Dyne Therapeutics 8-K 2016 FY Other Events

Exhibit 99.2

Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following discussion should be read together with the consolidated financial statements and the notes thereto included in Exhibit 99.3 attached to this Form 8-K.  All references to notes to our consolidated financial statements refer to the financial statements included in Exhibit 99.3 attached to this Form 8-K.  All references to Form 10-K refer to our Form 10-K for the year ended December 31, 2016 which was filed with the Securities and Exchange Commission on February 24, 2017.

OVERVIEW

We are a holding company and conduct substantially all of our business operations through our subsidiaries.  Our current business operations are focused primarily on the power generation sector of the energy industry.  We currently own approximately 31,000 MW of generating capacity in twelve states and also provide retail electricity to 963,000 residential customers and 42,000 commercial, industrial, and municipal customers in Illinois, Ohio, and Pennsylvania.  We report the results of our power generation business as five separate segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) MISO, (iv) IPH and (v) CAISO.  Upon the Delta Transaction Closing Date, we added the ERCOT segment to our reporting structure.

Business Discussion

We generate earnings and cash flows in the five segments of our power generation business through sales of electric energy, capacity, and ancillary services.  Primary factors affecting our earnings and cash flows include:

·prices for power, natural gas, coal and fuel oil, and related transportation, which in turn are largely driven by supply and demand.  Demand for power can vary due to weather and general economic conditions, among other things.  Power supplies similarly vary by region and are impacted significantly by available generating capacity, transmission capacity, and federal and state regulation;

·the relationship between electricity prices and prices for natural gas and coal, commonly referred to as the “spark spread” and “dark spread,” respectively, which impacts the margin we earn on the electricity we generate; and

·our ability to enter into commercial transactions to mitigate short- and medium-term earnings volatility and our ability to manage our liquidity requirements resulting from potential changes in collateral requirements as prices move.

Other factors that have affected, and are expected to continue to affect, earnings and cash flows for the power generation business include:

·transmission constraints, congestion, and other factors that can affect the price differential between the locations where we deliver generated power and the liquid market hub;

·our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management;

·our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations;

·our ability to optimize our assets through targeted investment in cost effective technology enhancements, such as turbine uprates, or efficiency improvements;

·our ability to operate and market production from our facilities during periods of planned/unplanned electric transmission outages;

·our ability to post the collateral necessary to execute our commercial strategy;

·the cost of compliance with existing and future environmental requirements that are likely to be more stringent and more comprehensive.  Please read Item 1. Business—Environmental Matters in our Form 10-K for further discussion;

·market supply conditions resulting from federal and regional renewable power mandates and initiatives or other state-led initiatives;

·our ability to maintain coal inventory levels during critical winter and summer peak periods, which is dependent upon the reliable performance of the mines, railroads, and river transporters;

·costs of transportation related to coal deliveries;

·regional renewable energy mandates and initiatives that may alter supply conditions within an ISO and our generating units’ positions in the aggregate supply stack;

·changes in market design or associated rules in the markets in which we operate, including the resulting effect on future capacity revenues from changes in the existing bilateral MISO capacity markets and the existing bilateral CAISO resource adequacy markets;

·our ability to maintain and operate our plants in a manner that ensures we receive full capacity payments under our various tolling agreements;

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·our ability to mitigate forced outage risk, including managing risk associated with capacity performance in PJM and performance incentives in ISO-NE;

·our ability to mitigate impacts associated with expiring RMR and/or capacity contracts;

·access to capital markets on reasonable terms, interest rates and other costs of liquidity;

·interest expense; and

·income taxes, which will be impacted by our ability to realize value from our NOLs and AMT credits.

Please read “Item 1A. Risk Factors” in our Form 10-K for additional factors that could affect our future operating results, financial condition and cash flows.

LIQUIDITY AND CAPITAL RESOURCES

Overview

We maintain a strong focus on liquidity.  We believe that we have adequate resources from a combination of our current liquidity position and cash expected to be generated from future operations to fund our liquidity and capital requirements as they become due.  Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs.  Examples of working capital needs include purchases and sales of commodities and associated collateral requirements, facility maintenance costs, and other costs such as payroll.

We have used a significant portion of our balance sheet capacity to finance our previous acquisitions as we have transformed our fleet.  We are now strongly focused on strengthening our balance sheet, managing debt and improving our leverage profile through debt reduction primarily from operating cash flows, PRIDE initiatives, and select asset sales.

Liquidity.  The following table summarizes our liquidity position at December 31, 2016 and February 7, 2017 and excludes amounts classified as restricted cash.

	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

(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.  Please read Note 22—Genco Chapter 11 Bankruptcy for further discussion.

(2)The seller in the Delta Transaction 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.  Please read Note 14—Debt—Letter of Credit Facilities for further discussion.

Liquidity Highlights:

·March 2016 - Raised $198 million through a PJM Forward Capacity Agreement.

·June 2016 - Issued $460 million of Tangible Equity Units (“TEUs”).  Net proceeds received of $443 million.

·June 2016 - Entered into new $2.0 billion, seven-year term loan.  Proceeds were placed into escrow until the Delta Transaction Closing Date.  Recorded as restricted cash as of December 31, 2016.

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·June 2016 - Amended credit agreement (Third Amendment) to increase revolver capacity by $75 million, and add a $2.0 billion Tranche C Term Loan, which was effective upon the Delta Transaction Closing Date.

·October 2016 - Issued $750 million of the 2025 Senior Notes through a private placement.

·November 2016 - Sold our 50% interest in the Elwood Facility for $173 million.  $35 million of posted collateral also returned to Dynegy.

·December 2016 - Repaid $550 million of existing Term Loan B, leaving remaining balance of $224 million.

·January 2017 - Amended credit agreement (Fourth Amendment) to increase revolver capacity by $45 million and extend maturity date to 2021, which was effective upon the Delta Transaction Closing Date.

·February 2017 - Amended credit agreement (Fifth Amendment) to increase the Tranche C Term Loan  amount (June 2016) by $224 million and to reduce interest rate by 75 basis points, which was effective upon the Delta Transaction Closing Date.  This is expected to save Dynegy approximately $100 million in interest costs over the next seven years.

·February 2017 - Entered into new $50 million letter of credit, which was effective upon the Delta Transaction Closing Date.

·February 2017 - Genco emerged from bankruptcy.  We exchanged $757 million of the Genco Senior Notes for $113 million cash, $182 million in Dynegy Senior Notes and 8.7 million 2017 Warrants.

·February 2017 - Closed the Delta Transaction for a base purchase price of $3.3 billion in cash.

·February 2017 - Paid ECP $375 million for the ECP Buyout Price.

·February 2017 - Issued 13,711,152 common shares to Terawatt Holdings, LP for $150 million.

Cash Flows

The following table presents net cash from operating, investing and financing activities for the years ended December 31, 2016, 2015 and 2014:

	Year Ended December 31,
(amounts in millions)	2016			2015			2014
Net cash provided by operating activities	$	645		$	94		$	221
Net cash used in investing activities	$	(93	)	$	(6,368	)	$	(107	)
Net cash provided by (used in) financing activities	$	2,742		$	(265	)	$	6,126

Operating Activities

Changes in net cash provided by operating activities for the year ended December 31, 2016 compared to December 31, 2015 were primarily due to:

	(in millions)
Increase in cash provided by operation of our power generation facilities and retail operations	$	129
Increase in interest payments on our various debt agreements	(48		)
Decrease in payments for acquisition-related costs	96
Increase in cash provided by changes in working capital and other	391
Decrease in legal settlement received in 2015	(17		)
	$	551

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Changes in net cash provided by operating activities for the year ended December 31, 2015 compared to December 31, 2014 were primarily due to:

	(in millions)
Increase in cash provided by operation of our power generation facilities and retail operations	$	437
Increase in interest payments on our various debt agreements	(297		)
Increase in payments for acquisition-related costs	(91		)
Decrease in cash provided by changes in working capital and other	(193		)
Legal settlement received in 2015	17
	$	(127	)

Future Operating Cash Flows.  Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the prices of natural gas, coal, and fuel oil and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run-time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, and our ability to achieve the cost savings contemplated in our “PRIDE Energized” initiative.  Additionally, our future operating cash flows will also be impacted by the operations of the plants acquired in the Delta Transaction, and the interest on the related financing.

Collateral Postings.  We use a portion of our capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands.  The following table summarizes our collateral postings to third parties by legal entity at December 31, 2016 and 2015:

(amounts in millions)	December 31, 2016		December 31, 2015
Dynegy Inc.:
Cash (1)	$	99	$	159
LCs	357		475
Total Dynegy Inc.	456		634
IPH:
Cash (1) (2)	25		11
LCs	25		45
Total IPH	50		56
Total	$	506	$	690

(1)Includes broker margin as well as other collateral postings included in Prepayments and other current assets in our consolidated balance sheets.  As of December 31, 2016 and 2015, $54 million and $106 million, respectively, of cash posted as collateral were netted against Liabilities from risk management activities in our consolidated balance sheets.

(2)Includes cash of $8 million and $1 million related to Genco as of December 31, 2016 and 2015, respectively.

Collateral postings decreased from December 31, 2015 to December 31, 2016 primarily due to reduced collateral requirements for exchange-traded commodity contracts, reduced collateral for tolls, and release of collateral related to jointly owned facilities.  The fair value of our derivatives collateralized by first priority liens included liabilities of $136 million and $167 million at December 31, 2016 and 2015, respectively.

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Investing Activities

Historical Investing Cash Flows.  Changes in net cash used in investing activities for the year ended December 31, 2016 compared to December 31, 2015 were primarily due to:

	(in millions)
Decrease in cash paid for the Duke/ECP acquisitions in 2015	$		6,078
Increase in proceeds from asset sales, primarily related to the sale of our unconsolidated investment in Elwood	176
Decrease in capital expenditures	8
Increase in distributions received from our unconsolidated investment in Elwood and other investing activity	13
	$	6,275

Changes in net cash used in investing activities for the year ended December 31, 2015 compared to December 31, 2014 were primarily due to:

	(in millions)
Cash paid for the Duke/ECP acquisitions	$	(6,078		)
Increase in capital expenditures	(176			)
Decrease in proceeds from asset sales, primarily related to the sale of Black Mountain in 2014	(18			)
Distributions received from our unconsolidated investment in Elwood and other investing activity	11
	$		(6,261	)

Capital Expenditures.  Our capital spending by reportable segment is as follows:

	Year Ended December 31,						Estimated
(amounts in millions)	2016		2015		2014		2017 (2)(3)
PJM	$	160	$	106	$	12	$	134
NY/NE	64		52		7		83
ERCOT	—		—		—		117
MISO	12		56		39		34
IPH	40		63		45		76
CAISO	7		11		18		35
Other	10		13		4		11
Total (1)	$	293	$	301	$	125	$	490

(1)Includes capitalized interest of $10 million, $12 million, and $9 million for the years ended December 31, 2016, 2015 and 2014, respectively.

(2)Includes estimated expenditures of $186 million for the newly acquired assets related to the Delta Transaction.

(3)Total 2017 includes approximately $96 million of timing impacts (cash prepayments and/or cash deferrals) due to contractual service agreements.

Capital spending in our PJM, MISO, and IPH segments primarily consisted of environmental and maintenance capital projects.  Capital spending in our NY/NE and CAISO segments primarily consisted of only maintenance capital projects.

Future Investing Cash Flows.  Capital expenditures for 2017 are noted above.  The capital budget is subject to revision as opportunities arise or circumstances change.  Additionally, our future investing cash flows will be reduced by funds used for the Delta Transaction.

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Financing Activities

Historical Financing Cash Flows.  Changes in net cash provided by financing activities for the year ended December 31, 2016 compared to cash used in financing activities for the year ended December 31, 2015 were primarily due to:

	(in millions)
Increase in proceeds from long-term borrowings, net of issuance costs primarily related the issuance of the Tranche C Term Loan, 2025 Senior Notes and forward capacity agreement	$	2,948
Increase in repayment of borrowings, primarily due to the early paydown of the Tranche B-2 term loan in 2016	(558		)
Increase in proceeds from issuance of equity, net of issuance costs primarily related to TEUs	365
Decrease of repurchases of common stock related to our share repurchase program in 2015	250
Other financing activity	2
	$	3,007

Changes in net cash provided by financing activities for the year ended December 31, 2015 compared to cash provided by financing activities for the year ended December 31, 2014 were primarily due to:

	(in millions)
Decrease in the proceeds from long-term borrowings, net of issuance costs primarily related to the $5.1B Senior Notes issued in 2014	$	(4,989	)
Decrease in proceeds from equity issuances, net of issuance costs primarily related to the Duke/ECP acquisitions	(1,112		)
Increase in repayments associated with our Tranche B-2 Term Loan and inventory financing agreements	(17		)
Repurchases of common stock related to our share repurchase program	(250		)
Dividend payments on our preferred stock issued in October 2014	(23		)
	$	(6,391	)

Summarized Debt and Other Obligations.  The following table depicts our third party debt obligations, and the extent to which they are secured as of December 31, 2016 and 2015:

(amounts in millions)	December 31, 2016			December 31, 2015
Dynegy Inc.:
Secured obligations (1)	$	2,224		$	780
Unsecured obligations	6,430			5,600
Inventory Financing Agreements	129			136
Equipment Financing Agreements	97			75
Forward Capacity Agreement	219			—
Unamortized discounts and issuance costs	(120		)	(96		)
Genco:
Unsecured obligations (2)	—			825
Unamortized discounts (2)	—			(111		)
Total long-term debt	$	8,979		$	7,209

(1)At December 31, 2016, the $2 billion Finance IV term loan was secured by a first-priority lien on amounts in the applicable escrow account which was classified as long-term Restricted cash in our consolidated balance sheet.  Upon the Delta Transaction Closing Date, this debt obligation became Dynegy Inc.’s general secured obligation.  Please read Note 14—Debt for further discussion.

(2)On December 9, 2016, Genco commenced a prepackaged plan of reorganization under Chapter 11 of the Bankruptcy Code.  As a result, we reclassified the Genco unsecured obligations as Liabilities subject to compromise in our consolidated balance sheet as of December 31, 2016.  See Note 22—Genco Chapter 11 Bankruptcy for further discussion.

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Future Financing Cash Flows.  Our future cash flows from financing activities include:

·Proceeds from our issuance of our common stock to ECP;

·Principal payments on our debt instruments;

·Periodic payments to settle our interest rate swap agreements;

·Dividend payments on our mandatory convertible preferred stock;

·Payments towards the ECP Buyout and the Genco Plan; and

·Draws on our Revolving Facility to fund the Delta Transaction.

Financing Trigger Events.  Our debt instruments and certain of our other financial obligations include provisions which, if not met, could require early payment, additional collateral support or similar actions.  The trigger events include the violation of covenants (including, in the case of the Credit Agreement under certain circumstances, the senior secured leverage ratio covenant discussed below), defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events, acceleration of other financial obligations and, in the case of the Credit Agreement, change of control provisions.  We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events.  Please read Note 14—Debt for further discussion.

Financial Covenants

Credit Agreement.  Our Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including a financial covenant specifying required thresholds for our senior secured leverage ratio calculated on a rolling four quarters basis.  To the extent Dynegy uses 25 percent or more of its Revolving Facility, the Fourth Amendment of the Credit Agreement requires that Dynegy must be in compliance with the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio (as defined in the Credit Agreement).  Beginning December 31, 2016 and thereafter, the Consolidated Senior Secured Net Debt to Consolidated Adjusted EBITDA ratio is 4.00:1.00.  We were in compliance with these covenants as of and for the three year period ended December 31, 2016.

Under the terms of the Credit Agreement, existing balances under our Forward Capacity Agreement, Inventory Financing Agreements, and Equipment Financing Agreements are excluded from Net Debt.  Further, the balance of the Tranche C Term Loan is excluded from Net Debt until the closing of the Delta Transaction, whereupon it becomes Dynegy Inc.’s secured obligation.

Please read Note 14—Debt for further discussion.

Dividends.  We have paid no cash dividends on our common stock and have no current intention of doing so.  Any future determinations to pay cash dividends will be at the discretion of our Board of Directors, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board of Directors.

We pay quarterly dividends on our Mandatory Convertible Preferred Stock on February 1, May 1, August 1, and November 1 of each year, if declared by our Board of Directors.  For the years ended December 31, 2016 and 2015, we paid an aggregate of $22 million and $23 million in dividends, respectively.  No dividends were paid during 2014.

On January 3, 2017, our Board of Directors declared a dividend on our Mandatory Convertible Preferred Stock of $1.34 per share, or approximately $5 million in the aggregate.  The dividend is for the period beginning on November 1, 2016 and ending on January 31, 2017.  Such dividends were paid on February 1, 2017, to stockholders of record as of January 15, 2017.

Credit Ratings

Our credit rating status is currently “non-investment grade” and our current ratings are as follows:

	Moody’s	S&P
Dynegy Inc.:
Corporate Family Rating	B2	B+
Senior Secured	Ba3	BB
Senior Unsecured	B3	B+

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Disclosure of Contractual Obligations and Other Environmental Obligations

We have incurred various contractual obligations, financial commitments, and other environmental obligations in the normal course of our operations and financing activities.  Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements.  These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities.  Our other environmental obligations consist of ELG expenditures and AROs.

The following table summarizes the contractual obligations and other environmental obligations of the Company and its consolidated subsidiaries as of December 31, 2016.  The table below does not include interest payment obligations related to the Genco Senior Notes or obligations associated with the Delta Transaction.  Cash obligations reflected are not discounted and do not include accretion or dividends.

	Expiration by Period
(amounts in millions)	Total		Less than 1 Year		1 - 3 Years		3 - 5 Years		More than 5 Years
Long-term debt (including current portion)	$	9,002	$	188	$	2,395	$	264	$	6,155
Interest payments on debt	3,448		584		1,155		832		877
Coal purchase commitments	827		359		342		126		—
Coal transportation	823		101		164		167		391
Contractual service agreements	482		42		163		240		37
Gas purchase commitments	420		411		9		—		—
Gas transportation	173		36		53		37		47
Pension funding obligations	248		7		45		46		150
Operating leases	53		11		10		10		22
Other obligations	85		28		24		7		26
Total contractual obligations	15,561		1,767		4,360		1,729		7,705
Total ELG expenditures (1)	308		41		178		49		40
Total AROs (1)	553		27		95		95		336
Total contractual and other environmental obligations	$	16,422	$	1,835	$	4,633	$	1,873	$	8,081

(1)See Item 1. Business-Environmental Matters in our Form 10-K for further discussion.

Long-Term Debt (including Current Portion).  Long-term debt includes amounts related to the Dynegy Senior Notes, the 2025 Senior Notes, the Credit Agreement, the Finance IV Credit Agreement, the Inventory Financing Agreements, the Forward Capacity Agreement, and the Amortizing Notes.  Amounts do not include unamortized discounts.  Please read Note 14—Debt for further discussion.

Interest Payments on Debt.  Interest payments on debt represent estimated periodic interest payment obligations associated with the Dynegy Senior Notes, the 2025 Senior Notes, the Credit Agreement, the Finance IV Credit Agreement, the Inventory Financing Agreements, and the Amortizing Notes.  Amounts include the impact of interest rate swap agreements.  Please read Note 14—Debt for further discussion.

Coal Purchase Commitments.  At December 31, 2016, our subsidiaries had contracts in place to purchase coal for various generation facilities.  The amounts in the table reflect our minimum purchase obligations.  To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar.

Coal Transportation.  At December 31, 2016, we had long-term coal transportation contracts in place.  We also had long-term rail car leases in place.  The amounts included in Coal transportation reflect our minimum purchase obligations based on the terms of the contracts.

Contractual Service Agreements.  Contractual service agreements represent obligations with respect to long-term plant maintenance agreements.  Recently we have undertaken several measures to restructure some of our existing maintenance service agreements with our turbine service providers.  The table above includes our current estimate of payments under the contracts through 2048 based on anticipated timing of outages and are subject to change as outage dates move.  As of December 31, 2016, our

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obligation with respect to these restructured agreements is limited to the termination payments, which are approximately $410 million in the event all contracts are terminated by us.  In addition during this year, we have committed to securing capital spares for our gas-fueled generation fleet to help minimize production disturbances.  As of December 31, 2016, we have obligations to purchase spare parts of $24 million with payments made through 2026, of which $11 million reflects spare parts received.  Please read Note 17—Commitments and Contingencies—Other Commitments and Contingencies for further discussion.

Gas Purchase Commitments.  At December 31, 2016, our subsidiaries had contracts in place to purchase gas for various generation facilities.  The amounts in the table reflect our minimum purchase obligations.

Gas Transportation.  Gas transportation includes fixed transport capacity obligations associated with fuel procurement for our gas plants.

Pension Funding Obligations.  Amounts include our minimum required contributions to our defined benefit pension plans through 2026 as determined by our actuary and are subject to change based on actual results of the plan.  We may elect to make voluntary contributions in 2017 which would decrease future funding obligations.  Please read Note 19—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

Operating Leases.  Operating leases include minimum lease payment obligations associated with office space, office equipment, and land leases.  Also included in operating leases is one charter agreement previously utilized in our former global liquids business.

Other Obligations.  Other obligations primarily include the following:

·$31 million related to limestone purchase commitments;

·$22 million related to interconnection services; and

·other miscellaneous items which are individually insignificant.

Commitments and Contingencies

Please read Note 17—Commitments and Contingencies, for further discussion of our material commitments and contingencies.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements at December 31, 2016.

RESULTS OF OPERATIONS

Overview and Discussion of Comparability of Results.  In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the years ended December 31, 2016, 2015 and 2014.  At the end of this section, we have included our business outlook for each segment.

We report the results of our power generation business primarily as five separate segments in our consolidated financial statements: (i) PJM, (ii) NY/NE, (iii) MISO, (iv) IPH and (v) CAISO.  Our consolidated financial results also reflect corporate-level expenses such as general and administrative expense, interest expense and income tax benefit (expense).  All references to hedging within our Annual Report on Form 10-K filed with the Securities and Exchange Commission (“SEC”) on February 24,  2017, and our Management’s Discussion and Analysis of Financial Condition and Results of Operations and consolidated financial statements included in Exhibits 99.2 and 99.3, respectively, attached to this Form 8-K relate to economic hedging activities as we do not elect hedge accounting.

Non-GAAP Measures.  In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA as performance measures, and Adjusted Free Cash Flow (“FCF”) as a liquidity measure.  These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business.  These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy and must be considered in conjunction with GAAP measures.

We believe that the non-GAAP measures disclosed in our filings are only useful as an additional tool to help management and investors make informed decisions about our financial and operating performance and liquidity.  By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures.  In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies’ non-GAAP financial measures having the same or similar names.  We

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strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure.

EBITDA and Adjusted EBITDA.  We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense.  We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of certain assets, (ii) the impacts of mark-to-market changes on derivatives related to our generation portfolio, as well as warrants, (iii) the impact of impairment charges and certain other costs such as those associated with acquisitions, and (iv) other material items.  Beginning in 2016, Adjusted EBITDA also excludes non-cash compensation expense.

We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance.  We consider EBITDA as another way to measure financial performance on an ongoing basis.  Adjusted EBITDA is meant to reflect the operating performance of our entire power generation fleet for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges and other items that could be considered “non-operating” or “non-core” in nature.  Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers, and evaluate overall financial performance, we believe they provide useful information for our investors.  In addition, many analysts, fund managers and other stakeholders who communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format.

As prescribed by the SEC, when EBITDA or Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss).  Management does not analyze interest expense and income taxes on a segment level; therefore, the most directly comparable GAAP financial measure to EBITDA or Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss).

Adjusted Free Cash Flow.  We define Adjusted FCF as cash flow from operating activities adjusted for non-discretionary maintenance and environmental capital expenditures and the cash impact of acquisition-related costs.  Adjusted FCF includes receipts or payments related to interest rate swaps, and excludes the impact of changes in collateral, working capital and other receipts and payments.  In 2014, Adjusted FCF did not exclude working capital and other charges.  The most directly comparable GAAP financial measure is cash flows from operating activities.

Dynegy’s non-GAAP liquidity measure may not be representative of the amount of residual cash flow that is available to Dynegy for discretionary expenditures, since it may not include deductions for mandatory debt service requirements and other non-discretionary expenditures.  Management believes, however, that Dynegy’s non-GAAP liquidity measure is useful to investors and the company as a liquidity measure because it measures the cash generating ability of Dynegy’s assets.  Dynegy measures Adjusted FCF on a consolidated basis.

The following table presents Adjusted FCF from operations for the years ended December 31, 2016, 2015 and 2014:

	Year Ended December 31,
(amounts in millions)	2016			2015			2014 (1)
Net cash provided by operating activities	$	645		$	94		$	221
Capital expenditures	(228		)	(251		)	(116		)
Acquisition related payments	73			272			—
Adjustment related to acquired derivatives	47			60			—
Interest rate swap settlement payments	(17		)	(17		)	(18		)
Collateral, working capital and other	(257		)	28			17
Adjusted Free Cash Flow	$	263		$	186		$	104

(1)Adjusted FCF for 2014 included working capital and other of $46 million; such amounts were excluded from Adjusted FCF in 2016 and 2015.

10

Consolidated Summary Financial Information—Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

We completed the EquiPower Acquisition and Duke Midwest Acquisition on April 1, 2015 and April 2, 2015, respectively; therefore, the results of these plants within our PJM and NY/NE segments are only included in our consolidated results from their respective acquisition dates.  Please read Note 3—Acquisitions—EquiPower Acquisition and Duke Midwest Acquisition for further discussion.  The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2016 and 2015, respectively:

							Favorable
	Year Ended December 31,						(Unfavorable)
(amounts in millions)	2016			2015			$ Change
Revenues
Energy	$	3,373		$	3,054		$	319
Capacity	773			671			102
Mark-to-market income, net	136			127			9
Contract amortization	(80		)	(83		)	3
Other	116			101			15
Total revenues	4,318			3,870			448
Cost of sales, excluding depreciation expense	(2,281		)	(2,028		)	(253		)
Gross margin	2,037			1,842			195
Operating and maintenance expense	(940		)	(839		)	(101		)
Depreciation expense	(689		)	(587		)	(102		)
Impairments	(858		)	(99		)	(759		)
Loss on sale of assets, net	(1		)	(1		)	—
General and administrative expense	(161		)	(128		)	(33		)
Acquisition and integration costs	(11		)	(124		)	113
Other	(17		)	—			(17		)
Operating income (loss)	(640		)	64			(704		)
Bankruptcy reorganization items	(96		)	—			(96		)
Earnings from unconsolidated investments	7			1			6
Interest expense	(625		)	(546		)	(79		)
Other income and expense, net	65			54			11
Loss before income taxes	(1,289		)	(427		)	(862		)
Income tax benefit	45			474			(429		)
Net income (loss)	(1,244		)	47			(1,291		)
Less: Net loss attributable to noncontrolling interest	(4		)	(3		)	(1		)
Net income (loss) attributable to Dynegy Inc.	$	(1,240	)	$	50		$	(1,290	)

11

The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	2,202		$	837		$	383		$	754		$	142		$	—		$	4,318
Cost of sales, excluding depreciation expense	(985		)	(486		)	(291		)	(450		)	(69		)	—			(2,281		)
Gross margin	1,217			351			92			304			73			—			2,037
Operating and maintenance expense	(391		)	(165		)	(143		)	(204		)	(36		)	(1		)	(940		)
Depreciation expense	(346		)	(215		)	(49		)	(32		)	(42		)	(5		)	(689		)
Impairments	(65		)	—			(645		)	(148		)	—			—			(858		)
Gain (loss) on sale of assets, net	—			—			—			1			—			(2		)	(1		)
General and administrative expense	—			—			—			—			—			(161		)	(161		)
Acquisition and integration costs	—			—			—			8			—			(19		)	(11		)
Other (1)	(1		)	—			—			(16		)	—			—			(17		)
Operating income (loss)	$	414		$	(29	)	$	(745	)	$	(87	)	$	(5	)	$	(188	)	$	(640	)
	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	1,716		$	695		$	482		$	799		$	178		$	—		$	3,870
Cost of sales, excluding depreciation expense	(716		)	(414		)	(287		)	(506		)	(105		)	—			(2,028		)
Gross margin	1,000			281			195			293			73			—			1,842
Operating and maintenance expense	(296		)	(126		)	(174		)	(215		)	(32		)	4			(839		)
Depreciation expense	(281		)	(186		)	(39		)	(29		)	(48		)	(4		)	(587		)
Impairments	—			(25		)	(74		)	—			—			—			(99		)
Loss on sale of assets, net	—			—			—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			—			—			(128		)	(128		)
Acquisition and integration costs	—			—			—			—			—			(124		)	(124		)
Operating income (loss)	$	423		$	(56	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64

Discussion of Consolidated Results of Operations

Revenues.  The following table summarizes the change in revenues by segment:

(amounts in millions)	PJM		��	NY/NE			MISO			IPH			CAISO			Total
Revenues, net of hedges, attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	467		$	194		$	—		$	—		$	—		$	661
Higher (lower) power prices and spark spreads	(66		)	(26		)	(16		)	38			—			(70		)
Higher (lower) generation volumes (1)	122			(64		)	(37		)	(100		)	(39		)	(118		)
Higher (lower) capacity revenues	(36		)	(17		)	10			16			9			(18		)
Change in MTM value of derivative transactions	(61		)	41			(55		)	(8		)	(4		)	(87		)
Lower (higher) contract amortization	9			(4		)	—			12			(3		)	14
Other (2)	51			18			(1		)	(3		)	1			66
Total change in revenues	$	486		$	142		$	(99	)	$	(45	)	$	(36	)	$	448

(1)Decrease due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns; PJM segment increased due to higher demand for gas-fired generation as a result lower gas prices.

(2)Other primarily consists of ancillary, tolling, transmission and gas revenues.

12

Cost of Sales.  The following table summarizes the change in cost of sales by segment:

(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Total
Cost of sales attributable to Duke Midwest and EquiPower plants for the first quarter of 2016	$	157		$	128		$	—		$	—		$	—		$	285
Lower prices	(95		)	(13		)	(2		)	(11		)	(7		)	(128		)
Higher (lower) generation volumes (1)	133			(23		)	(21		)	(83		)	(19		)	(13		)
Higher (lower) transportation costs (2)	3			(16		)	—			—			(1		)	(14		)
Lower (higher) contract amortization	20			(3		)	6			10			—			33
Other (3)	51			(1		)	21			28			(9		)	90
Total change in cost of sales	$	269		$	72		$	4		$	(56	)	$	(36	)	$	253

(1)Lower generation volumes primarily due to mild winter weather which decreased demand across our key markets as well as planned outages and shutdowns; PJM segment increased as a result of higher plant availability and demand.

(2)Lower transportation costs primarily at our NY/NE segment due to reduced demand charge payment at Independence.

(3)Other primarily consists of transmission expenses, gas purchases, and various non-recurring expenses.

Operating and Maintenance Expense.  Operating and maintenance expense increased by $101 million primarily due to  the Duke Midwest and EquiPower plants for the first quarter of 2016 and planned major maintenance outages at our PJM and NY/NE segments, partially offset by a decrease primarily due to plant shutdowns at our MISO segment.

Depreciation Expense.  Depreciation expense increased by $102 million primarily due to Duke Midwest and EquiPower plants for the first quarter of 2016, offset by a decrease due to a lower depreciable base of certain generation facilities as a result of impairments at our MISO and NY/NE segments.

Impairments.  Impairments increased by $759 million due to the following (amounts in millions):

		Year Ended December 31,
Facility	Segment	2016		2015
Stuart	PJM	$	56	$	—
Elwood unconsolidated investment	PJM	9		—
Baldwin	MISO	645		—
Wood River	MISO	—		74
Newton FGD	IPH	148		—
Brayton Point	NY/NE	—		25
Total		$	858	$	99

Please read Note 9—Property, Plant and Equipment for further discussion.

General and Administrative Expense.  General and administrative expense increased by $33 million primarily due to higher overhead associated with the Acquisitions and higher legal fees primarily related to costs associated with the Genco reorganization that were incurred prior to Genco’s filing of the Bankruptcy Petition.  Please read Note 22—Genco Chapter 11 Bankruptcy—Reorganization items for further discussion.

Acquisition and Integration Costs.  Acquisition and integration costs decreased by $113 million due to $53 million in lower advisory and consulting fees, $12 million in severance, retention, and payroll costs, and $48 million in Bridge Loan financing fees related to the Acquisitions in 2015.

Other.  Other of $17 million for the year ended December 31, 2016 is primarily due to a charge associated with the termination of an above market coal supply contract.

Bankruptcy Reorganization Items.  Bankruptcy reorganization items increased by $96 million primarily due to the write-off of the remaining unamortized discount related to the Genco Senior Notes and legal costs associated with the Genco reorganization that were incurred after Genco’s filing of the Bankruptcy Petition.  Please read Note 22—Genco Chapter 11 Bankruptcy—Reorganization items for further discussion.

Interest Expense.  Interest expense increased by $79 million primarily due to interest on our Tranche C Term Loan, 2025 Senior Notes, and Amortizing Notes.  Please read Note 14—Debt for further discussion.

13

Other Income and Expense, Net.  Other income and expense, net increased by $11 million primarily due to:

	(in millions)
Gain related to the PPE settlement (Note 17)	$	20
Previously contingent proceeds received related to the AER Acquisition	$	14
Supplier settlement	$	12
Casualty loss insurance reimbursement, net	$	11
Change in fair value of our common stock warrants	$	(48	)

Income Tax Benefit.  The net unfavorable change of $429 million was a result of a $459 million benefit due to a release of the valuation allowance that occurred during the year ended December 31, 2015.  The remaining $30 million favorable change was for discrete items including a 2016 change in our corporate tax structure, a 2015 state law change in Connecticut, the benefit from accelerating the minimum tax credit and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance.  Please read Note 3—Acquisitions for further discussion of the release of the valuation allowance.

As of December 31, 2016, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more likely than not that our net deferred tax assets can be realized in the future.  Please read Note 15—Income Taxes for further discussion.

Net Income (Loss) Attributable to Dynegy Inc.  The $1.290 billion decrease was primarily due to (i) $759 million in higher impairment charges recorded in 2016 compared to 2015, and (ii) income from a $459 million deferred tax valuation allowance release in 2015, which did not reoccur in 2016, partially offset by a $156 million contribution from Duke Midwest and EquiPower plants in the first quarter of 2016.

Adjusted EBITDA — Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

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

	Year Ended December 31, 2016
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Net loss attributable to Dynegy Inc.																			$	(1,240	)
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	779			215			(691		)	(135		)	60			(155		)	73
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 (1)	5			—			24			(4		)	(1		)	(1		)	23
Adjusted EBITDA	$	757		$	171		$	27		$	102		$	59		$	(109	)	$	1,007

14

(1)Other includes an adjustment to exclude Wood River’s energy margin and O&M costs of $23 million.

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

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Net income attributable to Dynegy Inc.																			$	50
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	697			139			(53		)	84			47			(193		)	721
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 (1)	(2		)	—			12			—			—			1			11
Adjusted EBITDA (2)	$	649		$	175		$	27		$	77		$	44		$	(122	)	$	850

(1)Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.

(2)Not adjusted for the following 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.

Adjusted EBITDA increased by $157 million primarily due to a $209 million contribution from Duke Midwest and EquiPower plants in the first quarter of 2016.  The offsetting $52 million decrease was driven by (i) lower energy margin, net of hedges, at the NY/NE and CAISO segments as a result of mild winter weather which decreased demand across our key markets and lowered power prices and spark spreads, (ii) lower energy margin, net of hedges, at the MISO segment due to higher fuel costs as a result of the 2015 coal inventory management efforts and an inventory flyover adjustment, and (iii) lower capacity revenues as a result of performance penalties and lower pricing at the PJM segment and lower pricing at the NY/NE segment.  Please read Discussion of Segment Adjusted EBITDA for further information.

15

Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

PJM Segment

The following table provides summary financial data regarding our PJM segment results of operations for the years ended December 31, 2016 and 2015, respectively:

							Favorable
	Year Ended December 31,						(Unfavorable)
(dollars in millions, except for price information)	2016			2015			$ Change
Operating Revenues
Energy	$	1,692		$	1,266		$	426
Capacity	398			345			53
Mark-to-market income, net	118			105			13
Contract amortization	(47		)	(47		)	—
Other	41			47			(6		)
Total operating revenues	2,202			1,716			486
Operating Costs
Cost of sales	(1,033		)	(771		)	(262		)
Contract amortization	48			55			(7		)
Total operating costs	(985		)	(716		)	(269		)
Gross margin	1,217			1,000			217
Operating and maintenance expense	(391		)	(296		)	(95		)
Depreciation expense	(346		)	(281		)	(65		)
Impairments	(65		)	—			(65		)
Other	(1		)	—			(1		)
Operating income	414			423			(9		)
Depreciation and amortization expense	349			275			74
Earnings from unconsolidated investments	7			1			6
Other income and expense, net	9			(2		)	11
EBITDA	779			697			82
Adjustment to reflect Adjusted EBITDA from unconsolidated investment	—			12			(12		)
Mark-to-market adjustments	(92		)	(58		)	(34		)
Impairments	65			—			65
Other	5			(2		)	7
Adjusted EBITDA	$	757		$	649		$	108
Million Megawatt Hours Generated (1)	52.8			40.4			12.4
IMA (1)(2):
Combined-Cycle Facilities	97		%	99		%
Coal-Fired Facilities	80		%	74		%
Average Capacity Factor (1)(3):
Combined-Cycle Facilities	74		%	75		%
Coal-Fired Facilities	53		%	51		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
PJM West	$	22.62		$	25.24		$	(2.62	)
AD Hub	$	22.52		$	28.22		$	(5.70	)
Average Market On-Peak Power Prices ($/MWh) (5):
PJM West	$	34.65		$	43.21		$	(8.56	)
AD Hub	$	32.93		$	37.52		$	(4.59	)
Average natural gas price—TetcoM3 ($/MMBtu) (6)	$	1.72		$	2.57		$	(0.85	)

16

(1)Reflects the activity for the period in which the 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 CTs.

(3)Reflects actual production as a percentage of available capacity.  The calculation excludes 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.

Operating income decreased by $9 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	174
Lower capacity revenues as a result of lower pricing and performance penalties	$	(36	)
Change in MTM value of derivative transactions	$	(61	)
Higher O&M costs associated with planned major maintenance outages	$	(25	)
Impairment charges incurred in 2016	$	(65	)

Adjusted EBITDA increased by $108 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	170
Higher energy margin, net of hedges, due to the following:
Higher generation volumes as a result of higher plant availability	$	21
Lower power prices and spark spreads as a result of mild weather	$	(10	)
Lower capacity revenues as a result of lower pricing and performance penalties	$	(36	)
Higher O&M costs associated with planned major maintenance outages	$	(23	)

17

NY/NE Segment

The following table provides summary financial data regarding our NY/NE segment results of operations for the years ended December 31, 2016 and 2015, respectively:

							Favorable
	Year Ended December 31,						(Unfavorable)
(dollars in millions, except for price information)	2016			2015			$ Change
Operating Revenues
Energy	$	570		$	524		$	46
Capacity	168			154			14
Mark-to-market income, net	65			2			63
Contract amortization	(10		)	(4		)	(6		)
Other	44			19			25
Total operating revenues	837			695			142
Operating Costs
Cost of sales	(469		)	(410		)	(59		)
Contract amortization	(17		)	(4		)	(13		)
Total operating costs	(486		)	(414		)	(72		)
Gross margin	351			281			70
Operating and maintenance expense	(165		)	(126		)	(39		)
Depreciation expense	(215		)	(186		)	(29		)
Impairments	—			(25		)	25
Operating loss	(29		)	(56		)	27
Depreciation and amortization expense	243			195			48
Other income and expense, net	1			—			1
EBITDA	215			139			76
Mark-to-market adjustments	(44		)	11			(55		)
Impairments	—			25			(25		)
Adjusted EBITDA	$	171		$	175		$	(4	)
Million Megawatt Hours Generated (1)	16.9			15.7			1.2
IMA for Combined-Cycle Facilities (1)(2)	96		%	98		%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)	48		%	56		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
New York—Zone A	$	24.18		$	27.60		$	(3.42	)
Mass Hub	$	13.80		$	15.23		$	(1.43	)
Average Market On-Peak Power Prices ($/MWh) (5):
Mass Hub	$	35.52		$	48.96		$	(13.44	)
Average natural gas price—Algonquin Citygates ($/MMBtu) (6)	$	3.10		$	4.82		$	(1.72	)

18

(1)Reflects the activity for the period in which the 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 our Brayton Point facility.

(3)Reflects actual production as a percentage of available capacity.  The calculation excludes our Brayton Point facility.

(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.

Operating loss decreased by $27 million primarily due to the following:

	(in millions)
Loss attributable to Duke Midwest and EquiPower plants in the first quarter of 2016	$	(16	)
Lower energy margin, net of hedges, due to lower spark spreads and lower generation volumes	$	(39	)
Higher O&M costs associated with planned major maintenance outages	$	(8	)
Change in MTM value of derivative transactions	$	41
Impairment charges incurred in 2015	$	25
Lower depreciation due to a fourth quarter 2015 impairment of our Brayton Point facility	$	22

Adjusted EBITDA decreased by $4 million primarily due to the following:

	(in millions)
Contribution from Duke Midwest and EquiPower plants in the first quarter of 2016	$	39
Lower energy margin, net of hedges, due to the following:
Lower spark spreads as a result of mild winter weather	$	(14	)
Lower generation volumes as a result of more planned outages	$	(25	)
Lower capacity revenues as a result of lower pricing	$	(17	)
Higher tolling revenues as a result of a 2016 tolling contract	$	12
Higher O&M costs associated with planned major maintenance outages	$	(5	)

19

MISO Segment

The following table provides summary financial data regarding our MISO segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2016			2015			$ Change
Operating Revenues
Energy	$	404		$	458		$	(54	)
Capacity	27			17			10
Mark-to-market income (loss), net	(49		)	6			(55		)
Other	1			1			—
Total operating revenues	383			482			(99		)
Operating Costs
Cost of sales	(291		)	(293		)	2
Contract amortization	—			6			(6		)
Total operating costs	(291		)	(287		)	(4		)
Gross margin	92			195			(103		)
Operating and maintenance expense	(143		)	(174		)	31
Depreciation expense	(49		)	(39		)	(10		)
Impairments	(645		)	(74		)	(571		)
Operating loss	(745		)	(92		)	(653		)
Depreciation and amortization expense	54			38			16
Other income and expense, net	—			1			(1		)
EBITDA	(691		)	(53		)	(638		)
Mark-to-market adjustments	49			(6		)	55
Impairments	645			74			571
Other	24			12			12
Adjusted EBITDA (1)	$	27		$	27		$	—
Million Megawatt Hours Generated	14.4			15.9			(1.5		)
IMA for Coal-Fired Facilities (2)	89		%	87		%
Average Capacity Factor for Coal-Fired Facilities (3)	63		%	61		%
Average Market On-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub)	$	33.71		$	33.50		$	0.21
Commonwealth Edison (NI Hub)	$	31.98		$	33.98		$	(2.00	)

(1)2015 is not adjusted for Wood River’s energy margin and O&M costs of $13 million which are excluded in 2016.

(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.

(3)Reflects actual production as a percentage of available capacity.

(4)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

20

Operating loss increased by $653 million primarily due to the following:

	(in millions)
Higher impairment charges on our Baldwin facility in 2016 compared to that on our Wood River facility in 2015	$	(571	)
Lower energy margin, net of hedges, due to lower generation volumes, lower power prices and higher fuel costs	$	(52	)
Change in MTM value of derivative transactions	$	(55	)
Lower O&M costs due to planned shutdowns and fewer planned outages	$	31

Adjusted EBITDA, excluding Wood River, was unchanged from 2015 but was impacted by the following:

	(in millions)
Lower energy margin, net of hedges, due to the following:
Higher fuel costs incurred in 2016 as a result of 2015 coal inventory management efforts and an inventory flyover adjustment	$	(13	)
Lower power prices as a result of mild winter weather	$	(4	)
Lower generation volumes as a result of mild winter weather and shutdowns	$	(8	)
Higher capacity revenues due to higher volumes	$	12
Lower O&M costs due to fewer planned outages	$	12

21

IPH Segment

The following table provides summary financial data regarding our IPH segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2016			2015			$ Change
Operating Revenues
Energy	$	619		$	681		$	(62	)
Capacity	140			124			16
Mark-to-market income, net	2			10			(8		)
Contract amortization	(13		)	(25		)	12
Other	6			9			(3		)
Total operating revenues	754			799			(45		)
Operating Costs
Cost of sales	(471		)	(537		)	66
Contract amortization	21			31			(10		)
Total operating costs	(450		)	(506		)	56
Gross margin	304			293			11
Operating and maintenance expense	(204		)	(215		)	11
Depreciation expense	(32		)	(29		)	(3		)
Impairments	(148		)	—			(148		)
Acquisition and integration costs	8			—			8
Gain on sale of assets, net	1			—			1
Other	(16		)	—			(16		)
Operating income (loss)	(87		)	49			(136		)
Depreciation and amortization expense	33			35			(2		)
Bankruptcy reorganization items	(96		)	—			(96		)
Other income and expense, net	15			—			15
EBITDA	(135		)	84			(219		)
Adjustment to exclude noncontrolling interest	2			3			(1		)
Acquisition, integration and restructuring costs	(8		)	—			(8		)
Bankruptcy reorganization items	96			—			96
Mark-to-market adjustments	(2		)	(10		)	8
Impairments	148			—			148
Gain on sale of assets, net	(1		)	—			(1		)
Non-cash compensation expense	6			—			6
Other	(4		)	—			(4		)
Adjusted EBITDA	$	102		$	77		$	25
Million Megawatt Hours Generated	15.4			18.5			(3.1		)
IMA for IPH Facilities (1)	89		%	89		%
Average Capacity Factor for IPH Facilities (2)	46		%	52		%
Average Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub)	$	33.71		$	33.50		$	0.21
Commonwealth Edison (NI Hub)	$	31.98		$	33.98		$	(2.00	)

22

(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 CTs.

(2)Reflects actual production as a percentage of available capacity.  The calculation excludes CTs.

(3)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

Operating loss for 2016 was $87 million compared to operating income of $49 million for 2015.  The $136 million decrease was primarily due to the following:

	(in millions)
Higher capacity revenues due to higher pricing and volumes	$	16
Lower O&M costs primarily due to fewer planned outages	$	11
Impairment charges incurred in 2016	$	(148	)

Adjusted EBITDA increased by $25 million primarily due to the following:

	(in millions)
Higher capacity revenues due to higher pricing and volumes	$	16
Lower O&M costs primarily due to fewer planned outages	$	15

23

CAISO Segment

The following table provides summary financial data regarding our CAISO segment results of operations for the years ended December 31, 2016 and 2015, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2016			2015			$ Change
Operating Revenues
Energy	$	88		$	125		$	(37	)
Capacity	40			31			9
Mark-to-market income, net	—			4			(4		)
Contract amortization	(10		)	(7		)	(3		)
Other	24			25			(1		)
Total operating revenues	142			178			(36		)
Operating Costs
Cost of sales	(69		)	(105		)	36
Total operating costs	(69		)	(105		)	36
Gross margin	73			73			—
Operating and maintenance expense	(36		)	(32		)	(4		)
Depreciation expense	(42		)	(48		)	6
Loss on sale of assets, net	—			(1		)	1
Operating loss	(5		)	(8		)	3
Depreciation and amortization expense	53			55			(2		)
Other income and expense, net	12			—			12
EBITDA	60			47			13
Mark-to-market adjustments	—			(4		)	4
Loss on sale of assets, net	—			1			(1		)
Other	(1		)	—			(1		)
Adjusted EBITDA	$	59		$	44		$	15
Million Megawatt Hours Generated	2.6			4.0			(1.4		)
IMA for Combined-Cycle Facilities (1)	96		%	96		%
Average Capacity Factor for Combined-Cycle Facilities (2)	27		%	38		%
Average Market On-Peak Spark Spreads ($/MWh) (3):
North of Path 15 (NP 15)	$	12.67		$	14.32		$	(1.65	)
Average natural gas price—PG&E Citygate ($/MMBtu) (4)	$	2.70		$	2.99		$	(0.29	)

(1)IMA is an internal measurement calculation that reflects the percentage of generation available 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 CTs.

(2)Reflects actual production as a percentage of available capacity.  The calculation excludes CTs.

(3)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.

(4)Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

24

Operating loss decreased by $3 million primarily due to lower energy margin, net of hedges, of $7 million primarily due to lower generation volumes.

Adjusted EBITDA increased by $15 million primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of higher fuel costs	$	(7	)
Higher capacity revenues due to higher contracted volumes	$	9
Supplier settlement	$	12

Consolidated Summary Financial Information—Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

We completed the EquiPower Acquisition and Duke Midwest Acquisition on April 1, 2015 and April 2, 2015, respectively; therefore, the results of these plants within our PJM and NY/NE segments are only included in our consolidated results from their respective acquisition dates.  Please read Note 3—Acquisitions—EquiPower Acquisition and Duke Midwest Acquisition for further discussion.  The following table provides summary financial data regarding our consolidated results of operations for the years ended December 31, 2015 and 2014, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(amounts in millions)	2015			2014			$ Change
Revenues
Energy	$	3,054		$	2,290		$	764
Capacity	671			293			378
Mark-to-market income (loss), net	127			(28		)	155
Contract amortization	(83		)	(111		)	28
Other	101			53			48
Total revenues	3,870			2,497			1,373
Cost of sales, excluding depreciation expense	(2,028		)	(1,661		)	(367		)
Gross margin	1,842			836			1,006
Operating and maintenance expense	(839		)	(477		)	(362		)
Depreciation expense	(587		)	(247		)	(340		)
Impairments	(99		)	—			(99		)
Gain (loss) on sale of assets, net	(1		)	18			(19		)
General and administrative expense	(128		)	(114		)	(14		)
Acquisition and integration costs	(124		)	(35		)	(89		)
Operating income (loss)	64			(19		)	83
Bankruptcy reorganization items	—			3			(3		)
Earnings from unconsolidated investments	1			10			(9		)
Interest expense	(546		)	(223		)	(323		)
Other income and expense, net	54			(39		)	93
Loss before income taxes	(427		)	(268		)	(159		)
Income tax benefit	474			1			473
Net income (loss)	47			(267		)	314
Less: Net income (loss) attributable to noncontrolling interest	(3		)	6			(9		)
Net income (loss) attributable to Dynegy Inc.	$	50		$	(273	)	$	323

25

The following tables provide summary financial data regarding our operating income (loss) by segment for the years ended December 31, 2015 and 2014, respectively:

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	1,716		$	695		$	482		$	799		$	178		$	—		$	3,870
Cost of sales, excluding depreciation expense	(716		)	(414		)	(287		)	(506		)	(105		)	—			(2,028		)
Gross margin	1,000			281			195			293			73			—			1,842
Operating and maintenance expense	(296		)	(126		)	(174		)	(215		)	(32		)	4			(839		)
Depreciation expense	(281		)	(186		)	(39		)	(29		)	(48		)	(4		)	(587		)
Impairments	—			(25		)	(74		)	—			—			—			(99		)
Loss on sale of assets, net	—			—			—			—			(1		)	—			(1		)
General and administrative expense	—			—			—			—			—			(128		)	(128		)
Acquisition and integration costs	—			—			—			—			—			(124		)	(124		)
Operating income (loss)	$	423		$	(56	)	$	(92	)	$	49		$	(8	)	$	(252	)	$	64

	Year Ended December 31, 2014
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Revenues	$	331		$	457		$	605		$	846		$	258		$	—		$	2,497
Cost of sales, excluding depreciation expense	(215		)	(313		)	(346		)	(596		)	(191		)	—			(1,661		)
Gross margin	116			144			259			250			67			—			836
Operating and maintenance expense	(33		)	(39		)	(156		)	(199		)	(51		)	1			(477		)
Depreciation expense	(84		)	(26		)	(51		)	(37		)	(44		)	(5		)	(247		)
Gain on sale of assets, net	—			—			—			—			1			17			18
General and administrative expense	—			—			—			—			—			(114		)	(114		)
Acquisition and integration costs	—			—			—			(16		)	—			(19		)	(35		)
Operating income (loss)	$	(1	)	$	79		$	52		$	(2	)	$	(27	)	$	(120	)	$	(19	)

Discussion of Consolidated Results of Operations

Revenues.  The following table summarizes the change in revenues by segment:

(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Total
Revenues, net of hedges, attributable to newly acquired Duke Midwest and EquiPower plants in 2015	$	1,320		$	383		$	—		$	—		$	—		$	1,703
Lower revenues attributable to our legacy plants, including IPH:
Higher (lower) power prices and spark spreads (1)	(237		)	(92		)	10			(83		)	(53		)	(455		)
Higher (lower) generation volumes (1)	251			(17		)	(104		)	(114		)	(33		)	(17		)
Higher capacity revenues	14			27			12			82			3			138
Change in MTM value of derivative transactions	28			12			(38		)	48			3			53
Lower (higher) contract amortization	—			65			—			15			(2		)	78
Expiration of ConEd contract at Independence	—			(97		)	—			—			—			(97		)
Other (2)	9			(43		)	(3		)	5			2			(30		)
Total change in revenues	$	1,385		$	238		$	(123	)	$	(47	)	$	(80	)	$	1,373

(1)Decrease at our legacy plants, excluding PJM, due to lower demand in our generation areas as a result of milder temperatures.

(2)Other primarily consists of ancillary, tolling, transmission and gas revenues.

26

Cost of Sales.  The following table summarizes the change in cost of sales by segment:

(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Total
Cost of sales attributable to newly acquired Duke Midwest and EquiPower plants in 2015	$	510		$	254		$	—		$	—		$	—		$	764
Lower cost of sales attributable to our legacy plants, including IPH:
Lower prices	(107		)	(148		)	(2		)	(14		)	(59		)	(330		)
Higher (lower) generation volumes	81			(5		)	(54		)	(118		)	(17		)	(113		)
Higher (lower) transportation costs	1			(5		)	—			—			(7		)	(11		)
Lower contract amortization	—			1			—			16			—			17
Other (1)	16			4			(3		)	26			(3		)	40
Total change in cost of sales	$	501		$	101		$	(59	)	$	(90	)	$	(86	)	$	367

(1)Other primarily consists of transmission costs and various non-recurring expenses.

Operating and Maintenance Expense.  Operating and maintenance expense increased by $362 million primarily due to $326 million in costs attributable to newly acquired Duke Midwest and EquiPower plants and $36 million in higher costs from our legacy plants as a result of more planned outages.

Depreciation Expense.  Depreciation expense increased by $340 million primarily attributable to newly acquired Duke Midwest and EquiPower plants.

Impairments. Impairments increased by $99 million due to charges in 2015 of $74 million at our MISO segment on our Wood River facility and $25 million at our NY/NE segment on our Brayton Point facility.  Please read Note 9—Property, Plant and Equipment for further discussion.

Gain (Loss) on Sale of Assets, net.  Gain (loss) on sale of assets, net decreased by $19 million primarily due to a $17 million gain from the sale of our 50 percent ownership interest in Black Mountain in 2014, not repeated in 2015.  Please read Note 11—Unconsolidated Investments for further discussion.

General and Administrative Expense.  General and administrative expense increased by $14 million primarily due to higher overhead associated with the Acquisitions and higher legal fees.

Acquisition and Integration Costs.  Acquisition and integration costs increased by $89 million due to $12 million in severance, retention and payroll costs and $48 million in Bridge Loan financing fees related to the Acquisitions in 2015, and $29 million in higher advisory and consulting fees.  Please read Note 3—Acquisitions for further discussion.

Earnings from Unconsolidated Investments.  Earnings from unconsolidated investments decreased by $9 million primarily due to $10 million in cash distributions received from Black Mountain in 2014.  Please read Note 11—Unconsolidated Investments for further discussion.

Interest Expense.  Interest expense increased by $323 million primarily due to the issuance of debt in October 2014 to finance the Acquisitions.  Please read Note 14—Debt for further discussion.

Other Income and Expense, Net.  Other income and expense, net increased by $93 million primarily due to the change in the fair value of our common stock warrants.

Income Tax Benefit.  Income tax benefit increased by $473 million primarily due to the release of $453 million of our valuation allowance as a result of increased net deferred tax liabilities related to the EquiPower Acquisition.  In addition, we recorded an additional tax benefit of $21 million for discrete items including a state law change in Connecticut and the application of our effective state tax rates for jurisdictions for which we do not record a valuation allowance.  Please read Note 3—Acquisitions for further discussion of the release of the valuation allowance.

As of December 31, 2015, we continued to maintain a valuation allowance against our net deferred tax assets in each jurisdiction as they arise as there was not sufficient evidence to overcome our historical cumulative losses to conclude that it is more likely than not that our net deferred tax assets can be realized in the future.  Please read Note 15—Income Taxes for further discussion.

Net Income (Loss) Attributable to Noncontrolling Interest.  Net income (loss) attributable to noncontrolling interest decreased by $9 million as a result of changes in our minority shareholder’s 20 percent interest in EEI.

27

Net income (Loss) Attributable to Dynegy Inc.  The $323 million increase was primarily due to a $226 million contribution from newly acquired Duke Midwest and EquiPower plants and income from a $453 million deferred tax valuation allowance release, partially offset by $323 million higher interest expense primarily as a result of the issuance of debt in 2014 to finance the Acquisitions.

Adjusted EBITDA — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

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

	Year Ended December 31, 2015
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Net income attributable to Dynegy Inc.																			$	50
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	697			139			(53		)	84			47			(193		)	721
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 (1)	(2		)	—			12			—			—			1			11
Adjusted EBITDA (2)	$	649		$	175		$	27		$	77		$	44		$	(122	)	$	850

(1)Other includes an adjustment to exclude costs related to the Baldwin transformer project of $7 million.

(2)Not adjusted for the following 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.

28

The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2014:

	Year Ended December 31, 2014
(amounts in millions)	PJM			NY/NE			MISO			IPH			CAISO			Other			Total
Net loss attributable to Dynegy Inc.																			$	(273	)
Income attributable to noncontrolling interest																			6
Income tax benefit																			(1		)
Other income and expense, net																			39
Interest expense																			223
Earnings from unconsolidated investments																			(10		)
Bankruptcy reorganization items																			(3		)
Operating income (loss)	$	(1	)	$	79		$	52		$	(2	)	$	(27	)	$	(120	)	$	(19	)
Depreciation and amortization expense	86			82			51			36			49			5			309
Bankruptcy reorganization items	—			—			—			—			—			3			3
Earnings from unconsolidated investments	—			—			—			—			—			10			10
Other income and expense, net	—			—			—			—			—			(39		)	(39		)
EBITDA	85			161			103			34			22			(141		)	264
Adjustment to exclude noncontrolling interest	—			—			—			(6		)	—			—			(6		)
Acquisition and integration costs	—			—			—			16			—			19			35
Bankruptcy reorganization items	—			—			—			—			—			(3		)	(3		)
Mark-to-market adjustments, including warrants	36			(1		)	(44		)	38			(1		)	40			68
Gain on sale of assets, net	—			—			—			—			(1		)	(17		)	(18		)
Other	—			—			3			1			—			3			7
Adjusted EBITDA (1)	$	121		$	160		$	62		$	83		$	20		$	(99	)	$	347

(1)Not adjusted for the following items which are excluded in 2016: (i) non-cash compensation expense of $19 million, and (ii) income attributable to Wood River’s energy margin and O&M costs of $37 million.

Adjusted EBITDA increased by $503 million primarily due to a $590 million contribution from newly acquired Duke Midwest and EquiPower plants in 2015.  The offsetting $87 million decrease from our legacy plants was driven by lower energy margin, net of hedges, at the MISO, IPH, and CAISO segments primarily due to lower generation volumes as a result of mild temperatures, as well as the expiration of the ConEd contract at Independence at the NY/NE segment.  This decrease was partially offset by higher capacity revenues across all segments and higher energy margin, net of hedges, at the PJM segment primarily as a result of higher spark spreads and run times.  Please read Discussion of Segment Adjusted EBITDA for further information.

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Discussion of Segment Adjusted EBITDA — Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

PJM Segment

The following table provides summary financial data regarding our PJM segment results of operations for the years ended December 31, 2015 and 2014, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2015			2014			$ Change
Operating Revenues
Energy	$	1,266		$	280		$	986
Capacity	345			70			275
Mark-to-market income (loss), net	105			(36		)	141
Contract amortization	(47		)	(2		)	(45		)
Other	47			19			28
Total operating revenues	1,716			331			1,385
Operating Costs
Cost of sales	(771		)	(215		)	(556		)
Contract amortization	55			—			55
Total operating costs	(716		)	(215		)	(501		)
Gross margin	1,000			116			884
Operating and maintenance expense	(296		)	(33		)	(263		)
Depreciation expense	(281		)	(84		)	(197		)
Operating income (loss)	423			(1		)	424
Depreciation and amortization expense	275			86			189
Earnings from unconsolidated investments	1			—			1
Other income and expense, net	(2		)	—			(2		)
EBITDA	697			85			612
Adjustment to reflect Adjusted EBITDA from unconsolidated investment	12			—			12
Mark-to-market adjustments	(58		)	36			(94		)
Other	(2		)	—			(2		)
Adjusted EBITDA	$	649		$	121		$	528
Million Megawatt Hours Generated (1)	40.4			5.8			34.6
IMA (1)(2):
Combined-Cycle Facilities	99		%	98		%
Coal-Fired Facilities	74		%	N/A
Average Capacity Factor (1)(3):
Combined-Cycle Facilities	75		%	38		%
Coal-Fired Facilities	51		%	N/A
Average Market On-Peak Spark Spreads ($/MWh) (4):
PJM West	$	25.24		$	26.82		$	(1.58	)
AD Hub	$	28.22		$	31.94		$	(3.72	)
Average Market On-Peak Power Prices ($/MWh) (5):
PJM West	$	43.21		$	62.71		$	(19.50	)
AD Hub	$	37.52		$	54.86		$	(17.34	)
Average natural gas price—TetcoM3 ($/MMBtu) (6)	$	2.57		$	5.13		$	(2.56	)

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(1)Reflects the activity for the period in which the 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 CTs.

(3)Reflects actual production as a percentage of available capacity.  The calculation excludes 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.

Operating income for 2015 was $423 million compared to operating loss of $1 million for 2014.  The $424 million increase was primarily due to the following:

	(in millions)
Contribution from newly acquired Duke Midwest and EquiPower plants in 2015	$	375
Remaining increase attributable to our legacy plants:
Higher energy margin, net of hedges, due to higher run times partially offset by lower spark spreads	$	25
Change in MTM value of derivative transactions	$	28
Higher capacity revenues due to higher pricing	$	14

Adjusted EBITDA increased by $528 million primarily due to the following:

	(in millions)
Contribution from newly acquired Duke Midwest and EquiPower plants in 2015	$	510
Remaining increase attributable to our legacy plants:
Higher energy margin, net of hedges, due to the following:
Higher generation volumes due to higher run times	$	40
Lower spark spreads	$	(32	)
Higher capacity revenues due to higher pricing	$	14

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NY/NE Segment

The following table provides summary financial data regarding our NY/NE segment results of operations for the years ended December 31, 2015 and 2014, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2015			2014			$ Change
Operating Revenues
Energy	$	524		$	356		$	168
Capacity	154			148			6
Mark-to-market income, net	2			1			1
Contract amortization	(4		)	(64		)	60
Other	19			16			3
Total operating revenues	695			457			238
Operating Costs
Cost of sales	(410		)	(321		)	(89		)
Contract amortization	(4		)	8			(12		)
Total operating costs	(414		)	(313		)	(101		)
Gross margin	281			144			137
Operating and maintenance expense	(126		)	(39		)	(87		)
Depreciation expense	(186		)	(26		)	(160		)
Impairments	(25		)	—			(25		)
Operating income (loss)	(56		)	79			(135		)
Depreciation and amortization expense	195			82			113
EBITDA	139			161			(22		)
Mark-to-market adjustments	11			(1		)	12
Impairments	25			—			25
Adjusted EBITDA	$	175		$	160		$	15
Million Megawatt Hours Generated (1)	15.7			7.1			8.6
IMA for Combined-Cycle Facilities (1)(2)	98		%	100		%
Average Capacity Factor for Combined-Cycle Facilities (1)(3)	56		%	52		%
Average Market On-Peak Spark Spreads ($/MWh) (4):
New York—Zone A	$	27.60		$	34.64		$	(7.04	)
Mass Hub	$	15.23		$	20.08		$	(4.85	)
Average Market On-Peak Power Prices ($/MWh) (5):
Mass Hub	$	48.96		$	76.97		$	(28.01	)
Average natural gas price—Algonquin Citygates ($/MMBtu) (6)	$	4.82		$	8.13		$	(3.31	)

(1)Reflects the activity for the period in which the 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 our Brayton Point facility.

(3)Reflects actual production as a percentage of available capacity.  The calculation excludes our Brayton Point facility.

(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.

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Operating loss for 2015 was $56 million compared to operating income of $79 million for 2014.  The $135 million decrease was primarily due to the following:

	(in millions)
Loss attributable to newly acquired Duke Midwest and EquiPower plants in 2015	$	(145	)
Remaining increase attributable to our legacy plants:
Expiration of the ConEd contract at Independence	$	(97	)
Change in MTM value of derivative transactions	$	12
Higher capacity revenues due to open market sales	$	27
Lower contract amortization	$	64

Adjusted EBITDA increased by $15 million primarily due to the following:

	(in millions)
Contribution from newly acquired Duke Midwest and EquiPower plants in 2015	$	80
Remaining decrease attributable to our legacy plants:
Expiration of the ConEd contract at Independence	$	(97	)
Higher capacity revenues due to open market sales	$	27

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MISO Segment

The following table provides summary financial data regarding our MISO segment results of operations for the years ended December 31, 2015 and 2014, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2015			2014			$ Change
Operating Revenues
Energy	$	458		$	552		$	(94	)
Capacity	17			5			12
Mark-to-market income, net	6			44			(38		)
Other	1			4			(3		)
Total operating revenues	482			605			(123		)
Operating Costs
Cost of sales	(293		)	(352		)	59
Contract amortization	6			6			—
Total operating costs	(287		)	(346		)	59
Gross margin	195			259			(64		)
Operating and maintenance expense	(174		)	(156		)	(18		)
Depreciation expense	(39		)	(51		)	12
Impairments	(74		)	—			(74		)
Operating income (loss)	(92		)	52			(144		)
Depreciation and amortization expense	38			51			(13		)
Other income and expense, net	1			—			1
EBITDA	(53		)	103			(156		)
Mark-to-market adjustments	(6		)	(44		)	38
Impairments	74			—			74
Other	12			3			9
Adjusted EBITDA (1)	$	27		$	62		$	(35	)
Million Megawatt Hours Generated	15.9			19.1			(3.2		)
IMA for Coal-Fired Facilities (2)	87		%	88		%
Average Capacity Factor for Coal-Fired Facilities (3)	61		%	72		%
Average Market On-Peak Power Prices ($/MWh) (4):
Indiana (Indy Hub)	$	33.50		$	48.28		$	(14.78	)
Commonwealth Edison (NI Hub)	$	33.98		$	50.60		$	(16.62	)

(1)2015 and 2014 are not adjusted for Wood River’s energy margin and O&M costs of $13 million and $37 million respectively, which are excluded in 2016.

(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.

(3)Reflects actual production as a percentage of available capacity.

(4)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

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Operating loss for 2015 was $92 million compared to operating income of $52 million for 2014.  The $144 million decrease was primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes	$	(36	)
Change in MTM value of derivative transactions	$	(38	)
Impairment charges incurred in 2015	$	(74	)

Adjusted EBITDA decreased by $35 million primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, primarily due to lower generation volumes as a result of milder weather	$	(30	)
Higher capacity revenues as a result of higher pricing and volumes	$	12
Higher O&M costs due to planned and unplanned outages	$	(12	)

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IPH Segment

The following table provides summary financial data regarding our IPH segment results of operations for the years ended December 31, 2015 and 2014, respectively.

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2015			2014			$ Change
Operating Revenues
Energy	$	681		$	886		$	(205	)
Capacity	124			42			82
Mark-to-market income (loss), net	10			(38		)	48
Contract amortization	(25		)	(40		)	15
Other	9			(4		)	13
Total operating revenues	799			846			(47		)
Operating Costs
Cost of sales	(537		)	(643		)	106
Contract amortization	31			47			(16		)
Total operating costs	(506		)	(596		)	90
Gross margin	293			250			43
Operating and maintenance expense	(215		)	(199		)	(16		)
Depreciation expense	(29		)	(37		)	8
Acquisition and integration costs	—			(16		)	16
Operating income (loss)	49			(2		)	51
Depreciation and amortization expense	35			36			(1		)
EBITDA	84			34			50
Adjustments to exclude noncontrolling interest	3			(6		)	9
Acquisition, integration and restructuring costs	—			16			(16		)
Mark-to-market adjustments	(10		)	38			(48		)
Other	—			1			(1		)
Adjusted EBITDA	$	77		$	83		$	(6	)
Million Megawatt Hours Generated	18.5			23.7			(5.2		)
IMA for IPH Facilities (1)	89		%	89		%
Average Capacity Factor for IPH Facilities (2)	52		%	68		%
Average Market On-Peak Power Prices ($/MWh) (3):
Indiana (Indy Hub)	$	33.50		$	48.28		$	(14.78	)
Commonwealth Edison (NI Hub)	$	33.98		$	50.60		$	(16.62	)

(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 CTs.

(2)Reflects actual production as a percentage of available capacity.  The calculation excludes CTs.

(3)Reflects the average of day-ahead quoted prices for the periods presented and does not necessarily reflect prices we realized.

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Operating income for 2015 was $49 million compared to an operating loss of $2 million for 2014.  The $51 million increase was primarily due to the following:

	(in millions)
Higher capacity revenues due to higher MISO and PJM pricing and volumes	$	82
Change in MTM value of derivative transactions	$	48
Acquisition and integration costs incurred in 2014	$	16
Lower energy margin, net of hedges, due to lower power prices and generation volumes	$	(75	)
Lower retail gross margin	$	(10	)

Adjusted EBITDA decreased by $6 million primarily due to the following:

	(in millions)
Lower energy margin, net of hedges, due to the following:
Lower realized power prices as a result of milder weather	$	(67	)
Lower generation volumes as a result of milder weather	$	(8	)
Higher capacity revenues due to higher MISO and PJM pricing and volumes	$	82
Higher O&M costs driven by planned outages	$	(11	)
Lower retail gross margin	$	(10	)

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CAISO Segment

The following table provides summary financial data regarding our CAISO segment results of operations for the years ended December 31, 2015 and 2014, respectively:

	Year Ended December 31,						Favorable (Unfavorable)
(dollars in millions, except for price information)	2015			2014			$ Change
Operating Revenues
Energy	$	125		$	216		$	(91	)
Capacity	31			28			3
Mark-to-market income, net	4			1			3
Contract amortization	(7		)	(5		)	(2		)
Other	25			18			7
Total operating revenues	178			258			(80		)
Operating Costs
Cost of sales	(105		)	(191		)	86
Total operating costs	(105		)	(191		)	86
Gross margin	73			67			6
Operating and maintenance expense	(32		)	(51		)	19
Depreciation expense	(48		)	(44		)	(4		)
Gain (loss) on sale of assets, net	(1		)	1			(2		)
Operating loss	(8		)	(27		)	19
Depreciation and amortization expense	55			49			6
EBITDA	47			22			25
Mark-to-market adjustments	(4		)	(1		)	(3		)
Loss (gain) on sale of assets, net	1			(1		)	2
Adjusted EBITDA	$	44		$	20		$	24
Million Megawatt Hours Generated	4.0			4.2			(0.2		)
IMA for Combined-Cycle Facilities (1)	96		%	98		%
Average Capacity Factor for Combined-Cycle Facilities (2)	38		%	46		%
Average Market On-Peak Spark Spreads ($/MWh) (3):
North of Path 15 (NP 15)	$	14.32		$	17.18		$	(2.86	)
Average natural gas price—PG&E Citygate ($/MMBtu) (4)	$	2.99		$	4.85		$	(1.86	)

(1)IMA is an internal measurement calculation that reflects the percentage of generation available 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 CTs.

(2)Reflects actual production as a percentage of available capacity.  The calculation excludes CTs.

(3)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.

(4)Reflects the average of daily quoted prices for the periods presented and does not reflect costs incurred by us.

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Operating loss decreased by $19 million primarily due to lower O&M costs related to the reversal of a legal accrual for station power at Moss Landing and lower plant retirement and remediation costs at Morro Bay.

Adjusted EBITDA increased by $24 million primarily due to the following:

	(in millions)
Higher capacity and tolling revenues due to higher volumes at Moss Landing	$	8
Lower O&M costs related to the reversal of a legal accrual for station power at Moss Landing and lower plant retirement and remediation costs at Morro Bay	$	18

Outlook

We expect that our future financial results will continue to be impacted by market structure and prices for electric energy, capacity, and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions, and the availability of our plants.  Further, there is a trend toward greater environmental regulation of all aspects of our business.  As this trend continues, it is possible that we will experience additional costs related to water, air, and coal ash regulations.

The portions of our generation volumes sold, coal requirements contracted, coal requirements priced, and coal transportation requirements contracted, by segment, are discussed below.  We look to procure and price additional coal and coal transportation opportunistically.  For our gas-fired fleet, we hedge price risk by selling forward spark spreads which involves purchasing the required amount of natural gas at the same time as we sell power.  We expect to continue our hedging program for energy over a one- to three-year period using various instruments, including retail sales in our PJM and IPH segments, and in accordance with our risk management policy.

Our Operating Segments

PJM Segment.  The PJM segment is comprised of 23 power generation facilities located within the PJM region, with a total generating capacity of 13,510 MW.

In PJM, we are installing a total of 290 MW of uprates, which will be accomplished primarily through upgrades to the hot gas path components of our combined-cycle gas turbines.  The uprates started in the Fall of 2015 and are expected to be completed in the Spring of 2017.

PJM introduced its new CP product beginning with the Planning Year 2016-2017 capacity auction.  Beginning in Planning Year 2018-2019, PJM introduced Base, which, alongside CP, replaced the legacy capacity product.  Base capacity resources are those capacity resources that are not capable of sustained, predictable operation throughout the entire delivery year, but are capable of providing energy and reserves during hot weather operations.  They are subject to non-performance charges assessed during emergency conditions, from June through September.

Our Kendall facility has one tolling agreement for 85 MW that expires in 2017.  Effective as of the closing of the Delta Transaction, we acquired a 50% non-operating ownership interest in the Sayreville facility.  In addition, we use our retail business to hedge a portion of the energy output from our facilities.  Dynegy’s portfolio beyond the prompt year is primarily open to benefit from possible future power market pricing improvements.

The following table reflects our hedging activities as of February 7, 2017:

	2017		2018		2019 to 2021
Generation volumes hedged	82	%	37	%	4	%
Coal requirements contracted (1)	85	%	70	%	11	%
Coal requirements priced (1)	85	%	70	%	—	%
Coal transportation requirements contracted (1)	100	%	100	%	100	%

(1)Excludes non-operated jointly-owned generating units.

A new long-term coal transportation agreement for our Kincaid facility was completed in 2015.  The contract, which commenced in 2017, reflects a reduction from the 2016 rate.

PJM Capacity Market.  Many of our facilities within PJM are located in subzones, which for capacity pricing purposes can constrain due to lack of transmission, mixed between Eastern Mid-Atlantic Area Council (“EMAAC”), Mid-Atlantic

39

Area Council (“MAAC”), Commonwealth Edison (“COMED”), American Transmission Service, Inc. (“ATSI”), RTO, and PPL Electric Utilities, Corp. (“PPL”).  PJM has begun the transition of the PJM capacity market to CP product.  On August 26-27, 2015, PJM held a transitional auction to convert up to 60 percent of PJM’s capacity needs for Planning Year 2016-2017 from legacy capacity to CP.  On September 3-4, 2015, PJM held a transitional auction to convert 70 percent of PJM’s capacity needs for Planning Year 2017-2018 from legacy capacity to CP.  On August 10-14, 2015, PJM held the Base Residual Auction to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for the Planning Year 2018-2019.  On May 11-17, 2016, PJM held the Base Residual Auction to procure CP for 80 percent and Base for 20 percent of PJM’s capacity needs for the Planning Year 2019-2020.  PJM will procure 100 percent CP beginning with Planning Year 2020-2021.

The most recent RPM auction results for the zones in which our assets are located, are as follows for each Planning Year:

	2014-2015		2015-2016		2016-2017				2017-2018				2018-2019				2019-2020
	Legacy Capacity		Legacy Capacity		Legacy Capacity		CP		Legacy Capacity		CP		Base		CP		Base		CP
RTO zone, price per MW-day	$	125.99	$	136.00	$	59.37	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00
MAAC zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00
EMAAC zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	210.63	$	225.42	$	99.77	$	119.77
COMED zone, price per MW-day	$	125.99	$	136.00	$	59.37	$	134.00	$	120.00	$	151.50	$	200.21	$	215.00	$	182.77	$	202.77
ATSI zone, price per MW-day	$	125.99	$	357.00	$	114.23	$	134.00	$	120.00	$	151.50	$	149.98	$	164.77	$	80.00	$	100.00
PPL zone, price per MW-day	$	136.50	$	167.46	$	119.13	$	134.00	$	120.00	$	151.50	$	75.00	$	164.77	$	80.00	$	100.00

Our capacity sales, net of purchases, aggregated by Planning Year and capacity type through Planning Year 2019-2020, are as follows:

	2016-2017		2017-2018		2018-2019		2019-2020
Legacy/Base auction capacity sold, net (MW)	4,123		3,763		2,172		1,722
CP auction capacity sold, net (MW)	6,703		7,859		8,526		9,046
Bilateral capacity sold, net (MW)	85		—		295		200
Total segment capacity sold, net (MW)	10,911		11,622		10,993		10,968
Average price per MW-day	$	120.35	$	141.49	$	179.06	$	128.85

NY/NE Segment.  The NY/NE segment is comprised of 11 power generation facilities located within the ISO-NE (5,331 MW) and NYISO (1,212 MW) regions, totaling 6,543 MW of electric generating capacity.

In New England, at our Lake Road and Milford-Connecticut facilities, we cleared 70 MW of new uprates in FCA-10, at a capacity rate of $7.03 per kW-month for seven years beginning with Planning Year 2019-2020 and extending through Planning Year 2025-2026.  For FCA-11, we cleared a total of 34 MW of uprates at Lake Road and Casco Bay that did not qualify for a seven year rate lock.  Milford-Massachusetts cleared an incremental 53 MW of new capacity in FCA-11 that qualified the entire plant for a seven year rate lock.  Milford-Massachusetts will receive the FCA-11 clearing price of $5.30 per kW-month for 202 MW through Planning Year 2026-2027.

In New York, we completed uprate installations which are expected to result in 35 MW of additional summer capacity and 79 MW of additional winter capacity.  In addition to the benefit of incremental output, both blocks have experienced improved efficiency as a result of the uprates.

In New England, almost all of our capacity sales are made through ISO-NE capacity auctions.

In New York, 66 percent of our Independence facility’s winter capacity had been sold bilaterally prior to the most recent auction, covering the Winter 2016-2017 planning period.

Our Brayton Point facility is expected to be retired in ISO-NE in June 2017.

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The following table reflects our hedging activities as of February 7, 2017:

	2017		2018		2019 to 2021
Generation volumes hedged (1)	69	%	13	%	5	%

(1)Excludes our Brayton Point facility and volumes subject to tolling agreements.

ISO-NE Capacity Market.  We have approximately 5,331 MW of power generation in ISO-NE.  The most recent FCA results for ISO-NE Rest-of-Pool, in which most of our assets are located, are as follows for each Planning Year:

	2014-2015		2015-2016		2016-2017		2017-2018		2018-2019		2019-2020		2020-2021
Price per kW-month	$	3.21	$	3.43	$	3.15	$	7.03	$	9.55	$	7.03	$	5.30

On February 6, 2017, ISO-NE conducted the capacity auction for Planning Year 2020-2021 (FCA-11).  In this auction, Rest-of-Pool cleared at $5.30 per kW-month.  Performance incentive rules will go into effect for Planning Year 2018-2019, having the potential to increase capacity payments for those resources that are providing excess energy or reserves during a shortage event, while penalizing those that produce less than the required level.

Our capacity sales, aggregated by Planning Year through Planning Year 2020-2021, are as follows:

	2016-2017		2017-2018		2018-2019		2019-2020		2020-2021
Auction capacity sold (MW)	3,915		3,433		3,471		3,500		3,595
Bilateral capacity sold (MW)	199		148		91		44		—
Total capacity sold (MW)	4,114		3,581		3,562		3,544		3,595
Average price per kW-month	$	3.22	$	6.98	$	10.08	$	7.02	$	5.38

On January 2, 2017, the Casco Bay tolling agreement expired.  Effective as of the closing of the Delta Transaction, we obtained a pre-existing tolling agreement and acquired a 50% non-operating ownership interest in the Bellingham NEA facility.  The tolling agreement expires in the spring of 2017.  The majority of our ISO-NE capacity sales are transacted through ISO-NE’s primary FCA.  Dynegy continues to market and pursue longer term multi-year capacity transactions that extend past FCA-11.

NYISO Capacity Market.  We have approximately 1,212 MW of power generation in NYISO.  The most recent seasonal auction results for NYISO’s Rest-of-State zones, in which the capacity for our Independence plant clears, are as follows for each planning period:

	Winter 2014-2015		Summer 2015		Winter 2015-2016		Summer 2016		Winter 2016-2017
Price per kW-month	$	2.90	$	3.50	$	1.25	$	3.62	$	0.75

Our capacity sales, aggregated by season through Summer 2019, are as follows:

	Winter 2016-2017		Summer 2017		Winter 2017-2018		Summer 2018		Winter 2018-2019		Summer 2019
Auction capacity sold (MW)	362		—		—		—		—		—
Bilateral capacity sold (MW)	775		868		655		620		330		255
Total capacity sold (MW)	1,137		868		655		620		330		255
Average price per kW-month	$	1.98	$	3.44	$	2.84	$	3.66	$	3.32	$	3.39

Due to the short-term, seasonal nature of the NYISO capacity auctions, we monetize the majority of Independence’s capacity through bilateral trades.

ERCOT Segment.  The ERCOT segment is comprised of six power generation facilities located within the ERCOT region, with a total generating capacity of 4,696 MW.

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The following table reflects our hedging activities as of February 7, 2017:

	2017		2018		2019 to 2021
Generation volumes hedged	19	%	10	%	—	%
Coal requirements contracted	100	%	—	%	—	%
Coal requirements priced	100	%	—	%	—	%
Coal transportation requirements contracted	100	%	100	%	—	%

ERCOT Market.  The energy and fuel hedges summarized in the table above are augmented by the forward sale of ancillary services.

MISO and IPH Segments.

MISO Segment.  The MISO segment is comprised of three power generation facilities located within the MISO region, with a total generating capacity of 1,913 MW.  On June 9, 2016, Dynegy announced that Hennepin will receive firm transmission service for a majority of the facility into the PJM control area beginning with Planning Year 2017-2018.  Beginning June 1, 2017, Hennepin will pseudo-tie and offer energy and capacity for 260 MW, or 14 percent of our current MISO capacity and energy, into PJM.  Hennepin’s remaining volume of approximately 34 MW will continue to be offered into MISO.

Dynegy’s portfolio beyond the prompt year is primarily open to benefit from possible future power market pricing improvements.

The following table reflects our hedging activities as of February 7, 2017:

	2017		2018		2019 to 2021
Generation volumes hedged (1)	73	%	42	%	5	%
Coal requirements contracted	90	%	68	%	40	%
Coal requirements priced	90	%	68	%	—	%
Coal transportation requirements contracted	100	%	98	%	96	%

(1)Excludes Baldwin Unit 1 starting October 2018 and Hennepin Unit 1 starting June 2017.

IPH Segment.  The IPH segment is comprised of five power generation facilities, totaling 3,563 MW and primarily operates in MISO.  Joppa, which is within the Electric Energy, Inc. control area, is interconnected to Tennessee Valley Authority and Louisville Gas and Electric Company, but primarily sells its capacity and energy to MISO.  We currently offer a portion of our IPH segment generating capacity and energy into PJM.  As of June 1, 2016, our Coffeen, Duck Creek, E.D. Edwards, and Newton facilities have 937 MW, or 26 percent of IPH’s current capacity and energy, electrically tied into PJM through pseudo-tie arrangements.  Additionally, IPH has secured firm transmission beginning June 1, 2017 to export 240 MW into PJM from our Joppa facility.

On February 24, 2016, IPM was awarded a three year capacity and energy sale contract for 959 MW with capacity revenue of $152 million.  This contract supports 112 communities in Illinois represented by Good Energy, and commenced on June 1, 2016.

IPH will continue to use our retail business to hedge a portion of the output from our IPH facilities.  The retail hedges are well correlated to our facilities due to the close proximity of the hedge and through participation in FTR markets.

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In 2015, we entered into a long-term coal transportation agreement for our Joppa facility which begins in 2018 and includes a reduction compared to the 2017 rate.  Similarly, in the fourth quarter of 2016, we negotiated new long-term coal transportation agreements for our Edwards and Newton facilities which also begin in 2018 and include reductions compared to the 2017 rate.  The following table reflects our hedging activities as of February 7, 2017:

	2017		2018		2019 to 2021
Generation volumes hedged	75	%	44	%	20	%
Coal requirements contracted	94	%	49	%	26	%
Coal requirements priced	71	%	45	%	—	%
Coal transportation requirements contracted	100	%	100	%	100	%

MISO Capacity Market.  We have approximately 5,476 MW of power generation in MISO.  This includes the 937 MW related to PJM pseudo-tie arrangements from the IPH fleet which began June 1, 2016.  With Joppa’s export capability and Hennepin’s pseudo-tie arrangement that will begin on June 1, 2017, we will have approximately 1,437 MW expected to be sold in PJM for Planning Year 2017-2018.  The capacity auction results for MISO Local Resource Zone 4, in which our assets are located, are as follows for each Planning Year:

	2014-2015		2015-2016		2016-2017
Price per MW-day	$	16.75	$	150.00	$	72.00

We cleared no volume in the MISO Planning Year 2014-2015 capacity auction.  Our MISO and IPH segments cleared 398 MW and 155 MW, respectively, in the MISO Planning Year 2015-2016 capacity auction at $150 per MW-day, incremental to our retail load obligations.  Our MISO and IPH segments cleared no incremental volumes, in excess of our retail load obligations, in the MISO Planning Year 2016-2017 capacity auction.

MISO capacity sales through Planning Year 2019-2020 are as follows:

	2016-2017		2017-2018		2018-2019		2019-2020
MISO Segment:
Bilateral capacity sold in MISO (MW)	1,011		1,075		242		185
Legacy/Base auction capacity sold in PJM (MW)	—		214		—		—
Total MISO segment capacity sold (MW)	1,011		1,289		242		185
Average price per kW-month	$	2.75	$	2.96	$	2.68	$	2.60
IPH Segment:
Bilateral capacity sold in MISO (MW)	2,246		2,250		1,837		570
Legacy/Base auction capacity sold in PJM (MW)	50		375		—		260
CP auction capacity sold in PJM (MW)	730		472		835		356
Total IPH segment capacity sold (MW)	3,026		3,097		2,672		1,186
Average price per kW-month	$	4.26	$	4.46	$	4.98	$	3.95

A majority of the Mercury and Air Toxic Standards related asset retirements will conclude this year; however, we expect economic retirements to continue reducing reserve margins in MISO.

CAISO Segment.  The CAISO segment is comprised of two power generation facilities located within the CAISO region, with a total generating capacity of 1,185 MW.

In its 2015 Gas Transmission and Storage rate case, which sets gas transportation rates for 2015-2017, PG&E proposed revenue requirements and allocation proposals which would result in a significant increase in the rates for electric generators served by the local transmission system, including Moss Landing.  Historically, after PG&E’s gas transportation rate structure was changed to unbundle the Backbone Transmission System (“BB”) rates, PG&E gas transmission and storage rate case settlements have included a bill credit for Moss Landing that effectively reduced the differential between rates for BB and local transmission system service, allowing the plant to compete against other power generators.  Dynegy actively participated in the hearing process before the CPUC.  However, on June 23, 2016, the CPUC approved a rate increase for local transmission customers, including Dynegy, of approximately 200 percent.  Dynegy filed a request for rehearing of the CPUC’s unfavorable June 23, 2016 decision on August 1, 2016.  The request for rehearing does not act as a stay on the rate increase, which went into effect on August 1, 2016.  If Dynegy’s request for rehearing is denied, Dynegy will explore options for an appeal.

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As a result of the offsetting risks of our other segments, we are able to reduce the costs associated with hedging with third parties by executing a portion of our natural gas hedges with an affiliate.  We continue to manage our remaining commodity price exposure to changing fuel and power prices in accordance with our risk management policy.  The following table reflects our hedging activities as of February 7, 2017:

	2017		2018		2019 to 2021
Generation volumes hedged	57	%	—	%	—	%

CAISO Capacity Market.  On April 29, 2016, CAISO published the 2017 Local Capacity Technical Analysis—Final Report and Study Results, which identifies Local Capacity Requirements (“LCR”) and influences procurement decisions of Load Serving Entities.  The Moss Landing area has been identified as a critical sub-area and will be included as part of the Greater Bay Area’s LCR criteria.  Beginning in 2017, we will have the ability to sell Greater Bay Area RA capacity, in addition to CAISO System RA capacity, from the Moss Landing units.

We currently have approximately 1,185 MW of power generation in CAISO.  The CAISO capacity market is a bilateral market in which Load Serving Entities are required to procure sufficient resources to meet their peak load plus a 15 percent reserve margin.  We transact with investor owned utilities, municipalities, community choice aggregators, retail providers, and other marketers through Request for Offers solicitations, broker markets, and directly with bilateral transactions for both the Standard and Flexible RA capacity.  Beginning on November 1, 2016, CAISO implemented the voluntary capacity auction for annual, monthly, and intra-month procurement to cover for deficiencies in the market.  The voluntary competitive solicitation process FERC approved on October 1, 2015 is a modification to the CPM and provides another avenue to sell RA capacity.  There have been recent CPM designations through the Competitive Solicitation Process including Moss Landing Unit 1 on December 18, 2016.

Our capacity sales, including CPM designations, aggregated by calendar year for 2017 through 2019 for Moss Landing, are as follows:

	2017	2018	2019
Bilateral capacity sold (Avg MW)	746	400	850

We have also sold seasonal capacity for Moss Landing opportunistically.  Our Oakland facility operated under an RMR contract with the CAISO for 2015 and was given notice of extension for 2016.

Other Market Developments

On January 25, 2016, the U.S. Supreme Court overturned the decision of the U.S. Court of Appeals for the District of Columbia Circuit and affirmed FERC’s jurisdiction over compensation to Demand Response providers in wholesale competitive markets and the compensation method as proscribed in FERC Order No. 745.  The decision effectively maintains the status-quo with respect to Demand Response participation in the wholesale markets, because the ISOs/RTOs refrained from making changes to market design while the case was pending.

SEASONALITY

Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas.  Power marketing operations and generating facilities typically have higher volatility and demand in the summer cooling months and winter heating season.

CRITICAL ACCOUNTING POLICIES

Our Accounting Department is responsible for the development and application of accounting policy and control procedures.  This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments and reports to the Chief Financial Officer (“CFO”).

The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments.  It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments.  We have identified the following critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of our financial position and results of operations:

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·Revenue Recognition and Derivative Instruments;

·Fair Value Measurements;

·Accounting for Income Taxes;

·Business Combinations;

·Impairment of Long-Lived Assets; and

·Goodwill Impairment.

Revenue Recognition and Derivative Instruments

We earn revenue from our facilities in three primary ways: (i) the sale of energy, including fuel, through both physical and financial transactions; (ii) sale of capacity; and (iii) sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load and provide emergency reserves for major changes to the balance of generation and load.  We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative.  Please read “Derivative Instruments—Generation” below for further discussion of the accounting for these types of transactions.

Derivative Instruments—Generation.  We enter into commodity contracts that meet the definition of a derivative.  These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business.  These contracts include forward contracts, which commit us to sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity.  There are two different ways to account for these types of contracts, as Dynegy does not elect hedge accounting for any of its derivative instruments: (i) as an accrual contract, if the criteria for the “normal purchase, normal sale” exception are met, documented, and elected; or (ii) as a mark-to-market contract with changes in fair value recognized in current period earnings.  All derivative commodity contracts that do not qualify for, or for which we do not elect, the “normal purchase, normal sale” exception are recorded at fair value in risk management assets and liabilities in the consolidated balance sheets with the associated changes in fair value recorded currently to revenues.  Comparability of our financial statements to our peers for similar contracts may not be possible due to differences in electing the “normal purchase, normal sale” exception.

Entities may choose whether or not to offset related assets and liabilities and report the net amounts on their consolidated balance sheets if the right of offset exists.  We elect to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we elect to offset the fair value of amounts recognized for the cash collateral paid or received against the fair value of amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement.  As a result, our consolidated balance sheets present derivative assets and liabilities, as well as the related cash collateral paid or received, on a net basis.

Derivative Instruments—Financing Activities.  We are exposed to changes in interest rate risk through our variable rate debt.  In order to manage our interest rate risk, we enter into interest rate swap agreements that meet the definition of a derivative.  All derivative instruments are recorded at their fair value on the consolidated balance sheets with the changes in fair value recorded currently to interest expense.  Our interest-based derivative instruments are not designated as hedges of our variable debt.

Fair Value Measurements

Fair Value Measurements.  Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.  In estimating fair value, we use discounted cash flow (“DCF”) projections, recent comparable market transactions, if available, or quoted prices.  We consider assumptions that third parties would make in estimating fair value, including, but not limited to, the highest and best use of the asset.  There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates, commodity prices, useful lives and growth factors.  The assumptions used by another party could differ significantly from our assumptions.

Our estimate of fair value reflects the impact of credit risk.  We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique.  These inputs are classified as readily observable, market corroborated, or generally unobservable.  We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information.  Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs.  We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction.  The inputs used to measure fair value have been placed in a hierarchy based on priority.  The hierarchy gives the highest priority to unadjusted, readily observable quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement).

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Fair Value Measurements—Risk Management Activities.  The determination of the fair value for each derivative contract incorporates various factors.  These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities.  Valuation adjustments are generally based on capital market implied ratings when assessing the credit standing of our counterparties, and when applicable, adjusted based on management’s estimates of assumptions market participants would use in determining fair value.

Assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts.  Exchange-traded derivatives, as discussed above, are generally classified as Level 1; however, some exchange-traded derivatives are valued using broker or dealer quotations or market transactions in either the listed or OTC markets.  In such cases, these exchange-traded derivatives are classified within Level 2.  OTC derivative instruments include swaps, forwards, and options.  In certain instances, these instruments may utilize models to measure fair value.  Generally, we use a similar model to value similar instruments.  Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability, and market-corroborated inputs.  Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2.  Other OTC derivatives trade in less active markets with a lower availability of pricing information.  In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market.  When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3.

Changes to our assumptions for the fair value of our derivative instruments (primarily forward price curves, pricing risk, and credit risk) could result in a material change to the fair value of our risk management assets and liabilities recorded to our consolidated balance sheets and corresponding changes in fair value recorded to our consolidated statements of operations.  Please read Note 5—Fair Value Measurements for further discussion of our assumptions.

Accounting for Income Taxes

We file a consolidated U.S. federal income tax return.  We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences.

As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate.  This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes.  These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheets.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period due to changes in our sales profile by state, as well as jurisdictional and legislative changes by state.  As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences.  We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business.

The guidance related to accounting for income taxes requires that a valuation allowance be established when it is more likely than not that all or a portion of a deferred tax asset will not be realized.  The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those temporary differences are deductible.  In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies.

We do not believe we will produce sufficient future taxable income, nor are there tax planning strategies available to realize the tax benefits from net deferred tax assets not otherwise realized by reversing existing taxable temporary differences.  Therefore, we continue to recognize a valuation allowance against our net deferred tax assets as of December 31, 2016.  Any change in the valuation allowance would impact our income tax benefit (expense) and net income (loss) in the period in which the change occurs.

Accounting for uncertainty in income taxes requires that we determine whether it is more likely than not that a tax position we have taken will be sustained upon examination.  If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement.  There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized.

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We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense.

Please read Note 15—Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions, and changes in our valuation allowance.

Business Combinations

Accounting Standards Codification (“ASC”) 815, Business Combinations requires that the purchase price for a business combination be assigned and allocated to the identifiable assets acquired and liabilities assumed based upon their fair value.  Generally, the amount recorded in the financial statements for an acquisition’s assets and liabilities is equal to the purchase price (the fair value of the consideration paid); however, a purchase price that exceeds the fair value of the net assets acquired will result in the recognition of goodwill.  Conversely, a purchase price that is below the fair value of the net assets acquired will result in the recognition of a bargain purchase in the income statement.

In addition to the potential for the recognition of goodwill or a bargain purchase, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded in our consolidated balance sheets, which can impact the timing and amount of depreciation and amortization expense recorded in any given period.  We utilize our best effort to make our determinations and review all information available, including estimated future cash flows and prices of similar assets when making our best estimate.  We also may hire independent appraisers or valuation specialists to help us make this determination as we deem appropriate under the circumstances.

There is a significant amount of judgment in determining the fair value of the Acquisitions and in allocating value to individual assets and liabilities.  Had different assumptions been used, the fair value of the assets acquired and liabilities assumed could have been significantly higher or lower with a corresponding increase or reduction in recognized goodwill, or could have required recognition of a bargain purchase.  Refer to Note 3—Acquisitions for further discussion of the Acquisitions.

Impairment of Long-Lived Assets

ASC 360, Property, Plant and Equipment (“PP&E”) requires for an entity to assess whether the recorded values of PP&E and finite-lived intangible assets have become impaired when certain indicators of impairment exist.  Examples of these indicators include, but are not limited to:

·a significant decrease in the market price of a long-lived asset (asset group);

·a significant adverse change in the extent or manner in which a long-lived asset (asset group) is being used, or in its physical condition;

·a significant adverse change in legal factors or in the business climate that could affect the value of a long-lived asset (asset group), including an adverse action or assessment by a regulator;

·an accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset (asset group);

·a current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset (asset group); and

·a current expectation that it is more likely than not a long-lived asset (asset group) will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

If we determine that an asset or asset group may have become impaired, then we will perform step one of the impairment analysis, which requires us to determine if the asset’s value is recoverable using forecasted undiscounted cash flows.  If it is determined that the asset’s value is not recoverable, then we will perform step two of the impairment analysis and fair value the asset using a DCF model and record an impairment charge to reduce the value of the asset to its fair value.  The assumptions and estimates used by management to assess whether the asset may have become impaired, whether the asset’s value is recoverable, and to determine the fair value of the estimate are significant and may vary materially from the assumptions used by our peers.  Some examples of the assumptions and estimates used include:

·determination of decreases in the market price of an asset being a short-term or long-term, fundamental change;

·the highest and best use of the asset;

·forecasted environmental and regulatory changes;

·management’s fundamental view of the long-term pricing environment for energy and capacity;

·management’s forecast of gross margin, capital expenditures, and operations and maintenance costs;

·remaining useful life of our assets;

·salvage value;

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·discount rates; and

·inflation rates.

Changes in any of management’s assumptions and estimates could result in significantly different results than what we have reported herein.

We performed asset impairment analyses of certain of our facilities in 2016 and, as a result, recorded impairment charges of $56 million, $148 million, and $645 million for our Stuart, Newton, and Baldwin facilities, respectively.  Please read Note 9—Property, Plant and Equipment for further discussion.

Goodwill Impairment

We record goodwill when the purchase price for an acquisition classified as a business combination exceeds the estimated net fair value of the identifiable tangible and intangible assets acquired.  The amount of goodwill which can be recognized as part of an acquisition can change materially based upon the assumptions used when determining the net fair value of those assets.  We allocate goodwill to reporting units based on the relative fair value of the purchased operating assets assigned to those reporting units.

ASC 350, Intangibles-Goodwill and Other requires an entity to assess whether goodwill has become impaired at least annually, or when certain indicators of impairment exist on an interim basis.  We have elected October 1 for our annual assessment.  Examples of the indicators of impairment include, but are not limited to:

·a deterioration of general economic conditions, limitation on accessing capital, or other developments in equity and credit markets;

·increases in costs which have a negative effect on earnings and cash flows;

·overall financial performance such as negative or declining cash flows or a decline in actual or planned revenue or earnings;

·other relevant entity-specific events such as changes in management, key personnel, strategy, or customers, contemplation of bankruptcy, or litigation;

·a more likely than not expectation of selling or disposing all, or a portion, of a reporting unit; and,

·recognition of a goodwill impairment loss in the financial statements of a subsidiary that is a component of a reporting unit.

Determining whether a goodwill impairment trigger exists involves significant judgment by management, which may result in a different answer if our peers were to consider the same facts and circumstances.  In the event management determines a triggering event has occurred or it is the period for the annual assessment, ASC 350 allows an entity to elect to qualitatively assess whether it is more likely than not that an impairment has occurred (step zero).  If we determine that it is more likely than not that goodwill has become impaired, we utilize a two-step process to conclude if goodwill has become impaired and to calculate the impairment charge.  Step one involves fair valuing the reporting units to which goodwill has been assigned and comparing that fair value to the book value of the reporting units, inclusive of goodwill.  In the event the fair value of the reporting unit is less than its book value, inclusive of goodwill, step two must be performed, which compares the implied fair value of goodwill to its book value.

The assumptions and estimates used by management to determine the fair value of our reporting units and goodwill for step one and step two, respectively, are significant and may vary materially from the assumptions and estimates used by our peers.  Some examples of the assumptions and estimates used include:

·the highest and best use of the reporting units assets;

·forecasted environmental and regulatory changes;

·management’s fundamental view of the long-term pricing environment for energy and capacity;

·remaining useful life of our assets;

·salvage value;

·discount rates; and

·inflation rates.

At October 1, 2016, Dynegy performed its annual goodwill assessment and determined that no impairment was required.  Changes in management’s assumptions and estimates regarding the fair value of these reporting units could result in a materially different result.

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RECENT ACCOUNTING PRONOUNCEMENTS

Please read Note 2—Summary of Significant Accounting Policies for further discussion of accounting principles adopted and accounting principles not yet adopted.

RISK MANAGEMENT DISCLOSURES

The following table provides a reconciliation of the risk management data contained within our consolidated balance sheets on a net basis:

(amounts in millions)	As of and for the Year Ended December 31, 2016
Fair value of portfolio at December 31, 2015	$	(90	)
Risk management losses recognized through the statement of operations in the period, net	61
Contracts realized or otherwise settled during the period	87
Change in collateral/margin netting	(52		)
Fair value of portfolio at December 31, 2016	$	6

The net risk management asset of $6 million is the aggregate of the following line items in our consolidated balance sheets: Current Assets—Assets from risk management activities, Other Assets—Assets from risk management activities, Current Liabilities—Liabilities from risk management activities, and Other Liabilities—Liabilities from risk management activities.

Risk Management Asset and Liability Disclosures.  The following table provides an assessment of net contract values by year as of December 31, 2016, based on our valuation methodology:

Net Fair Value of Risk Management Portfolio

(amounts in millions)	Total			2017			2018			2019			2020			2021		Thereafter
Market quotations (1) (2)	$	(50	)	$	(20	)	$	(25	)	$	(4	)	$	(1	)	$	—	$	—
Prices based on models (2)	2			—			—			1			1			—		—
Total (3)	$	(48	)	$	(20	)	$	(25	)	$	(3	)	$	—		$	—	$	—

(1)Prices obtained from actively traded, liquid markets for commodities.

(2)The market quotations category represents our transactions classified as Level 1 and Level 2.  The prices based on models category represents transactions classified as Level 3.  Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

(3)Excludes $54 million of broker margin that has been netted against Risk management liabilities in our consolidated balance sheet.  Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

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