DYN Dynegy Inc. (delisted)

Dynegy Inc. (NYSE: DYN):

 

Summary of First Quarter 2017 Financial Results (in millions):

   

Three Months EndedMarch 31,

2017   2016 Operating Revenues $ 1,247 $ 1,123 Net Income (loss) $ 597 $ (10 ) Adjusted EBITDA (1) $ 230 $ 251  

2017 Guidance Ranges (in millions):

  Adjusted EBITDA (1)   $1,200 - $1,400 Adjusted Free Cash Flow (1) $300 - $500; increased from the prior range of $150 - $350  

Operating Highlights:

• Adjusted free cash flow guidance increased by $150 million due to modified capital and outage plan
• $1.4 billion in liquidity at March 31, 2017
• Generated nearly 26 million megawatt hours in first quarter 2017
• Safety performance improved by nearly 50% in the first quarter as compared to 2016

Portfolio Transformation:

• Completed the Illinois Power Holdings (Genco) financial restructuring in February 2017, resulting in a simplified, more efficient corporate structure and a strengthened balance sheet with more than $640 million of debt eliminated
• Signed an agreement with LS Power to sell Armstrong and Troy PJM peaking units, 1,269 MW total, for $480 million ($378/kW) and received early termination of the Hart-Scott-Rodino Act waiting period; proceeds will go toward debt reduction
• Currently in the second round of the mitigation sales process for Milford (MA) and Dighton, 364 MW total
• Signed agreements with joint operating partners, AEP and AES, to retire the Stuart and Killen power plants, nearly 3,000 MW total, by mid-2018
• Agreed to purchase AES’ 28.1% ownership interest in Zimmer Power Station and 36% interest in Miami Fort Power Station, approximately 740 MW total, for $50 million plus working capital

___________________________________     (1) Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures; see “Regulation G Reconciliations” for further details.  

Dynegy Inc. (NYSE: DYN) reported net income of $597 million for the first quarter of 2017, compared to a net loss of $10 million for the first quarter of 2016. The quarter-over-quarter increase is mainly due to a $483 million gain from the cancellation of debt resulting from the Genco restructuring and a $313 million tax benefit primarily resulting from the partial release of a deferred tax valuation allowance as a result of the ENGIE acquisition. These benefits were offset by a $194 million decrease in operating income due to reduced spark spreads from mild winter weather, lower gains on our hedging transactions and incremental acquisition and integration costs as a result of the ENGIE acquisition.

The Company reported consolidated Adjusted EBITDA of $230 million for the 2017 first quarter compared to $251 million for the 2016 first quarter. While the assets acquired from ENGIE during the first quarter of 2017 contributed $15 million in Adjusted EBITDA, consolidated results declined as a result of lower capacity revenues and energy margin, net of hedges, at the PJM and NY/NE segments as mild winter weather and increased gas costs lowered energy margin compared to the first quarter of 2016.

“Protection provided by our hedging program and our growth in retail contracting has enabled us to remain on track financially despite the lack of weather and a persistently low commodity price environment,” said Robert Flexon, Dynegy President and Chief Executive Officer. “Additionally, we made significant progress during the quarter on our multiple delevering strategies which consist of various asset sales, cash generated by our portfolio including the newly acquired ENGIE fleet and other portfolio optimization efforts.”

 

First Quarter Comparative Results

    Quarter Ended March 31, 2017   2016 (in millions)

Operating Income(Loss)

  Adjusted EBITDA (1)

Operating Income(Loss)

  Adjusted EBITDA (1) PJM $ 86 $ 191 $ 177 $ 209 NY/NE (41 ) 42 (2 ) 53 ERCOT (28 ) (9 ) — — MISO 17 10 13 (1 ) IPH 18 31 14 21 CAISO (14 ) (3 ) (14 ) — Other (87 ) (32 ) (43 ) (31 ) Total $ (49 ) $ 230   $ 145   $ 251   ___________________________________     (1) Adjusted EBITDA is a non-GAAP financial measure, see “Regulation G Reconciliations” for further details.  

Segment Review of Results Quarter-over-Quarter

PJM - Operating income for the 2017 first quarter totaled $86 million, compared to $177 million for the same period of 2016, as non-cash mark-to-market losses on derivatives, a non-cash impairment related to the Killen facility, lower capacity revenues and lower energy margin, net of hedges pressured results. Adjusted EBITDA totaled $191 million during the 2017 first quarter compared to $209 million during the same period in 2016 as lower energy margins, net of hedges, together with lower capacity revenues more than offset contributions from the new assets acquired from ENGIE.

NY/NE - Operating loss for the 2017 first quarter totaled $41 million, compared to $2 million for the same period in 2016, primarily due to non-cash mark-to-market losses on derivatives. Adjusted EBITDA totaled $42 million during the 2017 first quarter, compared to $53 million during the same period in 2016 as lower energy margins, net of hedges, and lower capacity revenues more than offset contributions from the new assets acquired from ENGIE.

ERCOT - Operating loss for the 2017 first quarter totaled $28 million, while Adjusted EBITDA was a loss of $9 million for the same period. Results for the quarter include $4 million in operations support overhead allocation and reflect the impact of five unit outages in February and March without the benefit of ownership in January.

MISO/IPH - Operating income for the 2017 first quarter totaled $35 million, compared to $27 million for the same period in 2016, as higher capacity revenues and lower O&M costs more than offset non-cash mark-to-market losses on derivatives and lower energy margin, net of hedges. Adjusted EBITDA totaled $41 million during the 2017 first quarter compared to $20 million during the same period in 2016 as the capacity revenue and O&M benefits noted above more than offset lower energy margin, net of hedges.

CAISO - Operating loss for the 2017 first quarter totaled $14 million, unchanged from the same period in 2016. Adjusted EBITDA loss totaled $3 million during the 2017 first quarter compared to breakeven during the same period in 2016 due to lower energy margin, net of hedges.

Liquidity

As of March 31, 2017, Dynegy’s total available liquidity was $1.4 billion as reflected in the table below.

  (amounts in millions)     Revolving facilities and LC capacity (1) $ 1,675 Less: Outstanding revolvers (300 ) Outstanding LCs (476 ) Revolving facilities and LC availability 899 Cash and cash equivalents 467   Total available liquidity $ 1,366   ___________________________________     (1) Dynegy Inc. includes $1.5 billion in senior secured revolving credit facilities and $130 million related to LCs.  

Consolidated Cash Flow

Cash provided by operations totaled $149 million for the first quarter 2017. During the period, our power generation facilities and retail operations provided cash of $261 million. Corporate activities, primarily related to general and administrative, interest and acquisition-related expenses, as well as other working capital changes used cash of $112 million during the period.

Cash used in investing activities totaled $3.3 billion during the first quarter 2017 as Dynegy used $3,263 million at the closing of the ENGIE acquisition and invested $31 million in capital expenditures.

Cash used in financing activities totaled $228 million for the first quarter 2017. Cash uses include (i) $375 million paid for the Energy Capital Partners Buyout, (ii) $119 million of payments related to the termination of the Genco senior notes (iii) $99 million in financing costs related to our debt issuances, (iv) $75 million for debt reduction related to Dynegy’s equipment financing agreements and tangible equity units (TEUs), (v) $5 million in dividend payments on our preferred stock and (vi) $4 million in interest rate swap settlement payments. Partially offsetting these cash outflows were (i) $300 million in cash proceeds from a revolver draw and (ii) $150 million in cash proceeds from the issuance of Dynegy Inc. common stock to ECP at the closing of the ENGIE acquisition.

2017 Guidance

Dynegy’s full-year 2017 Adjusted EBITDA guidance range remains unchanged at $1,200-1,400 million. The Company’s Adjusted free cash flow range is being increased by $150 million, to $300 million to $500 million, primarily as a result of deferring and changing the scope of previously scheduled maintenance capital expenditures.

Environmental Update/Capital Allocation

As previously disclosed, Dynegy has continued to evaluate the timing of ELG-related projects and related expenditures and has determined that, based on existing rules, most of the projects originally scheduled for 2017 and 2018 will be delayed for approximately two years. As a result, approximately $40 million in ELG-related capital expenditures originally expected in 2017 have been rescheduled to 2019 and approximately $140 million in 2018 spend has been rescheduled to 2020.

Additionally, the Company recently restructured the first tranche of an existing PJM capacity monetization to defer settlement of the obligation from planning year 2017-2018 to planning year 2019-2020. As a result, $64 million in payments originally scheduled for 2017 have been deferred to 2019, and $45 million in payments originally scheduled for 2018 have been deferred to 2020.

The funds previously allocated to these items have been reallocated to debt reduction.

Retail Growth

Dynegy’s retail business has grown to become one of the top five residential suppliers in Ohio and is committed to expanding its presence in the state. Recently, the retail business finalized its largest aggregation contract, a three-year municipal agreement to supply electricity to the residents of the City of Cincinnati. Dynegy currently has a successful integrated wholesale and retail platform in Ohio and Illinois and is actively pursuing broadening it to other locations where the Company has generation.

Safety

Total safety performance in the first quarter of 2017 improved by nearly 50% as compared to 2016. Dynegy’s gas facilities continued to perform in the top decile, while coal-fueled units improved significantly due to focus on rigorous safety initiatives.

Environmental Improvements

Dynegy’s transformation to a largely gas-fueled portfolio of assets has significantly improved the Company’s environmental footprint. Between 2014 and 2017, sulfur dioxide (SO2), greenhouse gases (GHG) and nitrogen oxides (NOx) emissions intensities (lb/MWh) will have declined by 48%, 25% and 17% respectively. (1)

In addition, the Company is well on its way to realizing its stated goal of recycling 100% of coal combustion byproduct (CCB) for beneficial reuse by 2020, with Dynegy reusing more than 70% of CCB last year and on track to achieve 80% by the end of 2017. Applications include serving as a substitute for cement in concrete and as a replacement for gypsum in wallboard. This lessens landfill needs and directly offsets CO2 generated by manufacturing these products. It not only makes good environmental sense, it makes good financial sense by eliminating a cost stream and turning it into a revenue stream.

(1) 2017 emissions are based on expected asset ownership and forecasted production.

Updates to Asset Portfolio

Peaker Sales to LS Power

On February 23, Dynegy signed an agreement with LS Power to sell Armstrong and Troy, two PJM peaking units totaling 1,269 MW, for $480 million ($378/kW). On April 6, the United States Department of Justice and Federal Trade Commission granted early termination of the Hart-Scott-Rodino Act waiting period. The transaction close is pending Federal Energy Regulatory Commission (FERC) approval.

Southeastern New England (SENE) Mitigation

Dynegy is engaged in the second round of its auction process for assets the Company intends to sell to meet FERC’s market mitigation requirements associated with the ENGIE acquisition approval.

Asset Retirements

Dynegy and its joint operating partners, AEP and AES, have formally agreed to shut down the Stuart and Killen coal-fueled facilities totaling approximately 3,000 MW by mid-2018. Current ownership interests will be retained through the shutdown date, and the Company’s portion of previously cleared capacity from Stuart and Killen will be transferred to other Dynegy plants.

Ownership Consolidation of Jointly Owned Units

On April 24, Dynegy agreed to purchase AES’ 28.1% ownership interest in Zimmer and 36% in Miami Fort stations, totaling approximately 740 MW of generating capacity, for $50 million, subject to certain adjustments. As previously disclosed, Dynegy will also acquire AEP’s ownership interest in Zimmer and sell its ownership interest in Conesville to AEP. No consideration will be exchanged between AEP and Dynegy, however AEP will return a previously issued letter of credit totaling $58 million to Dynegy. Upon closing, the Company will fully own and operate Miami Fort and Zimmer with no additional debt incurred and no material impact to liquidity.

PRIDE Update and ENGIE Integration

Dynegy’s PRIDE Energized (Producing Results through Innovation by Dynegy Employees) program is on track to meet its 2017 target of $65 million in EBITDA by the end of the fourth quarter and already exceeded its three-year balance sheet goal of $400 million in 2016 with $422 million in improvements. Dynegy has identified over $75 million in additional balance sheet improvements for 2017 to further exceed the three-year target.

To date, Dynegy has secured $95 million of the $120 million ENGIE synergies target and remains on track to achieve 90% of the targeted ENGIE synergies by year end.

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. The Company will answer questions about its 2017 first quarter financial results during an investor conference call and webcast tomorrow, May 5, 2017 at 9 a.m. ET/8 a.m. CT. Participants may access the webcast from the Company’s website.

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 Northeast, Mid-Atlantic, Midwest and Texas, Dynegy operates power generating facilities capable of producing more than 31,000 megawatts of electricity—or enough energy to power about 25 million American homes. 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 Statement

This news release contains statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements,” particularly those statements concerning Dynegy’s beliefs and expectations regarding sale of Dynegy’s PJM peaking units, the sale process to satisfy the FERC market mitigation requirements, anticipated asset retirements, and ownership consolidation of Zimmer and Miami Fort units; execution of its PRIDE Energized target in balance sheet and operating improvements; the execution and timing of debt repayments and various delevering strategies; broadening the retail platform; achievement of Dynegy’s CCB goals; anticipated earnings and cash flows and Dynegy’s 2017 Adjusted EBITDA and Adjusted 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 2016 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 the power and capacity procurement processes in the markets in which we operate; (vi) expectations regarding, or impacts of, environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts, and other laws and regulations that we are, or could become, subject to, which could increase our costs, result in an impairment of our assets, cause us to limit or terminate the operation of certain of our facilities, or otherwise have a negative financial effect; (vii) beliefs about the outcome of legal, administrative, legislative, and regulatory matters, including any impacts from the change in administration to these matters; (viii) projected operating or financial results, including anticipated cash flows from operations, revenues, and profitability; (ix) our focus on safety and our ability to operate our assets efficiently so as to capture revenue generating opportunities and operating margins; (x) our ability to mitigate forced outage risk, including managing risk associated with CP in PJM and performance incentives in ISO-NE; (xi) our ability to optimize our assets through targeted investment in cost effective technology enhancements; (xii) the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility; (xiii) efforts to secure retail sales and the ability to grow the retail business; (xiv) efforts to identify opportunities to reduce congestion and improve busbar power prices; (xv) ability to mitigate impacts associated with expiring reliability must run “RMR” and/or capacity contracts; (xvi) expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios, and other payments; (xvii) expectations regarding performance standards and capital and maintenance expenditures; (xviii) the timing and anticipated benefits to be achieved through our Company-wide improvement programs, including our PRIDE initiative; (xix) expectations regarding strengthening the balance sheet, managing debt and improving Dynegy’s leverage profile; (xx) expectations, timing and benefits of the AES and AEP transactions; (xxi) efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures; (xxii) anticipated timing, outcome and impact of expected retirements; (xxiii) beliefs about the costs and scope of the ongoing demolition and site remediation efforts; and (xxiv) expectations regarding the synergies and anticipated benefits of the ENGIE Acquisition. 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 March 31, 2017   2016 Revenues $ 1,247 $ 1,123 Cost of sales, excluding depreciation expense (757 ) (545 ) Gross margin 490 578 Operating and maintenance expense (232 ) (221 ) Depreciation expense (200 ) (171 ) Impairments (20 ) — General and administrative expense (40 ) (37 ) Acquisition and integration costs (45 ) (4 ) Other (2 ) —   Operating income (loss) (49 ) 145 Bankruptcy reorganization items 483 — Earnings (losses) from unconsolidated investments (1 ) 2 Interest expense (167 ) (142 ) Other income and expense, net 17   1   Income before income taxes 283 6 Income tax benefit (expense) 313   (16 ) Net income (loss) 596 (10 ) Less: Net loss attributable to noncontrolling interest (1 ) —   Net income (loss) attributable to Dynegy Inc. 597 (10 ) Less: Dividends on preferred stock 5   5   Net income (loss) attributable to Dynegy Inc. common stockholders $ 592   $ (15 )   Earnings (Loss) Per Share: Basic earnings (loss) per share attributable to Dynegy Inc. common stockholders $ 4.00 $ (0.13 ) Diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders $ 3.57 $ (0.13 )   Basic shares outstanding 148 117 Diluted shares outstanding 167 117  

The following table reflects significant components of our weighted average shares outstanding used in the basic and diluted loss per share calculations for the three months ended March 31, 2017 and 2016:

    Three Months Ended March 31, (in millions) 2017   2016 Shares outstanding at the beginning of the period (1) 140 117 Weighted-average shares outstanding during the period of: Shares issued under the PIPE Transaction 8 — Basic weighted-average shares outstanding 148 117 Dilution from potentially dilutive shares (2) 19 — Diluted weighted-average shares outstanding 167 117 ___________________________________     (1) The minimum settlement amount of the TEUs, or 23,092,460 shares, are considered to be outstanding since the issuance date of June 21, 2016, and are included in the computation of basic earnings (loss) per share for the three months ended March 31, 2017. No such amounts were considered outstanding for the three months ended March 31, 2016. (2) Shares included in the computation of diluted earnings (loss) per share for the three months ended March 31, 2017 primarily consist of approximately 5.4 million shares related to our TEUs and 12.9 million shares related to our mandatory convertible preferred stock.  

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 March 31, 2016.

DYNEGY INC.OPERATING DATA

The following table provides summary financial data regarding our PJM, NY/NE, ERCOT, MISO, IPH and CAISO segment results of operations for the three months ended March 31, 2017 and 2016, respectively.

    Three Months Ended March 31,   2017       2016   PJM Million Megawatt Hours Generated (1) 13.4 13.0 IMA (1)(2): Combined Cycle Facilities 89 % 98 % Coal-Fueled Facilities 65 % 77 % Average Capacity Factor (1)(3): Combined Cycle Facilities 68 % 83 % Coal-Fueled Facilities 60 % 43 % CDDs (4) 2 2 HDDs (4) 2,226 2,449 Average Market On-Peak Spark Spreads ($/MWh) (5): PJM West $ 11.38 $ 18.73 AD Hub $ 12.63 $ 19.81 Average Market On-Peak Power Prices ($/MWh) (6): PJM West $ 32.52 $ 31.49 AD Hub $ 31.39 $ 28.80 Average natural gas price—TetcoM3 ($/MMBtu) (7) $ 3.02 $ 1.82   NY/NE Million Megawatt Hours Generated (1) 4.7 3.9 IMA for Combined Cycle Facilities (1)(2) 98 % 89 % Average Capacity Factor for Combined Cycle Facilities (1)(3) 37 % 40 % CDDs (4) — — HDDs (4) 2,772 2,719 Average Market On-Peak Spark Spreads ($/MWh) (5): New York—Zone A $ 10.99 $ 16.69 Mass Hub $ 6.63 $ 10.82 Average Market On-Peak Power Prices ($/MWh) (6): Mass Hub $ 37.76 $ 33.85 Average natural gas price—Algonquin Citygates ($/MMBtu) (7) $ 4.45 $ 3.29   ERCOT Million Megawatt Hours Generated (1) 0.6 — IMA (1)(2): Combined-Cycle Facilities 97 % — % Coal-Fueled Facility 93 % — % Average Capacity Factor (1)(3): Combined-Cycle Facilities 9 % — % Coal-Fueled Facility 18 % — % CDDs (4) 267 120 HDDs (4) 494 758 Average Market On-Peak Spark Spreads ($/MWh) (5): ERCOT North $ 4.11 $ 6.65 Average Market On-Peak Power Prices ($/MWh) (6): ERCOT North $ 23.54 $ 19.62 Average natural gas price—Waha Hub ($/MMBtu) (7) $ 2.78 $ 1.85   MISO Million Megawatt Hours Generated 2.7 3.3 IMA for Coal-Fueled Facilities (2) 89 % 89 % Average Capacity Factor for Coal-Fueled Facilities (3) 65 % 50 % CDDs (4) 57 28 HDDs (4) 2,203 2,424 Average Market On-Peak Power Prices ($/MWh) (6): Indiana (Indy Hub) $ 32.65 $ 25.61 Commonwealth Edison (NI Hub) $ 30.27 $ 27.34   IPH Million Megawatt Hours Generated 3.8 3.3 IMA for IPH Facilities (2) 86 % 86 % Average Capacity Factor for IPH Facilities (3) 52 % 39 % CDDs (4) 57 28 HDDs (4) 2,203 2,424 Average Market On-Peak Power Prices ($/MWh) ($/MWh) (6): Indiana (Indy Hub) $ 32.65 $ 25.61 Commonwealth Edison (NI Hub) $ 30.27 $ 27.34   CAISO Million Megawatt Hours Generated 0.3 0.7 IMA for Combined Cycle Facilities (2) 95 % 99 % Average Capacity Factor for Combined Cycle Facilities (3) 14 % 29 % CDDs (4) 25 44 HDDs (4) 717 594 Average Market On-Peak Spark Spreads ($/MWh) (5): North of Path 15 (NP 15) $ 8.34 $ 10.71 Average natural gas price—PG&E Citygate ($/MMBtu) (7) $ 3.34 $ 2.20 ___________________________________     (1) Adjusted EBITDA includes the activity of the assets acquired in the ENGIE acquisition for our period of ownership. Million Megawatt Hours Generated and Average Capacity Factor include such activity for the full month of February. IMA includes such activity for March only. (2) 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. The calculation excludes certain events outside of management control such as weather related issues. The calculation excludes our Brayton Point facility and CTs. (3) Reflects actual production as a percentage of available capacity. The calculation excludes our Brayton Point facility and CTs. (4) Reflects CDDs or HDDs for the region based on NOAA data. (5) Reflects the simple average of the on-peak spark spreads available to a 7.0 MMBtu/MWh heat rate generator selling power at day-ahead prices and buying delivered natural gas at a daily cash market price and does not reflect spark spreads available to us. (6) Reflects the average of day-ahead settled prices for the periods presented and does not necessarily reflect prices we realized. (7) Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.  

DYNEGY INC.REG G RECONCILIATIONS - ADJUSTED EBITDATHREE MONTHS ENDED MARCH 31, 2017(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2017:

    Three Months Ended March 31, 2017 PJM   NY/NE   ERCOT   MISO   IPH   CAISO   Other   Total Net income attributable to Dynegy Inc. $ 597 Plus / (Less): Loss attributable to noncontrolling interest (1 ) Income tax benefit (313 ) Other income and expense, net (17 ) Interest expense 167 Loss from unconsolidated investments 1 Bankruptcy reorganization items (483 ) Operating income (loss) $ 86 $ (41 ) $ (28 ) $ 17 $ 18 $ (14 ) $ (87 ) $ (49 ) Depreciation and amortization expense 100 68 13 8 14 15 2 220 Bankruptcy reorganization items — — — — 498 — (15 ) 483 Loss from unconsolidated investments (1 ) — — — — — — (1 ) Other income and expense, net —   —   —   —   1   —   16   17   EBITDA (1) 185 27 (15 ) 25 531 1 (84 ) 670 Plus / (Less): Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest 1 — — — — — — 1 Acquisition, integration costs and restructuring costs — — — — — — 46 46 Bankruptcy reorganization items — — — — (498 ) — 15 (483 ) Mark-to-market adjustments, including warrants (15 ) 15 6 (15 ) (1 ) (4 ) (12 ) (26 ) Impairments 20 — — — — — — 20 Non-cash compensation expense — — — — — — 5 5 Other —   —   —   —   (1 ) —   (2 ) (3 ) Adjusted EBITDA (1)(2) $ 191   $ 42   $ (9 ) $ 10   $ 31   $ (3 ) $ (32 ) $ 230   ___________________________________     (1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on May 4, 2017, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, 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 to exclude Wood River’s energy margin and O&M costs.  

DYNEGY INC.REG G RECONCILIATIONS - ADJUSTED EBITDATHREE MONTHS ENDED MARCH 31, 2016(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended March 31, 2016:

    Three Months Ended March 31, 2016 PJM   NY/NE   ERCOT   MISO   IPH   CAISO   Other   Total Net loss attributable to Dynegy Inc. $ (10 ) Plus / (Less): Income tax expense 16 Other income and expense, net (1 ) Interest expense 142 Earnings from unconsolidated investments (2 ) Operating income (loss) $ 177 $ (2 ) $ — $ 13 $ 14 $ (14 ) $ (43 ) $ 145 Depreciation and amortization expense 83 75 — 9 10 12 1 190 Earnings from unconsolidated investments 2 — — — — — — 2 Other income and expense, net —   —   —   —   —   —   1   1   EBITDA (1) 262 73 — 22 24 (2 ) (41 ) 338 Plus / (Less): Adjustment to reflect Adjusted EBITDA from unconsolidated investment 3 — — — — — — 3 Acquisition and integration costs — — — — — — 4 4 Mark-to-market adjustments, including warrants (56 ) (20 ) — (28 ) (3 ) 2 (1 ) (106 ) Non-cash compensation expense — — — — — — 7 7 Other (2) —   —   —   5   —   —   —   5   Adjusted EBITDA (1) $ 209   $ 53   $ —   $ (1 ) $ 21   $ —   $ (31 ) $ 251   ___________________________________     (1) EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on May 4, 2017, for definitions, utility and uses of such non-GAAP financial measures. A reconciliation of EBITDA to Operating income (loss) is presented above. Management does not allocate G&A, interest expense and income taxes on a segment level and therefore uses Operating income (loss) as the most directly comparable GAAP measure. (2) Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $5 million.  

DYNEGY INC.REG G RECONCILIATIONS - UPDATED 2017 GUIDANCE(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance:

    Dynegy Consolidated Low   High Net income attributable to Dynegy Inc. (1) $ 455 $ 655 Plus / (Less): Interest expense 655 660 Tax benefit (310 ) (320 ) Depreciation and amortization expense 815   835   EBITDA (2) 1,615 1,830 Plus / (Less): Acquisition, integration and restructuring costs 45 50 Bankruptcy reorganization items (480 ) (500 ) Impairments 20   20   Adjusted EBITDA (2) $ 1,200 $ 1,400 Cash interest payments (600 ) (600 ) Acquisition, integration and restructuring costs (45 ) (50 ) Other cash items (80 ) (80 ) Cash Flow from Operations 475 670 Maintenance capital expenditures (210 ) (210 ) Environmental capital expenditures (10 ) (10 ) Acquisition, integration and restructuring costs 45   50   Adjusted Free Cash Flow (2) $ 300   $ 500   ___________________________________     (1) For purposes of our 2017 guidance, fair value adjustments related to derivatives and our common stock warrants are assumed to be zero. (2) EBITDA, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures. Please refer to Item 2.02 of our Form 8-K filed on May 4, 2017, for definitions, utility and uses of such non-GAAP financial measures.  

DYNEGY INC.REG G RECONCILIATIONS - ORIGINAL 2017 GUIDANCE(UNAUDITED) (IN MILLIONS)

The 2017 guidance was prepared using reasonable efforts and based on currently available information assuming the following: (a) the Delta transaction closed on February 7, 2017, (b) all of the purchase price is allocated to property, plant and equipment, (c) property, plant and equipment is depreciated over an average useful life of 20 years, and (d) Genco restructuring completed on February 2, 2017.

The following table provides summary financial data regarding our 2017 Adjusted EBITDA and Adjusted Free Cash Flow guidance, updated based on February 7, 2017 forward curves, as presented on February 23, 2017:

    Dynegy Consolidated Low   High Net loss attributable to Dynegy Inc. (1) $ (265 ) $ (95 ) Plus / (Less): Interest expense 660 665 Depreciation and amortization expense 765   785   EBITDA (2) 1,160 1,355 Plus / (Less): Acquisition, integration and restructuring costs 40   45   Adjusted EBITDA (2) 1,200 1,400 Cash interest payments (625 ) (625 ) Acquisition, integration and restructuring costs (40 ) (45 ) Other cash items (35 ) (35 ) Cash Flow from Operations 500 695 Maintenance capital expenditures (370 ) (370 ) Environmental capital expenditures (20 ) (20 ) Acquisition, integration and restructuring costs 40   45   Adjusted Free Cash Flow (2) $ 150   $ 350   ___________________________________     (1) For purposes of our 2017 guidance, fair value adjustments related to derivatives and our common stock warrants are assumed to be zero. (2)

EBITDA, Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP measures. Please refer to Item 2.02 of our Form 8-K filed on May 4, 2017, for definitions, utility and uses of such non-GAAP financial measures.

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Dynegy Inc.Media:David Onufer, 713-767-5800orAnalysts: 713-507-6466