Dynegy Inc. (NYSE: DYN) reported 2015 second quarter consolidated Adjusted EBITDA of $193 million, compared to $38 million for the 2014 second quarter. The $155 million increase was primarily due to the Company’s recent acquisition of Duke Energy’s Midwest Generation assets and the acquisition of EquiPower Resources Corp. and Brayton Point Holdings, LLC as well as higher spark spreads and higher market capacity payments in the Gas segment. The Adjusted EBITDA was partially offset by lower power prices and generation volumes at the Coal segment as well as the expiration of a capacity contract at Independence at the Gas segment. Operating income was $10 million for the 2015 second quarter compared to an operating loss of $54 million for the same period in 2014. The net income attributable to Dynegy Inc. for the 2015 second quarter was $388 million, compared to a net loss attributable to Dynegy Inc. of $123 million for the 2014 second quarter.

For the first half of 2015, Dynegy Inc. reported consolidated Adjusted EBITDA of $278 million, compared to $190 million for the first half of 2014. The $88 million increase in Adjusted EBITDA resulted from the Company’s recent acquisitions and higher spark spreads at the Gas segment, partially offset by lower power prices at the Coal segment and the expiration of a capacity contract at Independence. The operating loss for the first half of 2015 was $30 million compared to an operating loss of $53 million in the first half of 2014. The net income attributable to Dynegy Inc. for the first half of 2015 was $208 million, compared to a net loss of $164 million for the first half of 2014.

“Mild summer temperatures and above average rainfall during the second quarter impacted both the demand for power and prices across our core operating regions. However, our recent acquisitions did immediately contribute to our second quarter financial performance as the newly expanded combined cycle fleet benefited from their advantageous access to the region’s natural gas supplies,” said Dynegy President and Chief Executive Officer Robert C. Flexon.

“With the combination of our expanded fleet in the PJM and ISO New England regions and the continuing tightening of generation supply in our core markets due to retirements, the cash flow outlook for the Company remains strong. As a result of these factors along with the sector-wide decline in equity values, the Company has accelerated its capital allocation plans with the authorization of a share repurchase program for up to $250 million in the open market,” added Flexon.

Second Quarter Comparative Results

 
      Quarter Ended June 30, 2015
(in millions)
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (5 ) $ (14 ) $ 86 $ (57 ) 10
Plus / (Less):
Depreciation expense 47 8 119 1 175
Amortization expense (10 )

-

5

-

(5 )
Earnings from unconsolidated investments

-

-

3

-

3
Other items, net

-

 

-

 

-

  4   4  

EBITDA (1)

 32 (6 ) 213 (52 ) 187
Plus / (Less):
Acquisition and integration costs

-

-

-

23 23
Loss attributable to noncontrolling interest

-

2

-

-

2
Mark-to-market adjustments (14 ) 6 (10 )

-

(18 )
Change in fair value of common stock warrants

-

-

-

(3 ) (3 )
Loss on sale of assets, net

-

-

1

-

1
Other 1   3   (2 ) (1 ) 1  

Adjusted EBITDA (1)

 $ 19   $ 5   $ 202   $ (33 ) $ 193  
     
Quarter Ended June 30, 2014
(in millions)
Coal   IPH   Gas   Other   Total
Operating loss $ (5 ) $ (17 ) $ (2 ) $ (30 ) $ (54 )
Plus / (Less):
Depreciation expense 11 10 35 1 57
Amortization expense (2 ) 3 18

-

19
Earnings from unconsolidated investments

-

-

10

-

10
Other items, net

-

 

-

 

-

  (39 ) (39 )

EBITDA (1)

 4 (4 ) 61 (68 ) (7 )
Plus / (Less):
Acquisition and integration costs

-

2

-

-

2
Income attributable to noncontrolling interest

-

(1 )

-

-

(1 )
Mark-to-market adjustments

-

4 10

-

14
Change in fair value of common stock warrants

-

-

-

43 43
Gain on sale of assets, net

-

-

(14 )

-

(14 )
Other 4   (1 ) 1   (3 ) 1  

Adjusted EBITDA (1)

 $ 8   $

-

  $ 58   $ (28 ) $ 38  

__________________________________________

       

(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 August 6, 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 second quarter and 2014 second quarter operating loss were both $5 million. Adjusted EBITDA totaled $19 million during the 2015 second quarter compared to $8 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 partially offset by lower realized power prices on the unhedged portion of the MISO fleet and associated lower generation volumes.

IPH - The 2015 second quarter operating loss was $14 million, compared to an operating loss of $17 million for the same period in 2014. Adjusted EBITDA totaled $5 million during the 2015 second quarter compared to zero during the same period in 2014. The quarter-over-quarter increase in Adjusted EBITDA resulted from higher capacity revenues and energy margin partially offset by higher operations and maintenance expense.

Gas - The 2015 second quarter operating income was $86 million, compared to an operating loss of $2 million for the same period in 2014. Adjusted EBITDA totaled $202 million during the 2015 second quarter compared to $58 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 spark spreads, and higher market capacity payments, partially offset by the expiration of a capacity contract at Independence.

Liquidity

As of June 30, 2015, Dynegy’s total available liquidity was $1.7 billion as reflected in the table below.

        June 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 (525 ) (20 ) (545 )
Revolving Facility and LC availability 955 5 960
Cash and cash equivalents 569   142   711  

Total available liquidity (4)

 $ 1,524   $ 147   $ 1,671  

__________________________________________

     

(1)

     Includes cash of $116 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 incremental 5-year senior secured revolving credit facilities which became available at closing of the Acquisitions, $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 June 30, 2015, there was approximately $15 million outstanding on the note, which is not reflected in the table above.

Consolidated Cash Flow

Cash used in operations for the first half of 2015 was $21 million. During the period, our power generation business provided cash of $317 million. Corporate and other activities used cash of $332 million primarily due to interest payments on our various debt agreements of $247 million and payments for acquisition-related costs of $102 million. Partially offsetting these costs was a $17 million cash inflow related to a receipt of escrow funds from Ponderosa Pine Energy, LLC.

Cash used in investing activities during the first half of 2015 was $1.056 billion. The Company paid $6.092 billion in cash, net of cash acquired, in connection with the Company’s recent acquisitions and paid $10 million for other investing activities. 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 $82 million in maintenance capital expenditures, $14 million in environmental capital expenditures and $6 million in capitalized interest.

Cash used in financing activities during the first half of 2015 was $82 million.

PRIDE

In 2013, Dynegy launched the PRIDE (Producing Results through Innovation by Dynegy Employees) program with a three-year target (2014-2016) of $135 million in operating improvements and $165 million in balance sheet efficiencies. Due to the success of the program, Dynegy is projected to achieve its three-year targets by the end of 2015 - a full year ahead of schedule.

The newly acquired EquiPower and Duke Midwest generation and retail assets will be added to the PRIDE program and new consolidated targets for 2016 will be set later this year. 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 Guidance

Dynegy’s full-year 2015 Adjusted EBITDA and Free Cash Flow guidance ranges are reaffirmed at $825 million to $1,025 million and $100 to $300 million, respectively.

Share Repurchase Program

In connection with the Company’s financial outlook, the continuing reduction in generation supply, and the overall decline of equities in the commodity and power sector, Dynegy’s Board of Directors has authorized a share repurchase program accelerating the Company’s capital allocation plans. The share repurchase program for up to $250 million is being initiated in the third quarter of 2015 with targeted completion in 2016.

The shares will be purchased from time to time at management’s discretion at prevailing market prices, through open market or privately negotiated transactions in accordance with applicable federal securities laws, depending upon market conditions.

Joppa CT Recommission

In connection with Dynegy’s pursuit of uprates and expansion of its existing fleet, the Company recommissioned five Joppa CTs, two 35 MW units and three 55 MW units, at a total cost of $1.5 million or $6.38 per kW. The units had been on maintenance outage since 2013.

Transactions Update

On June 25, 2015, Dynegy announced an increased Adjusted EBITDA synergy expectation from the acquisitions of $130 million from a revised figure of $100 million. Balance sheet synergies remain at $375 million.

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 second quarter financial results during an investor conference call and webcast tomorrow, August 7, 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.

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 Dynegy’s cash-flow outlook; expectations regarding the amount of shares, manner, timing and funding of the share repurchase program; execution of its PRIDE target in balance sheet and operating improvements by year-end 2015, including improving operating performance, cost structure and the balance sheet efficiency to drive cash flow benefits; anticipated earnings and cash flows and Dynegy’s 2015 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 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 natural gas prices, if any; (iii) beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale and retail 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 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 to which we are, or could become, subject; (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) our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins; (x) Dynegy’s ability to mitigate forced outage risk as it becomes subject to proposed capacity performance 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 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 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, including our PRIDE initiative; (xix) expectations regarding the synergies and anticipated benefits of the Duke Midwest, EquiPower and Brayton Point transactions; (xx) beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the South Bay and Vermilion facilities; (xxi) beliefs regarding redevelopment efforts for the Morro Bay facility; and (xxii) beliefs concerning the Company’s capital allocation program, including the amount of shares, manner, timing and funding of the share repurchase program.

 

DYNEGY INC.

REPORTED UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

(IN MILLIONS, EXCEPT PER SHARE DATA)

   
Three Months Ended June 30, Six Months Ended June 30,
2015   2014 2015   2014
Revenues $ 990 $ 521 $ 1,622 $ 1,283
Cost of sales, excluding depreciation expense (496 ) (365 ) (873 ) (917 )
Gross margin 494 156 749 366
Operating and maintenance expense (250 ) (136 ) (361 ) (246 )
Depreciation expense (175 ) (57 ) (239 ) (124 )
Gain (loss) on sale of assets, net (1 ) 14 (1 ) 14
General and administrative expense (35 ) (29 ) (65 ) (55 )
Acquisition and integration costs (23 ) (2 ) (113 ) (8 )
Operating income (loss) 10 (54 ) (30 ) (53 )
Earnings from unconsolidated investments 3 10 3 10
Interest expense (132 ) (42 ) (268 ) (72 )
Other income and expense, net 4   (39 ) (1 ) (45 )
Loss before income taxes (115 ) (125 ) (296 ) (160 )
Income tax benefit 501   3   501   1  
Net income (loss) 386 (122 ) 205 (159 )
Less: Net income (loss) attributable to noncontrolling interest (2 ) 1   (3 ) 5  
Net income (loss) attributable to Dynegy Inc. 388 (123 ) 208 (164 )
Less: Dividends on preferred stock 6  

-

  11  

-

 
Net income (loss) attributable to Dynegy Inc. common stockholders $ 382   $ (123 ) $ 197   $ (164 )
 
Earnings (Loss) Per Share:
Basic earnings (loss) per share attributable to Dynegy Inc. common
stockholders $ 2.98 $ (1.23 ) $ 1.56 $ (1.64 )
Diluted earnings (loss) per share attributable to Dynegy Inc. common
stockholders $ 2.73 $ (1.23 ) $ 1.49 $ (1.64 )
 
Basic shares outstanding 128 100 126 100
Diluted shares outstanding 142 100 140 100

__________________________________________

(1) The basic and diluted loss per share from continuing operations attributable to Dynegy Inc. is presented below:

 
Income (loss) from continuing operations         $ 386   $ (122 )   $ 205   $ (159 )
Less: Net income (loss) attributable to noncontrolling interest (2 ) 1   (3 ) 5  
Income (loss) from continuing operations attributable to Dynegy Inc. 388 (123 ) 208 (164 )
Less: Dividends on preferred stock 6  

-

  11  

-

 
Income (loss) from continuing operations attributable to Dynegy Inc.
common stockholders for basic earnings (loss) per share 382 (123 ) 197 (164 )
Add: Dividends on preferred stock 6  

-

  11  

-

 
Adjusted income (loss) from continuing operations attributable to Dynegy

Inc. common stockholders for diluted earnings (loss) per share

$ 388   $ (123 ) $ 208   $ (164 )
 
Basic weighted-average shares 128 100 126 100

Effect of dilutive securities (2)

 14  

-

  14  

-

 
Diluted weighted-average shares 142   100   140   100  
 
Earnings (loss) per share from continuing operations attributable to Dynegy
Inc. common stockholders:
Basic $ 2.98 $ (1.23 ) $ 1.56 $ (1.64 )

Diluted (2)

 $ 2.73 $ (1.23 ) $ 1.49 $ (1.64 )

__________________________________________

       

(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 and six months ended June 30, 2014.
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2015

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended June 30, 2015:

     
Three Months Ended June 30, 2015
Coal   IPH   Gas   Other   Total
Net income attributable to Dynegy Inc. $ 388
Plus / (Less):
Loss attributable to noncontrolling interest (2 )
Income tax benefit (501 )
Interest expense 132
Depreciation expense 175
Amortization expense (5 )

EBITDA (1)

 $ 32 $ (6 ) $ 213 $ (52 ) $ 187
Acquisition and integration costs

-

-

-

23 23
Loss attributable to noncontrolling interest

-

2

-

-

2
Mark-to-market adjustments (14 ) 6 (10 )

-

(18 )
Change in fair value of common stock warrants

-

-

-

(3 ) (3 )
Loss on sale of assets, net

-

-

1

-

1
Other 1   3   (2 ) (1 ) 1  

Adjusted EBITDA (1)

 $ 19   $ 5   $ 202   $ (33 ) $ 193  

__________________________________________

       

(1)

     EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 6, 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 June 30, 2015
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (5 ) $ (14 ) $ 86 $ (57 ) $ 10
Depreciation expense 47 8 119 1 175
Amortization expense (10 )

-

5

-

(5 )
Earnings from unconsolidated investments

-

-

3

-

3
Other items, net

-

 

-

 

-

  4   4  
EBITDA $ 32   $ (6 ) $ 213   $ (52 ) $ 187  
 
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED JUNE 30, 2014

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended June 30, 2014:

 
        Three Months Ended June 30, 2014
Coal   IPH   Gas   Other   Total
Net loss attributable to Dynegy Inc. $ (123 )
Plus / (Less):
Income attributable to noncontrolling interest 1
Income tax benefit (3 )
Interest expense 42
Depreciation expense 57
Amortization expense 19  

EBITDA (1)

 $ 4 $ (4 ) $ 61 $ (68 ) $ (7 )
Plus / (Less):
Acquisition and integration costs

-

2

-

-

2
Income attributable to noncontrolling interest

-

(1 )

-

-

(1 )
Mark-to-market adjustments

-

4 10

-

14
Change in fair value of common stock warrants —

-

-

43 43
Gain on sale of assets, net

-

-

(14 )

-

(14 )
Other 4   (1 ) 1   (3 ) 1  

Adjusted EBITDA (1)

 $ 8   $

-

  $ 58   $ (28 ) $ 38  

__________________________________________

       

(1)

     EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 6, 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 loss as the most directly comparable GAAP measure.
       
Three Months Ended June 30, 2014
Coal   IPH   Gas   Other   Total
Operating loss $ (5 ) $ (17 ) $ (2 ) $ (30 ) $ (54 )
Depreciation expense 11 10 35 1 57
Amortization expense (2 ) 3 18

-

19
Earnings from unconsolidated investments

-

-

10

-

10
Other items, net

-

 

-

 

-

  (39 ) (39 )
EBITDA $ 4   $ (4 ) $ 61   $ (68 ) $ (7 )
 
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2015

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the six months ended June 30, 2015:

 
        Six Months Ended June 30, 2015
Coal   IPH   Gas   Other   Total
Net income attributable to Dynegy Inc. $ 208
Plus / (Less):
Loss attributable to noncontrolling interest (3 )
Income tax benefit (501 )
Interest expense 268
Depreciation expense 239
Amortization expense (9 )

EBITDA (1)

 $ 48 $ 23 $ 308 $ (177 ) $ 202
Acquisition and integration costs

-

-

-

113 113
Loss attributable to noncontrolling interest

-

3

-

-

3
Mark-to-market adjustments (21 ) (5 ) (23 )

-

(49 )
Change in fair value of common stock warrants

-

-

-

2 2
Loss on sale of assets, net

-

-

1

-

1
Other 2   6   (2 )

-

  6  

Adjusted EBITDA (1)

 $ 29   $ 27   $ 284   $ (62 ) $ 278  
 

__________________________________________

       

(1)

     EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 6, 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.
       
Six Months Ended June 30, 2015
Coal   IPH   Gas   Other   Total
Operating income (loss) $ 2 $ 8 $ 138 $ (178 ) $ (30 )
Depreciation expense 57 16 164 2 239
Amortization expense (11 ) (1 ) 3

-

(9 )
Earnings from unconsolidated investments

-

-

3

-

3
Other items, net

-

 

-

 

-

  (1 ) (1 )
EBITDA $ 48   $ 23   $ 308   $ (177 ) $ 202  
 
 

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

SIX MONTHS ENDED JUNE 30, 2014

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the six months ended June 30, 2014:

 
        Six Months Ended June 30, 2014
Coal   IPH   Gas   Other   Total
Net loss attributable to Dynegy Inc. $ (164 )
Plus / (Less):
Income attributable to noncontrolling interest 5
Income tax benefit (1 )
Interest expense 72
Depreciation expense 124
Amortization expense 35  

EBITDA (1)

 $ 26 $ (13 ) $ 157 $ (99 ) $ 71
Plus / (Less):
Acquisition and integration costs

-

8

-

-

8
Income attributable to noncontrolling interest

-

(5 )

-

-

(5 )
Mark-to-market adjustments 19 38 18

-

75
Change in fair value of common stock warrants

-

-

-

49 49
Gain on sale of assets, net

-

-

(14 )

-

(14 )
Other 5   2   1   (2 ) 6  

Adjusted EBITDA (1)

 $ 50   $ 30   $ 162   $ (52 ) $ 190  
 

__________________________________________

       

(1)

     EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on August 6, 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.
       
Six Months Ended June 30, 2014
Coal   IPH   Gas   Other   Total
Operating income (loss) $ 4 $ (33 ) $ 32 $ (56 ) $ (53 )
Depreciation expense 25 18 79 2 124
Amortization expense (3 ) 2 36

-

35
Earnings from unconsolidated investments

-

-

10

-

10
Other items, net

-

 

-

 

-

  (45 ) (45 )
EBITDA $ 26   $ (13 ) $ 157   $ (99 ) $ 71  
 
 

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 six months ended June 30, 2015 and 2014, respectively.

 
        Three Months Ended June 30,   Six Months Ended June 30,
2015   2014 2015   2014
Coal

Million Megawatt Hours Generated (9)

 7.5 4.6 12.3 9.9

IMA for Coal-Fired Facilities (1) (9)

 72 % 92 % 79 % 90 %

Average Capacity Factor for Coal-Fired Facilities (2) (9)

 50 % 71 % 57 % 76 %

Average Quoted Market On-Peak Power Prices ($/MWh) (3):

Indiana (Indy Hub) $ 33.15 $ 45.31 $ 36.21 $ 58.34
Commonwealth Edison (NI Hub) $ 31.47 $ 46.02 $ 36.15 $ 63.63
Mass Hub $ 29.16 $ 46.89 $ 62.67 $ 108.75
AD Hub $ 37.75 $ 48.88 $ 41.86 $ 69.42

Average Quoted Market Off-Peak Power Prices ($/MWh) (3):

Indiana (Indy Hub) $ 23.89 $ 30.36 $ 26.43 $ 36.73
Commonwealth Edison (NI Hub) $ 19.70 $ 28.34 $ 23.78 $ 35.64
Mass Hub $ 19.25 $ 33.81 $ 47.84 $ 78.37
AD Hub $ 25.76 $ 32.78 $ 28.69 $ 40.62
 
IPH
Million Megawatt Hours Generated 4.7 5.1 9.9 11.4

IMA for IPH Facilities (4)

 91 % 86 % 92 % 89 %

Average Capacity Factor for IPH Facilities (5)

 54 % 58 % 56 % 65 %

Average Quoted Market Power Prices ($/MWh) (3):

On-Peak: Indiana (Indy Hub) $ 33.15 $ 45.31 $ 36.21 $ 58.34
Off-Peak: Indiana (Indy Hub) $ 23.89 $ 30.36 $ 26.43 $ 36.73
 
Gas

Million Megawatt Hours Generated (6) (9)

 12.8 3.7 17.8 8.2

IMA for Combined Cycle Facilities (4) (9)

 97 % 97 % 98 % 99 %

Average Capacity Factor for Combined Cycle Facilities (5) (9)

 61 % 39 % 61 % 44 %

Average Market On-Peak Spark Spreads ($/MWh) (7):

Commonwealth Edison (NI Hub) $ 12.57 $ 13.47 $ 15.13 $ 13.26
PJM West $ 29.38 $ 25.39 $ 23.46 $ 28.85
North of Path 15 (NP 15) $ 14.99 $ 15.83 $ 13.82 $ 16.15
New York—Zone A $ 22.34 $ 19.02 $ 31.07 $ 46.49
Mass Hub $ 13.48 $ 17.28 $ 14.21 $ 22.87
AD Hub $ 27.53 $ 24.19 $ 29.68 $ 40.02

Average Market Off-Peak Spark Spreads ($/MWh) (7):

Commonwealth Edison (NI Hub) $ 0.80 $ (4.22 ) $ 2.75 $ (14.73 )
PJM West $ 15.66 $ 7.97 $ 8.32 $ (2.21 )
North of Path 15 (NP 15) $ 7.79 $ 4.64 $ 7.51 $ 6.34
New York—Zone A $ 6.54 $ 4.44 $ 15.93 $ 19.17
Mass Hub $ 3.58 $ 4.20 $ (0.62 ) $ (7.50 )
AD Hub $ 15.55 $ 8.10 $ 16.52 $ 11.22

Average natural gas price—Henry Hub ($/MMBtu) (8)

 $ 2.72 $ 4.58 $ 2.80 $ 4.83
 

__________________________________________

       

(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 six months ended June 30, 2015 exclude our Brayton Point facility and CTs. For the three months ended June 30, 2015, the IMA for our facilities within MISO and PJM (excluding CTs) was 76 percent and 70 percent, respectively. For the six months ended June 30, 2015, the IMA for our facilities within MISO and PJM (excluding CTs) was 86 percent and 70 percent, respectively.

(2)

 Reflects actual production as a percentage of available capacity. The calculations for the three and six months ended June 30, 2015 exclude our Brayton Point facility and CTs. For the three months ended June 30, 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 56 percent and 45 percent, respectively. For the six months ended June 30, 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 65 percent and 45 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.

(5)

 Reflects actual production as a percentage of available capacity.

(6)

 The three and six months ended June 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.

UPDATED 2015 ADJUSTED EBITDA AND FREE CASH FLOW GUIDANCE

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our updated 2015 Adjusted EBITDA guidance:

 
      Dynegy Consolidated
Low   High

Net income attributable to Dynegy Inc. (3)

$ 89 $ 269
Plus / (Less):

Income tax benefit (2)

 (501 ) (501 )
Other items, net (5 ) (5 )
Interest expense 535   535  
Operating Income 118 298
Depreciation expense 580 600
Amortization expense 5 (5 )
Other items, net 2   2  

EBITDA (1)

705 895
Plus / (Less):
Transaction fees and expenses 80 85
Integration costs 30 35
Other 10   10  

Adjusted EBITDA (1)

$ 825   $ 1,025  

__________________________________________

       

(1)

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

(2)

 Represents actual amounts for the six months ended June 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.

The following table provides summary financial data regarding our updated 2015 Free Cash Flow guidance:

        Dynegy Consolidated
Low   High

Adjusted EBITDA (1)

$ 825 $ 1,025
Cash interest payments (517 ) (517 )

Transaction fees and expenses (2)

 (105 ) (110 )
Integration costs (30 ) (35 )
Other non-cash and working capital items (15 ) (15 )
Cash Flow from Operations 158 348
Maintenance capital expenditures (240 ) (240 )
Environmental capital expenditures (45 ) (45 )

Transaction fees and expenses (2)

 105 110
Integration costs 30 35

Acquisition interest (3)

 92   92  
Free Cash Flow $ 100   $ 300  

__________________________________________

       

(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).