2015 First Quarter Financial
Highlights:
- $85 million in consolidated Adjusted
EBITDA for the 2015 first quarter, a decrease of $67 million
compared to the 2014 first quarter.
- $2,106 million in consolidated
liquidity, including $199 million at IPH as of March 31,
2015.
- $55 million in Cash Flow used in
Operations through March 31, 2015.
- Affirmed full-year 2015 Adjusted EBITDA
guidance range of $825 million to $1,025 million and Free Cash Flow
guidance range of $100 to $300 million.
Operating and Commercial
Highlights:
- Gas segment in-market availability was
99% and the equivalent availability factor for Coal and IPH
segments was 91% and 90%, respectively.
- 2015-2016 MISO planning year capacity
auction cleared at $150 MW/day in Zone 4, with Dynegy clearing 553
MW of capacity. Additional Dynegy capacity was self-scheduled in
the auction to back the Company’s retail sales.
Recent Developments:
- On April 1, completed the acquisition
of EquiPower Resources Corp. and Brayton Point Holdings, LLC from
Energy Capital Partners for approximately $3.35 billion in cash
plus $100 million in Dynegy common stock; allocated $100 million in
excess cash to reduce equity issued at closing.
- On April 2, completed the acquisition
of Duke Energy’s Midwest generation assets and retail business for
approximately $2.8 billion in cash.
- Increased acquisition EBITDA synergies
to $100 million from $40 million and balance sheet synergies
increased to $375 million from $200 million.
Dynegy Inc. (NYSE: DYN) reported 2015 first quarter consolidated
Adjusted EBITDA of $85 million, compared to $152 million for the
2014 first quarter. The $67 million decrease resulted from more
moderate weather that contributed to lower realized power prices as
well as the expiration of the ConEd contract at Independence.
Operating loss was $40 million for the 2015 first quarter compared
to an operating income of $1 million for the same period in 2014.
The net loss attributable to Dynegy Inc. for the 2015 first quarter
was $180 million, compared to $41 million for the 2014 first
quarter.
“The completion of the EquiPower Resources Corp, Brayton Point
Holdings, LLC, and Duke Energy’s Midwest commercial generation
assets and retail business acquisitions has transformed the Company
into one of the leading power producers. Dynegy is well positioned
to capitalize on market conditions with our expanded footprint in
the PJM and ISO-NE markets. As generating assets continue to be
retired across our markets, capacity prices are increasingly
signaling the need for investment. The recent MISO auction is an
example of the rising value for existing supply,” said Dynegy
President and Chief Executive Officer Robert C. Flexon. “Our
guidance is on track to meet our 2015 post acquisition
targets.”
First Quarter
Comparative Results
Quarter Ended March 31, 2015 (in millions)
Coal IPH
Gas Other
Total Operating income (loss) $ 7 $ 22 $ 52 $ (121 )
$ (40 ) Plus / (Less): Depreciation expense 10 8 45 1 64
Amortization expense (1 ) (1 ) (2 )
-
(4 ) Other items, net
-
-
-
(5 ) (5 )
EBITDA (1) 16 29 95 (125 ) 15 Plus /
(Less): Acquisition and integration costs
-
-
-
90 90 Loss attributable to noncontrolling interest
-
1
-
-
1 Mark-to-market income, net (7 ) (11 ) (13 )
-
(31 ) Change in fair value of common stock warrants
-
-
-
5 5 Other 1 3
-
1 5
Adjusted EBITDA (1) $ 10 $
22 $ 82 $ (29 ) $ 85
Quarter
Ended March 31, 2014 (in millions) Coal
IPH Gas Other Total Operating income
(loss) $ 9 $ (16 ) $ 34 $ (26 ) $ 1 Plus / (Less): Depreciation
expense 14 8 44 1 67 Amortization expense (1 ) (1 ) 18
-
16 Other items, net
-
-
-
(6 ) (6 )
EBITDA (1) 22 (9 ) 96 (31 ) 78 Plus /
(Less): Acquisition and integration costs
-
6
-
-
6 Income attributable to noncontrolling interest
-
(4 )
-
-
(4 ) Mark-to-market loss, net 19 34 8
-
61 Change in fair value of common stock warrants
-
-
-
6 6 Other 1 3
-
1 5
Adjusted EBITDA (1) $ 42 $
30 $ 104 $ (24 ) $ 152
(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 May 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 first quarter operating income was $7
million, compared to operating income of $9 million for the same
period in 2014. Adjusted EBITDA totaled $10 million during the 2015
first quarter compared to $42 million during the same period in
2014. The quarter-over-quarter decrease in Adjusted EBITDA is due
to a decrease in realized power prices on the unhedged portion of
the fleet and lower generation volumes caused partially by a
February transmission outage that negatively impacted both on and
off-peak economics.
IPH - The 2015 first quarter operating income was $22
million, compared to an operating loss of $16 million for the same
period in 2014. Adjusted EBITDA totaled $22 million during the 2015
first quarter compared to $30 million during the same period in
2014. Quarter-over-quarter Adjusted EBITDA decreased due to lower
market prices on the unhedged portion of the fleet and lower
generation volumes. This decrease was meaningfully offset, however,
as retail sales were made at higher average prices, and capacity
sales increased during the 2015 first quarter primarily associated
with the segment’s cost-based contracts.
Gas - The 2015 first quarter operating income was $52
million, compared to an operating income of $34 million for the
same period in 2014. Adjusted EBITDA totaled $82 million during the
2015 first quarter compared to $104 million during the same period
in 2014. The quarter-over-quarter decrease in Adjusted EBITDA is
primarily due to the expiration of the ConEd contract at
Independence. Lower energy margins, primarily at Independence and
Ontelaunee, were offset by higher capacity market revenue at
Independence and Kendall.
Liquidity
As of March 31, 2015, Dynegy’s total
available liquidity was $2.1 billion as reflected in the table
below.
March 31, 2015 (amounts in
millions) Dynegy Inc. IPH (1) (2)
Total Revolving Facilities and LC capacity (3)
$ 530 $ 25 $ 555 Less: Outstanding letters of credit (183 )
-
(183 ) Revolving Facility and LC availability 347 25 372
Cash and cash equivalents 1,560 174 1,734
Total available liquidity (4) (5) $ 1,907 $ 199 $
2,106 (1) Includes cash of $127
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) a five-year $475 million senior secured
revolving credit facility and a $55 million letter of credit
facility at Dynegy Inc., and (ii) a two-year $25 million secured
revolving 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 March 31, 2015, there
was $11 million outstanding on that note, which is not reflected in
the table above. (5) After the close of the acquisitions, our total
available liquidity was approximately $1.8 billion.
Consolidated Cash Flow
Cash used in operations for the 2015 first quarter was $55
million. During the period, our power generation business provided
cash of $111 million. Corporate and other activities used cash of
$99 million as the company paid $92 million on the Notes issued in
2014, $8 million in interest on its Credit Agreement and Senior
Notes issued in 2013, $8 million in interest on the Genco Senior
Notes, and $8 million in acquisition-related costs. Partially
offsetting these costs was a $17 million cash inflow related to a
receipt of escrow funds from Ponderosa Pine Energy, LLC. Changes in
working capital and other expenses, including general and
administrative costs, used an additional $67 million.
Cash used in investing activities totaled $40 million for the
2015 first quarter including $31 million in maintenance capital
expenditures, $6 million in environmental capital expenditures and
$3 million in capitalized interest.
Cash used in financing activities during the 2015 first quarter
was $41 million, which includes debt obligation payments of $25
million and $7 million paid in preferred stock dividends.
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. 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 remain unchanged at $825 million to $1,025 million
and $100 to 300 million, respectively.
Transactions Update
On April 1, 2015, Dynegy announced an increased synergy
expectation from the acquisitions of $100 million from the initial
figure of $40 million. Balance sheet synergies have increased from
$200 million to $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 first quarter financial results during an investor
conference call and webcast tomorrow, May 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 transformation as
a leading power producer; its position to capitalize on market
conditions; beliefs regarding capacity prices and the recent MISO
auction; expectations regarding Dynegy’s 2015 post acquisition
targets; 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 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; and (xxi) beliefs regarding redevelopment
efforts for the Morro Bay facility.
DYNEGY INC.
REPORTED UNAUDITED CONSOLIDATED
STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE
DATA)
Three Months Ended March
31,
2015 2014 Revenues $ 632 $ 762
Cost of sales, excluding depreciation expense (377 ) (552 ) Gross
margin 255 210 Operating and maintenance expense (111 ) (110 )
Depreciation expense (64 ) (67 ) General and administrative expense
(30 ) (26 ) Acquisition and integration costs (90 ) (6 ) Operating
income (loss) (40 ) 1 Interest expense (136 ) (30 ) Other income
and expense, net (5 ) (6 ) Loss before income taxes (181 ) (35 )
Income tax expense
-
(2 ) Net loss (181 ) (37 ) Less: Net income (loss)
attributable to noncontrolling interest (1 ) 4 Net loss
attributable to Dynegy Inc. (180 ) (41 ) Less: Dividends on
preferred stock 5
-
Net loss attributable to Dynegy Inc. common stockholders $
(185 ) $ (41 )
Loss Per Share: Basic and diluted loss
per share attributable to Dynegy Inc. common stockholders (1) $
(1.49 ) $ (0.41 ) Basic and diluted shares outstanding 124
100
(1) The basic and diluted loss per share
from continuing operations attributable to Dynegy Inc. is presented
below:
Loss from continuing operations $ (181 ) $ (37 ) Less: Net
income (loss) attributable to noncontrolling interest (1 ) 4
Loss from continuing operations attributable to Dynegy Inc. (180 )
(41 ) Less: Dividends on preferred stock 5
-
Loss from continuing operations attributable to Dynegy Inc.
common stockholders $ (185 ) $ (41 ) Basic and diluted
weighted-average shares (2) 124 100 Basic and diluted loss
per share from continuing operations attributable to Dynegy Inc.
common stockholders (2) $ (1.49 ) $ (0.41 ) (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 utilized the basic
shares outstanding amount to calculate both basic and diluted loss
per share for the three months ended March 31, 2015 and 2014.
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
THREE MONTHS ENDED MARCH 31,
2015
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
three months ended March 31, 2015:
Three Months Ended March 31, 2015 Coal
IPH Gas Other
Total Net loss attributable to Dynegy Inc. $ (180 )
Plus / (Less): Loss attributable to noncontrolling interest (1 )
Interest expense 136 Depreciation expense 64 Amortization expense
(4 )
EBITDA (1) $ 16 $ 29 $ 95 $ (125 ) $ 15 Acquisition and
integration costs
-
-
-
90 90 Loss attributable to noncontrolling interest
-
1
-
-
1 Mark-to-market income, net (7 ) (11 ) (13 )
-
(31 ) Change in fair value of common stock warrants
-
-
-
5 5 Other 1 3
-
1 5
Adjusted EBITDA (1) $ 10 $
22 $ 82 $ (29 ) $ 85
(1)
EBITDA and Adjusted EBITDA are non-GAAP
financial measures. Please refer to Item 2.02 of our Form 8-K filed
on May 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 March 31, 2015 Coal IPH
Gas Other Total Operating income (loss)
$ 7 $ 22 $ 52 $ (121 ) $ (40 ) Depreciation expense 10 8 45 1 64
Amortization expense (1 ) (1 ) (2 )
-
(4 ) Other items, net
-
-
-
(5 ) (5 )
EBITDA $ 16 $ 29 $ 95
$ (125 ) $ 15
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
THREE MONTHS ENDED MARCH 31,
2014
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
three months ended March 31, 2014:
Three Months Ended March 31, 2014 Coal
IPH Gas
Other Total Net loss attributable to
Dynegy Inc. $ (41 ) Plus / (Less): Income attributable to
noncontrolling interest 4 Income tax expense 2 Interest expense 30
Depreciation expense 67 Amortization expense 16
EBITDA
(1) $ 22 $ (9 ) $ 96 $ (31 ) $ 78 Plus / (Less): Acquisition
and integration costs
-
6
-
-
6 Income attributable to noncontrolling interest
-
(4 )
-
-
(4 ) Mark-to-market loss, net 19 34 8
-
61 Change in fair value of common stock warrants
-
-
-
6 6 Other 1 3
-
1 5
Adjusted EBITDA (1) $ 42 $
30 $ 104 $ (24 ) $ 152
(1)
EBITDA and Adjusted EBITDA are non-GAAP
financial measures. Please refer to Item 2.02 of our Form 8-K filed
on May 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 March 31, 2014 Coal
IPH Gas Other Total Operating income
(loss) $ 9 $ (16 ) $ 34 $ (26 ) $ 1 Depreciation expense 14 8
44 1 67 Amortization expense (1 ) (1 ) 18
-
16 Other items, net
-
-
-
(6 ) (6 )
EBITDA $ 22 $ (9 ) $ 96 $ (31
) $ 78
DYNEGY INC.
OPERATING DATA
The following table provides summary
financial data regarding our Coal, IPH and Gas segment results of
operations for the three months ended March 31, 2015 and 2014,
respectively.
Three Months Ended March 31, 2015
2014 Coal Million Megawatt Hours
Generated 4.8 5.3 IMA for Coal-Fired Facilities (1) 91 % 88 %
Average Capacity Factor for Coal-Fired Facilities (2) 74 % 82 %
Average Quoted Market Power Prices ($/MWh) (3): On-Peak: Indiana
(Indy Hub) $ 39.27 $ 71.36 Off-Peak: Indiana (Indy Hub) $ 28.97 $
43.10
IPH Million Megawatt Hours Generated 5.5 6.7
IMA for IPH Facilities (1) 93 % 90 % Average Capacity Factor for
IPH Facilities (2) 60 % 73 % Average Quoted Market Power Prices
($/MWh) (3): On-Peak: Indiana (Indy Hub) $ 39.27 $ 71.36 Off-Peak:
Indiana (Indy Hub) $ 28.97 $ 43.10
Gas Million
Megawatt Hours Generated (4) 5.0 4.5 IMA for Combined Cycle
Facilities (1) 99 % 99 % Average Capacity Factor for Combined Cycle
Facilities (2) 53 % 47 % Average Market On-Peak Spark Spreads
($/MWh) (5): Commonwealth Edison (NI Hub) $ 17.68 $ 13.05 PJM West
$ 17.55 $ 32.30 North of Path 15 (NP 15) $ 11.82 $ 16.48
New York--Zone A
$ 39.80 $ 73.97 Mass Hub $ 14.92 $ 28.47 Average Market Off-Peak
Spark Spreads ($/MWh) (5): Commonwealth Edison (NI Hub) $ 4.71 $
(25.25 ) PJM West $ 0.98 $ (12.38 ) North of Path 15 (NP 15) $ 6.14
$ 8.05
New York--Zone A
$ 25.32 $ 33.91 Mass Hub $ (4.84 ) $ (19.20 )
Average natural gas price-Henry Hub
($/MMBtu) (6)
$ 2.87 $ 5.08 (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. (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)
The three months ended March 31, 2014 includes our ownership
percentage in the MWh generated by our investment in the Black
Mountain power generation facility which was subsequently sold on
June 27, 2014. (5) 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. (6) Reflects the average of daily quoted
prices for the periods presented and does not reflect costs
incurred by us.
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.Media: Micah Hirschfield, 713.767.5800orAnalysts:
713.507.6466
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