Dynegy Inc. (NYSE: DYN) reported 2015 third quarter consolidated Adjusted EBITDA of $350 million, compared to $90 million for the 2014 third quarter. The $260 million increase was primarily due to the Company's recent acquisitions, higher spark spreads in the Gas segment, higher wholesale capacity revenues at the IPH and Coal segments, and improved results for the retail business. These improvements in Adjusted EBITDA were partially offset by the expiration of a capacity contract at the Independence plant in the Gas segment. Operating income was $107 million for the 2015 third quarter compared to $22 million for the same period in 2014. The net loss attributable to Dynegy Inc. for the 2015 third quarter was $24 million, compared to a net loss attributable to Dynegy Inc. of $5 million for the 2014 third quarter.

For the first nine months of 2015, Dynegy Inc. reported consolidated Adjusted EBITDA of $628 million, compared to $280 million for the first nine months of 2014. The $348 million increase in Adjusted EBITDA resulted from the Company's recent acquisitions, higher spark spreads and tolling and market capacity revenues in the Gas segment, and stronger capacity and retail results in the Coal and IPH segments. Partially offsetting these improvements were lower realized power prices on the unhedged power sales in the Coal segment and the expiration of the capacity contract at Independence. The operating income for the first nine months of 2015 was $77 million compared to an operating loss of $31 million in the first nine months of 2014. The net income attributable to Dynegy Inc. for the first nine months of 2015 was $184 million, compared to a net loss attributable to Dynegy Inc. of $169 million for the first nine months of 2014.

"Dynegy remains on track to meet the 2015 guidance range for Adjusted EBITDA and Free Cash Flow in spite of the mild third quarter summer temperatures, which adversely impacted the demand for power and power prices across our operating regions," said Dynegy President and Chief Executive Officer Robert C. Flexon. "Our recent acquisitions significantly contributed to our financial performance during the quarter, and that, along with recent PRIDE contributions to our balance sheet and liquidity management, has allowed us to accelerate our stock repurchase program with approximately 75% of our $250 million program already completed."

Third Quarter Comparative Results

        Quarter Ended September 30, 2015
(in millions)
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) 107
Plus / (Less):
Depreciation expense 39 8 126 1 174
Amortization expense (13 ) (5 ) 13

-
(5 )
Losses from unconsolidated investments

-

-
(4 )

-
(4 )
Other items, net

-
 

-
 

-
  46   46  
EBITDA (1) (10 ) 34 287 7 318
Plus / (Less):
Acquisition and integration costs

-

-

-
8 8
Mark-to-market adjustments (14 ) (3 ) (6 )

-
(23 )
Change in fair value of common stock warrants

-

-

-
(45 ) (45 )
Impairments and other charges 74

-

-

-
74
Cash distributions from unconsolidated investments

-

-
8

-
8
Other 4   3   2   1   10  
Adjusted EBITDA (1) $ 54   $ 34   $ 291   $ (29 ) $ 350  
 
Quarter Ended September 30, 2014
(in millions)
Coal IPH Gas Other Total
Operating income (loss) $ (2 ) $ 19 $ 40 $ (35 ) $ 22
Plus / (Less):
Depreciation expense 14 10 36 1 61
Amortization expense (1 ) (13 ) 21

-
7
Other items, net

-
  1  

-
  4   5  
EBITDA (1) 11 17 97 (30 ) 95
Plus / (Less):
Acquisition and integration costs

-

-

-
9 9
Mark-to-market adjustments (12 ) (4 ) 5

-
(11 )
Change in fair value of common stock warrants

-

-

-
(6 ) (6 )
Gain on sale of assets, net

-

-
(3 )

-
(3 )
Other 2   2   (1 ) 3   6  
Adjusted EBITDA (1) $ 1   $ 15   $ 98   $ (24 ) $ 90  

_________________________________________
(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 4, 2015, for definitions, purposes and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. 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.

Segment Review of Results Quarter-over-Quarter

Coal - The 2015 third quarter operating loss was $36 million, compared to an operating loss of $2 million for the same period in 2014. Adjusted EBITDA totaled $54 million during the 2015 third quarter compared to $1 million during the same period in 2014. The quarter-over-quarter increase in Adjusted EBITDA primarily resulted from the positive impact of the Company's recent acquisitions, higher realized power prices, and improved wholesale capacity revenues.

IPH - The 2015 third quarter operating income was $31 million, compared to an operating income of $19 million for the same period in 2014. Adjusted EBITDA totaled $34 million during the 2015 third quarter compared to $15 million during the same period in 2014. The quarter-over-quarter increase in Adjusted EBITDA resulted from higher wholesale capacity revenues and retail gross margin.

Gas - The 2015 third quarter operating income was $152 million, compared to an operating income of $40 million for the same period in 2014. Adjusted EBITDA totaled $291 million during the 2015 third quarter compared to $98 million during the same period in 2014. The quarter-over-quarter increase in Adjusted EBITDA is primarily due to the Company's recent acquisitions, higher hedged energy margin, and tolling and market capacity revenues, partially offset by the expiration of the capacity contract at Independence.

Liquidity

As of September 30, 2015, Dynegy's total available liquidity was $1.9 billion as reflected in the table below.
       
September 30, 2015
(amounts in millions) Dynegy Inc.  

IPH (1)(2)
  Total
Revolving Facilities and LC capacity (3) $ 1,480 $ 25 $ 1,505
Less: Outstanding letters of credit (485 ) (20 ) (505 )
Revolving Facility and LC availability 995 5 1,000
Cash and cash equivalents 789   145   934  
Total available liquidity (4) $ 1,784   $ 150   $ 1,934  

__________________________________________
(1)       Includes cash of $128 million related to Genco.
(2) Due to the ring-fenced nature of IPH, cash at the IPH and Genco entities may not be moved out of these entities without meeting certain criteria. However, cash at these entities is available to support current operations of these entities.
(3) Includes: (i) $950 million of aggregate available capacity related to our incremental revolving credit facilities, $475 million of available capacity related to the five-year senior secured revolving credit facility and $55 million related to a letter of credit facility at Dynegy Inc. and (ii) $25 million related to the two-year secured letter of credit facility at IPH.
(4) On December 2, 2013, Dynegy and Illinois Power Resources, LLC entered into an intercompany revolving promissory note of $25 million. At September 30, 2015, there was approximately $16 million outstanding on the note, which is not reflected in the table above.

Consolidated Cash Flow

Cash provided by operations for the first nine months of 2015 was $302 million. During the period, our power generation business provided cash of $655 million. Corporate and other activities used cash of $357 million primarily due to interest payments on our various debt agreements of $263 million and payments for acquisition-related costs of $111 million. Partially offsetting these costs was a $17 million cash inflow related to a receipt of escrow funds from Ponderosa Pine Energy, LLC. In addition, changes in working capital provided cash of approximately $4 million.

Cash used in investing activities during the first nine months of 2015 was $1.099 billion. The Company paid $6.078 billion in cash, net of cash acquired, in connection with the Company's recent acquisitions. In addition, there was a $5.148 billion cash inflow related to the release of restricted cash from existing escrow accounts for closing the acquisitions. The Company had $142 million in maintenance capital expenditures, $20 million in environmental capital expenditures, and $9 million in capitalized interest.

Cash used in financing activities during the first nine months of 2015 was $139 million.

PRIDE (Producing Results through Innovation by Dynegy Employees)

In 2013, Dynegy launched the PRIDE Reloaded program with a three-year target (2014-2016) of $135 million in operating improvements and $165 million in balance sheet efficiencies. Dynegy is projected to achieve its three-year targets by the end of 2015 - a full year ahead of schedule. Dynegy has identified, secured, or realized $132 million of the $135 million EBITDA target, and has achieved $230 million in balance sheet efficiencies, which is 39% above the balance sheet efficiency goal.

Through the end of this year, Dynegy's PRIDE program will have produced more than $280 million in EBITDA improvements and approximately $950 million in balance sheet benefits with minimal investments since its inception in 2011.

On September 29, 2015, Dynegy announced "PRIDE Energized" - the next iteration of the Company's PRIDE program - targeted to deliver an incremental $250 million in EBITDA and $400 million in balance sheet improvements for Dynegy over the next three years (2016-2018). The benefits of "PRIDE Energized" come in addition to Dynegy's previously announced $130 million in acquisition synergies. The overall goal of the PRIDE program continues to be improving operating performance, cost structure and balance sheet efficiency to drive incremental cash flow benefits.

2015 and 2016 Guidance

Dynegy's full-year 2015 Adjusted EBITDA and Free Cash Flow guidance ranges are narrowed at $825 million to $925 million and $140 million to $240 million, respectively.

Full-year 2016 Adjusted EBITDA guidance range is set at $1,100 million to $1,300 million and Free Cash Flow guidance of $300 million to $500 million.

Beginning in 2016, the company's Free Cash Flow guidance will exclude the upfront initial capital cost for newly required environmental compliance capital expenditures and will instead include only the recurring spend necessary to operate that equipment over time. As such, $50 million in capital spend, including $30 million for the Newton Power Station scrubber, has been excluded from Dynegy's 2016 Free Cash Flow guidance range, and will instead be reported as part of its capital allocation program similar to the company's other capital investments.

Share Repurchase Program

On August 3, 2015, the company announced that its Board of Directors had authorized a new $250 million share buyback program to be completed during 2016. As of September 30, 2015, the Company had repurchased 4,996,299 shares at an aggregate cost of $127 million. From October 1 - October 13, 2015, Dynegy repurchased an additional 2,629,056 shares at an aggregate cost of $60 million.

Wood River Power Station Retirement

Dynegy Inc. announced today plans to retire its 465 megawatt Wood River Power Station in Alton, Illinois in mid-2016. The Wood River Power Station includes two coal-fueled units that entered commercial operation in 1954 and 1964, respectively.

The decision to retire the Wood River facility is attributable to its uneconomic operation stemming from the poorly designed wholesale capacity market that mixes out-of-state regulated generators, that receive rate based compensation from their home states to recover costs, with Central and Southern Illinois competitive generators that rely on the capacity market for fair compensation to recover costs.

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 2015 third quarter financial results during an investor conference call and webcast tomorrow, November 5, 2015 at 9 a.m. ET/8 a.m. CT. Participants may access the webcast from the Company's website.

About Dynegy

We are committed to leadership in the electricity sector. With nearly 26,000 megawatts of power generation capacity and two retail electricity companies, Dynegy is capable of supplying 21 million homes with safe, reliable and economic energy. Homefield Energy and Dynegy Energy Services are retail electricity providers serving businesses and residents in Illinois, Ohio, and Pennsylvania.

Forward Looking Statements

This press release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as "forward-looking statements," particularly those statements concerning expectations regarding the share repurchase program; anticipated acquisition synergies and execution of its PRIDE Energized targets over the next three years; anticipated earnings and cash flows and Dynegy's full-year 2015 and 2016 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 its 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 2014 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 Dynegy is, or could become, subject to, which could increase its costs, result in an impairment of its assets, cause it 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 its 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 new 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 its 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) the timing and anticipated benefits to be achieved through Dynegy's company-wide improvement programs, including its PRIDE initiative; (xix) expectations regarding the synergies and anticipated benefits of the Acquisitions; (xx) beliefs concerning Dynegy's capital allocation program, including the amount of shares, manner, timing and funding of the share repurchase program; (xxi) anticipated timing, outcomes and impacts of the expected retirements of Brayton Point, Edwards Unit 1 and Wood River; (xxii) beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the Vermilion facility and any potential future remediation obligations at the South Bay facility; and (xxiii) beliefs regarding redevelopment efforts for the Morro Bay facility.
 

DYNEGY INC.

REPORTED UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(IN MILLIONS, EXCEPT PER SHARE DATA)

 
 

Three Months Ended September 30,

Nine Months Ended September 30,
2015   2014 2015 2014
Revenues $ 1,232 $ 615 $ 2,854 $ 1,898
Cost of sales, excluding depreciation expense (621 ) (387 ) (1,494 ) (1,304 )
Gross margin 611 228 1,360 594
Operating and maintenance expense (219 ) (114 ) (580 ) (360 )
Depreciation expense (174 ) (61 ) (413 ) (185 )
Impairments and other charges (74 )

-
(74 )

-
Gain (loss) on sale of assets, net

-
3 (1 ) 17
General and administrative expense (29 ) (25 ) (94 ) (80 )
Acquisition and integration costs (8 ) (9 ) (121 ) (17 )
Operating income (loss) 107 22 77 (31 )
Earnings (losses) from unconsolidated investments (4 )

-
(1 ) 10
Interest expense (145 ) (32 ) (413 ) (104 )
Other income and expense, net 46   5   45   (40 )
Income (loss) before income taxes 4 (5 ) (292 ) (165 )
Income tax benefit (expense) (28 )

-
  473   1  
Net income (loss) (24 ) (5 ) 181 (164 )
Less: Net income (loss) attributable to noncontrolling interest

-
 

-
  (3 ) 5  
Net income (loss) attributable to Dynegy Inc. (24 ) (5 ) 184 (169 )
Less: Dividends on preferred stock 5  

-
  16  

-
 

Net income (loss) attributable to Dynegy Inc. common stockholders
$ (29 ) $ (5 ) $ 168   $ (169 )
 
Earnings (Loss) Per Share:

Basic earnings (loss) per share attributable to Dynegy Inc. commonstockholders
$ (0.23 ) $ (0.05 ) $ 1.33 $ (1.69 )

Diluted earnings (loss) per share attributable to Dynegy Inc. commonstockholders
$ (0.23 ) $ (0.05 ) $ 1.31 $ (1.69 )
 
Basic shares outstanding 126 100 126 100
Diluted shares outstanding 126 100 140 100

 

__________________________________________

 

(1) The basic and diluted loss per share from continuing operations attributable to Dynegy Inc. is presented below:
 
Income (loss) from continuing operations   $ (24 )   $ (5 )   $ 181   $ (164 )
Less: Net income (loss) attributable to noncontrolling interest

-
 

-
  (3 ) 5  
Income (loss) from continuing operations attributable to Dynegy Inc. (24 ) (5 ) 184 (169 )
Less: Dividends on preferred stock 5  

-
  16  

-
 
Income (loss) from continuing operations attributable to Dynegy Inc.
common stockholders for basic earnings (loss) per share (29 ) (5 ) 168 (169 )
Add: Dividends on preferred stock 5  

-
  16  

-
 
Adjusted income (loss) from continuing operations attributable to Dynegy
Inc. common stockholders for diluted earnings (loss) per share $ (24 ) $ (5 ) $ 184   $ (169 )
 
Basic weighted-average shares 126 100 126 100
Effect of dilutive securities (2)

-
 

-
  14  

-
 
Diluted weighted-average shares 126   100   140   100  
 
Earnings (loss) per share from continuing operations attributable to Dynegy
Inc. common stockholders:
Basic $ (0.23 ) $ (0.05 ) $ 1.33 $ (1.69 )
Diluted (2) $ (0.23 ) $ (0.05 ) $ 1.31 $ (1.69 )

_________________________________________
(2)       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, 2015 and the three and nine months ended September 30, 2014.
 

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 threemonths 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 expense 174
Amortization expense (5 )
EBITDA (1) $ (10 ) $ 34 $ 287 $ 7 $ 318
Acquisition and integration costs

-

-

-
8 8
Mark-to-market adjustments (14 ) (3 ) (6 )

-
(23 )
Change in fair value of common stock warrants

-

-

-
(45 ) (45 )
Impairments and other charges 74

-

-

-
74
Cash distributions from unconsolidated investments

-

-
8

-
8
Other 4   3   2   1   10  
Adjusted EBITDA (1) $ 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 4, 2015, 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, 2015
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) $ 107
Depreciation expense 39 8 126 1 174
Amortization expense (13 ) (5 ) 13

-
(5 )
Losses from unconsolidated investments

-

-
(4 )

-
(4 )
Other items, net

-
 

-
 

-
  46   46  
EBITDA $ (10 ) $ 34   $ 287   $ 7   $ 318  
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED SEPTEMBER 30, 2014

(UNAUDITED) (IN MILLIONS)
 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the threemonths ended September 30, 2014:
       
Three Months Ended September 30, 2014
Coal   IPH   Gas   Other   Total
Net loss attributable to Dynegy Inc. $ (5 )
Plus / (Less):
Interest expense 32
Depreciation expense 61
Amortization expense 7  
EBITDA (1) $ 11 $ 17 $ 97 $ (30 ) $ 95
Plus / (Less):
Acquisition and integration costs

-

-

-
9 9
Mark-to-market adjustments (12 ) (4 ) 5

-
(11 )
Change in fair value of common stock warrants

-

-

-
(6 ) (6 )
Gain on sale of assets, net

-

-
(3 )

-
(3 )
Other 2   2   (1 ) 3   6  
Adjusted EBITDA (1) $ 1   $ 15   $ 98   $ (24 ) $ 90  

__________________________________________
(1)       EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 4, 2015, 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, 2014
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (2 ) $ 19 $ 40 $ (35 ) $ 22
Depreciation expense 14 10 36 1 61
Amortization expense (1 ) (13 ) 21

-
7
Other items, net

-
  1  

-
  4   5
EBITDA $ 11   $ 17   $ 97   $ (30 ) $ 95
 

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 monthsended 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 expense 413
Amortization expense (14 )
EBITDA (1) $ 38 $ 57 $ 595 $ (170 ) $ 520
Acquisition and integration costs

-

-

-
121 121
Loss attributable to noncontrolling interest

-
3

-

-
3
Mark-to-market adjustments (35 ) (8 ) (29 )

-
(72 )
Change in fair value of common stock warrants

-

-

-
(43 ) (43 )
Impairments and other charges 74

-

-

-
74
Loss on sale of assets, net

-

-
1

-
1
Cash distributions from unconsolidated investments

-

-
8

-
8
Other 6   9  

-
  1   16  
Adjusted EBITDA (1) $ 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 4, 2015, 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, 2015
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (34 ) $ 39 $ 290 $ (218 ) $ 77
Depreciation expense 96 24 290 3 413
Amortization expense (24 ) (6 ) 16

-
(14 )
Loss from unconsolidated investments

-

-
(1 )

-
(1 )
Other items, net

-
 

-
 

-
  45   45  
EBITDA $ 38   $ 57   $ 595   $ (170 ) $ 520  
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

NINE MONTHS ENDED SEPTEMBER 30, 2014

(UNAUDITED) (IN MILLIONS)
 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the nine monthsended September 30, 2014:
       
Nine Months Ended September 30, 2014
Coal   IPH   Gas   Other   Total
Net loss attributable to Dynegy Inc. $ (169 )
Plus / (Less):
Income attributable to noncontrolling interest 5
Income tax benefit (1 )
Interest expense 104
Depreciation expense 185
Amortization expense 42  
EBITDA (1) $ 37 $ 4 $ 254 $ (129 ) $ 166
Plus / (Less):
Acquisition and integration costs

-
8

-
9 17
Income attributable to noncontrolling interest

-
(5 )

-

-
(5 )
Mark-to-market adjustments 7 34 23

-
64
Change in fair value of common stock warrants

-

-

-
43 43
Gain on sale of assets, net

-

-
(17 )

-
(17 )
Other 7   4  

-
  1   12  
Adjusted EBITDA (1) $ 51   $ 45   $ 260   $ (76 ) $ 280  

__________________________________________
(1)       EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on November 4, 2015, 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, 2014
Coal   IPH   Gas   Other   Total
Operating income (loss) $ 2 $ (14 ) $ 72 $ (91 ) $ (31 )
Depreciation expense 39 28 115 3 185
Amortization expense (4 ) (11 ) 57

-
42
Earnings from unconsolidated investments

-

-
10

-
10
Other items, net

-
  1  

-
  (41 ) (40 )
EBITDA $ 37   $ 4   $ 254   $ (129 ) $ 166  
         

DYNEGY INC.

OPERATING DATA
 

The following table provides summary financial data regarding our Coal, IPH and Gas segment results of operationsfor the three and nine months ended September 30, 2015 and 2014, respectively.
 

Three Months Ended September 30,

Nine Months Ended September 30,
2015     2014 2015     2014
Coal
Million Megawatt Hours Generated (9) 9.4 4.5 21.7 14.4
IMA for Coal-Fired Facilities (1) (9) 82 % 81 % 80 % 88 %
Average Capacity Factor for Coal-Fired Facilities (2) (9) 62 % 69 % 59 % 74 %
Average Quoted Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 33.09 $ 37.90 $ 35.17 $ 51.53
Commonwealth Edison (NI Hub) $ 34.03 $ 37.58 $ 35.44 $ 54.95
Mass Hub $ 35.52 $ 42.01 $ 53.62 $ 86.50
AD Hub $ 35.87 $ 39.02 $ 39.86 $ 59.29
Average Quoted Market Off-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 23.37 $ 27.57 $ 25.41 $ 33.68
Commonwealth Edison (NI Hub) $ 22.93 $ 25.40 $ 23.49 $ 32.23
Mass Hub $ 21.02 $ 27.01 $ 38.90 $ 61.25
AD Hub $ 24.21 $ 27.91 $ 27.20 $ 36.38
 
IPH
Million Megawatt Hours Generated 4.8 6.4 14.7 17.8
IMA for IPH Facilities (4) 84 % 93 % 89 % 89 %
Average Capacity Factor for IPH Facilities (5) 54 % 74 % 55 % 69 %
Average Quoted Market Power Prices ($/MWh) (3):
On-Peak: Indiana (Indy Hub) $ 33.09 $ 37.90 $ 35.17 $ 51.53
Off-Peak: Indiana (Indy Hub) $ 23.37 $ 27.57 $ 25.41 $ 33.68
 
Gas
Million Megawatt Hours Generated (6) (9) 15.4 4.8 33.2 13.0
IMA for Combined Cycle Facilities (4) (9) 99 % 99 % 98 % 99 %
Average Capacity Factor for Combined Cycle Facilities (5) (9) 72 % 51 % 63 % 46 %
Average Market On-Peak Spark Spreads ($/MWh) (7):
Commonwealth Edison (NI Hub) $ 14.49 $ 9.65 $ 14.91 $ 12.05
PJM West $ 29.82 $ 26.30 $ 25.58 $ 27.99
North of Path 15 (NP 15) $ 16.25 $ 19.40 $ 14.63 $ 17.23

New York--Zone A
$ 26.32 $ 24.58 $ 29.49 $ 39.18
Mass Hub $ 18.90 $ 21.22 $ 15.77 $ 22.30
AD Hub $ 27.28 $ 23.17 $ 28.88 $ 34.41
Average Market Off-Peak Spark Spreads ($/MWh) (7):
Commonwealth Edison (NI Hub) $ 3.39 $ (2.53 ) $ 2.97 $ (10.67 )
PJM West $ 15.50 $ 12.48 $ 10.71 $ 2.68
North of Path 15 (NP 15) $ 8.22 $ 8.55 $ 7.75 $ 7.07

New York--Zone A
$ 10.49 $ 9.26 $ 14.12 $ 15.86
Mass Hub $ 4.39 $ 6.22 $ 1.05 $ (2.95 )
AD Hub $ 15.62 $ 12.07 $ 16.22 $ 11.50

Average natural gas price--Henry Hub ($/MMBtu) (8)
$ 2.74 $ 3.94 $ 2.78 $ 4.52
   
(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 calculations for the three and nine months ended September 30, 2015 exclude our Brayton Point facility and CTs. For the three months ended September 30, 2015, the IMA for our facilities within MISO and PJM (excluding CTs) were 91 percent and 77 percent, respectively. For the nine months ended September 30, 2015, the IMA for our facilities within MISO and PJM (excluding CTs) were 87 percent and 73 percent, respectively.
(2) Reflects actual production as a percentage of available capacity. The calculations for the three and nine months ended September 30, 2015 exclude our Brayton Point facility and CTs. For the three months ended September 30, 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 68 percent and 57 percent, respectively. For the nine months ended September 30, 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 66 percent and 51 percent, respectively.
(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) The three and nine months ended September 30, 2014 includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility which was sold on June 27, 2014.
(7) 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.
(8) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.
(9) Reflects the activity for the period in which the Acquisitions were included in our consolidated results.
   

DYNEGY INC.

REVISED 2015 ADJUSTED EBITDA AND FREE CASH FLOW GUIDANCE

(UNAUDITED) (IN MILLIONS)
 

The following table provides summary financial data regarding our revised 2015 Adjusted EBITDA guidance, updated based onOctober 19, 2015 forward curves, as presented on November 4, 2015:
     
Dynegy Consolidated
Low High
Net income attributable to Dynegy Inc. (3) $ 41 $ 111
Plus / (Less):
Income tax benefit (2) (473 ) (473 )
Other items, net (4) (4 ) (4 )
Interest expense   537     537  
Operating Income 101 171
Depreciation expense 580 600
Amortization expense (5 ) (5 )
Other items, net   1     1  
EBITDA (1) 677 767
Plus / (Less):
Transaction fees and expenses 85 90
Integration costs 35 40
Other (5)   28     28  
Adjusted EBITDA (1) $ 825   $ 925  
     
(1) EBITDA, Adjusted EBITDA and Free Cash Flow are non-GAAP measures.
(2) Represents actual amounts for the nine months ended September 30, 2015.
(3) For purposes of Net income attributable to Dynegy Inc. guidance reconciliation, mark-to-market adjustments and changes in the fair value of common stock warrants are assumed to be zero.
(4) Represents actual amounts for the nine months ended September 30, 2015. Other items, net primarily consists of the loss attributable to noncontrolling interest and losses from unconsolidated investments.
(5) Represents actual amounts for the nine months ended September 30, 2015. Other consists primarily of adjustments for losses attributable to noncontrolling interest, cash distributions from unconsolidated investments and asset retirement obligation accretion.
 

The following table provides summary financial data regarding our revised 2015 Free Cash Flow guidance:
     
Dynegy Consolidated
Low     High
Adjusted EBITDA (1) $ 825 $ 925
Cash interest payments (517 ) (517 )
Transaction fees and expenses (2) (110 ) (115 )
Integration costs (35 ) (40 )
Other non-cash and working capital items   (5 )   (5 )
Cash Flow from Operations 158 248
Maintenance capital expenditures (225 ) (225 )
Environmental capital expenditures (30 ) (30 )
Transaction fees and expenses (2) 110 115
Integration costs 35 40
Acquisition interest (3)   92     92  
Free Cash Flow $ 140   $ 240  
     
(1) EBITDA, Adjusted EBITDA and Free Cash Flow are non-GAAP measures.
(2) Consists of nonrecurring transaction costs including a commitment fee on the Bridge Loan Facilities, legal and advisory fees related to the acquisitions, a fee for executing the $950M million Revolver and syndication fees associated with the issuance of the $5.1 billion Notes and Common Stock and Mandatory Convertible Preferred Stock Offerings.
(3) Reflects $92 million of interest on $5.1 billion Notes for the period prior to the close of the acquisitions (January-March).
       

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, based on October 19, 2015forward curves, as presented on November 4, 2015:
       
Dynegy Consolidated
Low High
Net income (loss) attributable to Dynegy Inc. (3) $ (152 ) $ 23
Plus / (Less):
Interest expense   542     542  
Operating Income 390 565
Depreciation expense 680 700
Amortization expense   30     30  
EBITDA (1) 1,100 1,295
Plus / (Less):
Integration costs  

-
    5  
Adjusted EBITDA (1) $ 1,100   $ 1,300  
 

(1) EBITDA, Adjusted EBITDA and Free Cash Flow are non-GAAP measures.
 
 

The following table provides summary financial data regarding our 2016 Free Cash Flow guidance:
 
Dynegy Consolidated
Low High
Adjusted EBITDA (1) $ 1,100 $ 1,300
Cash interest payments (515 ) (515 )
Integration costs

-
(5 )
Other non-cash and working capital items  

35
   

35
 
Cash Flow from Operations

620

815
Maintenance capital expenditures (300 ) (300 )
Environmental capital expenditures

(20
)

(20
)
Integration costs  

-
    5  
Free Cash Flow $ 300   $ 500  
 

(1) EBITDA, Adjusted EBITDA and Free Cash Flow are non-GAAP measures.

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