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Dynegy Announces Full Year 2014 Results, Updates 2015 Guidance

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Dynegy Inc. (NYSE:DYN) reported 2014 consolidated Adjusted EBITDA of $347 million, compared to $227 million for 2013. The $120 million increase in Adjusted EBITDA was primarily due to the December 2, 2013 addition of Illinois Power Holdings (IPH), improved realized power prices in the Coal segment and improved spark spreads and generation volumes in the Gas segment. These gains were partially offset by lower revenues from the Moss Landing toll and the Independence capacity contract expiration in the Gas segment and higher delivered fuel costs for the Coal segment. The operating loss for the full year 2014 was $19 million compared to an operating loss of $318 million for the full year 2013. The net loss attributable to Dynegy Inc. for the full year 2014 was $273 million, compared to a net loss of $356 million for the full year 2013.

Dynegy reported fourth quarter 2014 consolidated Adjusted EBITDA of $67 million, compared to $63 million for the fourth quarter 2013. The $4 million increase in Adjusted EBITDA was primarily due to the addition of IPH and was partially offset by lower revenues associated with the Moss Landing toll and expiration of the Independence capacity contract. Operating income was $12 million for the fourth quarter 2014 compared to an operating loss of $107 million for the same period in 2013. The net loss attributable to Dynegy Inc. for the fourth quarter 2014 was $104 million, compared to a net loss of $91 million for the fourth quarter 2013.

“We achieved our 2014 Adjusted EBITDA guidance and exceeded the top end of our Free Cash Flow guidance range which had been increased this past August. Higher realized power prices and spark spreads during the year more than offset contract expirations at our Moss Landing and Independence plants,” said Dynegy President and Chief Executive Officer, Robert C. Flexon. “We are progressing through the regulatory review process of our pending acquisitions and will move quickly to close the Duke Midwest, EquiPower, and Brayton Point transactions following FERC approval. Post-closing, the Company will have a diverse footprint in what we believe are the best power markets in the US. With meaningful asset retirements on the horizon, capacity and energy prices are set to increase over the next few years and will drive significant free cash flow for the benefit of the Company and our stockholders.”

Full Year Comparative Results

Year Ended December 31, 2014
(in millions)
Coal IPH Gas Other Total
Operating income (loss) $ 52 $ (2 ) $ 79 $ (148 ) $ (19 )
Plus / (Less):
Depreciation expense 51 37 155 4 247
Bankruptcy reorganization items, net

3 3
Amortization expense (6 ) (7 ) 63

50
Earnings from unconsolidated investments

10

10
Other items, net

(39 ) (39 )
EBITDA (1) 97 28 307 (180 ) 252
Plus / (Less):
Bankruptcy reorganization items, net

(3 ) (3 )
Acquisition and integration costs

16

19 35
Mark-to-market (income) loss, net (44 ) 38 22 12 28
Change in fair value of common stock warrants

40 40
Income attributable to noncontrolling interest

(6 )

(6 )
Gain on sale of assets, net

(18 )

(18 )
Other 9 7

3 19
Adjusted EBITDA (1) $ 62 $ 83 $ 311 $ (109 ) $ 347
Year Ended December 31, 2013
(in millions)
Coal IPH Gas Other Total
Operating income (loss) $ (207 ) $ (17 ) $ 7 $ (101 ) $ (318 )
Plus / (Less):
Depreciation expense 50 3 160 3 216
Bankruptcy reorganization items, net

(1 ) (1 )
Amortization expense 126 (2 ) 127

251
Earnings from unconsolidated investments

2

2
Other items, net

2 6 8
EBITDA (1) (31 ) (16 ) 298 (93 ) 158
Plus / (Less):
Bankruptcy reorganization items, net

1 1
Acquisition and integration costs

20

20
Mark-to-market loss, net 25 8 4

37
Change in fair value of common stock warrants

1 1
Other 2

8 10
Adjusted EBITDA (1) $ (4 ) $ 12 $ 302 $ (83 ) $ 227
(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 February 24, 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.

Fourth Quarter Comparative Results

Quarter Ended December 31, 2014
(in millions)
Coal IPH Gas Other Total
Operating income (loss) $ 50 $ 12 $ 7 $ (57 ) $ 12
Plus / (Less):
Depreciation expense 12 9 40 1 62
Bankruptcy reorganization items, net

1 1
Amortization expense (2 ) 4 6

8
Other items, net

(1 )

4 3
EBITDA (1) 60 24 53 (51 ) 86
Plus / (Less):
Bankruptcy reorganization items, net

(1 ) (1 )
Acquisition and integration costs

8

10 18
Mark-to-market (income) loss, net (51 ) 4 (1 ) 12 (36 )
Change in fair value of common stock warrants

(3 ) (3 )
Net income attributable to noncontrolling interest

(1 )

(1 )
Gain on sale of assets, net

(1 )

(1 )
Other 2 3

5
Adjusted EBITDA (1) $ 11 $ 38 $ 51 $ (33 ) $ 67
Quarter Ended December 31, 2013
(in millions)
Coal IPH Gas Other Total
Operating loss $ (44 ) $ (17 ) $ (23 ) $ (23 ) $ (107 )
Plus / (Less):
Depreciation expense 14 3 42 1 60
Bankruptcy reorganization items, net

1 1
Amortization expense 31 (2 ) 32

61
Earnings from unconsolidated investments

2

2
Other items, net

2 (1 ) 1
EBITDA (1) 1 (16 ) 55 (22 ) 18
Plus / (Less):
Bankruptcy reorganization items, net

(1 ) (1 )
Acquisition and integration costs

20

(6 ) 14
Mark-to-market loss, net 9 8 12

29
Other

3 3
Adjusted EBITDA (1) $ 10 $ 12 $ 67 $ (26 ) $ 63
(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 February 24, 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 Year-over-Year

Coal - The full year 2014 operating income was $52 million, compared to an operating loss of $207 million for the full year 2013. Adjusted EBITDA totaled $62 million during 2014 compared to a loss of $4 million in 2013. The $66 million year-over-year increase in Adjusted EBITDA is primarily due to higher realized energy prices and lower operating and maintenance expense that more than offset lower generation volumes and higher delivered fuel costs due to a contracted price increase.

IPH – The full year 2014 operating loss was $2 million, compared to an operating loss of $17 million for the one month of ownership in 2013. Adjusted EBITDA totaled $83 million during 2014 compared to $12 million in 2013. The year-over-year increase in Adjusted EBITDA is primarily due to a full year of ownership in 2014, compared to one month in 2013.

Gas – The full year 2014 operating income was $79 million, compared to $7 million for the full year 2013. Adjusted EBITDA totaled $311 million during 2014 compared to $302 million in 2013. The $9 million year-over-year increase in Adjusted EBITDA is primarily due to improved spark spreads and generation volumes at Independence and Ontelaunee. That and higher capacity revenue at Kendall were partially offset by a decrease in revenues associated with the Moss Landing tolling agreement and the Independence capacity contract expirations.

Segment Review of Results Quarter-over-Quarter

Coal - The fourth quarter 2014 operating income was $50 million, compared to an operating loss of $44 million for the same period in 2013. Adjusted EBITDA for the segment was relatively steady, totaling $11 million during the fourth quarter 2014 compared to $10 million during the same period in 2013, due to higher realized prices being largely offset by a decline in generation volumes primarily due to a planned outage at Baldwin.

IPH – The fourth quarter 2014 operating income was $12 million, compared to an operating loss of $17 million for the one month of ownership in 2013. Adjusted EBITDA totaled $38 million during the fourth quarter 2014 compared to $12 million during the same period in 2013. The quarter-over-quarter increase in Adjusted EBITDA reflects full ownership during the quarter in 2014 versus one month ownership in 2013.

Gas – The fourth quarter 2014 operating income was $7 million, compared to an operating loss of $23 million for the same period in 2013. Adjusted EBITDA totaled $51 million during the fourth quarter 2014 compared to $67 million during the same period in 2013. The quarter-over-quarter decrease in Adjusted EBITDA is primarily due to a decrease in revenues associated with the Moss Landing toll agreement and Independence capacity contract expirations.

Liquidity

As of December 31, 2014, Dynegy’s total available liquidity was $2.2 billion as reflected in the table below.

December 31, 2014
(amounts in millions) Dynegy Inc. IPH (1) (2) Total
Revolving Facilities and LC capacity (3) $ 530 $

$ 530
Less: Outstanding letters of credit (178 )

(178 )
Revolving Facilities and LC availability 352

352
Cash and cash equivalents 1,696 174 1,870
Total available liquidity $ 2,048 $ 174 $ 2,222
(1) Includes Cash and cash equivalents of $126 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 $475 million of available capacity related to the Revolving Facility and $55 million related to a letter of credit with Macquarie Bank.

Consolidated Cash Flow

Cash provided by operations for the full year of 2014 was $163 million. During the full year 2014, our power generation business provided cash of $451 million. Corporate and other activities used cash of $230 million primarily due to interest payments related to our debt and payments for acquisition-related costs. In addition, changes in working capital and other, including general and administrative expenses, used cash of approximately $58 million.

Cash used in investing activities totaled $5.3 billion for the full year of 2014, which consisted primarily of a $5.1 billion cash outflow related to restricted cash balances due to escrow requirements associated with the senior notes private placement in October 2014 for the transactions financing. During the full year of 2014, capital expenditures totaled $132 million, including $90 million in maintenance capital expenditures, $33 million in environmental capital expenditures and $9 million in capitalized interest.

Cash provided by financing activities during the quarter was $6.1 billion primarily due to $6.2 billion in proceeds from transactions financing in October 2014.

PRIDE Reloaded

The Company launched the PRIDE (Producing Results through Innovation by Dynegy Employees) Reloaded program a year ago with a three-year target of $135 million in operating improvements and $165 million in balance sheet efficiencies. In 2014, the Company exceeded its $60 million EBITDA improvement target and its $65 million balance sheet efficiency target and due to the Company’s performance to date, is set to accelerate its pace to achieve its three-year targets by the end of 2015-a full year ahead of schedule. After the transactions close, the newly acquired EquiPower and Duke Midwest assets will be added to the PRIDE Reloaded program and consolidated targets for 2016 will be set. The overall goal of the PRIDE Reloaded program continues to be improving operating performance, cost structure and balance sheet efficiency to drive incremental cash flow benefits.

2015 Guidance

Dynegy has updated its 2015 guidance target using February 10 price curves. Given the later than expected acquisition closing dates, Dynegy has revised its 2015 guidance targets to a range of $825 million to $1,025 million in consolidated full year Adjusted EBITDA and $100 million to $300 million in Free Cash Flow, prior to acquisition-related costs and discretionary capital expenditures. Whereas prior guidance estimates assumed a January 1 close, new guidance estimates assume an April 1 close for the pending Duke Midwest, EquiPower and Brayton Point transactions.

Other Recent Developments

Capacity Contract Sales - Total capacity sales through bilateral wholesale and retail channels are nearly 7,500 MW through planning year 2019/2020 at a weighted average price of over $3.00/kW-month. This represents sales of over 20% of the available capacity. The Company sold 1,400 MW of bilateral capacity in MISO during 2014.

New England Capacity Auction - The 2018/2019 New England (ISO-NE) capacity auction cleared at $9.55 per kW-month for most resources, a $2.52 per kW-month increase from the prior year’s capacity auction clearing price – a $70 million increase in gross margin for the consolidated company post acquisition closing. The New England capacity price for 2018/2019 is significantly higher than the estimated capacity price used in our acquisition analysis.

Baldwin Transmission Projects - In Q4 of 2014 we signed a construction agreement with Ameren Transmission to implement several transmission projects designed to alleviate network congestion around our Baldwin facility. The first project will be completed in June 2015 with the upgrade of the Baldwin facility’s transformer. Additional transmission line work will be performed through 2017.

California Strategic Review - The sales process for the California portfolio has been terminated as the bids received were below our view of the portfolio’s value.

Newton Scrubber Project - Dynegy has converted the engineering, procurement, and construction contract for the Newtown Scrubber Project from a target price agreement to a fixed-price contract. As a result, the forecasted cost to complete has been lowered by $30 million to $224 million. The majority of the capital outlay will occur in 2018-2019.

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 fourth quarter and full year 2014 financial results during an investor conference call and webcast tomorrow, February 25, 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 approximately 13,000 megawatts of power generation capacity and two retail electricity companies, we serve our customers and markets by providing safe, reliable and economic energy. Homefield Energy and Dynegy Energy Services are retail electricity providers serving businesses and residents in Illinois.

Forward-Looking Statement

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 timing of FERC approval and closing of the Duke Midwest, EquiPower and Brayton Point transactions; Dynegy’s post-closing position in the U.S. power markets; expectations regarding future capacity and energy prices and subsequent benefits to Dynegy and its stockholders; execution of its PRIDE reloaded 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 (when filed). 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 market, 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) our ability to mitigate forced outage risk as it pertains to new rules and regulations on capacity related to capacity performance in PJM and performance incentives in ISO-NE; (xi) our ability to optimize our assets through targeted investment in cost effective technology enhancements; (xii) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (xiii) efforts to secure retail sales and the ability to grow the retail business; (xiv) efforts to identify opportunities to reduce congestion and improve busbar power prices; (xv) ability to mitigate impacts associated with expiring 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, financing, completion, timing, terms 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) the strategic evaluation of our California assets; and (xxii) beliefs regarding redevelopment efforts for the Morro Bay facility.

DYNEGY INC.

REPORTED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED) (IN MILLIONS, EXCEPT PER SHARE DATA)

Twelve Months Ended
December 31,

2014 2013
Revenues $ 2,497 $ 1,466
Cost of sales, excluding depreciation expense (1,661 ) (1,145 )
Gross margin 836 321
Operating and maintenance expense (477 ) (308 )
Depreciation expense (247 ) (216 )
Gain on sale of assets, net 18 2
General and administrative expense (114 ) (97 )
Acquisition and integration costs (35 ) (20 )
Operating loss (19 ) (318 )
Bankruptcy reorganization items, net 3 (1 )
Earnings from unconsolidated investments 10 2
Interest expense (223 ) (97 )
Loss on extinguishment of debt

(11 )
Other income and expense, net (39 ) 8
Loss from continuing operations before income taxes (268 ) (417 )
Income tax benefit 1 58
Loss from continuing operations (267 ) (359 )
Income from discontinued operations, net of tax

3
Net loss (267 ) (356 )
Less: Net income attributable to noncontrolling interest 6

Net loss attributable to Dynegy Inc. (273 ) (356 )
Less: Dividends on preferred stock 5

Net loss attributable to Dynegy Inc. common stockholders $ (278 ) $ (356 )
Loss Per Share:
Basic and diluted loss per share attributable to Dynegy Inc. common stockholders:
Loss from continuing operations (1) $ (2.65 ) $ (3.59 )
Income from discontinued operations

0.03
Basic and diluted loss per share attributable to Dynegy Inc. common stockholders $ (2.65 ) $ (3.56 )
Basic and diluted shares outstanding 105 100

(1) The reconciliation of basic loss per share from continuing operations to diluted loss per share from continuing operations of our common stock outstanding during the period is presented below:

Twelve Months Ended
December 31,

2014 2013
Loss from continuing operations $ (267 ) $ (359 )
Less: Net income attributable to noncontrolling interest 6

Loss from continuing operations attributable to Dynegy Inc. (273 ) (359 )
Less: Dividends on preferred stock 5

Loss from continuing operations attributable to Dynegy Inc. common stockholders $ (278 ) $ (359 )
Basic and diluted weighted-average shares (2) 105 100
Basic and diluted loss per share from continuing operations attributable to Dynegy Inc. common stockholders $ (2.65 ) $ (3.59 )

(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 all periods presented.

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

TWELVE MONTHS ENDED DECEMBER 31, 2014

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2014:

Twelve Months Ended December 31, 2014
Coal IPH Gas Other Total
Net loss attributable to Dynegy Inc. $ (273 )
Plus / (Less):
Net income attributable to noncontrolling interest 6
Income tax benefit (1 )
Interest expense 223
Depreciation expense 247
Amortization expense 50
EBITDA (1) $ 97 $ 28 $ 307 $ (180 ) $ 252
Plus / (Less):
Bankruptcy reorganization items, net

(3 ) (3 )
Acquisition and integration costs

16

19 35
Mark-to-market (income) loss, net (44 ) 38 22 12 28
Change in fair value of common stock warrants

40 40
Net income attributable to noncontrolling interest

(6 )

(6 )
Gain on sale of assets, net

(18 )

(18 )
Other 9 7

3 19
Adjusted EBITDA (1) $ 62 $ 83 $ 311 $ (109 ) $ 347

(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 24, 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.

Twelve Months Ended December 31, 2014
Coal IPH Gas Other Total
Operating income (loss) $ 52 $ (2) $ 79 $ (148 ) $ (19 )
Depreciation expense 51 37 155 4 247
Bankruptcy reorganization items, net

3 3
Amortization expense (6 ) (7 ) 63

50
Earnings from unconsolidated investments

10

10
Other items, net

(39 ) (39 )
EBITDA $ 97 $ 28 $ 307 $ (180 ) $ 252

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

TWELVE MONTHS ENDED DECEMBER 31, 2013

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the 12 months ended December 31, 2013:

Twelve Months Ended December 31, 2013
Coal IPH Gas Other Total
Net loss attributable to Dynegy Inc. $ (356 )
Plus / (Less):
Income from discontinued operations, net of tax (3 )
Income tax benefit (58 )
Interest expense 97
Loss on extinguishment of debt 11
Depreciation expense 216
Amortization expense 251
EBITDA (1) $ (31 ) $ (16 ) $ 298 $ (93 ) $ 158
Plus / (Less):
Bankruptcy reorganization items, net

1 1
Acquisition and integration costs

20

20
Mark-to-market loss, net 25 8 4

37
Change in fair value of common stock warrants

1 1
Other 2

8 10
Adjusted EBITDA (1) $ (4 ) $ 12 $ 302 $ (83 ) $ 227

(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 24, 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.

Twelve Months Ended December 31, 2013
Coal IPH Gas Other Total
Operating income (loss) $ (207 ) $ (17 ) $ 7 $ (101 ) $ (318 )
Depreciation expense 50 3 160 3 216
Bankruptcy reorganization items, net

(1 ) (1 )
Amortization expense 126 (2 ) 127

251
Earnings from unconsolidated investments

2

2
Other items, net

2 6 8
EBITDA $ (31 ) $ (16 ) $ 298 $ (93 ) $ 158

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2014

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2014:

Three Months Ended December 31, 2014
Coal IPH Gas Other Total
Net loss attributable to Dynegy Inc. $ (104 )
Plus / (Less):
Net income attributable to noncontrolling interest 1
Interest expense 119
Depreciation expense 62
Amortization expense 8
EBITDA (1) $ 60 $ 24 $ 53 $ (51 ) $ 86
Plus / (Less):
Bankruptcy reorganization items, net

(1 ) (1 )
Acquisition and integration costs

8

10 18
Mark-to-market (income) loss, net (51 ) 4 (1 ) 12 (36 )
Change in fair value of common stock warrants

(3 ) (3 )
Net income attributable to noncontrolling interest

(1 )

(1 )
Gain on sale of assets, net

(1 )

(1 )
Other 2 3

5
Adjusted EBITDA (1) $ 11 $ 38 $ 51 $ (33 ) $ 67

(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 24, 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 December 31, 2014
Coal IPH Gas Other Total
Operating income (loss) $ 50 $ 12 $ 7 $ (57 ) $ 12
Depreciation expense 12 9 40 1 62
Bankruptcy reorganization items, net

1 1
Amortization expense (2 ) 4 6

8
Other items, net

(1 )

4 3
EBITDA $ 60 $ 24 $ 53 $ (51 ) $ 86

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2013

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2013:

Three Months Ended December 31, 2013
Coal IPH Gas Other Total
Net loss attributable to Dynegy Inc. $ (91 )
Plus / (Less):
Income tax benefit (38 )
Interest expense 26
Depreciation expense 60
Amortization expense 61
EBITDA (1) $ 1 $ (16 ) $ 55 $ (22 ) $ 18
Plus / (Less):
Bankruptcy reorganization items, net

(1 ) (1 )
Acquisition and integration costs

20

(6 ) 14
Mark-to-market loss, net 9 8 12

29
Other

3 3
Adjusted EBITDA (1) $ 10 $ 12 $ 67 $ (26 ) $ 63

(1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 24, 2015, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating 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 December 31, 2013
Coal IPH Gas Other Total
Operating loss $ (44 ) $ (17 ) $ (23 ) $ (23 ) $ (107 )
Depreciation expense 14 3 42 1 60
Bankruptcy reorganization items, net

1 1
Amortization expense 31 (2 ) 32

61
Earnings from unconsolidated investments

2

2
Other items, net

2 (1 ) 1
EBITDA $ 1 $ (16 ) $ 55 $ (22 ) $ 18

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 twelve months ended December 31, 2014 and 2013, respectively. As a result of the AER Acquisition, 2013 results only include activity for the period December 2, 2013 through December 31, 2013.

Three Months Ended
December 31,

Twelve Months Ended
December 31,

2014 2013 2014 2013
Coal
Million Megawatt Hours Generated 4.6 5.5 19.0 20.4
In Market Availability for Coal-Fired Facilities (1) 88 % 86 % 88 % 89 %
Average Capacity Factor for Coal-Fired Facilities (2) 69 % 83 % 73 % 78 %
Average Quoted Market Power Prices ($/MWh) (3):
On-Peak: Indiana (Indy Hub) $ 38.54 $ 37.71 $ 48.28 $ 38.01
Off-Peak: Indiana (Indy Hub) $ 29.06 $ 28.44 $ 32.52 $ 27.49
IPH
Million Megawatt Hours Generated (4) 6.2 2.4 25.1 $ 2.4
In Market Availability for IPH Facilities (5) 87 % 90 % 89 % 90 %
Average Capacity Factor for IPH Facilities (6) 67 % 75 % 68 % 75 %
Average Quoted Market Power Prices ($/MWh) (7):
On-Peak: Indiana (Indy Hub) $ 38.54 $ 40.32 $ 48.28 $ 40.32
Off-Peak: Indiana (Indy Hub) $ 29.06 $ 30.82 $ 32.52 $ 30.82
Gas
Million Megawatt Hours Generated (8) 4.1 3.7 17.1 16.2
In Market Availability for Combined Cycle Facilities (9) 97 % 97 % 99 % 97 %
Average Capacity Factor for Combined Cycle Facilities (2) 43 % 38 % 45 % 43 %
Average Market On-Peak Spark Spreads ($/MWh) (10):
Commonwealth Edison (NI Hub) $ 10.25 $ 7.29 $ 11.60 $ 11.38
PJM West $ 23.26 $ 15.47 $ 26.82 $ 17.65
North of Path 15 (NP 15) $ 17.04 $ 16.93 $ 17.18 $ 16.21
New York-Zone A $ 21.01 $ 24.24 $ 34.64 $ 20.12
Mass Hub $ 13.35 $ 12.69 $ 20.08 $ 16.35
Average Market Off-Peak Spark Spreads ($/MWh) (10):
Commonwealth Edison (NI Hub) $ (1.03 ) $ (1.17 ) $ (8.26 ) $ (0.13 )
PJM West $ 11.80 $ 5.99 $ 4.97 $ 4.99
North of Path (NP 15) $ 7.99 $ 9.92 $ 7.30 $ 8.46
New York-Zone A $ 8.77 $ 6.87 $ 14.09 $ 7.49
Mass Hub $ (0.48 ) $ (5.46 ) $ (2.31 ) $ (0.16 )
Average natural gas price-Henry Hub ($/MMBtu) (11) $ 3.75 $ 3.84 $ 4.34 $ 3.72
(1) In Market Availability 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.
(2) Reflects actual production as a percentage of available capacity.
(3) Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
(4) Reflects production volumes in million MWh generated during the period IPH was included in our consolidated results.
(5) Reflects the percentage of generation available during the period IPH was included in our consolidated results.
(6) Reflects actual production as a percentage of available capacity during the period IPH was included in our consolidated results.
(7) Reflects the average of day-ahead quoted prices for the period IPH was included in our consolidated results and does not necessarily reflect prices we realized.
(8) The year ended December 31, 2013 includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility. The year ended December 31, 2014 includes our ownership percentage in the MWh generated through June 27, 2014 when we completed the sale of our 50 percent partnership interest in Black Mountain.
(9) Reflects the percentage of generation available when market prices are such that these units could be profitably dispatched.
(10) 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.
(11) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

DYNEGY INC.

2014 FREE CASH FLOW GUIDANCE

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our 2014 Free Cash Flow guidance:

Dynegy Consolidated
Low High
Adjusted EBITDA (1) $ 330 $ 360
Cash interest payments (145 ) (145 )
Other changes 15 15
Cash Flow from Operations 200 230
Maintenance capital expenditures (120 ) (120 )
Environmental capital expenditures (35 ) (35 )
Free Cash Flow $ 45 $ 75

(1) EBITDA and Adjusted EBITDA are non-GAAP measures.

DYNEGY INC.

UPDATED 2015 ADJUSTED EBITDA AND FREE CASH FLOW GUIDANCE

(UNAUDITED) (IN MILLIONS)

Dynegy has not completed its purchase price allocation or determined the estimated useful lives of the assets to be acquired. The 2015 updated guidance below was prepared using reasonable efforts and based on currently available information assuming the following: (a) the transactions will close on April 1, 2015, (b) February 10, 2015 price curves, (c) all of the purchase price is allocated to working capital; property, plant and equipment; and the elimination of historical goodwill; and (d) property, plant and equipment is depreciated over an average useful life of 25 years.

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

Dynegy Consolidated
Low High
Net loss attributable to Dynegy Inc. $ (230 ) $ (50 )
Plus / (Less):

Interest expense

535 535
Operating Income $ 305 $ 485
Depreciation expense 420 440
Amortization expense (10 ) (20 )
EBITDA (1) 715 905
Plus / (Less):
Transaction fees and expenses 80 85
Integration costs 30 35
Adjusted EBITDA (1) $ 825 $ 1,025

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).

ILLINOIS POWER HOLDINGS (IPH)

UPDATED 2015 ADJUSTED EBITDA GUIDANCE

(UNAUDITED) (IN MILLIONS)

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

Operating Income $ 65
Depreciation expense 36
Amortization expense (6 )
EBITDA (1) 95
Plus / (Less):
Acquisition and integration costs 5
Adjusted EBITDA (1) $ 100

(1) EBITDA and Adjusted EBITDA are non-GAAP measures. 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.

DYNEGY INC.

SUMMARY CASH FLOW INFORMATION (1)

TWELVE MONTHS ENDED DECEMBER 31, 2014

(UNAUDITED) (IN MILLIONS)

Twelve Months Ended December 31, 2014
Dynegy IPH Consolidated
Adjusted EBITDA (2) $ 264 $ 83 $ 347
Interest payments (69 ) (60 ) (129 )
Collateral 8 (25 ) (17 )
Working capital / non-cash adjustments / other changes (60 ) 22 (38 )
Cash provided by operating activities 143 20 163
Maintenance capital expenditures (80 ) (10 ) (90 )
Environmental capital expenditures (7 ) (26 ) (33 )
Collateral (8 ) 25 17
Interest accrued on $5.1 billion Notes (held in escrow) 65

65
Interest rate swap settlement payments (18 )

(18 )
Free Cash Flow $ 95 $ 9 $ 104
Capital expenditures $ (87 ) $ (45 ) $ (132 )
Proceeds from asset sales, net 18

18
Increase in restricted cash (5,148 )

(5,148 )
Net cash used in investing activities $ (5,217 ) $ (45 ) $ (5,262 )
Proceeds from issuance of preferred stock, net $ 387 $

$ 387
Proceeds from issuance of common stock, net 719

719
Proceeds from long-term borrowings, net of financing costs 5,055

5,055
Repayments of borrowings (14 )

(14 )
Intercompany revolving promissory note (17 ) 17

Interest rate swap settlement payments (18 )

(18 )
Other financing (3 )

(3 )
Net cash provided by financing activities $ 6,109 $ 17 $ 6,126

(1) This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of Free Cash Flow. We believe it is useful to our analysts and investors to understand this relationship because it demonstrates how the cash generated by our operations is used to satisfy various liquidity requirements. A reconciliation of Free Cash Flow from Net cash provided by (used in) operating activities is presented above. Please refer to Item 2.02 of our Form 8-K filed on February 24, 2015, for definitions, utility and uses of such non-GAAP financial measures.

(2) Adjusted EBITDA is a non-GAAP financial measure. Please refer to Item 2.02 of our Form 8-K filed on February 24, 2015, for definitions, utility and uses of such non-GAAP financial measures. Please see Reported Segmented Results of Operations for the twelve months ended December 31, 2014 for a reconciliation of Adjusted EBITDA to Net loss.

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