News Release

Dynegy Announces Fourth Quarter and Full Year 2015 Results, Updates 2016 Guidance

Full Year and Fourth Quarter 2015 Summary:

  • $850 million in consolidated Adjusted EBITDA for 2015, a $503 million increase over 2014 and within the 2015 guidance range of $825 million to $925 million.
  • $186 million in Free Cash Flow, within the 2015 Free Cash Flow guidance range of $140 million to $240 million.
  • Newly acquired assets contributed $590 million to Adjusted EBITDA in 2015.
  • $1,513 million in consolidated liquidity, including $65 million at IPH as of December 31, 2015.
  • $222 million in consolidated Adjusted EBITDA for the quarter, a $155 million increase compared to the fourth quarter 2014.

2016 Guidance:

  • 2016 Adjusted EBITDA guidance range updated to $1,000 million to $1,200 million.
  • 2016 Free Cash Flow guidance range updated to $200 million to $400 million.

Recent Developments:

  • Dynegy completed its $250 million share repurchase program on November 19, 2015, having repurchased a total of 11,326,122 shares.
  • In December 2015, Dynegy signed a one year tolling agreement for its Casco Bay Energy Facility, effectively hedging its energy margin for the year.
  • Each of the Company's six CCGT facilities in PJM set annual production records in 2015, including the four plants that were acquired as part of the Duke and ECP acquisitions.
  • On February 24, 2016, Dynegy was awarded a three year capacity and energy sale at the IPH segment for 959 MW with capacity revenue in excess of $152 million with 113 communities in Illinois represented by Good Energy.

HOUSTON--(BUSINESS WIRE)--Feb. 24, 2016-- Dynegy Inc. (NYSE: DYN) reported 2015 consolidated Adjusted EBITDA of $850 million, compared to $347 million for 2014. The $503 million increase in Adjusted EBITDA was primarily due to the newly acquired plants as well as higher capacity revenues at the Coal, IPH, and Gas segments and higher spark spreads and run times at our legacy PJM gas plants. These gains were partially offset by the expiration of the ConEd capacity contract at Independence and lower power prices and generation volumes at the Coal and IPH segments driven primarily by milder weather relative to 2014. The operating income for the full year 2015 was $64 million compared to an operating loss of $19 million for the full year 2014. The net income attributable to Dynegy Inc. for the full year 2015 was $50 million, compared to a net loss attributable to Dynegy Inc. of $273 million for the full year 2014.

Dynegy reported fourth quarter 2015 consolidated Adjusted EBITDA of $222 million, compared to $67 million for the fourth quarter 2014. The $155 million increase in Adjusted EBITDA was primarily due to the newly acquired plants as well as higher capacity revenues at the Coal, Gas, and IPH segments. These gains were partially offset by the expiration of the ConEd capacity contract at Independence, lower generation volumes at the legacy Coal and IPH segments, and higher operating expenses at the Coal and IPH segments primarily due to environmental compliance studies and significant planned outages during the quarter. The fourth quarter operating loss was $13 million compared to operating income of $12 million for the fourth quarter 2014. The net loss attributable to Dynegy Inc. for the fourth quarter 2015 was $134 million, compared to $104 million for the fourth quarter 2014.

“While the operating environment remains challenging due to low commodity prices and unseasonably moderate weather in the fourth quarter, we achieved our financial targets benefiting from our fuel and geographic diversity and ended the year with $1.5 billion in liquidity. The annual production records set by our CCGT fleet in PJM combined with the results from our newly acquired plants and higher capacity revenues, helped to offset the contract expirations at our Independence plant and mild weather in the markets where we operate,” said Dynegy President and Chief Executive Officer, Robert C. Flexon. “We achieved our 2015 PRIDE improvement targets including the completion of 92 MW of uprates in PJM. Dynegy is now focused on achieving our new targets set in our PRIDE Energized program. In 2016, we expect to add an additional 210 MW across PJM and NYISO. The reduction in our guidance targets reflects the impact of the mild first quarter winter and the corresponding impact of lower prices primarily on our New England and MISO portfolios.”

Full Year Comparative Results

 
    Year Ended December 31, 2015
(in millions)
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (93 ) $ 49 $ 360 $ (252 ) $ 64
Plus / (Less):
Depreciation expense 138 29 416 4 587
Amortization expense (39 ) (6 ) 39

-

(6 )
Earnings from unconsolidated investments

-

-

1

-

1
Other items, net (1 )

-

 

-

  55   54  
EBITDA (1) 5 72 816 (193 ) 700
Plus / (Less):
Acquisition and integration costs

-

-

-

124 124
Loss attributable to noncontrolling interest

-

3

-

-

3
Mark-to-market adjustments (31 ) (10 ) (26 )

-

(67 )
Change in fair value of common stock warrants

-

-

-

(54 ) (54 )
Impairments 99

-

-

-

99
Loss on sale of assets, net

-

-

1

-

1
Cash distributions from unconsolidated investments

-

-

12

-

12
Baldwin transformer project 7

-

-

-

7
ARO accretion expense 8 12 1

-

21
Other 4  

-

  (1 ) 1   4  
Adjusted EBITDA (1) $ 92   $ 77   $ 803   $ (122 ) $ 850  
 
 
Year Ended December 31, 2014
(in millions)
Coal IPH Gas Other Total
Operating income (loss) $ 40 $ (2 ) $ 79 $ (136 ) $ (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) 85 28 307 (168 ) 252
Plus / (Less):
Acquisition and integration costs

-

16

-

19 35
Bankruptcy reorganization items, net

-

-

-

(3 ) (3 )
Income attributable to noncontrolling interest

-

(6 )

-

-

(6 )
Mark-to-market adjustments (32 ) 38 22

-

28
Change in fair value of common stock warrants

-

-

-

40 40
Gain on sale of assets, net

-

-

(18 )

-

(18 )
ARO accretion expense 6 6

-

-

12
Other 3   1  

-

  3   7  
Adjusted EBITDA (1) $ 62   $ 83   $ 311   $ (109 ) $ 347  

__________________________________________

(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, 2016, 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, 2015
(in millions)
Coal   IPH   Gas   Other   Total
Operating income (loss) $ (59 ) $ 10 $ 70 $ (34 ) $ (13 )
Plus / (Less):
Depreciation expense 42 5 126 1 174
Amortization expense (15 )

-

23

-

8
Earnings from unconsolidated investments

-

-

2

-

2
Other items, net (1 )

-

 

-

  10   9  
EBITDA (1) (33 ) 15 221 (23 ) 180
Plus / (Less):
Acquisition and integration costs

-

-

-

3 3
Mark-to-market adjustments 4 (2 ) 3

-

5
Change in fair value of common stock warrants

-

-

-

(11 ) (11 )
Impairments 25

-

-

-

25
Cash distributions from unconsolidated investments

-

-

4

-

4
Baldwin transformer project 7

-

-

-

7
ARO accretion expense 2 3 1

-

6
Other 4  

-

  (1 )

-

  3  
Adjusted EBITDA (1) $ 9   $ 16   $ 228   $ (31 ) $ 222  
 
 
Quarter Ended December 31, 2014
(in millions)
Coal IPH Gas Other Total
Operating income (loss) $ 38 $ 12 $ 7 $ (45 ) $ 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) 48 24 53 (39 ) 86
Plus / (Less):
Acquisition and integration costs

-

8

-

10 18
Bankruptcy reorganization items, net

-

-

-

(1 ) (1 )
Income attributable to noncontrolling interest

-

(1 )

-

-

(1 )
Mark-to-market adjustments (39 ) 4 (1 )

-

(36 )
Change in fair value of common stock warrants

-

-

-

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

-

-

(1 )

-

(1 )
ARO accretion expense 1 2

-

-

3
Other 1   1  

-

 

-

  2  
Adjusted EBITDA (1) $ 11   $ 38   $ 51   $ (33 ) $ 67  

__________________________________________

(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, 2016, 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 2015 operating loss was $93 million, compared to an operating income of $40 million for the full year 2014. Adjusted EBITDA totaled $92 million during 2015 compared to $62 million in 2014. The $30 million year-over-year increase in Adjusted EBITDA is primarily due to the positive impacts from the newly acquired plants and higher wholesale capacity revenues related to the Company's legacy plants. These results were partially offset by lower generation volumes and higher operating costs associated with environmental compliance studies and three eight-week outages at the legacy facilities.

Gas - The full year 2015 operating income was $360 million, compared to $79 million for the full year 2014. Adjusted EBITDA totaled $803 million during 2015 compared to $311 million in 2014. The $492 million year-over-year increase in Adjusted EBITDA is primarily due to the positive impact from the newly acquired plants as well as higher spark spreads, run times, and capacity revenues at our legacy PJM facilities. These results were partially offset by the expiration of the ConEd contract at Independence.

IPH - The full year 2015 operating income was $49 million, compared to an operating loss of $2 million for the full year 2014. Adjusted EBITDA totaled $77 million during 2015 compared to $83 million in 2014. Lower generation volumes and realized prices were offset by higher capacity revenues received from MISO and PJM; however, higher year over year planned outages resulted in higher costs at the Joppa and Edwards facilities leading to the segment's lower results.

Segment Review of Results Quarter-over-Quarter

Coal - The fourth quarter 2015 operating loss was $59 million, compared to an operating income of $38 million for the same period in 2014. Adjusted EBITDA for the segment was relatively steady, totaling $9 million during the fourth quarter 2015, compared to $11 million during the same period in 2014 as higher outage costs associated with major outages at Baldwin and Havana and lower generation volumes offset the uplift from the newly acquired assets.

Gas - The fourth quarter 2015 operating income was $70 million, compared to $7 million for the same period in 2014. Adjusted EBITDA totaled $228 million during the fourth quarter 2015 compared to $51 million during the same period in 2014. The quarter-over-quarter increase in Adjusted EBITDA is primarily due to the positive impact from our newly acquired plants, higher market capacity pricing, and higher spark spreads and run times at the Company's legacy PJM plants, which more than offset the expiration of the Independence capacity contract.

IPH - The fourth quarter 2015 operating income was $10 million, compared to $12 million for the same period in 2014. Adjusted EBITDA totaled $16 million during the fourth quarter 2015 compared to $38 million during the same period in 2014. The quarter-over-quarter decrease in Adjusted EBITDA is primarily due to higher plant outage expenses and a non-recurring retail gross margin benefit in 2014 that was not repeated in 2015.

Liquidity

As of December 31, 2015, Dynegy’s total available liquidity was $1.5 billion as reflected in the table below.

   
December 31, 2015
(amounts in millions) Dynegy Inc.   IPH (1) (2)   Total
Revolving Facility and LC capacity (3) $ 1,480 $ 48 $ 1,528
Less: Outstanding letters of credit (475 ) (45 ) (520 )
Revolving Facility and LC availability 1,005 3 1,008
Cash and cash equivalents 443   62   505  
Total available liquidity (4) $ 1,448   $ 65   $ 1,513  

__________________________________________

(1)   Includes Cash and cash equivalents of $61 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) Dynegy, Inc. includes (i) $950 million of aggregate available capacity related to our incremental revolving credit facilities, (ii) $475 million of available capacity related to the five-year senior secured revolving credit facility and (iii) $55 million related to a letter of credit. IPH includes (i) $25 million related to the two-year secured letter of credit facility and (ii) $23 million related to our fully cash collateralized letter of credit and reimbursement agreement.
(4) On December 2, 2013, Dynegy and Illinois Power Resources, LLC entered into an intercompany revolving promissory note of $25 million. At December 31, 2015, there was $25 million outstanding on the note, which is not reflected in the table above.
 

Consolidated Cash Flow

Cash provided by operations for the full year of 2015 was $94 million. During the full year 2015, our power generation business provided cash of $888 million. Corporate and other activities used cash of $588 million primarily due to interest payments on our various debt agreements of $490 million and payments for acquisition-related costs of $115 million, offset by $17 million related to the Ponderosa Pine Energy, LLC cash receipt. Changes in working capital and other, including general and administrative expenses, used cash of $206 million, net, during the period.

Cash used in investing activities totaled $1.194 billion for the full year of 2015. During the full year 2015, we paid $6.078 billion in cash, net of cash acquired, in connection with the acquisitions. In addition, there was a $5.148 billion inflow, related to the release of restricted cash as a result of closing the acquisitions. The Company also received a distribution of $11 million from our unconsolidated investment in Elwood Energy LLC, of which $8 million is considered a return of capital. During the full year of 2015, capital expenditures totaled $275 million, including $235 million in maintenance capital expenditures, $28 million in environmental capital expenditures and $12 million in capitalized interest.

Cash used in financing activities totaled $265 million for the full year of 2015 primarily due to $250 million of payments related to our share repurchase program, $37 million in financing costs related to our debt and equity issuances, $31 million in repayments associated with our inventory financing agreements and term loan, $23 million in dividend payments on our Mandatory Convertible Preferred Stock, and $17 million in interest rate swap settlement payments, offset by $97 million in proceeds received related to inventory financing agreements.

PRIDE Energized

The Company launched the PRIDE (Producing Results through Innovation by Dynegy Employees) Energized program this year with a three-year target of $250 million in EBITDA and operating improvements and $400 million in balance sheet efficiencies. The acquired EquiPower and Duke Midwest assets have been added to the PRIDE Energized program. The overall goal of the PRIDE Energized program continues to be improving operating performance, cost structure, and balance sheet efficiency to drive incremental cash flow benefits.

Dynegy projects $135 million of the Adjusted EBITDA and operating improvements three-year target will be achieved in 2016 with 66 percent of EBITDA improvements toward the $135 million goal for the year having already been identified. One hundred percent of the $200 million goal in balance sheet initiatives has been identified and implemented in the first quarter of 2016.

Uprates

At investor day in June 2015, the Company announced plans for uprates at various locations. Currently, 387 MW of uprates are expected to be achieved as follows:

                                         
          PJM         ISO-NE         NYISO         Total MW By Year
2015         92                             92
2016         165                   45         210
2017         15         42                   57
2018                   28                   28
Total MW By ISO         272         70         45         387
                               

The uprates at the Company’s legacy plants, which total 115 MW, are part of Pride Energized. The balance of the uprates was included in acquisition synergies. During June 2015, Dynegy also added 235 MW of peaking capacity in MISO for less than $5 per kW.

Share Repurchase Program

Dynegy announced a share repurchase program on August 6, 2015, which accelerated the Company’s capital allocation plans. The share repurchase program for up to $250 million was initially targeted for completion in 2016.

However, due to positive balance sheet improvements associated with the PRIDE program, Dynegy was able to accelerate its share repurchases completing the entire $250 million share repurchase program early on November 19, 2015, having repurchased a total of 11,326,122 shares.

2016 Guidance

Full-year 2016 Adjusted EBITDA guidance range has been updated to $1,000 million to $1,200 million from $1,100 million to $1,300 million previously. Free Cash Flow guidance is updated to $200 million to $400 million from $300 million to $500 million previously. The reduction in the Company's guidance targets reflects the impact of lower power prices across Dynegy's key markets and lower spark spreads in New England as a result of unusually mild first quarter weather.

Beginning this year, Free Cash Flow excludes certain capital costs related to compliance with environmental requirements. 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 instead will be reported as part of its capital allocation program similar to the company’s other capital investments.

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 2015 financial results during an investor conference call and webcast tomorrow, February 25, 2016 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 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 Dynegy’s beliefs and expectations regarding its future uprate projects across PJM, ISO New England, and NYISO; execution of its PRIDE Energized target in balance sheet and operating improvements by year-end 2016; anticipated earnings and cash flows and Dynegy’s 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 Dynegy’s filings with the Securities and Exchange Commission (the “SEC”). Specifically, Dynegy makes reference to, and incorporates herein by reference, the section entitled “Risk Factors” in its 2015 Form 10-K (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 power markets, including the anticipation of plant retirements and higher market pricing over the longer term; (iv) sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof; (v) the effects of, or changes to, MISO, PJM, CAISO, NYISO or ISO-NE power and capacity procurement processes; (vi) expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect; (vii) beliefs about the outcome of legal, administrative, legislative and regulatory matters; (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, including managing risk associated with CP in PJM and new 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) anticipated timing, outcomes and impacts of the expected retirements of Brayton Point and Wood River; (xx) 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 (xxi) 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,

2015   2014
Revenues $ 3,870 $ 2,497
Cost of sales, excluding depreciation expense (2,028 ) (1,661 )
Gross margin 1,842 836
Operating and maintenance expense (839 ) (477 )
Depreciation expense (587 ) (247 )
Impairments (99 )

-

Gain (loss) on sale of assets, net (1 ) 18
General and administrative expense (128 ) (114 )
Acquisition and integration costs (124 ) (35 )
Operating income (loss) 64 (19 )
Bankruptcy reorganization items, net

-

3
Earnings from unconsolidated investments 1 10
Interest expense (546 ) (223 )
Other income and expense, net 54   (39 )
Loss from continuing operations before income taxes (427 ) (268 )
Income tax benefit 474   1  
Net income (loss) 47 (267 )
Less: Net income (loss) attributable to noncontrolling interest (3 ) 6  
Net income (loss) attributable to Dynegy Inc. 50 (273 )
Less: Dividends on preferred stock 22   5  
Net income (loss) attributable to Dynegy Inc. common stockholders $ 28   $ (278 )
 
Earnings (Loss) Per Share:
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders $ 0.22 $ (2.65 )
 
Basic shares outstanding 125 105
Diluted shares outstanding 126 105
   

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

 

Twelve Months Ended
December 31,

2015   2014
Income (loss) from continuing operations $ 47 $ (267 )
Less: Net income (loss) attributable to noncontrolling interest (3 ) 6  
Income (loss) from continuing operations attributable to Dynegy Inc. 50 (273 )
Less: Dividends on preferred stock 22   5  
Income (loss) from continuing operations attributable to Dynegy Inc. common stockholders for basic and diluted earnings (loss) per share $ 28   $ (278 )
 
Basic weighted-average shares 125 105
Effect of dilutive securities (1) 1  

-

 
Diluted weighted-average shares 126   105  
 
Basic and diluted earnings (loss) per share from continuing operations attributable to Dynegy Inc. common stockholders (1) $ 0.22 $ (2.65 )

__________________________________________

(1)   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 twelve months ended December 31, 2014.
   

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

TWELVE MONTHS ENDED DECEMBER 31, 2015

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2015:

 
Twelve Months Ended December 31, 2015
Coal   IPH   Gas   Other   Total
Net income attributable to Dynegy Inc. $ 50
Plus / (Less):
Loss attributable to noncontrolling interest (3 )
Income tax benefit (474 )
Interest expense 546
Depreciation expense 587
Amortization expense (6 )
EBITDA (1) $ 5 $ 72 $ 816 $ (193 ) $ 700
Plus / (Less):
Acquisition and integration costs

-

-

-

124 124
Loss attributable to noncontrolling interest

-

3

-

-

3
Mark-to-market adjustments (31 ) (10 ) (26 )

-

(67 )
Change in fair value of common stock warrants

-

-

-

(54 ) (54 )
Impairments 99

-

-

-

99
Loss on sale of assets, net

-

-

1

-

1
Cash distributions from unconsolidated investments

-

-

12

-

12
Baldwin transformer project 7

-

-

-

7
ARO accretion expense 8 12 1

-

21
Other 4  

-

  (1 ) 1   4  
Adjusted EBITDA (1) $ 92   $ 77   $ 803   $ (122 ) $ 850  
 

__________________________________________

(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, 2016, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented below. Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.

 
Twelve Months Ended December 31, 2015
Coal IPH Gas Other Total
Operating income (loss) $ (93 ) $ 49 $ 360 $ (252 ) $ 64
Depreciation expense 138 29 416 4 587
Amortization expense (39 ) (6 ) 39

-

(6 )
Earnings from unconsolidated investments

-

-

1

-

1
Other items, net (1) (1 )

-

 

-

  55   54  
EBITDA $ 5   $ 72   $ 816   $ (193 ) $ 700  
 

__________________________________________

(1) Other items, net primarily consists of the change in fair value of our common stock warrants, the write-off of certain power generation assets and the receipt of casualty insurance proceeds.

   

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):
Income attributable to noncontrolling interest 6
Income tax benefit (1 )
Interest expense 223
Depreciation expense 247
Amortization expense 50  
EBITDA (1) $ 85 $ 28 $ 307 $ (168 ) $ 252
Plus / (Less):
Acquisition and integration costs

-

16

-

19 35
Bankruptcy reorganization items, net

-

-

-

(3 ) (3 )
Income attributable to noncontrolling interest

-

(6 )

-

-

(6 )
Mark-to-market adjustments (32 ) 38 22

-

28
Change in fair value of common stock warrants

-

-

-

40 40
Gain on sale of assets, net

-

-

(18 )

-

(18 )
ARO accretion expense 6 6

-

-

12
Other 3   1    

-

  3   7  
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, 2016, for definitions, utility and uses of such non-GAAP financial measures.  A reconciliation of EBITDA to Operating income (loss) is presented below.  Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.

 
Twelve Months Ended December 31, 2014
Coal IPH Gas Other Total
Operating income (loss) $ 40 $ (2 ) $ 79 $ (136 ) $ (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 (1)

-

 

-

 

-

  (39 ) (39 )
EBITDA $ 85   $ 28   $ 307   $ (168 ) $ 252  
 

__________________________________________

(1) Other items, net primarily consists of the change in fair value of our common stock warrants.

   

DYNEGY INC.

REPORTED SEGMENTED RESULTS OF OPERATIONS

THREE MONTHS ENDED DECEMBER 31, 2015

(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2015:

 
Three Months Ended December 31, 2015
Coal   IPH   Gas   Other   Total
Net loss attributable to Dynegy Inc. $ (134 )
Plus / (Less):
Income tax benefit (1 )
Interest expense 133
Depreciation expense 174
Amortization expense 8  
EBITDA (1) $ (33 ) $ 15 $ 221 $ (23 ) $ 180
Plus / (Less):
Acquisition and integration costs

-

-

-

3 3
Mark-to-market adjustments 4 (2 ) 3

-

5
Change in fair value of common stock warrants

-

-

-

(11 ) (11 )
Impairments 25

-

-

-

25
Cash distributions from unconsolidated investments

-

-

4

-

4
Baldwin transformer project 7

-

-

-

7
ARO accretion expense 2 3 1

-

6
Other 4  

-

  (1 )

-

  3  
Adjusted EBITDA (1) $ 9   $ 16   $ 228   $ (31 ) $ 222  
 

__________________________________________

(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, 2016, for definitions, utility and uses of such non-GAAP financial measures.  A reconciliation of EBITDA to Operating income (loss) is presented below.  Management does not allocate interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure.

 
Three Months Ended December 31, 2015
Coal IPH Gas Other Total
Operating income (loss) $ (59 ) $ 10 $ 70 $ (34 ) $ (13 )
Depreciation expense 42 5 126 1 174
Amortization expense (15 )

-

23

-

8
Earnings from unconsolidated investments

-

-

2

-

2
Other items, net (1) (1 )

-

 

-

  10   9  
EBITDA $ (33 ) $ 15   $ 221   $ (23 ) $ 180  
 

__________________________________________

(1) Other items, net primarily consists of the change in fair value of our common stock warrants, the write-off of certain power generation assets and the receipt of casualty insurance proceeds.

   

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):
Income attributable to noncontrolling interest 1
Interest expense 119
Depreciation expense 62
Amortization expense 8  
EBITDA (1) $ 48 $ 24 $ 53 $ (39 ) $ 86
Plus / (Less):
Acquisition and integration costs

-

8

-

10 18
Bankruptcy reorganization items, net

-

-

-

(1 ) (1 )
Income attributable to noncontrolling interest

-

(1 )

-

-

(1 )
Mark-to-market adjustments (39 ) 4 (1 )

-

(36 )
Change in fair value of common stock warrants

-

-

-

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

-

-

(1 )

-

(1 )
ARO accretion expense 1 2

-

-

3
Other 1   1  

-

 

-

  2  
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, 2016, 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, 2014
Coal IPH Gas Other Total
Operating income (loss) $ 38 $ 12 $ 7 $ (45 ) $ 12
Depreciation expense 12 9 40 1 62
Bankruptcy reorganization items, net

-

-

-

1 1
Amortization expense (2 ) 4 6

-

8
Other items, net (1)

-

  (1 )

-

  4   3  
EBITDA $ 48   $ 24   $ 53   $ (39 ) $ 86  
 

__________________________________________

(1) Other items, net primarily consists of the change in fair value of our common stock warrants.

 

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, 2015 and 2014, respectively.

 
   

Three Months Ended
December 31,

 

Twelve Months Ended
December 31,

2015   2014 2015   2014
Coal
Million Megawatt Hours Generated (9) 7.6 4.6 29.3 19.0
IMA for Coal-Fired Facilities (1) (9) 81 % 88 % 80 % 88 %
Average Capacity Factor for Coal-Fired Facilities (2) (9) 47 % 69 % 56 % 73 %
Average Quoted Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 28.52 $ 38.54 $ 33.50 $ 48.28
Commonwealth Edison (NI Hub) $ 29.60 $ 37.55 $ 33.98 $ 50.60
Mass Hub $ 34.98 $ 48.39 $ 48.96 $ 76.97
AD Hub $ 31.29 $ 41.56 $ 37.52 $ 54.86
Average Quoted Market Off-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 22.00 $ 29.06 $ 24.56 $ 32.52
Commonwealth Edison (NI Hub) $ 20.68 $ 26.27 $ 22.79 $ 30.74
Mass Hub $ 22.81 $ 34.57 $ 34.88 $ 54.58
AD Hub $ 23.32 $ 30.07 $ 26.40 $ 34.81
 
IPH
Million Megawatt Hours Generated 3.8 5.9 18.5 $ 23.7
IMA for IPH Facilities (4) 86 % 87 % 89 % 89 %
Average Capacity Factor for IPH Facilities (5) 43 % 67 % 52 % 68 %
Average Quoted Market Power Prices ($/MWh) (3):
On-Peak: Indiana (Indy Hub) $ 28.52 $ 38.54 $ 33.50 $ 48.28
Off-Peak: Indiana (Indy Hub) $ 22.00 $ 29.06 $ 24.56 $ 32.52
 
Gas
Million Megawatt Hours Generated (6) (9) 13.5 4.1 46.7 17.1
IMA for Combined Cycle Facilities (4) (9) 98 % 97 % 98 % 99 %
Average Capacity Factor for Combined Cycle Facilities (5) (9) 63 % 43 % 63 % 45 %
Average Market On-Peak Spark Spreads ($/MWh) (7):
Commonwealth Edison (NI Hub) $ 14.49 $ 10.25 $ 14.81 $ 11.60
PJM West $ 24.20 $ 23.26 $ 25.24 $ 26.82
North of Path 15 (NP 15) $ 13.39 $ 17.04 $ 14.32 $ 17.18
New York—Zone A $ 21.96 $ 21.01 $ 27.60 $ 34.64
Mass Hub $ 13.59 $ 13.35 $ 15.23 $ 20.08
AD Hub $ 26.24 $ 24.55 $ 28.22 $ 31.94
Average Market Off-Peak Spark Spreads ($/MWh) (7):
Commonwealth Edison (NI Hub) $ 5.57 $ (1.03 ) $ 3.62 $ (8.26 )
PJM West $ 15.21 $ 11.80 $ 11.84 $ 4.97
North of Path 15 (NP 15) $ 8.45 $ 7.99 $ 7.93 $ 7.30
New York—Zone A $ 5.00 $ 8.77 $ 11.84 $ 14.09
Mass Hub $ 1.42 $ (0.48 ) $ 1.14 $ (2.31 )
AD Hub $ 15.16 $ 13.06 $ 16.13 $ 11.89
Average natural gas price—Henry Hub ($/MMBtu) (8) $ 2.09 $ 3.75 $ 2.61 $ 4.34
 

__________________________________________

(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 twelve months ended December 31, 2015 exclude our Brayton Point facility and CTs. For the three months ended December 31, 2015, the IMA for our facilities within MISO and PJM (excluding CTs) were 87 percent and 78 percent, respectively. For the twelve months ended December 31, 2015, the IMA for our facilities within MISO and PJM (excluding CTs) were 87 percent and 74 percent, respectively.
(2) Reflects actual production as a percentage of available capacity. The calculations for the three and twelve months ended December 31, 2015 exclude our Brayton Point facility and CTs. For the three months ended December 31, 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 45 percent and 49 percent, respectively. For the twelve months ended December 31, 2015, the average capacity factors for our facilities within MISO and PJM (excluding CTs) were 61 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 twelve months ended December 31, 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.
SUMMARY CASH FLOW INFORMATION (1)
TWELVE MONTHS ENDED DECEMBER 31, 2015
(UNAUDITED) (IN MILLIONS)

 
  Twelve Months Ended December 31, 2015
Dynegy   IPH   Consolidated
Adjusted EBITDA (2) $ 773 $ 77 $ 850
Interest payments (441 ) (59 ) (500 )
Acquisition and integration payments (115 )

-

(115 )
Collateral 61 25 86
Hedge adjustment related to acquisitions (60 )

-

(60 )
Working capital and other changes (98 ) (69 )

 

(167 )
Net cash provided by (used in) operating activities 120 (26 ) 94
Maintenance capital expenditures (169 ) (28 ) (197 )
Environmental capital expenditures (6 ) (22 ) (28 )
Collateral (61 ) (25 ) (86 )
Interest accrued on $5.1 billion Notes (pre-acquisition interest) 92

-

92
Interest rate swap settlement payments (17 )

-

(17 )
Acquisition and Integration costs 115

-

115
Hedge adjustment related to acquisitions 60

-

60
Working capital and other changes 84   69   153  
Free Cash Flow $ 218   $ (32 ) $ 186  
 
Capital expenditures $ (212 ) $ (63 ) $ (275 )
(Increase) decrease in restricted cash 5,148

-

5,148
Acquisitions, net of cash acquired/divestitures (6,078 )

-

(6,078 )
Distributions from unconsolidated affiliates 8

-

8
Other investing 3  

-

  3  
Net cash used in investing activities $ (1,131 ) $ (63 ) $ (1,194 )
 
Proceeds from long-term borrowings $ 97 $

-

$ 97
Repayments of borrowings (31 ) (31 )
Financing costs from debt issuance (31 )

-

(31 )
Financing costs from equity issuance (6 )

-

(6 )
Dividends paid (23 )

-

(23 )
Interest rate swap settlement payments (17 )

-

(17 )
Repurchase of common stock (250 )

-

(250 )
Other financing (4 )

-

  (4 )
Net cash used in financing activities $ (265 ) $

-

  $ (265 )
 

__________________________________________

(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, 2016, 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, 2016, 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, 2015 for a reconciliation of Adjusted EBITDA to Net income attributable to Dynegy Inc.
 

DYNEGY INC.
2015 ADJUSTED EBITDA AND FREE CASH FLOW GUIDANCE
(UNAUDITED) (IN MILLIONS)

 

The following table provides summary financial data regarding our 2015 Adjusted EBITDA guidance, updated based on October 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 and Adjusted EBITDA 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 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 (1) $ 140   $ 240  
 

__________________________________________

(1)   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, 2015 forward curves, as presented on November 4, 2015:

   
Dynegy Consolidated
Low   High
Net income (loss) attributable to Dynegy Inc. $ (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 and Adjusted EBITDA 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 (1) $ 300   $ 500  

__________________________________________

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

 
 

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 February 8, 2016 forward curves, as presented on February 24, 2016:

   
Dynegy Consolidated
Low   High
Net loss attributable to Dynegy Inc. $ (275 ) $ (105 )
Plus / (Less):
Interest expense 535   540  
Operating Income 260 435
Depreciation expense 710 730
Amortization expense 30   30  
EBITDA (1) 1,000 1,195
Plus / (Less):
Integration costs

-

  5  
Adjusted EBITDA (1) $ 1,000   $ 1,200  

__________________________________________

 

(1) EBITDA and Adjusted EBITDA 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) $ 1,000 $ 1,200
Cash interest payments (515 ) (515 )
Integration costs

-

(5 )
Other cash items 35   35  
Cash Flow from Operations 520 715
Maintenance capital expenditures (300 ) (300 )
Environmental capital expenditures (20 ) (20 )
Integration costs

-

  5  
Free Cash Flow (1) $ 200   $ 400  

__________________________________________

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

 

Source: Dynegy Inc.

Dynegy Inc.
Media: Micah Hirschfield, 713.767.5800
or
Analysts: 713.507.6466