Dynegy Inc. (NYSE: DYN):
Summary of Second Quarter 2016 Financial Results (in
Millions):
Three Months Ended June
30 Six Months Ended June 30 2016 2015
2016 2015 Operating Revenues $ 904 $ 990 $ 2,027 $
1,622 Net income (loss) $ (801 ) $ 388 $ (811 ) $ 208 Adjusted
EBITDA $ 187 $ 193 $ 438 $ 278
2016 Full-Year Guidance:
- Adjusted EBITDA guidance range updated
to $1,000-1,100 million and Free Cash Flow guidance updated to
$200-300 million
ENGIE Acquisition Update:
- Issued $2 billion term loan and $460
million in tangible equity units to substantially complete
acquisition financing
- Acquired Energy Capital Partners’ (ECP)
35% interest in the Atlas joint venture, which was originally
formed to purchase ENGIE’s U.S. fossil portfolio
- The Public Utility Commission of Texas
(PUCT) approved Dynegy’s acquisition of ENGIE’s Texas fossil assets
on July 20; the Federal Energy Regulatory Commission (FERC) is the
last remaining regulatory approval
Recent Developments:
- Dynegy to sell its 50% equity interest
in Elwood Energy LLC to J-Power USA Development Co. Ltd. for $172.5
million; approximately $35 million previously posted collateral to
be returned
- Completed 197 MW of advanced gas path
(AGP) uprates at five plants, exceeding target of 179 MW
- 500 MW incremental MISO capacity from
Hennepin and Joppa to be pseudo tied to PJM beginning June 1,
2017
Dynegy Inc. (NYSE: DYN) reported a net loss for the 2016 second
quarter of $801 million, compared to net income of $388 million for
the 2015 second quarter. The quarter-over-quarter decrease is
primarily due to a $480 million deferred tax valuation allowance
reversal in the second quarter 2015, which did not reoccur in 2016,
and a $645 million asset impairment in the second quarter of 2016
primarily related to previously disclosed asset shutdowns.
The Company reported consolidated Adjusted EBITDA of $187
million, compared to $193 million for the 2015 second quarter. The
$6 million decrease in Adjusted EBITDA was primarily driven by a
net increase in operating and maintenance costs in the Gas Segment
as a result of a concentration of major planned outages during the
quarter partially offset by lower operating and maintenance costs
at the Coal and IPH segments due to fewer planned outages.
The net loss for the first half of 2016 was $811 million,
compared to net income of $208 million for the first half of 2015.
The year-to-date decrease was primarily driven by the second
quarter 2015 valuation allowance reversal and second quarter 2016
asset impairment noted above.
For the first half of 2016, the Company reported consolidated
Adjusted EBITDA of $438 million, compared to $278 million for the
first half of 2015. The $160 million increase in Adjusted EBITDA
was primarily driven by assets the Company acquired during the
second quarter of 2015 and higher capacity revenues in all
segments. Partially offsetting these improvements were lower
realized power prices and lower generation volumes at the Coal and
IPH segments as well as lower spark spreads and generation volumes
at the Gas segment, resulting from mild winter weather. Higher
operating and maintenance costs associated with planned outages in
the Gas segment also impacted results.
“During the quarter we continued the transformation of our
portfolio. Through our disciplined approach, we completed efficient
uprates, made steady progress on the ENGIE acquisition and arranged
for the sale of the Elwood Energy Facility. In addition, we
announced the retirement of 1,835 MW of generation, and the
movement of 500 MW from MISO to PJM,” said Dynegy President and
Chief Executive Officer Robert C. Flexon. “The desired outcome from
all of these efforts, as well as our ongoing PRIDE improvement
program, is a well-constructed portfolio composed of the right
assets in the right markets supported by the right balance sheet
that generates a strong return for our shareholders.”
Second Quarter Comparative
Results
Quarter Ended June 30, 2016 (in millions) Coal
IPH Gas
Other Total Net loss attributable to
Dynegy Inc. $ (801 ) Plus / (Less): Loss attributable to
noncontrolling interest (2 ) Income tax benefit (9 ) Other income
and expense, net (30 ) Interest expense 141 Earnings from
unconsolidated investments (1 )
Operating income (loss) $
(749 ) $ 3 $ 90 $ (46 ) $ (702 ) Plus / (Less): Depreciation and
amortization expense 27 3 132 2 164 Earnings from unconsolidated
investments
-
-
1
-
1 Other income and expense, net 6 14 12 (2 )
30
EBITDA (1) (716 ) 20 235 (46 ) (507 ) Plus /
(Less): Adjustments to reflect Adjusted EBITDA from unconsolidated
investments and exclude noncontrolling interest
-
2 1
-
3 Acquisition and integration costs
-
(8 )
-
5 (3 ) Mark-to-market adjustments, including warrants 83 (2 ) (52 )
-
29 Impairments 645
-
-
-
645 Wood River energy margin and O&M 15
-
-
-
15 Non-cash compensation expense
-
-
-
5 5 Other (1 ) (1 )
-
2
-
Adjusted EBITDA (1) $ 26 $ 11 $ 184
$ (34 ) $ 187
Quarter Ended June 30,
2015 (in millions) Coal IPH
Gas Other
Total Net income attributable to Dynegy Inc. $
388 Plus / (Less): Loss attributable to noncontrolling interest (2
) Income tax benefit (501 ) Other income and expense, net (4 )
Interest expense 132 Earnings from unconsolidated investments (3 )
Operating income (loss) $ (5 ) $ (14 ) $ 86 $ (57 ) $ 10
Plus / (Less): Depreciation and amortization expense 38 11 124 1
174 Earnings from unconsolidated investments
-
-
3
-
3 Other income and expense, net
-
-
-
4 4
EBITDA (1) 33 (3 ) 213 (52 ) 191
Plus / (Less): Adjustments to reflect Adjusted EBITDA from
unconsolidated investments and exclude noncontrolling interest
-
2
-
-
2 Acquisition and integration costs
-
-
-
23 23 Mark-to-market adjustments, including warrants (14 ) 6 (10 )
(3 ) (21 ) Other
-
-
(1 ) (1 ) (2 )
Adjusted EBITDA (1)(2) $ 19 $ 5
$ 202 $ (33 ) $ 193 (1)
EBITDA and Adjusted EBITDA are non-GAAP
financial measures and are used by management to evaluate Dynegy’s
business on an ongoing basis. Please refer to Item 2.02 of Dynegy’s
Form 8-K which is available on the Company’s website:
www.dynegy.com and filed on August 3, 2016, for definitions,
purposes and uses of such non-GAAP financial measures. 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.
(2) Not adjusted for these items which are excluded in 2016:
(i) non-cash compensation expense of $8 million, and (ii) Wood
River’s energy margin and O&M costs of $9 million.
Segment Review of Results Quarter-over-Quarter
Gas - The 2016 second quarter operating income was $90
million, compared to $86 million for the same period in 2015.
Adjusted EBITDA totaled $184 million during the 2016 second quarter
compared to $202 million during the same period in 2015. The
quarter-over-quarter decrease in Adjusted EBITDA was driven by
higher operating and maintenance costs associated with planned
major outages. The Company utilized these planned outages to
install capacity uprates. These expenses, together with lower
energy margin, were partially offset by higher capacity
revenues.
Coal - The 2016 second quarter operating loss was $749
million, compared to $5 million for the same period in 2015.
Adjusted EBITDA totaled $26 million during the 2016 second quarter
compared to $19 million during the same period in 2015. The
quarter-over-quarter increase in Adjusted EBITDA primarily resulted
from lower operating and maintenance expense due to fewer planned
outages. Lower energy margin driven by weaker power prices during
the quarter was offset by higher capacity revenues and higher
retail margins.
IPH - The 2016 second quarter operating income was $3
million, compared to an operating loss of $14 million for the same
period in 2015. Adjusted EBITDA totaled $11 million during the 2016
second quarter compared to $5 million during the same period in
2015. The quarter-over-quarter increase in Adjusted EBITDA was
primarily due to lower operating and maintenance expense due to
fewer planned outages. An increase in capacity revenues during the
period offset lower energy margin resulting from lower power prices
and generation.
Liquidity
As of June 30, 2016, Dynegy’s total available liquidity was
$2.2 billion as reflected in the table below, and excludes amounts
classified as restricted cash in our unaudited consolidated balance
sheet.
June 30, 2016
(amounts in millions) Dynegy Inc.
IPH (1) (2)
Total Revolving facilities and LC capacity (3) $ 1,480 $ 39
$ 1,519 Less: Outstanding LCs (387 ) (27 ) (414 ) Revolving
facilities and LC availability 1,093 12 1,105 Cash and cash
equivalents 1,066 76 1,142 Total available
liquidity (4) $ 2,159 $ 88 $ 2,247
(1) Includes cash and cash equivalents of $42 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 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 facility. IPH includes (i) up
to a maximum of $25 million related to the two-year secured letter
of credit facility and (ii) $14 million related to our fully
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 June 30, 2016, there was approximately $25 million
outstanding on the note, which is not reflected in the table above.
Consolidated Cash Flow
Cash provided by operations for the first half of 2016 was $317
million. During the period, our power generation facilities and
retail operations provided cash of $462 million. Corporate and
other activities used cash of $250 million primarily for interest
payments on various debt agreements. Changes in working capital and
other, net of general and administrative expenses, provided cash of
$105 million during the period.
Cash used in investing activities during the first half of 2016
was $2.278 billion. During the first half of 2016, non-current
restricted cash increased by $2.0 billion from proceeds from the
Tranche C Term Loan being held in escrow for the ENGIE acquisition
and $69 million in related pre-funded interest and original
issuance discount. Additionally, the Company paid $206 million in
maintenance capital expenditures, $11 million in environmental
capital expenditures and $7 million in capitalized interest. These
decreases were partially offset by receipt of an $8 million cash
inflow related to distributions from our unconsolidated investment
and receipt of $7 million in proceeds from an insurance claim.
Cash provided by financing activities during the first half of
2016 was $2.598 billion. During the period, the Company received
(i) $2.0 billion in proceeds related to the Tranche C Term Loan,
(ii) $446 million in net proceeds from our tangible equity units,
and (iii) $198 million of proceeds related to our forward capacity
agreement, partially offset by $20 million in repayments associated
with our equipment financing agreements and Tranche B-2 Term Loan,
$11 million in dividend payments on our mandatory convertible
preferred stock, and $9 million in interest rate swap settlement
payments.
ENGIE Acquisition
During the second quarter, Dynegy acquired Energy Capital
Partners’ (ECP) 35% interest in the Atlas joint venture, which the
two companies formed in February 2016 to purchase ENGIE’s U.S.
fossil portfolio. In accordance with the agreement with ECP, Dynegy
will pay ECP $375 million on the later of December 31, 2016 or
three months after the closing of the transaction. Alternatively,
Dynegy may pay the ECP buyout price after the first payment date,
but in such case, the ECP buyout price would be subject to
quarterly escalation up to a maximum of $468.5 million.
After reaching an agreement with ECP to acquire their interest
in the Atlas joint venture, Dynegy substantially completed the
transaction financing by raising a new $2 billion, seven-year,
secured term loan and $460 million in tangible equity units. A
total of $125 million in incremental liquidity facilities will also
be available upon the completion of the acquisition. The Company
will use the net proceeds from the financing, together with the
proceeds of ECP’s purchase of $150 million of the Company’s common
stock to occur concurrently with the closing of the acquisition and
existing liquidity, to fund the acquisition and pay related fees
and expenses.
On July 20, 2016, Dynegy received final approval for the
acquisition from the PUCT and remains on schedule to complete the
acquisition of ENGIE’s U.S. fossil portfolio in the fourth quarter
of 2016 pending the approval of FERC.
Elwood Energy Facility Divestiture
Dynegy announced today that it has signed a definitive agreement
to sell its 50% equity interest in the Elwood Energy Facility in
Elwood, IL to its partner, J-Power USA Development Co. Ltd. for
$172.5 million in cash. At closing, approximately $35 million in
previously posted collateral will be returned to Dynegy, and the
non-recourse asset level financing currently in place will remain
with the new owner. The Company intends to use the proceeds of the
sale, which is expected to close in the fourth quarter, to satisfy
a portion of its buyout obligation to ECP. JP Morgan serves as
financial advisor and Skadden, Arps serves as legal counsel on the
transaction.
MISO Pathway to PJM
In late May, Dynegy filed the Illinois Generation Reliability
Act to make Illinois a 100% PJM market instead of its current split
between two markets, PJM and MISO. The legislation is consistent
with Dynegy’s overall objective of moving all of the Company’s
Illinois generating assets to PJM.
Outside of this process, the Company received approval for 500
MW of incremental MISO capacity from Hennepin and Joppa to be
pseudo tied to PJM beginning June 1, 2017. Dynegy will
continue to explore similar paths for its remaining plants in MISO
while we wait for a ruling on the proposed legislation.
Illinois Unit Shutdowns
On May 3, 2016, Dynegy announced plans to shut down units one
and three at the Baldwin Power Station in Baldwin, IL and unit two
at the Newton Power Station in Newton, IL after they failed to
clear the recent MISO capacity auction. MISO has approved the
shutdown of Newton unit two by September 15, 2016 and the shutdown
of Baldwin unit one by October 17, 2016. The Company plans to file
the shutdown notice for Baldwin unit three in the third quarter.
Dynegy’s Wood River Power Station retired on June 1, 2016.
Uprates
During the 2016 second quarter, Dynegy completed nearly 200 MW
of AGP uprates at five plants as part of the plans the Company
announced at its investor day in June 2015.
Facility Amount of Uprate Market
Total Plant MW post-uprate Ontelaunee 40 MW PJM 640
Fayette 44 MW PJM 726 Washington 47 MW PJM 711 Independence 30 MW
NYISO 1,156 Kendall 36 MW PJM 1,288
The uprates at the Company’s legacy plants are part of Pride
Energized. The balance of the uprates was included in the Duke and
ECP acquisition synergies.
2016 Guidance
Dynegy’s full-year Adjusted EBITDA guidance range has been
updated to $1,000-1,100 million from $1,000 million to $1,200
million previously and Free Cash Flow guidance updated to $200-300
million from $200 million to $400 million previously.
PRIDE Energized
PRIDE Energized, the Company’s Producing Results through
Innovation by Dynegy Employees program, aims to deliver an
incremental $250 million in EBITDA and $400 million in balance
sheet improvements by the end of 2018. The Company is on target to
achieve the $135 million in Adjusted EBITDA and exceed the $200
million in balance sheet improvements it committed to for this
year.
New Brand Represents Dynegy’s Growth and
Transformation
Dynegy unveiled a new brand yesterday in recognition of how far
the Company has come and where it is headed. The brand, which
features a bird on a soaring trajectory under a boundless sky, is
also a D monogram that represents the Company’s strength and
reliability you can count on when needed.
“This brand change is a mile marker on Dynegy’s transformative
journey. We have rebuilt and enhanced our asset base in just the
past few years adding the Ameren, Duke and EquiPower asset
portfolios, and with the expected acquisition of the ENGIE assets,”
added Flexon. “Dynegy is a much different company today - a Company
that is moving forward and upward and one that believes
transparency and reliability are at the heart of our dynamic energy
company.”
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 2016 second quarter financial results during an investor
conference call and webcast tomorrow, August 4, 2016 at 9 a.m.
ET/8 a.m. CT. Participants may access the webcast from the
Company’s website. If you have trouble viewing the new website,
please be sure to clear your cache (CTRL-F5 on Windows
computers).
About Dynegy
At Dynegy, we generate more than just power for our customers.
We are committed to being a leader in the electricity sector.
Throughout the Midwest and Northeast, Dynegy operates power
generating facilities capable of producing nearly 26,000 megawatts
of electricity—or enough energy to power the homes of 21 million
U.S. families. We’re proud of what we do, but it’s about much more
than just output. We’re always striving to generate power safely
and responsibly for our wholesale and retail electricity customers
who depend on that energy to grow and thrive.
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 Dynegy’s: ability to
obtain FERC approval and to close the ENGIE acquisition in the
fourth quarter; sale, use of proceeds and timing of closing of
Dynegy’s ownership interest in its Elwood Energy Facility;
expectations of the proposed Illinois Generation Reliability Act;
the shutdown of certain Illinois coal-fueled units; 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 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) Dynegy’s expectations and beliefs related to the ENGIE
acquisition and satisfying closing conditions, including obtaining
FERC approval; (ii) Dynegy’s ability to successfully sell its
ownership interest in its Elwood Energy Facility; (iii) Dynegy’s
anticipated benefits associated with the proposed legislation
(iv) beliefs and assumptions about weather and general
economic conditions; (v) 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; (vi) 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; (vii) sufficiency of,
access to, and costs associated with coal, fuel oil, and natural
gas inventories and transportation thereof; (viii) the effects
of, or changes to, MISO, PJM, CAISO, NYISO, or ISO-NE power and
capacity procurement processes; (ix) 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; (x) beliefs about the outcome of
legal, administrative, legislative, and regulatory matters;
(xi) projected operating or financial results, including
anticipated cash flows from operations, revenues, and
profitability; (xii) our focus on safety and our ability to
efficiently operate our assets so as to capture revenue generating
opportunities and operating margins; (xiii) our ability to
mitigate forced outage risk, including managing risk associated
with CP in PJM and performance incentives in ISO-NE; (xiv) our
ability to optimize our assets through targeted investment in cost
effective technology enhancements; (xv) the effectiveness of
our strategies to capture opportunities presented by changes in
commodity prices and to manage our exposure to energy price
volatility; (xvi) efforts to secure retail sales and the
ability to grow the retail business; (xvii) efforts to
identify opportunities to reduce congestion and improve busbar
power prices; (xviii) ability to mitigate impacts associated
with expiring RMR and/or capacity contracts;
(xix) expectations regarding our compliance with the Credit
Agreement, including collateral demands, interest expense, any
applicable financial ratios, and other payments;
(xx) expectations regarding performance standards and capital
and maintenance expenditures; (xxi) beliefs concerning the
strategic review of Genco, including any restructuring options;
(xxii) the timing and anticipated benefits to be achieved
through our companywide improvement programs, including our PRIDE
initiative; (xxiii) anticipated timing, outcome, and impact of
the expected retirement of Brayton Point and the shutdown of
Baldwin Units 1 and 3 and Newton Unit 2; (xxiv) beliefs about
the costs and scope of the ongoing demolition and site remediation
efforts at the Vermilion and Wood River facilities and any
potential future remediation obligations at the South Bay facility;
(xxv) expectations regarding the synergies, completion, timing,
terms, and anticipated benefits of the ENGIE acquisition; and
(xxvi) beliefs regarding redevelopment efforts for the Morro
Bay facility. Any or all of Dynegy’s forward-looking statements may
turn out to be wrong. They can be affected by inaccurate
assumptions or by known or unknown risks, uncertainties, and other
factors, many of which are beyond Dynegy’s control, including those
set forth under Item 1A - Risk Factors of Dynegy’s Form 10-K.
DYNEGY INC.
REPORTED UNAUDITED CONSOLIDATED
STATEMENTS OF OPERATIONS
(IN MILLIONS, EXCEPT PER SHARE
DATA)
Three Months Ended June 30, Six Months Ended June
30, 2016 2015 2016
2015 Revenues $ 904 $ 990 $ 2,027 $ 1,622 Cost of
sales, excluding depreciation expense (493 ) (496 ) (1,038 ) (873 )
Gross margin 411 494 989 749 Operating and maintenance expense (256
) (250 ) (477 ) (361 ) Depreciation expense (160 ) (175 ) (331 )
(239 ) Impairments (645 )
-
(645 )
-
Loss on sale of assets, net
-
(1 )
-
(1 ) General and administrative expense (39 ) (35 ) (76 ) (65 )
Acquisition and integration costs 3 (23 ) (1 ) (113 ) Other (16)
-
(16)
-
Operating income (loss) (702 ) 10 (557 ) (30 ) Earnings from
unconsolidated investments 1 3 3 3 Interest expense (141 ) (132 )
(283 ) (268 ) Other income and expense, net 30 4 31
(1 ) Loss before income taxes (812 ) (115 ) (806 ) (296 )
Income tax benefit (expense) 9 501 (7 ) 501
Net income (loss) (803 ) 386 (813 ) 205 Less: Net loss attributable
to noncontrolling interest (2 ) (2 ) (2 ) (3 ) Net income (loss)
attributable to Dynegy Inc. (801 ) 388 (811 ) 208 Less: Dividends
on preferred stock 6 6 11 11 Net income
(loss) attributable to Dynegy Inc. common stockholders $ (807 ) $
382 $ (822 ) $ 197
Earnings (Loss) Per
Share: Basic earnings (loss) per share attributable to Dynegy
Inc. common stockholders $ (6.73 ) $ 2.98 $ (6.97 ) $ 1.56 Diluted
earnings (loss) per share attributable to Dynegy Inc. common
stockholders $ (6.73 ) $ 2.73 $ (6.97 ) $ 1.49 Basic shares
outstanding 120 128 118 126 Diluted shares outstanding 120 142 118
140
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
THREE MONTHS ENDED JUNE 30,
2016
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
three months ended June 30, 2016:
Three Months Ended June 30, 2016 Coal
IPH Gas Other
Total Net loss attributable to Dynegy Inc. $ (801 )
Plus / (Less): Loss attributable to noncontrolling interest (2 )
Income tax benefit (9 ) Interest expense 141 Depreciation and
amortization expense 164
EBITDA (1) $ (716 ) $ 20 $
235 $ (46 ) $ (507 ) Adjustments to reflect Adjusted EBITDA from
unconsolidated investments and exclude noncontrolling interest
-
2 1
-
3 Acquisition and integration costs
-
(8 )
-
5 (3 ) Mark-to-market adjustments, including warrants 83 (2 ) (52 )
-
29 Impairments 645
-
-
-
645 Wood River energy margin and O&M 15
-
-
-
15 Non-cash compensation expense
-
-
-
5 5 Other (1 ) (1 )
-
2
-
Adjusted EBITDA (1) $ 26 $ 11 $ 184
$ (34 ) $ 187
(1) EBITDA and Adjusted EBITDA are
non-GAAP financial measures. Please refer to Item 2.02 of our Form
8-K filed on August 3, 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 June 30,
2016
Coal IPH Gas Other Total
Operating income (loss) $ (749 ) $ 3 $ 90 $ (46 ) $ (702 )
Depreciation and amortization expense 27 3 132 2 164 Earnings from
unconsolidated investments
-
-
1
-
1 Other income and expense, net 6 14 12 (2 )
30
EBITDA $ (716 ) $ 20 $ 235 $ (46 ) $
(507 )
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
THREE MONTHS ENDED JUNE 30,
2015
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the
three months ended June 30, 2015:
Three Months Ended June 30, 2015 Coal
IPH Gas Other
Total Net income attributable to Dynegy Inc. $ 388
Plus / (Less): Loss attributable to noncontrolling interest (2 )
Income tax benefit (501 ) Interest expense 132 Depreciation and
amortization expense 174
EBITDA (1) $ 33 $ (3 ) $ 213
$ (52 ) $ 191 Plus / (Less): Adjustments to reflect Adjusted EBITDA
from unconsolidated investments and exclude noncontrolling interest
-
2
-
-
2 Acquisition and integration costs
-
-
-
23 23 Mark-to-market adjustments, including warrants (14 ) 6 (10 )
(3 ) (21 ) Other
-
-
(1 ) (1 ) (2 )
Adjusted EBITDA (1)(2) $ 19 $ 5
$ 202 $ (33 ) $ 193
(1) EBITDA and Adjusted EBITDA are
non-GAAP financial measures. Please refer to Item 2.02 of our Form
8-K filed on August 3, 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.
(2) Not adjusted for these items which are
excluded in 2016: (i) non-cash compensation expense of $8 million,
and (ii) Wood River’s energy margin and O&M costs of $9
million.
Three Months Ended June 30,
2015
Coal IPH Gas Other Total
Operating income (loss) $ (5 ) $ (14 ) $ 86 $ (57 ) $ 10
Depreciation and amortization expense 38 11 124 1 174 Earnings from
unconsolidated investments
-
-
3
-
3 Other income and expense, net
-
-
-
4 4
EBITDA $ 33 $ (3 ) $ 213
$ (52 ) $ 191
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
SIX MONTHS ENDED JUNE 30,
2016
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the six
months ended June 30, 2016:
Six Months Ended June 30, 2016 Coal IPH
Gas Other Total Net loss
attributable to Dynegy Inc. $ (811 ) Plus / (Less): Loss
attributable to noncontrolling interest (2 ) Income tax expense 7
Interest expense 283 Depreciation and amortization expense 354
EBITDA (1) $ (632 ) $ 44 $ 506 $ (87 ) $ (169 ) Plus
/ (Less): Adjustments to reflect Adjusted EBITDA from
unconsolidated investments and exclude noncontrolling interest
-
2 4
-
6 Acquisition and integration costs
-
(8 )
-
9 1 Mark-to-market adjustments, including warrants 43 (5 ) (114 )
(1 ) (77 ) Impairments 645
-
-
-
645 Wood River energy margin and O&M 20
-
-
-
20 Non-cash compensation expense
-
-
1 11 12 Other
-
(1 ) (1 ) 2
-
Adjusted EBITDA (1) $ 76 $ 32 $ 396
$ (66 ) $ 438
(1) EBITDA and Adjusted EBITDA are
non-GAAP financial measures. Please refer to Item 2.02 of our Form
8-K filed on August 3, 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.
Six Months Ended June 30, 2016
Coal IPH Gas Other Total
Operating income (loss) $ (695 ) $ 17 $ 210 $ (89 ) $ (557 )
Depreciation and amortization expense 57 13 281 3 354 Earnings from
unconsolidated investments
-
-
3
-
3 Other income and expense, net 6 14 12
(1 ) 31
EBITDA $ (632 ) $ 44 $ 506
$ (87 ) $ (169 )
DYNEGY INC.
REPORTED SEGMENTED RESULTS OF
OPERATIONS
SIX MONTHS ENDED JUNE 30,
2015
(UNAUDITED) (IN MILLIONS)
The following table provides summary
financial data regarding our Adjusted EBITDA by segment for the six
months ended June 30, 2015:
Six Months Ended June 30, 2015 Coal
IPH Gas Other
Total Net income attributable to Dynegy Inc. $ 208
Plus / (Less): Loss attributable to noncontrolling interest (3 )
Income tax benefit (501 ) Interest expense 268 Depreciation and
amortization expense 238
EBITDA (1) $ 50 $ 29 $ 308 $
(177 ) $ 210 Plus / (Less): Adjustments to reflect Adjusted EBITDA
from unconsolidated investments and exclude noncontrolling interest
-
3
-
-
3 Acquisition and integration costs
-
-
-
113 113 Mark-to-market adjustments, including warrants (21 ) (5 )
(23 ) 2 (47 ) Other
-
-
(1 )
-
(1 )
Adjusted EBITDA (1)(2) $ 29 $ 27 $
284 $ (62 ) $ 278
(1) EBITDA and Adjusted EBITDA
are non-GAAP financial measures. Please refer to Item 2.02 of our
Form 8-K filed on August 3, 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.
(2) Not adjusted for these
items which are excluded in 2016: (i) non-cash compensation expense
of $14 million, and (ii) Wood River’s energy margin and O&M
costs of $8 million.
Six Months Ended June 30, 2015 Coal IPH
Gas Other Total Operating income (loss)
$ 2 $ 8 $ 138 $ (178 ) $ (30 ) Depreciation and amortization
expense 48 21 167 2 238 Earnings from unconsolidated investments
-
-
3
-
3 Other income and expense, net
-
-
-
(1 ) (1 )
EBITDA $ 50 $ 29 $ 308
$ (177 ) $ 210
DYNEGY INC.
OPERATING DATA
The following table provides summary
financial data regarding our Coal, IPH and Gas segment results of
operations for the three and six months ended June 30, 2016 and
2015, respectively.
Three Months Ended June 30,
Six Months Ended June 30, 2016 2015
2016 2015 Coal Million Megawatt Hours
Generated (8) 7.7 7.5 15.3 12.3 IMA for Coal-Fired Facilities (1)
(8) 82 % 72 % 82 % 79 % Average Capacity Factor for Coal-Fired
Facilities (2) (8) 52 % 50 % 49 % 57 % Average Quoted Market
On-Peak Power Prices ($/MWh) (3): Indiana (Indy Hub) $ 31.14 $
33.15 $ 28.38 $ 36.21 Commonwealth Edison (NI Hub) $ 28.87 $ 31.47
$ 28.11 $ 36.15 Mass Hub $ 28.17 $ 29.16 $ 31.01 $ 62.67 AD Hub $
30.43 $ 37.58 $ 29.61 $ 41.42 Average Quoted Market Off-Peak Power
Prices ($/MWh) (3): Indiana (Indy Hub) $ 22.37 $ 23.89 $ 21.27 $
26.43 Commonwealth Edison (NI Hub) $ 19.32 $ 19.70 $ 19.93 $ 23.78
Mass Hub $ 20.43 $ 19.25 $ 23.32 $ 47.84 AD Hub $ 21.71 $ 25.92 $
22.32 $ 29.09
IPH Million Megawatt Hours Generated
3.3 4.7 6.6 9.9 IMA for IPH Facilities (4) 91 % 91 % 90 % 92 %
Average Capacity Factor for IPH Facilities (5) 38 % 54 % 38 % 56 %
Average Quoted Market Power Prices ($/MWh) (3): On-Peak: Indiana
(Indy Hub) $ 31.14 $ 33.15 $ 28.38 $ 36.21 Off-Peak: Indiana (Indy
Hub) $ 22.37 $ 23.89 $ 21.27 $ 26.43
Gas Million
Megawatt Hours Generated (8) 11.9 12.8 25.2 17.8 IMA for Combined
Cycle Facilities (4) (8) 98 % 97 % 97 % 98 % Average Capacity
Factor for Combined Cycle Facilities (5) (8) 53 % 61 % 57 % 61 %
Average Market On-Peak Spark Spreads ($/MWh) (6): Commonwealth
Edison (NI Hub) $ 14.23 $ 12.57 $ 13.64 $ 15.13 PJM West $ 21.15 $
29.38 $ 19.94 $ 23.46 North of Path 15 (NP 15) $ 10.76 $ 14.99 $
10.74 $ 13.82
New York--Zone A
$ 23.98 $ 22.34 $ 20.34 $ 31.07 Mass Hub $ 11.02 $ 13.48 $ 10.92 $
14.21 AD Hub $ 27.53 $ 24.19 $ 29.68 $ 40.02 Average Market
Off-Peak Spark Spreads ($/MWh) (6): Commonwealth Edison (NI Hub) $
4.68 $ 0.80 $ 5.47 $ 2.75 PJM West $ 11.38 $ 15.66 $ 12.09 $ 8.32
North of Path 15 (NP 15) $ 4.71 $ 7.79 $ 5.37 $ 7.51
New York--Zone A
$ 6.79 $ 6.54 $ 5.86 $ 15.93 Mass Hub $ 3.28 $ 3.58 $ 3.23 $ (0.62
) AD Hub $ 11.32 $ 15.72 $ 12.64 $ 16.93 Average natural gas
price—Henry Hub ($/MMBtu) (7) $ 2.11 $ 2.72 $ 2.04 $ 2.80
(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 calculation excludes
our Brayton Point facility and CTs. The IMA for our facilities
within MISO and PJM (excluding CTs) was 86 percent and 79 percent,
respectively, for the three months ended June 30, 2016 and 76
percent and 70 percent, respectively, for the three months ended
June 30, 2015. The IMA for our facilities within MISO and PJM
(excluding CTs) was 87 percent and 78 percent, respectively, for
the six months ended June 30, 2016 and 86 percent and 70 percent,
respectively, for the six months ended June 30, 2015. (2) Reflects
actual production as a percentage of available capacity. The
calculation excludes our Brayton Point facility and CTs. The
average capacity factors for our facilities within MISO and PJM
(excluding CTs) were 59 percent and 46 percent, respectively, for
the three months ended June 30, 2016 and 56 percent and 45 percent,
respectively, for the three months ended June 30, 2015. The average
capacity factors for our facilities within MISO and PJM (excluding
CTs) were 54 percent and 44 percent, respectively, for the six
months ended June 30, 2016 and 65 percent and 45 percent,
respectively, for the six months ended June 30, 2015. (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) 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. (7) Reflects the average of
daily quoted prices for the periods presented and does not reflect
costs incurred by us. (8) Reflects the activity for the period in
which the Acquisitions were included in our consolidated results.
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, updated
based on April 19, 2016 forward curves, as presented on May 3,
2016:
Dynegy Consolidated Low High
Net loss attributable to Dynegy Inc. (1) $
(351 ) $ (181 ) Plus / (Less):
Income tax expense (2) 16 16 Interest expense 540 545 Earnings from
unconsolidated investments (2) (2 ) (2 )
Operating Income
203 378 Depreciation expense 710 730 Amortization
expense 30 30 Earnings from unconsolidated investments (2) 2
2
EBITDA (3) 945 1,140 Plus / (Less):
Earnings from unconsolidated investments (2) (2 ) (2 ) Acquisition
and integration costs 35 40 Other (4) 22 22
Adjusted EBITDA (3) $ 1,000 $
1,200 (1) For purposes of Net loss
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. (2) Represents actual amounts for the three
months ended March 31, 2016. (3) EBITDA and Adjusted EBITDA are
non-GAAP measures. (4) Represents actual amounts for three months
ended March 31, 2016. Other consists primarily of cash
distributions from unconsolidated investments, asset retirement
obligation accretion, non-cash compensation expense, and energy
margin and operating and maintenance costs associated with our Wood
River facility.
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 )
Acquisition and integration costs (35 ) (40 ) Other cash items 10
10
Cash Flow from Operations 460
655 Maintenance capital expenditures (275 ) (275 )
Environmental capital expenditures (20 ) (20 ) Acquisition and
integration costs 35 40
Free Cash Flow (1)
$ 200 $ 400 (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, updated
based on July 14, 2016 forward curves, as presented on
August 3, 2016:
Dynegy Consolidated Low High
Net loss attributable to Dynegy Inc. (1) $
(1,038 ) $ (968 ) Plus / (Less):
Loss attributable to noncontrolling interest (2) (2 ) (2 ) Income
tax expense (2) 7 7 Other income and expense, net (2) (31 ) (31 )
Interest expense 605 610 Earnings from unconsolidated investments
(2) (3 ) (3 )
Operating loss (462 )
(387 ) Depreciation and amortization expense 700 720
Earnings from unconsolidated investments (2) 3 3 Other income and
expense, net (2) 31 31
EBITDA (3) 272
367 Plus / (Less): Acquisition and integration costs 45 50
Impairments (2) 645 645 Other (4) 38 38
Adjusted
EBITDA (3) $ 1,000 $ 1,100
(1) For purposes of Net loss 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. (2) Represents actual amounts for the six months ended
June 30, 2016. (3) EBITDA and Adjusted EBITDA are non-GAAP
measures. (4) Represents actual amounts for six months ended June
30, 2016. Other consists primarily of adjustments to reflect
Adjusted EBITDA from unconsolidated investment and exclude
noncontrolling interest, non-cash compensation expense, and Wood
River’s energy margin and operating and maintenance costs.
The following table provides summary
financial data regarding our 2016 Free Cash Flow guidance:
Dynegy Consolidated Low High
Adjusted EBITDA (1) $ 1,000 $
1,100 Cash interest payments (2) (515 ) (515 ) Acquisition
and integration costs (45 ) (50 ) Other cash items 10 10
Cash Flow from Operations 450 545
Maintenance capital expenditures (275 ) (275 ) Environmental
capital expenditures (20 ) (20 ) Acquisition and integration costs
45 50
Free Cash Flow (1) $ 200
$ 300 (1) Adjusted EBITDA and
Free Cash Flow are non-GAAP measures. (2) Excludes payments to an
escrow account of (i) $50 million of pre-funded interest and (ii)
$20 million of prefunded original issue discount which are
contingent upon the closing of the ENGIE acquisition.
View source
version on businesswire.com: http://www.businesswire.com/news/home/20160803006701/en/
Dynegy Inc.Media: Micah Hirschfield, 713.767.5800Analysts:
713.507.6466
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