Financial Highlights:
- $350 million in consolidated Adjusted
EBITDA for the third quarter, an increase of $260 million compared
to the 2014 third quarter.
- $628 million in consolidated Adjusted
EBITDA for the first nine months, an increase of $348 million
compared to the first nine months of 2014.
- $1,934 million in consolidated
liquidity, including $150 million at IPH as of September 30,
2015.
- 2015 Adjusted EBITDA guidance range
narrowed at $825 million to $925 million and Free Cash Flow
guidance range at $140 million to $240 million.
- 2016 Adjusted EBITDA guidance range
initiated at $1,100 million to $1,300 million and Free Cash Flow
guidance at $300 million to $500 million.
Recent Developments:
- Secured Resource Adequacy capacity with
Southern California Edison for Moss Landing units 1 and 2 for 575
MW, 400 MW, and 850 MW, for calendar years 2017, 2018, 2019,
respectively.
- Selected, along with three other
suppliers, to provide a total of 1,033 MW of Zone 4 MISO capacity
to the Illinois Power Authority for planning year 2016/2017 at a
weighted average price of $138.12 per MW-Day.
- Launched “PRIDE Energized” – the next
iteration of the Company’s PRIDE initiative – targeting $250
million in EBITDA and $400 million in balance sheet improvements
from 2016 to 2018, with $135 million of the Adjusted EBITDA
targeted to be achieved in 2016.
- Announced intent to retire 465 MW Wood
River Power Station in Alton, Illinois in mid-2016.
Capital Allocation:
- On September 25, 2015, Moody’s affirmed
Dynegy Inc.’s existing ratings and upgraded their outlook on the
company from stable to positive.
- Through October 2015, the Company
repurchased 7,625,355 shares at an aggregate cost of $187 million
under the current authorized stock repurchase program.
Dynegy Inc. (NYSE: DYN) reported 2015 third quarter consolidated
Adjusted EBITDA of $350 million, compared to $90 million for the
2014 third quarter. The $260 million increase was primarily due to
the Company’s recent acquisitions, higher spark spreads in the Gas
segment, higher wholesale capacity revenues at the IPH and Coal
segments, and improved results for the retail business. These
improvements in Adjusted EBITDA were partially offset by the
expiration of a capacity contract at the Independence plant in the
Gas segment. Operating income was $107 million for the 2015 third
quarter compared to $22 million for the same period in 2014. The
net loss attributable to Dynegy Inc. for the 2015 third quarter was
$24 million, compared to a net loss attributable to Dynegy Inc. of
$5 million for the 2014 third quarter.
For the first nine months of 2015, Dynegy Inc. reported
consolidated Adjusted EBITDA of $628 million, compared to $280
million for the first nine months of 2014. The $348 million
increase in Adjusted EBITDA resulted from the Company’s recent
acquisitions, higher spark spreads and tolling and market capacity
revenues in the Gas segment, and stronger capacity and retail
results in the Coal and IPH segments. Partially offsetting these
improvements were lower realized power prices on the unhedged power
sales in the Coal segment and the expiration of the capacity
contract at Independence. The operating income for the first nine
months of 2015 was $77 million compared to an operating loss of $31
million in the first nine months of 2014. The net income
attributable to Dynegy Inc. for the first nine months of 2015 was
$184 million, compared to a net loss attributable to Dynegy Inc. of
$169 million for the first nine months of 2014.
“Dynegy remains on track to meet the 2015 guidance range for
Adjusted EBITDA and Free Cash Flow in spite of the mild third
quarter summer temperatures, which adversely impacted the demand
for power and power prices across our operating regions,” said
Dynegy President and Chief Executive Officer Robert C. Flexon. “Our
recent acquisitions significantly contributed to our financial
performance during the quarter, and that, along with recent PRIDE
contributions to our balance sheet and liquidity management, has
allowed us to accelerate our stock repurchase program with
approximately 75% of our $250 million program already
completed.”
Third Quarter Comparative
Results
Quarter Ended September 30, 2015
(in millions) Coal IPH
Gas Other Total Operating
income (loss) $ (36 ) $ 31 $ 152 $ (40 ) 107 Plus / (Less):
Depreciation expense 39 8 126 1 174 Amortization expense (13 ) (5 )
13
-
(5 ) Losses from unconsolidated investments
-
-
(4 )
-
(4 ) Other items, net
-
-
-
46 46
EBITDA (1) (10 ) 34 287 7 318
Plus / (Less): Acquisition and integration costs
-
-
-
8 8 Mark-to-market adjustments (14 ) (3 ) (6 )
-
(23 ) Change in fair value of common stock warrants
-
-
-
(45 ) (45 ) Impairments and other charges 74
-
-
-
74 Cash distributions from unconsolidated investments
-
-
8
-
8 Other 4 3 2 1 10
Adjusted
EBITDA (1) $ 54 $ 34 $ 291 $ (29 ) $ 350
Quarter Ended September 30, 2014 (in
millions) Coal IPH Gas Other
Total Operating income (loss) $ (2 ) $ 19 $ 40 $ (35
) $ 22 Plus / (Less): Depreciation expense 14 10 36 1 61
Amortization expense (1 ) (13 ) 21
-
7 Other items, net
-
1
-
4 5
EBITDA (1) 11 17 97 (30 ) 95 Plus /
(Less): Acquisition and integration costs
-
-
-
9 9 Mark-to-market adjustments (12 ) (4 ) 5
-
(11 ) Change in fair value of common stock warrants
-
-
-
(6 ) (6 ) Gain on sale of assets, net
-
-
(3 )
-
(3 ) Other 2 2 (1 ) 3 6
Adjusted
EBITDA (1) $ 1 $ 15 $ 98 $ (24 ) $ 90
_________________________________________
(1)
EBITDA and Adjusted EBITDA are non-GAAP
financial measures and are used by management to evaluate Dynegy’s
business on an ongoing basis. Please refer to Item 2.02 of Dynegy’s
Form 8-K which is available on the Company’s website:
www.dynegy.com and filed on November 4, 2015, for definitions,
purposes and uses of such non-GAAP financial measures. A
reconciliation of EBITDA to Operating income (loss) is presented
above. General and administrative expenses are not allocated to
each segment and are included in the Other segment. Management does
not allocate interest expense and income taxes on a segment level
and therefore uses Operating income (loss) as the most directly
comparable GAAP measure.
Segment Review of Results
Quarter-over-Quarter
Coal - The 2015 third quarter operating loss was $36
million, compared to an operating loss of $2 million for the same
period in 2014. Adjusted EBITDA totaled $54 million during the 2015
third quarter compared to $1 million during the same period in
2014. The quarter-over-quarter increase in Adjusted EBITDA
primarily resulted from the positive impact of the Company’s recent
acquisitions, higher realized power prices, and improved wholesale
capacity revenues.
IPH - The 2015 third quarter operating income was $31
million, compared to an operating income of $19 million for the
same period in 2014. Adjusted EBITDA totaled $34 million during the
2015 third quarter compared to $15 million during the same period
in 2014. The quarter-over-quarter increase in Adjusted EBITDA
resulted from higher wholesale capacity revenues and retail gross
margin.
Gas - The 2015 third quarter operating income was $152
million, compared to an operating income of $40 million for the
same period in 2014. Adjusted EBITDA totaled $291 million during
the 2015 third quarter compared to $98 million during the same
period in 2014. The quarter-over-quarter increase in Adjusted
EBITDA is primarily due to the Company’s recent acquisitions,
higher hedged energy margin, and tolling and market capacity
revenues, partially offset by the expiration of the capacity
contract at Independence.
Liquidity
As of September 30, 2015, Dynegy’s total available
liquidity was $1.9 billion as reflected in the table below.
September 30, 2015 (amounts
in millions) Dynegy Inc.
IPH (1)(2)
Total Revolving Facilities and LC capacity (3) $
1,480 $ 25 $ 1,505 Less: Outstanding letters of credit (485 ) (20 )
(505 ) Revolving Facility and LC availability 995 5 1,000 Cash and
cash equivalents 789 145 934 Total available
liquidity (4) $ 1,784 $ 150 $ 1,934
__________________________________________
(1) Includes cash of $128 million related to
Genco. (2) Due to the ring-fenced nature of IPH, cash at the IPH
and Genco entities may not be moved out of these entities without
meeting certain criteria. However, cash at these entities is
available to support current operations of these entities. (3)
Includes: (i) $950 million of aggregate available capacity related
to our incremental revolving credit facilities, $475 million of
available capacity related to the five-year senior secured
revolving credit facility and $55 million related to a letter of
credit facility at Dynegy Inc. and (ii) $25 million related to the
two-year secured letter of credit facility at IPH. (4) On December
2, 2013, Dynegy and Illinois Power Resources, LLC entered into an
intercompany revolving promissory note of $25 million. At September
30, 2015, there was approximately $16 million outstanding on the
note, which is not reflected in the table above.
Consolidated Cash Flow
Cash provided by operations for the first nine months of 2015
was $302 million. During the period, our power generation business
provided cash of $655 million. Corporate and other activities used
cash of $357 million primarily due to interest payments on our
various debt agreements of $263 million and payments for
acquisition-related costs of $111 million. Partially offsetting
these costs was a $17 million cash inflow related to a receipt of
escrow funds from Ponderosa Pine Energy, LLC. In addition, changes
in working capital provided cash of approximately $4 million.
Cash used in investing activities during the first nine months
of 2015 was $1.099 billion. The Company paid $6.078 billion in
cash, net of cash acquired, in connection with the Company’s recent
acquisitions. In addition, there was a $5.148 billion cash inflow
related to the release of restricted cash from existing escrow
accounts for closing the acquisitions. The Company had $142 million
in maintenance capital expenditures, $20 million in environmental
capital expenditures, and $9 million in capitalized interest.
Cash used in financing activities during the first nine months
of 2015 was $139 million.
PRIDE (Producing Results through
Innovation by Dynegy Employees)
In 2013, Dynegy launched the PRIDE Reloaded program with a
three-year target (2014-2016) of $135 million in operating
improvements and $165 million in balance sheet efficiencies. Dynegy
is projected to achieve its three-year targets by the end of 2015 –
a full year ahead of schedule. Dynegy has identified, secured, or
realized $132 million of the $135 million EBITDA target, and has
achieved $230 million in balance sheet efficiencies, which is 39%
above the balance sheet efficiency goal.
Through the end of this year, Dynegy’s PRIDE program will have
produced more than $280 million in EBITDA improvements and
approximately $950 million in balance sheet benefits with minimal
investments since its inception in 2011.
On September 29, 2015, Dynegy announced “PRIDE Energized” - the
next iteration of the Company’s PRIDE program - targeted to deliver
an incremental $250 million in EBITDA and $400 million in balance
sheet improvements for Dynegy over the next three years
(2016-2018). The benefits of “PRIDE Energized” come in addition to
Dynegy’s previously announced $130 million in acquisition
synergies. The overall goal of the PRIDE program continues to be
improving operating performance, cost structure and balance sheet
efficiency to drive incremental cash flow benefits.
2015 and 2016 Guidance
Dynegy’s full-year 2015 Adjusted EBITDA and Free Cash Flow
guidance ranges are narrowed at $825 million to $925 million and
$140 million to $240 million, respectively.
Full-year 2016 Adjusted EBITDA guidance range is set at $1,100
million to $1,300 million and Free Cash Flow guidance of $300
million to $500 million.
Beginning in 2016, the company’s Free Cash Flow guidance will
exclude the upfront initial capital cost for newly required
environmental compliance capital expenditures and will instead
include only the recurring spend necessary to operate that
equipment over time. As such, $50 million in capital spend,
including $30 million for the Newton Power Station scrubber, has
been excluded from Dynegy’s 2016 Free Cash Flow guidance range, and
will instead be reported as part of its capital allocation program
similar to the company’s other capital investments.
Share Repurchase Program
On August 3, 2015, the company announced that its Board of
Directors had authorized a new $250 million share buyback program
to be completed during 2016. As of September 30, 2015, the Company
had repurchased 4,996,299 shares at an aggregate cost of $127
million. From October 1 - October 13, 2015, Dynegy repurchased an
additional 2,629,056 shares at an aggregate cost of $60
million.
Wood River Power Station
Retirement
Dynegy Inc. announced today plans to retire its 465 megawatt
Wood River Power Station in Alton, Illinois in mid-2016. The Wood
River Power Station includes two coal-fueled units that entered
commercial operation in 1954 and 1964, respectively.
The decision to retire the Wood River facility is attributable
to its uneconomic operation stemming from the poorly designed
wholesale capacity market that mixes out-of-state regulated
generators, that receive rate based compensation from their home
states to recover costs, with Central and Southern Illinois
competitive generators that rely on the capacity market for fair
compensation to recover costs.
Investor Conference
Call/Webcast
Dynegy’s earnings presentation and management comments on the
earnings presentation will be available on the “Investor Relations”
section of www.dynegy.com later today. Dynegy will answer questions
about its 2015 third quarter financial results during an investor
conference call and webcast tomorrow, November 5, 2015 at 9
a.m. ET/8 a.m. CT. Participants may access the webcast from the
Company’s website.
About Dynegy
We are committed to leadership in the electricity sector. With
nearly 26,000 megawatts of power generation capacity and two retail
electricity companies, Dynegy is capable of supplying 21 million
homes with safe, reliable and economic energy. Homefield Energy and
Dynegy Energy Services are retail electricity providers serving
businesses and residents in Illinois, Ohio, and Pennsylvania.
Forward Looking
Statements
This press release contains statements reflecting assumptions,
expectations, projections, intentions or beliefs about future
events that are intended as “forward-looking statements,”
particularly those statements concerning expectations regarding the
share repurchase program; anticipated acquisition synergies and
execution of its PRIDE Energized targets over the next three years;
anticipated earnings and cash flows and Dynegy’s full-year 2015 and
2016 Adjusted EBITDA and Free Cash Flow guidance. Historically,
Dynegy’s performance has deviated, in some cases materially, from
its cash flow and earnings guidance. Discussion of risks and
uncertainties that could cause actual results to differ materially
from current projections, forecasts, estimates and expectations of
Dynegy is contained in its filings with the Securities and Exchange
Commission (the “SEC”). Specifically, Dynegy makes reference to,
and incorporates herein by reference, the section entitled “Risk
Factors” in its 2014 Form 10-K and subsequent Form 10-Qs.
In addition to the risks and uncertainties set forth in Dynegy’s
SEC filings, the forward-looking statements described in this press
release could be affected by, among other things, (i) beliefs
and assumptions about weather and general economic
conditions;(ii) beliefs, assumptions and projections regarding
the demand for power, generation volumes and commodity pricing,
including natural gas prices and the timing of a recovery in power
market prices, if any; (iii) beliefs and assumptions about
market competition, generation capacity and regional supply and
demand characteristics of the wholesale and retail power markets,
including the anticipation of plant retirements and higher market
pricing over the longer term; (iv) sufficiency of, access to
and costs associated with coal, fuel oil and natural gas
inventories and transportation thereof; (v) the effects of, or
changes to, MISO, PJM, CAISO, NYISO or ISO-NE power and capacity
procurement processes; (vi) expectations regarding, or impacts
of, environmental matters, including costs of compliance,
availability and adequacy of emission credits and the impact of
ongoing proceedings and potential regulations or changes to current
regulations, including those relating to climate change, air
emissions, cooling water intake structures, coal combustion
byproducts and other laws and regulations that Dynegy is, or could
become, subject to, which could increase its costs, result in an
impairment of its assets, cause it to limit or terminate the
operation of certain of its facilities, or otherwise have a
negative financial effect; (vii) beliefs about the outcome of
legal, administrative, legislative and regulatory matters;
(viii) projected operating or financial results, including
anticipated cash flows from operations, revenues and profitability;
(ix) Dynegy’s focus on safety and its ability to efficiently
operate its assets so as to capture revenue generating
opportunities and operating margins; (x) Dynegy’s ability to
mitigate forced outage risk, including managing risk associated
with CP in PJM and new performance incentives in ISO-NE;
(xi) Dynegy’s ability to optimize its assets through targeted
investment in cost effective technology enhancements;
(xii) the effectiveness of Dynegy’s strategies to capture
opportunities presented by changes in commodity prices and to
manage its exposure to energy price volatility; (xiii) efforts
to secure retail sales and the ability to grow the retail business;
(xiv) efforts to identify opportunities to reduce congestion
and improve busbar power prices; (xv) ability to mitigate
impacts associated with expiring RMR and/or capacity contracts;
(xvi) expectations regarding Dynegy’s compliance with the
Credit Agreement, including collateral demands, interest expense,
any applicable financial ratios and other payments;
(xvii) expectations regarding performance standards and
capital and maintenance expenditures; (xviii) the timing and
anticipated benefits to be achieved through Dynegy’s company-wide
improvement programs, including its PRIDE initiative;
(xix) expectations regarding the synergies and anticipated
benefits of the Acquisitions; (xx) beliefs concerning Dynegy’s
capital allocation program, including the amount of shares, manner,
timing and funding of the share repurchase program; (xxi)
anticipated timing, outcomes and impacts of the expected
retirements of Brayton Point, Edwards Unit 1 and Wood River;
(xxii) beliefs about the costs and scope of the ongoing
demolition and site remediation efforts at the Vermilion facility
and any potential future remediation obligations at the South Bay
facility; and (xxiii) beliefs regarding redevelopment efforts
for the Morro Bay facility.
DYNEGY INC.
REPORTED UNAUDITED CONSOLIDATED
STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE
DATA)
Three Months EndedSeptember
30,
Nine Months EndedSeptember
30,
2015 2014 2015 2014 Revenues $
1,232 $ 615 $ 2,854 $ 1,898 Cost of sales, excluding depreciation
expense (621 ) (387 ) (1,494 ) (1,304 ) Gross margin 611 228 1,360
594 Operating and maintenance expense (219 ) (114 ) (580 ) (360 )
Depreciation expense (174 ) (61 ) (413 ) (185 ) Impairments and
other charges (74 )
-
(74 )
-
Gain (loss) on sale of assets, net
-
3 (1 ) 17 General and administrative expense (29 ) (25 ) (94 ) (80
) Acquisition and integration costs (8 ) (9 ) (121 ) (17 )
Operating income (loss) 107 22 77 (31 ) Earnings (losses) from
unconsolidated investments (4 )
-
(1 ) 10 Interest expense (145 ) (32 ) (413 ) (104 ) Other income
and expense, net 46 5 45 (40 ) Income (loss)
before income taxes 4 (5 ) (292 ) (165 ) Income tax benefit
(expense) (28 )
-
473 1 Net income (loss) (24 ) (5 ) 181 (164 )
Less: Net income (loss) attributable to noncontrolling interest
-
-
(3 ) 5 Net income (loss) attributable to Dynegy Inc.
(24 ) (5 ) 184 (169 ) Less: Dividends on preferred stock 5
-
16
-
Net income (loss) attributable to Dynegy
Inc. common stockholders
$ (29 ) $ (5 ) $ 168 $ (169 )
Earnings (Loss) Per
Share:
Basic earnings (loss) per share
attributable to Dynegy Inc. commonstockholders
$ (0.23 ) $ (0.05 ) $ 1.33 $ (1.69 )
Diluted earnings (loss) per share
attributable to Dynegy Inc. commonstockholders
$ (0.23 ) $ (0.05 ) $ 1.31 $ (1.69 ) Basic shares
outstanding 126 100 126 100 Diluted shares outstanding 126 100 140
100
__________________________________________
(1) The basic and diluted loss per share
from continuing operations attributable to Dynegy Inc. is presented
below:
Income (loss) from continuing operations $ (24 )
$ (5 ) $ 181 $ (164 ) Less: Net income (loss)
attributable to noncontrolling interest
-
-
(3 ) 5 Income (loss) from continuing operations
attributable to Dynegy Inc. (24 ) (5 ) 184 (169 ) Less: Dividends
on preferred stock 5
-
16
-
Income (loss) from continuing operations attributable to
Dynegy Inc. common stockholders for basic earnings (loss) per share
(29 ) (5 ) 168 (169 ) Add: Dividends on preferred stock 5
-
16
-
Adjusted income (loss) from continuing operations
attributable to Dynegy Inc. common stockholders for diluted
earnings (loss) per share $ (24 ) $ (5 ) $ 184 $ (169 )
Basic weighted-average shares 126 100 126 100 Effect of
dilutive securities (2)
-
-
14
-
Diluted weighted-average shares 126 100 140
100 Earnings (loss) per share from continuing
operations attributable to Dynegy Inc. common stockholders: Basic $
(0.23 ) $ (0.05 ) $ 1.33 $ (1.69 ) Diluted (2) $ (0.23 ) $ (0.05 )
$ 1.31 $ (1.69 )
_________________________________________
(2) Entities with a net loss from continuing
operations are prohibited from including potential common shares in
the computation of diluted per share amounts. Accordingly, we have
utilized the basic shares outstanding amount to calculate both
basic and diluted loss per share for the three months ended
September 30, 2015 and the three and nine months ended September
30, 2014.
DYNEGY INC.REPORTED SEGMENTED
RESULTS OF OPERATIONSTHREE MONTHS ENDED SEPTEMBER 30,
2015(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
threemonths ended September 30, 2015:
Three Months Ended September 30,
2015 Coal IPH Gas
Other Total Net loss attributable to Dynegy
Inc. $ (24 ) Plus / (Less): Income tax expense 28 Interest
expense 145 Depreciation expense 174 Amortization expense (5 )
EBITDA (1) $ (10 ) $ 34 $ 287 $ 7 $ 318 Acquisition and
integration costs
-
-
-
8 8 Mark-to-market adjustments (14 ) (3 ) (6 )
-
(23 ) Change in fair value of common stock warrants
-
-
-
(45 ) (45 ) Impairments and other charges 74
-
-
-
74 Cash distributions from unconsolidated investments
-
-
8
-
8 Other 4 3 2 1 10
Adjusted
EBITDA (1) $ 54 $ 34 $ 291 $ (29 ) $ 350
__________________________________________
(1) EBITDA and Adjusted EBITDA are non-GAAP
financial measures. Please refer to Item 2.02 of our Form 8-K filed
on November 4, 2015, for definitions, utility and uses of such
non-GAAP financial measures. A reconciliation of EBITDA to
Operating income (loss) is presented below. Management does not
allocate interest expense and income taxes on a segment level and
therefore uses Operating income (loss) as the most directly
comparable GAAP measure.
Three
Months Ended September 30, 2015 Coal IPH
Gas Other Total
Operating income (loss) $ (36 ) $ 31 $ 152 $ (40 ) $ 107
Depreciation expense 39 8 126 1 174 Amortization expense (13 ) (5 )
13
-
(5 ) Losses from unconsolidated investments
-
-
(4 )
-
(4 ) Other items, net
-
-
-
46 46
EBITDA $ (10 ) $ 34 $ 287
$ 7 $ 318
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
THREE MONTHS ENDED SEPTEMBER 30,
2014
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
threemonths ended September 30, 2014:
Three Months Ended September 30,
2014 Coal IPH Gas
Other Total Net loss attributable to Dynegy
Inc. $ (5 ) Plus / (Less): Interest expense 32 Depreciation
expense 61 Amortization expense 7
EBITDA (1) $ 11 $
17 $ 97 $ (30 ) $ 95 Plus / (Less): Acquisition and integration
costs
-
-
-
9 9 Mark-to-market adjustments (12 ) (4 ) 5
-
(11 ) Change in fair value of common stock warrants
-
-
-
(6 ) (6 ) Gain on sale of assets, net
-
-
(3 )
-
(3 ) Other 2 2 (1 ) 3 6
Adjusted
EBITDA (1) $ 1 $ 15 $ 98 $ (24 ) $ 90
__________________________________________
(1) EBITDA and Adjusted EBITDA are non-GAAP
financial measures. Please refer to Item 2.02 of our Form 8-K filed
on November 4, 2015, for definitions, utility and uses of such
non-GAAP financial measures. A reconciliation of EBITDA to
Operating income (loss) is presented below. Management does not
allocate interest expense and income taxes on a segment level and
therefore uses Operating income (loss) as the most directly
comparable GAAP measure.
Three Months Ended September 30, 2014 Coal
IPH Gas Other
Total Operating income (loss) $ (2 ) $ 19 $ 40 $ (35
) $ 22 Depreciation expense 14 10 36 1 61 Amortization expense (1 )
(13 ) 21
-
7 Other items, net
-
1
-
4 5
EBITDA $ 11 $ 17 $ 97
$ (30 ) $ 95
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30,
2015
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
nine monthsended September 30, 2015:
Nine Months Ended September 30,
2015 Coal IPH Gas
Other Total Net income attributable to
Dynegy Inc. $ 184 Plus / (Less): Loss attributable to
noncontrolling interest (3 ) Income tax benefit (473 ) Interest
expense 413 Depreciation expense 413 Amortization expense (14 )
EBITDA (1) $ 38 $ 57 $ 595 $ (170 ) $ 520 Acquisition and
integration costs
-
-
-
121 121 Loss attributable to noncontrolling interest
-
3
-
-
3 Mark-to-market adjustments (35 ) (8 ) (29 )
-
(72 ) Change in fair value of common stock warrants
-
-
-
(43 ) (43 ) Impairments and other charges 74
-
-
-
74 Loss on sale of assets, net
-
-
1
-
1 Cash distributions from unconsolidated investments
-
-
8
-
8 Other 6 9
-
1 16
Adjusted EBITDA (1) $ 83 $
61 $ 575 $ (91 ) $ 628
__________________________________________
(1) EBITDA and Adjusted EBITDA are non-GAAP
financial measures. Please refer to Item 2.02 of our Form 8-K filed
on November 4, 2015, for definitions, utility and uses of such
non-GAAP financial measures. A reconciliation of EBITDA to
Operating income (loss) is presented below. Management does not
allocate interest expense and income taxes on a segment level and
therefore uses Operating income (loss) as the most directly
comparable GAAP measure.
Nine
Months Ended September 30, 2015 Coal IPH
Gas Other Total
Operating income (loss) $ (34 ) $ 39 $ 290 $ (218 ) $ 77
Depreciation expense 96 24 290 3 413 Amortization expense (24 ) (6
) 16
-
(14 ) Loss from unconsolidated investments
-
-
(1 )
-
(1 ) Other items, net
-
-
-
45 45
EBITDA $ 38 $ 57 $
595 $ (170 ) $ 520
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
NINE MONTHS ENDED SEPTEMBER 30,
2014
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
nine monthsended September 30, 2014:
Nine Months Ended September 30,
2014 Coal IPH Gas
Other Total Net loss attributable to Dynegy
Inc. $ (169 ) Plus / (Less): Income attributable to
noncontrolling interest 5 Income tax benefit (1 ) Interest expense
104 Depreciation expense 185 Amortization expense 42
EBITDA (1) $ 37 $ 4 $ 254 $ (129 ) $ 166 Plus / (Less):
Acquisition and integration costs
-
8
-
9 17 Income attributable to noncontrolling interest
-
(5 )
-
-
(5 ) Mark-to-market adjustments 7 34 23
-
64 Change in fair value of common stock warrants
-
-
-
43 43 Gain on sale of assets, net
-
-
(17 )
-
(17 ) Other 7 4
-
1 12
Adjusted EBITDA (1) $ 51 $
45 $ 260 $ (76 ) $ 280
__________________________________________
(1) EBITDA and Adjusted EBITDA are non-GAAP
financial measures. Please refer to Item 2.02 of our Form 8-K filed
on November 4, 2015, for definitions, utility and uses of such
non-GAAP financial measures. A reconciliation of EBITDA to
Operating income (loss) is presented below. Management does not
allocate interest expense and income taxes on a segment level and
therefore uses Operating income (loss) as the most directly
comparable GAAP measure.
Nine
Months Ended September 30, 2014 Coal IPH
Gas Other Total
Operating income (loss) $ 2 $ (14 ) $ 72 $ (91 ) $ (31 )
Depreciation expense 39 28 115 3 185 Amortization expense (4 ) (11
) 57
-
42 Earnings from unconsolidated investments
-
-
10
-
10 Other items, net
-
1
-
(41 ) (40 )
EBITDA $ 37 $ 4 $ 254
$ (129 ) $ 166
DYNEGY INC.
OPERATING DATA
The following table provides summary
financial data regarding our Coal, IPH and Gas segment results of
operationsfor the three and nine months ended September 30, 2015
and 2014, respectively.
Three Months Ended September
30,
Nine Months Ended September
30,
2015 2014 2015
2014 Coal Million Megawatt Hours Generated (9) 9.4
4.5 21.7 14.4 IMA for Coal-Fired Facilities (1) (9) 82 % 81 % 80 %
88 % Average Capacity Factor for Coal-Fired Facilities (2) (9) 62 %
69 % 59 % 74 % Average Quoted Market On-Peak Power Prices ($/MWh)
(3): Indiana (Indy Hub) $ 33.09 $ 37.90 $ 35.17 $ 51.53
Commonwealth Edison (NI Hub) $ 34.03 $ 37.58 $ 35.44 $ 54.95 Mass
Hub $ 35.52 $ 42.01 $ 53.62 $ 86.50 AD Hub $ 35.87 $ 39.02 $ 39.86
$ 59.29 Average Quoted Market Off-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub) $ 23.37 $ 27.57 $ 25.41 $ 33.68 Commonwealth
Edison (NI Hub) $ 22.93 $ 25.40 $ 23.49 $ 32.23 Mass Hub $ 21.02 $
27.01 $ 38.90 $ 61.25 AD Hub $ 24.21 $ 27.91 $ 27.20 $ 36.38
IPH Million Megawatt Hours Generated 4.8 6.4 14.7 17.8 IMA
for IPH Facilities (4) 84 % 93 % 89 % 89 % Average Capacity Factor
for IPH Facilities (5) 54 % 74 % 55 % 69 % Average Quoted Market
Power Prices ($/MWh) (3): On-Peak: Indiana (Indy Hub) $ 33.09 $
37.90 $ 35.17 $ 51.53 Off-Peak: Indiana (Indy Hub) $ 23.37 $ 27.57
$ 25.41 $ 33.68
Gas Million Megawatt Hours Generated
(6) (9) 15.4 4.8 33.2 13.0 IMA for Combined Cycle Facilities (4)
(9) 99 % 99 % 98 % 99 % Average Capacity Factor for Combined Cycle
Facilities (5) (9) 72 % 51 % 63 % 46 % Average Market On-Peak Spark
Spreads ($/MWh) (7): Commonwealth Edison (NI Hub) $ 14.49 $ 9.65 $
14.91 $ 12.05 PJM West $ 29.82 $ 26.30 $ 25.58 $ 27.99 North of
Path 15 (NP 15) $ 16.25 $ 19.40 $ 14.63 $ 17.23
New York--Zone A
$ 26.32 $ 24.58 $ 29.49 $ 39.18 Mass Hub $ 18.90 $ 21.22 $ 15.77 $
22.30 AD Hub $ 27.28 $ 23.17 $ 28.88 $ 34.41 Average Market
Off-Peak Spark Spreads ($/MWh) (7): Commonwealth Edison (NI Hub) $
3.39 $ (2.53 ) $ 2.97 $ (10.67 ) PJM West $ 15.50 $ 12.48 $ 10.71 $
2.68 North of Path 15 (NP 15) $ 8.22 $ 8.55 $ 7.75 $ 7.07
New York--Zone A
$ 10.49 $ 9.26 $ 14.12 $ 15.86 Mass Hub $ 4.39 $ 6.22 $ 1.05 $
(2.95 ) AD Hub $ 15.62 $ 12.07 $ 16.22 $ 11.50
Average natural gas price--Henry Hub
($/MMBtu) (8)
$ 2.74 $ 3.94 $ 2.78 $ 4.52 (1) IMA is an
internal measurement calculation that reflects the percentage of
generation available during periods when market prices are such
that these units could be profitably dispatched. This calculation
excludes certain events outside of management control such as
weather related issues. The calculations for the three and nine
months ended September 30, 2015 exclude our Brayton Point facility
and CTs. For the three months ended September 30, 2015, the IMA for
our facilities within MISO and PJM (excluding CTs) were 91 percent
and 77 percent, respectively. For the nine months ended September
30, 2015, the IMA for our facilities within MISO and PJM (excluding
CTs) were 87 percent and 73 percent, respectively. (2) Reflects
actual production as a percentage of available capacity. The
calculations for the three and nine months ended September 30, 2015
exclude our Brayton Point facility and CTs. For the three months
ended September 30, 2015, the average capacity factors for our
facilities within MISO and PJM (excluding CTs) were 68 percent and
57 percent, respectively. For the nine months ended September 30,
2015, the average capacity factors for our facilities within MISO
and PJM (excluding CTs) were 66 percent and 51 percent,
respectively. (3) Reflects the average of day-ahead quoted prices
for the periods presented and does not necessarily reflect prices
we realized. (4) IMA is an internal measurement calculation that
reflects the percentage of generation available during periods when
market prices are such that these units could be profitably
dispatched. This calculation excludes certain events outside of
management control such as weather related issues. (5) Reflects
actual production as a percentage of available capacity. (6) The
three and nine months ended September 30, 2014 includes our
ownership percentage in the MWh generated by our investment in the
Black Mountain power generation facility which was sold on June 27,
2014. (7) Reflects the simple average of the on- and off-peak spark
spreads available to a 7.0 MMBtu/MWh heat rate generator selling
power at day-ahead prices and buying delivered natural gas at a
daily cash market price and does not reflect spark spreads
available to us. (8) Reflects the average of daily quoted prices
for the periods presented and does not reflect costs incurred by
us. (9) Reflects the activity for the period in which the
Acquisitions were included in our consolidated results.
DYNEGY INC.
REVISED 2015 ADJUSTED EBITDA AND FREE
CASH FLOW GUIDANCE
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our revised 2015 Adjusted EBITDA guidance,
updated based onOctober 19, 2015 forward curves, as presented on
November 4, 2015:
Dynegy Consolidated Low
High Net income attributable to Dynegy Inc. (3)
$ 41 $ 111 Plus / (Less): Income tax
benefit (2) (473 ) (473 ) Other items, net (4) (4 ) (4 ) Interest
expense 537 537
Operating Income
101 171 Depreciation expense 580 600 Amortization
expense (5 ) (5 ) Other items, net 1 1
EBITDA (1) 677 767 Plus / (Less): Transaction
fees and expenses 85 90 Integration costs 35 40 Other (5) 28
28
Adjusted EBITDA (1) $
825 $ 925
(1) EBITDA, Adjusted EBITDA and Free Cash Flow are non-GAAP
measures. (2) Represents actual amounts for the nine months ended
September 30, 2015. (3) For purposes of Net income attributable to
Dynegy Inc. guidance reconciliation, mark-to-market adjustments and
changes in the fair value of common stock warrants are assumed to
be zero. (4) Represents actual amounts for the nine months ended
September 30, 2015. Other items, net primarily consists of the loss
attributable to noncontrolling interest and losses from
unconsolidated investments. (5) Represents actual amounts for the
nine months ended September 30, 2015. Other consists primarily of
adjustments for losses attributable to noncontrolling interest,
cash distributions from unconsolidated investments and asset
retirement obligation accretion.
The following table provides summary
financial data regarding our revised 2015 Free Cash Flow
guidance:
Dynegy Consolidated Low
High Adjusted EBITDA (1) $ 825
$ 925 Cash interest payments (517 ) (517 )
Transaction fees and expenses (2) (110 ) (115 ) Integration costs
(35 ) (40 ) Other non-cash and working capital items (5 )
(5 )
Cash Flow from Operations 158 248
Maintenance capital expenditures (225 ) (225 ) Environmental
capital expenditures (30 ) (30 ) Transaction fees and expenses (2)
110 115 Integration costs 35 40 Acquisition interest (3) 92
92
Free Cash Flow $ 140
$ 240 (1) EBITDA,
Adjusted EBITDA and Free Cash Flow are non-GAAP measures. (2)
Consists of nonrecurring transaction costs including a commitment
fee on the Bridge Loan Facilities, legal and advisory fees related
to the acquisitions, a fee for executing the $950M million Revolver
and syndication fees associated with the issuance of the $5.1
billion Notes and Common Stock and Mandatory Convertible Preferred
Stock Offerings. (3) Reflects $92 million of interest on $5.1
billion Notes for the period prior to the close of the acquisitions
(January-March).
DYNEGY INC.
2016 ADJUSTED EBITDA AND FREE CASH FLOW
GUIDANCE
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our 2016 Adjusted EBITDA guidance, based
on October 19, 2015forward curves, as presented on November 4,
2015:
Dynegy Consolidated Low
High Net income (loss) attributable to Dynegy Inc.
(3) $ (152 ) $ 23 Plus /
(Less): Interest expense 542 542
Operating Income 390 565 Depreciation expense
680 700 Amortization expense 30 30
EBITDA (1) 1,100 1,295 Plus / (Less):
Integration costs
-
5
Adjusted EBITDA (1) $
1,100 $ 1,300
(1) EBITDA, Adjusted EBITDA and Free Cash
Flow are non-GAAP measures.
The following table provides summary
financial data regarding our 2016 Free Cash Flow guidance:
Dynegy Consolidated Low High
Adjusted EBITDA (1) $ 1,100 $
1,300 Cash interest payments (515 ) (515 ) Integration costs
-
(5 ) Other non-cash and working capital items
35
35
Cash Flow from Operations
620
815
Maintenance capital expenditures (300 ) (300 ) Environmental
capital expenditures
(20
)
(20
) Integration costs
-
5
Free Cash Flow $ 300
$ 500
(1) EBITDA, Adjusted EBITDA and Free Cash
Flow are non-GAAP measures.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20151104006849/en/
Dynegy Inc.Media: Micah Hirschfield, 713-767-5800orAnalysts:
713-507-6466
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