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the Vermilion and Wood River facilities and any potential future remediation obligations at the South Bay facility; (xxii) expectations regarding the synergies, completion, timing and anticipated benefits of the ENGIE acquisition; (xxiii) expectations regarding the completion and timing of the Elwood Energy facility sale, and anticipated use of proceeds from such sale; and (xxiv) beliefs regarding redevelopment efforts for the Morro Bay facility. 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, including those set forth under Item 1A - Risk Factors of Dynegy's Form 10-K and subsequent form 10-Qs.
 

DYNEGY INC.

REPORTED UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(IN MILLIONS, EXCEPT PER SHARE DATA)
 
         

Three Months Ended

September 30,
     

Nine Months Ended

September 30,
2016       2015 2016       2015
Revenues $ 1,184 $ 1,232 $ 3,211 $ 2,854
Cost of sales, excluding depreciation expense (660 ) (621 ) (1,698 ) (1,494 )
Gross margin 524 611 1,513 1,360
Operating and maintenance expense (218 ) (219 ) (695 ) (580 )
Depreciation expense (163 ) (174 ) (494 ) (413 )
Impairments (212 ) (74 ) (857 ) (74 )
General and administrative expense (41 ) (29 ) (117 ) (94 )
Acquisition and integration costs (7 ) (8 ) (8 ) (121 )
Other     (16 ) (1 )
Operating income (loss) (117 ) 107 (674 ) 77
Earnings (losses) from unconsolidated investment 4 (4 ) 7 (1 )
Interest expense (166 ) (145 ) (449 ) (413 )
Other income and expense, net 29   46   60   45  
Income (loss) before income taxes (250 ) 4 (1,056 ) (292 )
Income tax benefit (expense) 1   (28 ) (6 ) 473  
Net income (loss) (249 ) (24 ) (1,062 ) 181
Less: Net loss attributable to noncontrolling interest     (2 ) (3 )
Net income (loss) attributable to Dynegy Inc. (249 ) (24 ) (1,060 ) 184
Less: Dividends on preferred stock 5   5   16   16  

Net income (loss) attributable to Dynegy Inc. common

stockholders
$ (254 ) $ (29 ) $ (1,076 ) $ 168  
 
Earnings (Loss) Per Share:

Basic earnings (loss) per share attributable to Dynegy

Inc. common stockholders
$ (1.81 ) $ (0.23 ) $ (8.54 ) $ 1.33

Diluted earnings (loss) per share attributable to Dynegy

Inc. common stockholders
$ (1.81 ) $ (0.23 ) $ (8.54 ) $ 1.31
 
Basic shares outstanding 140 126 126 126
Diluted shares outstanding 140 126 126 140
 
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

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
Coal     IPH     Gas     Other     Total
Net loss attributable to Dynegy Inc. $ (249 )
Plus / (Less):
Income tax benefit (1 )
Interest expense 166
Depreciation and amortization expense 175  
EBITDA (1) $ $ (96 ) $ 210 $ (23 ) $ 91

Adjustments to reflect Adjusted EBITDA from

unconsolidated investment and exclude noncontrolling

interest
(1 ) (4 ) (5 )
Acquisition, integration, and restructuring costs 12 12
Mark-to-market adjustments, including warrants (20 ) 2 53 (4 ) 31
Impairments 55 148 9 212
Wood River energy margin and O&M 3 3
Non-cash compensation expense 1 5 6
Other 1   (3)   2      
Adjusted EBITDA (1) $ 39   $ 50   $ 271   $ (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, 2016, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
 
 
          Three Months Ended September 30, 2016
Coal     IPH     Gas     Other     Total
Operating income (loss) $ (33 ) $ (104 ) $ 69 $ (49 ) $ (117 )
Depreciation and amortization expense 30 7 137 1 175
Earnings from unconsolidated investment 4 4
Other income and expense, net 3   1     25   29  
EBITDA $   $ (96 ) $ 210   $ (23 ) $ 91  
 
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2015

(UNAUDITED) (IN MILLIONS)
 
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended September 30, 2015:
 
          Three Months Ended September 30, 2015
Coal     IPH     Gas     Other     Total
Net loss attributable to Dynegy Inc. $ (24 )
Plus / (Less):
Income tax expense 28
Interest expense 145
Depreciation and amortization expense 176  
EBITDA (1) $ (6 ) $ 37 $ 287 $ 7 $ 325
Plus / (Less):

Adjustment to reflect Adjusted EBITDA from unconsolidated

investment
8 8
Acquisition and integration costs 8 8
Mark-to-market adjustments, including warrants (14 ) (3 ) (6 ) (45 ) (68 )
Impairments 74 74
Other     2   1   3  
Adjusted EBITDA (1)(2) $ 54   $ 34   $ 291   $ (29 ) $ 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, 2016, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate 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 for these items which are excluded in 2016: (i) non-cash compensation expense of $6 million, and (ii) Wood River's energy margin and O&M costs of $1 million.
 
 
          Three Months Ended September 30, 2015
Coal     IPH     Gas     Other     Total
Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) $ 107
Depreciation and amortization expense 30 6 139 1 176
Losses from unconsolidated investment (4 ) (4 )
Other income and expense, net       46   46  
EBITDA $ (6 ) $ 37   $ 287   $ 7   $ 325  
 
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

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
Coal       IPH       Gas       Other       Total
Net loss attributable to Dynegy Inc. $ (1,060 )
Plus / (Less):
Loss attributable to noncontrolling interest (2 )
Income tax expense 6
Interest expense 449
Depreciation and amortization expense 529  
EBITDA (1) $ (632 ) $ (52 ) $ 716 $ (110 ) $ (78 )
Plus / (Less):
 
 

Adjustments to reflect Adjusted EBITDA from unconsolidated

investment and exclude noncontrolling interest
Acquisition, integration, and restructuring costs (8 ) 21 13
Mark-to-market adjustments, including warrants 23 (3 ) (61 ) (5 ) (46 )
Impairments 700 148 9 857
Wood River energy margin and O&M 23 23
Non-cash compensation expense 2 16 18
Other 1   (3)   1   2   1  
Adjusted EBITDA (1) $ 115   $ 82   $ 667   $ (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, 2016, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.
 
 
          Nine Months Ended September 30, 2016
Coal     IPH     Gas     Other     Total
Operating income (loss) $ (728 ) $ (87 ) $ 279 $ (138 ) $ (674 )
Depreciation and amortization expense 87 20 418 4 529
Earnings from unconsolidated investment 7 7
Other income and expense, net 9   15   12   24   60  
EBITDA $ (632 ) $ (52 ) $ 716   $ (110 ) $ (78 )
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2015

(UNAUDITED) (IN MILLIONS)
The following table provides summary financial data regarding our Adjusted EBITDA by segment for the nine months ended September 30, 2015:

 

 
    Nine Months Ended September 30, 2015
Coal   IPH   Gas   Other   Total
Net income attributable to Dynegy Inc. $ 184
Plus / (Less):
Loss attributable to noncontrolling interest (3 )
Income tax benefit (473 )
Interest expense 413
Depreciation and amortization expense   414  
EBITDA (1) $ 44 $ 66 $ 595 $ (170 ) $ 535
Plus / (Less):
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest

3 8 11
Acquisition and integration costs 121 121
Mark-to-market adjustments, including warrants (35 ) (8 ) (29 ) (43 ) (115 )
Impairments 74 74
Other           1     1     2  
Adjusted EBITDA (1)(2) $ 83   $ 61   $ 575   $ (91 ) $ 628  

__________________________________________
(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, 2016, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate 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 for these items which are excluded in 2016: (i) non-cash compensation expense of $20 million, and (ii) Wood River's energy margin and O&M costs of $9 million.
 
    Nine Months Ended September 30, 2015
Coal       IPH       Gas       Other       Total
Operating income (loss) $ (34 ) $ 39 $ 290 $ (218 ) $ 77
Depreciation and amortization expense 78 27 306 3 414
Losses from unconsolidated investment (1 ) (1 )
Other income and expense, net             45     45  
EBITDA $ 44   $ 66 $ 595   $ (170 ) $ 535  
 

DYNEGY INC.

OPERATING DATA
 

The following table provides summary financial data regarding our Coal, IPH and Gas segment results of operations for the three and nine months ended September 30, 2016 and 2015, respectively.
       

Three Months Ended September 30,

Nine Months Ended September 30,
2016     2015 2016     2015
Coal
Million Megawatt Hours Generated (8) 10 9.5 25.3 21.7
IMA for Coal-Fired Facilities (1) (8) 86 % 82 % 84 % 80 %
Average Capacity Factor for Coal-Fired Facilities (2) (8) 69 % 62 % 55 % 59 %
Average Quoted Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 40.19 $ 33.09 $ 32.32 $ 35.17
Commonwealth Edison (NI Hub) $ 38.41 $ 34.03 $ 31.54 $ 35.44
Mass Hub $ 41.31 $ 35.52 $ 34.44 $ 53.62
AD Hub $ 38.75 $ 35.87 $ 32.66 $ 39.86
Average Quoted Market Off-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 24.38 $ 23.37 $ 22.31 $ 25.41
Commonwealth Edison (NI Hub) $ 22.57 $ 22.93 $ 20.81 $ 23.49
Mass Hub $ 23.57 $ 21.02 $ 23.40 $ 38.90
AD Hub $ 23.53 $ 24.21 $ 22.72 $ 27.20
 
IPH
Million Megawatt Hours Generated 5.0 4.8 11.6 14.7
IMA for IPH Facilities (4) 88 % 84 % 88 % 89 %
Average Capacity Factor for IPH Facilities (5) 59 % 54 % 45 % 55 %
Average Quoted Market Power Prices ($/MWh) (3):
On-Peak: Indiana (Indy Hub) $ 40.19 $ 33.09 $ 32.32 $ 35.17
Off-Peak: Indiana (Indy Hub) $ 24.38 $ 23.37 $ 22.31 $ 25.41
 
Gas
Million Megawatt Hours Generated (8) 15.2 15.5 40.4 33.2
IMA for Combined Cycle Facilities (4) (8) 97 % 99 % 97 % 98 %
Average Capacity Factor for Combined Cycle Facilities (5) (8) 67 % 72 % 61 % 63 %
Average Market On-Peak Spark Spreads ($/MWh) (6):
Commonwealth Edison (NI Hub) $ 18.93 $ 14.49 $ 15.41 $ 14.91
PJM West $ 31.48 $ 29.82 $ 23.79 $ 25.58
North of Path 15 (NP 15) $ 15.44 $ 16.25 $ 12.32 $ 14.63
New York—Zone A $ 39.27 $ 26.32 $ 26.66 $ 29.49
Mass Hub $ 21.58 $ 18.90 $ 14.49 $ 15.77
AD Hub $ 27.27 $ 23.17 $ 28.88 $ 34.41
Average Market Off-Peak Spark Spreads ($/MWh) (6):
Commonwealth Edison (NI Hub) $ 3.09 $ 3.39 $ 4.68 $ 2.97
PJM West $ 15.10 $ 15.50 $ 13.10 $ 10.71
North of Path 15 (NP 15) $ 7.31 $ 8.22 $ 6.03 $ 7.75
New York—Zone A $ 13.24 $ 10.49 $ 8.32 $ 14.12
Mass Hub $ 3.85 $ 4.39 $ 3.46 $ 1.05
AD Hub $ 14.78 $ 15.62 $ 13.36 $ 16.22
Average natural gas price—Henry Hub ($/MMBtu) (7) $ 2.84 $ 2.74 $ 2.31 $ 2.78

__________________________________________
 
(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. This calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility and CTs. The IMA for our facilities within MISO and PJM (excluding CTs) was 90 percent and 83 percent, respectively, for the three months ended September 30, 2016 and 91 percent and 77 percent, respectively, for the three months ended September 30, 2015. The IMA for our facilities within MISO and PJM (excluding CTs) was 89 percent and 81 percent, respectively, for the nine months ended September 30, 2016 and 87 percent and 73 percent, respectively, for the nine months ended September 30, 2015.
(2) Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility and CTs. The average capacity factors for our facilities within MISO and PJM (excluding CTs) were 76 percent and 65 percent, respectively, for the three months ended September 30, 2016 and 68 percent and 57 percent, respectively, for the three months ended September 30, 2015. The average capacity factors for our facilities within MISO and PJM (excluding CTs) were 61 percent and 51 percent, respectively, for the nine months ended September 30, 2016 and 66 percent and 51 percent, respectively, for the nine months ended September 30, 2015.
(3) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
(4) 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. This calculation excludes certain events outside of management control such as weather related issues.
(5) Reflects actual production as a percentage of available capacity.
(6) Reflects the simple average of the on- and off-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.
(7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
(8) Reflects the activity for the period in which the Acquisitions were included in our consolidated results.
 

DYNEGY INC.

2016 ADJUSTED EBITDA AND FREE CASH FLOW GUIDANCE

(UNAUDITED) (IN MILLIONS)
 
The following table provides summary financial data regarding our 2016 Adjusted EBITDA guidance, updated based on October 12, 2016 forward curves, as presented on November 1, 2016:
 
 
        Dynegy Consolidated
Low       High
Net loss attributable to Dynegy Inc. (1) $ (1,258 ) $ (1,188 )
Plus / (Less):
Loss attributable to noncontrolling interest (2) (2 ) (2 )
Income tax expense (2) 6 6
Interest expense 625 630
Depreciation and amortization expense 685   705  
EBITDA (3) 56 151
Plus / (Less):
Acquisition, integration and restructuring costs 45 50
Impairments (2) 857 857
Other (4) 42   42  
Adjusted EBITDA (3) $ 1,000   $ 1,100  

__________________________________________
 
(1)   For purposes of our 2016 guidance, fair value adjustments related to derivatives and our common stock warrants are assumed to be zero.
 
(2) Represents actual amounts for the nine months ended September 30, 2016.
 
(3) EBITDA and Adjusted EBITDA are non-GAAP measures. Please refer to item 2.02 of our Form 8-K filed on November 1, 2016, for definitions, utility and uses of such non-GAAP financial measures.
 
(4) Represents actual amounts for nine months ended September 30, 2016. Other consists primarily of adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest, non-cash compensation expense, and Wood River's energy margin and operating and maintenance costs.
 
The following table provides summary financial data regarding our 2016 Free Cash Flow guidance:
 
           
Dynegy Consolidated
Low       High
Adjusted EBITDA (1) $ 1,000 $ 1,100
Cash interest payments (2) (515 ) (515 )
Acquisition, integration and restructuring costs (45 ) (50 )
Other cash items 10   10  
Cash Flow from Operations 450 545
Maintenance capital expenditures (275 ) (275 )
Environmental capital expenditures (20 ) (20 )
Acquisition, integration and restructuring costs 45   50  
Free Cash Flow (1) $ 200   $ 300  

__________________________________________
 
(1)   Adjusted EBITDA and Free Cash Flow are non-GAAP measures. Please refer to item 2.02 of our Form 8-K filed on November 1, 2016, for definitions, utility and uses of such non-GAAP financial measures.
 
(2) Excludes payments to an escrow account of (i) $50 million of pre-funded interest and (ii) $20 million of prefunded, original issue discount which are contingent upon the closing of the ENGIE acquisition.
 
 

DYNEGY INC.

2017 ADJUSTED EBITDA AND FREE CASH FLOW GUIDANCE

(UNAUDITED) (IN MILLIONS)
 
The 2017 guidance was prepared using reasonable efforts and based on currently available information assuming the following: (a) the Delta transaction will close on December 31, 2016, (b) all of the purchase price is allocated to property, plant and equipment, (c) property, plant and equipment is depreciated over an average useful life of 20 years, and (d) Genco restructuring will be completed in the first quarter of 2017.
 
The following table provides summary financial data regarding our 2017 Adjusted EBITDA guidance, updated based on October 12, 2016 forward curves, as presented on November 1, 2016:
 
 
        Dynegy Consolidated
Low       High
Net loss attributable to Dynegy Inc. (1) $ (290 ) $ (120 )
Plus / (Less):
Interest expense 680 685
Depreciation and amortization expense 795   815  
EBITDA (2) 1,185 1,380
Plus / (Less):
Acquisition, integration and restructuring costs 15   20  
Adjusted EBITDA (2) $ 1,200   $ 1,400  

__________________________________________
 
(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 and Adjusted EBITDA are non-GAAP measures. Please refer to item 2.02 of our Form 8-K filed on November 1, 2016, for definitions, utility and uses of such non-GAAP financial measures.
 

The following table provides summary financial data regarding our 2017 Free Cash Flow guidance:
 
           
Dynegy Consolidated
Low       High
Adjusted EBITDA (1) $ 1,200 $ 1,400
Cash interest payments (625 ) (625 )
Acquisition, integration and restructuring costs (15 ) (20 )
Other cash items (35 ) (35 )
Cash Flow from Operations 525 720
Maintenance capital expenditures (370 ) (370 )
Environmental capital expenditures (20 ) (20 )
Acquisition, integration and restructuring costs 15   20  
Free Cash Flow (1) $ 150   $ 350  

__________________________________________
 
(1)   Adjusted EBITDA and Free Cash Flow are non-GAAP measures. Please refer to item 2.02 of our Form 8-K filed on November 1, 2016, for definitions, utility and uses of such non-GAAP financial measures.
 

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