OREANDA-NEWS. August 04, 2016.

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.