Dynegy Announces 2016 Results, Portfolio Changes and Updated Acquisition Synergies Targets

HOUSTON--(BUSINESS WIRE)-- Dynegy Inc. (NYSE: DYN):

Summary of Fourth Quarter and Full-Year 2016 Financial Results (in millions):
		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
		2016				2015				2016				2015
Operating Revenues		$	1,107			$	1,016			$	4,318			$	3,870
Net Income (loss)		$	(180	)		$	(134	)		$	(1,240	)		$	50
Adjusted EBITDA (1)		$	219			$	222			$	1,007			$	850
Operating Cash Flow										$	676			$	94
Adjusted Free Cash Flow (1)										$	263			$	186

Affirms 2017 Guidance Ranges (in millions):
Adjusted EBITDA		$1,200 - $1,400
Adjusted Free Cash Flow		$150 - $350

Portfolio Changes

• Signed an agreement with LS Power to sell two PJM peaking units (Armstrong and Troy) totaling 1,269 MW for $480 million ($378/kW)
• Reached agreement with AEP to sell Dynegy’s ownership in the Conesville Power Station and acquire AEP’s interest in the Zimmer Power Station in Ohio
• Active discussions with partners underway on future of Stuart and Killen facilities

Recent Developments

• Increased ENGIE acquisition synergy targets from $90 million to $120 million
• Repriced $2 billion acquisition term loan resulting in approximately $100 million in interest savings over the next seven years and upsized the borrowing to refinance existing $224 million term loan previously due in 2020
• Completed Genco restructuring on February 2, eliminating $825 million of unsecured Genco bonds
• Closed ENGIE acquisition and issued 13.7 million shares of DYN common stock to ECP at $10.94 per share on February 7. In addition, Dynegy settled its remaining payment obligation to ECP of $375 million
• Exceeded 2016 PRIDE targets with $422 million in balance sheet improvements and $150 million in Adjusted EBITDA enhancements

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(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 a net loss for 2016 of $1.24 billion, compared to net income of $50 million for 2015. The year-over-year decrease was primarily driven by asset impairments related to the Baldwin, Newton and Stuart plants in 2016 and a second quarter 2015 deferred tax valuation allowance reversal which benefited 2015, but did not reoccur in 2016. This decrease was partially offset by the first quarter 2016 contribution from the Duke and EquiPower plants acquired in April 2015.

The Company reported 2016 consolidated Adjusted EBITDA of $1,007 million, compared to $850 million for 2015. The $157 million increase was primarily due to full-year contributions from the Duke and EquiPower plants in 2016 versus nine months in 2015. Partially offsetting this benefit were lower energy margins, net of hedges, across the majority of the segments primarily due to mild temperatures in the first quarter 2016 and lower capacity revenues at the PJM and NY/NE segments as a result of lower capacity prices.

The Company reported a fourth quarter 2016 net loss of $180 million, compared to a net loss of $134 million for 2015. The quarter-over-quarter change was primarily driven by Genco reorganization items, primarily due to the write-off of the remaining unamortized discount related to the Genco bonds.

The Company reported fourth quarter 2016 consolidated Adjusted EBITDA of $219 million, compared to $222 million for the fourth quarter 2015 as improved energy margins, net of hedges, and lower O&M costs at the PJM and MISO segments were offset by lower energy and capacity revenues in the NY/NE and PJM segments.

“The ENGIE acquisition solidified the transformation of our wholesale generation business we began in 2013. We have built the most efficient and lowest-cost platform in the industry while migrating our portfolio to a gas-dominated fleet in the ERCOT, NE-ISO and PJM markets. Our portfolio today has the longevity required for success,” said Dynegy President and Chief Executive Officer Robert C. Flexon.

“Looking ahead to 2017, our efforts are aimed at optimizing our portfolio in conjunction with improving our balance sheet and capital structure and today’s announcement with LS Power is a step in that direction,” Flexon continued. “In keeping with our integration track record, we now expect to deliver $120 million in synergies related to the ENGIE acquisition, a step up from our initial $90 million estimate.”

Full-Year Comparative Results
		Year Ended December 31,
		2016								2015
(in millions)		Operating Income (Loss)				Adjusted EBITDA				Operating Income (Loss)				Adjusted EBITDA
PJM		$	414			$	757			$	423			$	649
NY/NE		(29		)		171				(56		)		175
MISO		(745		)		27				(92		)		27
IPH		(87		)		102				49				77
CAISO		(5		)		59				(8		)		44
Other		(188		)		(109		)		(252		)		(122		)
Total		$	(640	)		$	1,007			$	64			$	850

Segment Review of Results Year-over-Year

PJM - The 2016 operating income was $414 million, compared to $423 million for 2015. The change was due to lower capacity revenues, non-cash mark-to-market losses on derivatives, higher O&M costs and 2016 impairment charges. Partially offsetting this was the full-year contribution of the Duke and EquiPower plants acquired in April 2015.

Adjusted EBITDA totaled $757 million during 2016 compared to $649 million in 2015, primarily due to the positive impact of the Duke and EquiPower plants which was partially offset by lower capacity prices and higher planned outage O&M costs.

NY/NE - The 2016 operating loss was $29 million, compared to $56 million for 2015. The change was attributable to a full-year 2016 contribution from the EquiPower plants versus nine months of 2015, lower impairment charges, lower depreciation due to a 2015 impairment and non-cash mark-to-market gains on derivatives. Adjusted EBITDA totaled $171 million in 2016 compared to $175 million in 2015.

MISO - The 2016 operating loss was $745 million, compared to a loss of $92 million in 2015, due to higher impairment charges. Adjusted EBITDA totaled $27 million for both 2016 and 2015.

IPH - The 2016 operating loss was $87 million, compared to 2015 operating income of $49 million as higher capacity revenues and lower O&M costs were offset by higher 2016 impairment charges. Adjusted EBITDA totaled $102 million in 2016, compared to $77 million in 2015 due to higher capacity revenues and lower O&M costs from fewer planned outages.

CAISO - The 2016 operating loss was $5 million, compared to $8 million for 2015 as a result of lower energy margin, net of hedges. Adjusted EBITDA totaled $59 million in 2016 compared to $44 million in 2015, primarily due to higher capacity revenues and a supplier settlement.

Fourth Quarter Comparative Results
		Quarter Ended December 31,
		2016								2015
(in millions)		Operating Income (Loss)				Adjusted EBITDA				Operating Income (Loss)				Adjusted EBITDA
PJM		$	137			$	181			$	101			$	171
NY/NE		(7		)		29				(55		)		56
MISO		(42		)		8				(28		)		(1		)
IPH		—				20				10				16
CAISO		(5		)		14				(6		)		12
Other		(49		)		(33		)		(35		)		(32		)
Total		$	34			$	219			$	(13	)		$	222

Segment Review of Results Quarter-over-Quarter

PJM - The fourth quarter 2016 operating income was $137 million, compared to $101 million for the fourth quarter 2015. The increase was due to higher energy margin, net of hedges, and non-cash mark-to-market gains on derivatives, partially offset by lower capacity revenues. Adjusted EBITDA totaled $181 million in 2016 versus $171 million in 2015 as lower O&M and higher retail margins benefited results.

NY/NE - The fourth quarter 2016 operating loss was $7 million, compared to $55 million for the fourth quarter 2015 due to lower impairment charges and non-cash mark-to-market gains on derivatives, partially offset by lower energy margin, net of hedges. Adjusted EBITDA totaled $29 million in 2016 compared to $56 million in 2015 primarily due to lower energy margins, net of hedges.

MISO - The fourth quarter 2016 operating loss was $42 million, compared to $28 million for the fourth quarter 2015. The decrease was due to lower energy margin, net of hedges, and non-cash mark-to-market losses on derivatives. Adjusted EBITDA increased to $8 million in 2016 compared to ($1) million in 2015 primarily due to lower O&M expense from fewer planned outages.

IPH - The fourth quarter 2016 operating income was zero, compared to $10 million for the fourth quarter 2015 primarily due to higher O&M costs. Adjusted EBITDA was $20 million in 2016 and $16 million in 2015.

CAISO - The fourth quarter 2016 operating loss was $5 million, compared to $6 million for the fourth quarter 2015. Adjusted EBITDA in 2016 was $14 million versus $12 million in 2015 primarily due to higher capacity revenues in the most recent period.

Liquidity

Dynegy’s total available liquidity is reflected in the table below.

		December 31, 2016												February 7, 2017 (2)
(amounts in millions)		Dynegy Inc.				IPH (1)				Consolidated				Consolidated
Revolving facilities and LC capacity (3)		$	1,480			$	44			$	1,524			$	1,650
Less:
Outstanding revolver amount		—				—				—				(300		)
Outstanding LCs		(357		)		(25		)		(382		)		(422		)
Revolving facilities and LC availability		1,123				19				1,142				928
Cash and cash equivalents		1,692				84				1,776				532
Total available liquidity		$	2,815			$	103			$	2,918			$	1,460

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(1)	Includes Cash and cash equivalents of $64 million related to Genco, which was operating as debtor-in-possession in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
(2)	The seller in the ENGIE acquisition provides certain transition credit support through February 7, 2019, and we will use the LC availability as this support terminates.
(3)	Dynegy Inc. includes $1.425 billion in senior secured revolving credit facilities and $55 million related to an LC. IPH consists of $44 million related to IPM LCs. The IPM LCs are collateralized by cash, and as of December 31, 2016, IPM had $19 million deposited with the issuing banks.

Consolidated Cash Flow

Cash provided by operations for the full year of 2016 was $676 million. During the full year 2016, our power generation facilities and retail operations provided cash of $1.02 billion. Corporate and other activities used cash of $557 million primarily for interest payments on various debt agreements of $538 million and acquisition-related costs of $19 million. In addition, changes in working capital and other provided cash of $216 million during the period.

Cash used in investing activities totaled $2.15 billion for the full year of 2016. During the period, restricted cash increased by $2.0 billion from proceeds from the tranche C term loan being held in escrow for the ENGIE acquisition and $21 million related to the original issuance discount and interest income. Additionally, we paid $326 million in capital expenditures, received $176 million from asset sales, received $14 million in distributions from our unconsolidated investment in Elwood and received $10 million in proceeds from an insurance claim.

Cash provided by financing activities totaled $2.74 billion for the full year of 2016 primarily due to $2 billion in proceeds related to the tranche C term loan, $750 million in proceeds from our 2025 bonds, $443 million in net proceeds from our tangible equity units and $198 million of proceeds related to our forward capacity agreement. This was partially offset by $18 million in financing costs related to our debt issuances, $550 million in voluntary repayments associated with our tranche B-2 term loan, $39 million in other scheduled debt payments, $22 million in dividend payments on our preferred stock and $17 million in interest rate swap settlement payments.

Recent Developments

Portfolio Changes

Dynegy has reached an agreement to sell two peaking facilities in PJM to LS Power for $480 million in cash. The assets to be sold include the Armstrong and Troy facilities totaling 1,269 MW. Proceeds will be used for debt reduction.

Dynegy reached an agreement with AEP to realign and consolidate the ownership of the Conesville and Zimmer Power Stations in Ohio. Dynegy agreed to sell its 40% ownership interest (312 MW) in Conesville Power Station and acquire AEP’s 25.4% ownership interest in Zimmer. No additional consideration will be paid to either party, however AEP will return a $58 million letter of credit previously posted by Dynegy to AEP. As a result, Dynegy will own 71.9% (971 MW) of the Company-operated Zimmer Power Station, a reliable and fully controlled coal plant and will no longer have an ownership interest in Conesville. The overall capacity for the Conesville and Zimmer generating stations is 780 MW and 1,350 MW, respectively.

Our co-owner of Killen Station, AES, is involved in an Electric Security Plan proceeding in Ohio in which AES has reached a settlement that, if approved, includes a plan to retire the Killen Station. Dynegy has agreed with AES to retire that plant by mid-2018. The Stuart Power Station, jointly owned by Dynegy, AES, and AEP, is also under advanced review for potential retirement. If both retirements occur, 2,900 MW of baseload coal generation would leave PJM. Dynegy continues to look to optimize its ownership structure in jointly owned units, Miami Fort and Zimmer Power Stations.

Genco Restructuring

Genco emerged from its prepackaged Chapter 11 restructuring on February 2, 2017. As a result, Genco’s $825 million in unsecured bonds were eliminated. Participating bondholders exchanged $757 million in bonds thus far for $113 million in cash, $182 million in new Dynegy unsecured bonds due 2024 and 8.7 million seven-year warrants for Dynegy Inc. common stock with a strike price of $35. Bondholders who did not participate have 165 days post-emergence to file a claim and receive consideration, after which time their claim will be permanently extinguished. As a result of the restructuring, Dynegy’s annual consolidated interest expense has been reduced by approximately $45 million. At year end, IPH had $84 million in cash on hand and $79 million in cash collateral posted, providing Dynegy with more than sufficient funding to pay bondholders. Upon return of all previously posted cash collateral and payment of advisor fees, approximately $38 million of cash will be retained by Dynegy.

ENGIE

On February 7, Dynegy completed its acquisition of ENGIE’s US portfolio. Dynegy repriced its term loan C resulting in approximately $100 million in interest savings over the next seven years. The Company also upsized the loan by $224 million to refinance the existing term loan B due in 2020, extending the maturity by four years to 2024. Simultaneous with closing, Dynegy upsized its liquidity facilities by $170 million to $1.65 billion and extended the maturity date on $450 million in existing revolver capacity from 2018 to 2021.

Separately, Dynegy has increased ENGIE synergy targets from $90 million to $120 million with 75% of the synergies secured at closing and a full 90% to be achieved by year end 2017.

PRIDE

PRIDE Energized (Producing Results through Innovation by Dynegy Employees) launched in early 2016 with goals of $250 million in EBITDA contributions and $400 million in balance sheet improvements by the end of 2018. Through the end of 2016, Dynegy achieved $150 million in contributions to EBITDA and $422 million in balance sheet improvements, reaching all balance sheet goals two years ahead of schedule.

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 financial results during an investor conference call and webcast tomorrow, February 24, 2017 at 9 am ET/8 am 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 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 transformation of its wholesale generation business; its industry platform and portfolio optimization and longevity, including sale of peaking facilities, realignment and consolidation of Ohio power stations, and anticipated power station retirements; its balance sheet and capital structure improvements; synergies related to the ENGIE acquisition; execution of its PRIDE Energized target in balance sheet and operating improvements by year-end 2018; 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 (when filed). 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 efficiently operate our assets 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) efforts to divest assets and the associated timing of such divestitures, and anticipated use of proceeds from such divestitures; (xxi) anticipated timing, outcome and impact of the expected retirements of Brayton Point; (xxii) 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; and (xxiii) expectations regarding the synergies and anticipated benefits of the Delta Transaction.

DYNEGY INC.
REPORTED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED) (IN MILLIONS, EXCEPT PER SHARE DATA)
		Twelve Months Ended
		December 31,
		2016				2015
Revenues		$	4,318			$	3,870
Cost of sales, excluding depreciation expense		(2,281		)		(2,028		)
Gross margin		2,037				1,842
Operating and maintenance expense		(940		)		(839		)
Depreciation expense		(689		)		(587		)
Impairments		(858		)		(99		)
Loss on sale of assets, net		(1		)		(1		)
General and administrative expense		(161		)		(128		)
Acquisition and integration costs		(11		)		(124		)
Other		(17		)		—
Operating income (loss)		(640		)		64
Bankruptcy reorganization items		(96		)		—
Earnings from unconsolidated investments		7				1
Interest expense		(625		)		(546		)
Other income and expense, net		65				54
Loss before income taxes		(1,289		)		(427		)
Income tax benefit		45				474
Net income (loss)		(1,244		)		47
Less: Net loss attributable to noncontrolling interest		(4		)		(3		)
Net income (loss) attributable to Dynegy Inc.		(1,240		)		50
Less: Dividends on preferred stock		22				22
Net income (loss) attributable to Dynegy Inc. common stockholders		$	(1,262	)		$	28
Earnings (Loss) Per Share:
Basic and diluted earnings (loss) per share attributable to Dynegy Inc. common stockholders		$	(9.78	)		$	0.22
Basic shares outstanding		129				125
Diluted shares outstanding		129				126

The following table reflects the significant components of our weighted average shares outstanding used in basic and diluted loss per share calculations for the twelve months ended December 31, 2016 and 2015:

		Twelve Months Ended December 31,
(in millions, except per share amounts)		2016			2015
Shares outstanding at the beginning of the period		117			124
Weighted-average shares during the period of:
Shares issuances		—			4
Shares repurchases		—			(3	)
Prepaid stock purchase contract (TEUs) (1)		12			—
Basic weighted-average shares		129			125
Dilution from potentially dilutive shares (2)		—			1
Diluted weighted-average shares		129			126

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(1)	The minimum settlement amount, or 23,092,460 shares, are considered to be outstanding since June 21, 2016 and are included in the computation of basic earnings (loss) per share.
(2)	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for the twelve months ended December 31, 2016 and 2015.

DYNEGY INC.

OPERATING DATA

The following table provides summary financial data regarding our PJM, NY/NE, MISO, IPH and CAISO segment results of operations for the three and twelve months ended December 31, 2016 and 2015, respectively.

		Three Months Ended								Twelve Months Ended
		December 31,								December 31,
			2016				2015				2016				2015
PJM
Million Megawatt Hours Generated (1)			13.5				12.4				52.8				40.4
IMA (1)(2):
Combined Cycle Facilities			97	%			98	%			97	%			99	%
Coal-Fueled Facilities			78	%			78	%			80	%			74	%
Average Capacity Factor (1)(3):
Combined Cycle Facilities			73	%			74	%			74	%			75	%
Coal-Fueled Facilities			58	%			49	%			53	%			51	%
Average Market On-Peak Spark Spreads ($/MWh) (4):
PJM West		$	19.11			$	24.20			$	22.62			$	25.24
AD Hub		$	20.18			$	26.24			$	22.52			$	28.22
Average Market On-Peak Power Prices ($/MWh) (5):
PJM West		$	34.31			$	33.02			$	34.65			$	43.21
AD Hub		$	33.76			$	31.29			$	32.93			$	37.52
Average natural gas price—TetcoM3 ($/MMBtu) (6)		$	2.17			$	1.26			$	1.72			$	2.57
NY/NE
Million Megawatt Hours Generated (1)			3.8				4.7				16.9				15.7
IMA for Combined Cycle Facilities (1)(2)			97	%			99	%			96	%			98	%
Average Capacity Factor for Combined Cycle Facilities (1)(3)			43	%			53	%			48	%			56	%
Average Market On-Peak Spark Spreads ($/MWh) (4):
New York—Zone A		$	16.76			$	21.96			$	24.18			$	27.60
Mass Hub		$	11.72			$	13.59			$	13.80			$	15.23
Average Market On-Peak Power Prices ($/MWh) (5):
Mass Hub		$	38.74			$	34.98			$	35.52			$	48.96
Average natural gas price—Algonquin Citygates ($/MMBtu) (6)		$	3.86			$	3.06			$	3.10			$	4.82
MISO
Million Megawatt Hours Generated			3.2				3.0				14.4				15.9
IMA for Coal-Fueled Facilities (2)			89	%			87	%			89	%			87	%
Average Capacity Factor for Coal-Fueled Facilities (3)			72	%			45	%			63	%			61	%
Average Market On-Peak Power Prices ($/MWh) (5):
Indiana (Indy Hub)		$	37.89			$	28.52			$	33.71			$	33.50
Commonwealth Edison (NI Hub)		$	33.28			$	29.60			$	31.98			$	33.98
IPH
Million Megawatt Hours Generated			3.8				3.8				15.4				18.5
IMA for IPH Facilities (2)			87	%			86	%			89	%			89	%
Average Capacity Factor for IPH Facilities (3)			52	%			43	%			46	%			52	%
Average Market On-Peak Power Prices ($/MWh) ($/MWh) (5):
Indiana (Indy Hub)		$	37.89			$	28.52			$	33.71			$	33.50
Commonwealth Edison (NI Hub)		$	33.28			$	29.60			$	31.98			$	33.98
CAISO
Million Megawatt Hours Generated			0.6				1.1				2.6				4.0
IMA for Combined Cycle Facilities (2)			95	%			97	%			96	%			96	%
Average Capacity Factor for Combined Cycle Facilities (3)			26	%			44	%			27	%			38	%
Average Market On-Peak Spark Spreads ($/MWh) (4):
North of Path 15 (NP 15)		$	13.71			$	13.39			$	12.67			$	14.32
Average natural gas price—PG&E Citygate ($/MMBtu) (6)		$	3.27			$	2.70			$	2.70			$	2.99

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(1)	Reflects the activity for the period in which the EquiPower and Duke acquisitions were included in our consolidated results.
(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 Brayton Point and CTs.
(3)	Reflects actual production as a percentage of available capacity. The calculation excludes Brayton Point and CTs.
(4)	Reflects the 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.
(5)	Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.
(6)	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 EBITDA

TWELVE MONTHS ENDED DECEMBER 31, 2016

(UNAUDITED) (IN MILLIONS)

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

		Twelve Months Ended December 31, 2016
		PJM				NY/NE				MISO				IPH				CAISO				Other				Total
Net income attributable to Dynegy Inc.																										$	(1,240	)
Plus / (Less):
Loss attributable to noncontrolling interest																										(4		)
Income tax benefit																										(45		)
Other income and expense, net																										(65		)
Interest expense																										625
Earnings from unconsolidated investments																										(7		)
Bankruptcy reorganization items																										96
Operating income (loss)		$	414			$	(29	)		$	(745	)		$	(87	)		$	(5	)		$	(188	)		$	(640	)
Depreciation and amortization expense		349				243				54				33				53				5				737
Bankruptcy reorganization items		—				—				—				(96		)		—				—				(96		)
Earnings from unconsolidated investments		7				—				—				—				—				—				7
Other income and expense, net		9				1				—				15				12				28				65
EBITDA (1)			779				215				(691	)			(135	)			60				(155	)			73
Plus / (Less):
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest		—				—				—				2				—				—				2
Acquisition, integration and restructuring costs		—				—				—				(8		)		—				29				21
Bankruptcy reorganization items		—				—				—				96				—				—				96
Mark-to-market adjustments, including warrants		(92		)		(44		)		49				(2		)		—				(6		)		(95		)
Impairments		65				—				645				148				—				—				858
Loss (gain) on sale of assets, net		—				—				—				(1		)		—				2				1
Non-cash compensation expense		—				—				—				6				—				22				28
Other (2)		5				—				24				(4		)		(1		)		(1		)		23
Adjusted EBITDA (1)		$	757			$	171			$	27			$	102			$	59			$	(109	)		$	1,007

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

TWELVE MONTHS ENDED DECEMBER 31, 2015

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the twelve months ended December 31, 2015:

		Twelve Months Ended December 31, 2015
		PJM				NY/NE				MISO				IPH				CAISO				Other				Total
Net loss attributable to Dynegy Inc.																										$	50
Plus / (Less):
Loss attributable to noncontrolling interest																										(3		)
Income tax benefit																										(474		)
Other income and expense, net																										(54		)
Interest expense																										546
Earnings from unconsolidated investments																										(1		)
Operating income (loss)		$	423			$	(56	)		$	(92	)		$	49			$	(8	)		$	(252	)		$ 64
Depreciation and amortization expense		275				195				38				35				55				4				602
Earnings from unconsolidated investments		1				—				—				—				—				—				1
Other income and expense, net		(2		)		—				1				—				—				55				54
EBITDA (1)		697				139				(53		)		84				47				(193		)		721
Plus / (Less):
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest		12				—				—				3				—				—				15
Acquisition and integration costs		—				—				—				—				—				124				124
Mark-to-market adjustments, including warrants		(58		)		11				(6		)		(10		)		(4		)		(54		)		(121		)
Impairments		—				25				74				—				—				—				99
Loss on sale of assets, net		—				—				—				—				1				—				1
Other (2)		(2		)		—				12				—				—				1				11
Adjusted EBITDA (1)(3)		$	649			$	175			$	27			$	77			$	44			$	(122	)		$	850

__________________________________

(1)	EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 23, 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)	For the year ended December 31, 2016, Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million. For the year ended December 31, 2015, Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.
(3)	Not adjusted for these items which are excluded in 2016: (i) non-cash compensation expense of $27 million, and (ii) Wood River’s energy margin and O&M costs of $13 million.

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

THREE MONTHS ENDED DECEMBER 31, 2016

(UNAUDITED) (IN MILLIONS)

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

		Three Months Ended December 31, 2016
		PJM				NY/NE				MISO				IPH				CAISO				Other				Total
Net income attributable to Dynegy Inc.																										$	(180	)
Plus / (Less):
Loss attributable to noncontrolling interest																										(2		)
Income tax benefit																										(51		)
Other income and expense, net																										(5		)
Interest expense																										176
Bankruptcy reorganization items																										96
Operating income (loss)		$	137			$	(7	)		$	(42	)		$	—			$	(5	)		$	(49	)		$	34
Depreciation expense		90				53				31				13				19				2				208
Bankruptcy reorganization items		—				—				—				(96		)		—				—				(96		)
Other income and expense, net		—				1				—				—				—				4				5
EBITDA (1)			227				47				(11	)			(83	)			14				(43	)			151
Plus / (Less):
Adjustments to reflect Adjusted EBITDA from unconsolidated investment and exclude noncontrolling interest		—				—				—				2				—				—				2
Acquisition, integration and restructuring costs		—				—				—				—				—				8				8
Bankruptcy reorganization items		—				—				—				96				—				—				96
Mark-to-market adjustments, including warrants		(49		)		(17		)		16				1				1				(1		)		(49		)
Impairments		1				—				—				—				—				—				1
Loss on sale of assets, net		—				—				—				—				—				2				2
Non-cash compensation expense		—				—				—				6				—				4				10
Other (2)		2				(1		)		3				(2		)		(1		)		(3		)		(2		)
Adjusted EBITDA (1)		$	181			$	29			$	8			$	20			$	14			$	(33	)		$	219

DYNEGY INC.

REG G RECONCILIATIONS - ADJUSTED EBITDA

THREE MONTHS ENDED DECEMBER 31, 2015

(UNAUDITED) (IN MILLIONS)

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the three months ended December 31, 2015:

		Three Months Ended December 31, 2015
		PJM				NY/NE				MISO				IPH				CAISO				Other				Total
Net loss attributable to Dynegy Inc.																										$	(134	)
Plus / (Less):
Income tax benefit																										(1		)
Other income and expense, net																										(9		)
Interest expense																										133
Earnings from unconsolidated investments																										(2		)
Operating income (loss)		$	101			$	(55	)		$	(28	)		$	10			$	(6	)		$	(35	)		$ (13		)
Depreciation expense		79				75				7				8				18				1				188
Amortization expense		2				—				—				—				—				—				2
Other income and expense, net		(2		)		—				1				—				—				10				9
EBITDA (1)		180				20				(20		)		18				12				(24		)		186
Plus / (Less):
Adjustment to reflect Adjusted EBITDA from unconsolidated investment		4				—				—				—				—				—				4
Acquisition and integration costs		—				—				—				—				—				3				3
Mark-to-market adjustments, including warrants		(10		)		12				6				(2		)		(1		)		(11		)		(6		)
Impairments		—				25				—				—				—				—				25
Other (2)		(3		)		(1		)		13				—				1				—				10
Adjusted EBITDA (1)(3)		$	171			$	56			$	(1	)		$	16			$	12			$	(32	)		$	222

___________________________________

(1)	EBITDA and Adjusted EBITDA are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 23, 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)	For the quarter ended December 31, 2016, Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $2 million. For the quarter ended December 31, 2015, Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.
(3)	Not adjusted for these items which are excluded in 2016: (i) non-cash compensation expense of $7 million, and (ii) loss attributable to Wood River’s energy margin and O&M costs of $4 million.

DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED FREE CASH FLOW (1)
TWELVE MONTHS ENDED DECEMBER 31, 2016
(UNAUDITED) (IN MILLIONS)
		Twelve Months Ended December 31, 2016
		Dynegy				IPH				Consolidated
Adjusted EBITDA (2)		$	905			$	102			$	1,007
Interest payments		(498		)		(60		)		(558		)
Acquisition and integration payments		(19		)		—				(19		)
Adjustment related to acquired derivatives		(47		)		—				(47		)
Collateral, working capital and other		210				83				293
Net cash provided by operating activities		551				125				676
Capital expenditures		(246		)		(15		)		(261		)
Acquisition related payments		73				—				73
Adjustment related to acquired derivatives		47				—				47
Interest rate swap settlement payments		(17		)		—				(17		)
Collateral, working capital and other		(172		)		(83		)		(255		)
Adjusted Free Cash Flow (2)		$	236			$	27			$	263
Capital expenditures		$	(286	)		$	(40	)		$	(326	)
Increase in restricted cash		(2,021		)		—				(2,021		)
Distributions from unconsolidated affiliates		14				—				14
Proceeds from asset sales, net		173				3				176
Other investing		10				—				10
Net cash used in investing activities		$	(2,110	)		$	(37	)		$	(2,147	)
Proceeds from long-term borrowings, net of debt issuance costs		$	3,014			$	—			$	3,014
Repayments of borrowings		(589		)		—				(589		)
Proceeds from issuance of equity, net of issuance costs		359				—				359
Preferred stock dividends paid		(22		)		—				(22		)
Interest rate swap settlement payments		(17		)		—				(17		)
Other financing		(3		)		—				(3		)
Net cash provided by financing activities		$	2,742			$	—			$	2,742

___________________________________

(1)	This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of Adjusted Free Cash Flow. We believe it is useful to our analysts and investors to understand this relationship because it demonstrates how the cash generated by our operations is used to satisfy various liquidity requirements. A reconciliation of Adjusted Free Cash Flow from Net cash provided by operating activities is presented above. Please refer to Item 2.02 of our Form 8-K filed on February 23, 2017, for definitions, utility and uses of such non-GAAP financial measures.
(2)	Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 23, 2017, for definitions, utility and uses of such non-GAAP financial measures. See Regulation G Reconciliations - Adjusted EBITDA for the twelve months ended December 31, 2016 for a reconciliation of Adjusted EBITDA to Net loss attributable to Dynegy Inc.

DYNEGY INC.
REG G RECONCILIATIONS - ADJUSTED FREE CASH FLOW (1)
TWELVE MONTHS ENDED DECEMBER 31, 2015
(UNAUDITED) (IN MILLIONS)
		Twelve Months Ended December 31, 2015
		Dynegy				IPH				Consolidated
Adjusted EBITDA (2)		$	773			$	77			$	850
Interest payments		(441		)		(59		)		(500		)
Acquisition and integration payments		(115		)		—				(115		)
Adjustment related to acquired derivatives		(60		)		—				(60		)
Collateral, working capital and other		(37		)		(44		)		(81		)
Net cash provided by (used in) operating activities		120				(26		)		94
Capital expenditures		(175		)		(50		)		(225		)
Acquisition related payments		207				—				207
Adjustment related to acquired derivatives		60				—				60
Interest rate swap settlement payments		(17		)		—				(17		)
Collateral, working capital and other		23				44				67
Adjusted Free Cash Flow (2)		$	218			$	(32	)		$	186
Capital expenditures		$	(212	)		$	(63	)		$	(275	)
Decrease in restricted cash		5,148				—				5,148
Acquisitions, net of cash acquired		(6,078		)		—				(6,078		)
Distributions from unconsolidated affiliates		8				—				8
Other investing		3				—				3
Net cash used in investing activities		$	(1,131	)		$	(63	)		$	(1,194	)
Proceeds from long-term borrowings, net of debt issuance costs		$	66			$	—			$	66
Repayments of borrowings		(31		)		—				(31		)
Proceeds from issuance of equity, net of issuance costs		(6		)		—				(6		)
Preferred stock dividends paid		(23		)		—				(23		)
Interest rate swap settlement payments		(17		)		—				(17		)
Repurchase of common stock		(250		)		—				(250		)
Other financing		(4		)		—				(4		)
Net cash used in financing activities		$	(265	)		$	—			$	(265	)

___________________________________

(1)	This presentation is intended to demonstrate the relationship between the performance measure of Adjusted EBITDA and the liquidity measure of Adjusted Free Cash Flow. We believe it is useful to our analysts and investors to understand this relationship because it demonstrates how the cash generated by our operations is used to satisfy various liquidity requirements. A reconciliation of Adjusted Free Cash Flow from Net cash provided by (used in) operating activities is presented above. Please refer to Item 2.02 of our Form 8-K filed on February 23, 2017, for definitions, utility and uses of such non-GAAP financial measures.
(2)	Adjusted EBITDA and Adjusted Free Cash Flow are non-GAAP financial measures. Please refer to Item 2.02 of our Form 8-K filed on February 23, 2017, for definitions, utility and uses of such non-GAAP financial measures. See Regulation G Reconciliations - Adjusted EBITDA for the twelve months ended December 31, 2015 for a reconciliation of Adjusted EBITDA to Net income attributable to Dynegy Inc.

DYNEGY INC.

REG G RECONCILIATIONS - 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 February 23, 2017, for definitions, utility and uses of such non-GAAP financial measures.

View source version on businesswire.com: http://www.businesswire.com/news/home/20170223006769/en/

Dynegy Inc.

Media:

David Onufer, 713-767-5800

or

Analysts: 713-507-6466

Source: Dynegy Inc.