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(1)

Unit capabilities are based on winter capacity. We have not included the Stallings and Oglesby facilities, consisting of approximately 150 MW that were historically included in our Coal segment, as these facilities were retired effective January 7, 2013. We also have not included the Morro Bay facility, as it is currently retired and is out of operation, effective February 5, 2014. Additionally, we have not included the DNE facilities, consisting of approximately 1,700 MW, as these facilities were deconsolidated effective October 1, 2012, and were sold during 2013. Please read Note 23—Dispositions and Discontinued Operations for further discussion of the sale of the DNE facilities.

(2)	Represents Unit 6 generating capacity. Units 1-5, with a combined net generating capacity of 228 MW, are retired and out of operation.

(3)	Represents Units 4 and 5 generating capacity. Units 1-3, with a combined net generating capacity of 119 MW, are retired and out of operation.

(4)	We indirectly own an 80 percent interest in this facility. Total output capacity of this facility is 1,002 MW. Additionally, Joppa has 235 MW of natural gas-fired capacity which is currently not operating and therefore excluded from the table above.

(5)	We indirectly own a 50 percent interest in this facility. Total output capacity of this facility is 85 MW.

•	Customer Focus—We focus on understanding the needs of our customers and stakeholders and delivering solutions that exceed expectations;

•	Continuous Improvement—We are committed to the pursuit of quality, efficiency and flexibility throughout our business; and

•	Capital Structure Management and Allocation—We will create a sustainable and flexible capital structure with diversified liquidity sources to efficiently support and allocate resources across our business activities.

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•	anticipated benefits and expected synergies resulting from the AER Acquisition and beliefs associated with the integration of operations;

•	lack of comparable financial data due to the application of fresh-start accounting;

•	expectations regarding our compliance with the Credit Agreement, including collateral demands, interest expense, any applicable financial ratios and other payments;

•	efforts to secure retail sales and the timing of such sales;

•	the timing and anticipated benefits to be achieved through our company-wide savings improvement programs, including our PRIDE initiative;

•	efforts to identify opportunities to reduce congestion and improve busbar power prices;

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expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits and the impact of ongoing proceedings and potential regulations or changes to current regulations, including those relating to climate change, air emissions, cooling water intake structures, coal combustion byproducts and other laws and regulations to which we are, or could become, subject;

•	beliefs, assumptions and projections regarding the demand for power, generation volumes and commodity pricing, including natural gas prices and the timing of a recovery in natural gas prices, if any;

•	sufficiency of, access to and costs associated with coal, fuel oil and natural gas inventories and transportation thereof;

•	beliefs and assumptions about market competition, generation capacity and regional supply and demand characteristics of the wholesale and retail power generation market, including the anticipation of higher market pricing over the longer term;

•	the effectiveness of our strategies to capture opportunities presented by changes in commodity prices and to manage our exposure to energy price volatility;

•	beliefs and assumptions about weather and general economic conditions;

•	projected operating or financial results, including anticipated cash flows from operations, revenues and profitability;

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•	our focus on safety and our ability to efficiently operate our assets so as to capture revenue generating opportunities and operating margins;

•	beliefs about the costs and scope of the ongoing demolition and site remediation efforts at the South Bay and Vermilion facilities;

•	beliefs regarding successful renegotiation of the IBEW Local 1245 collective bargaining agreement;

•	beliefs regarding redevelopment efforts for the Morro Bay facility;

•	beliefs and assumptions regarding approval by the CPUC of the SCE 2016 transaction for Moss Landing Units 6 & 7;

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

•	beliefs about the outcome of legal, administrative, legislative and regulatory matters; and

•	expectations regarding performance standards and capital and maintenance expenditures.

•	the existence and effectiveness of demand-side management;

•	conservation efforts and the extent to which they impact electricity demand;

•	addition of new supplies of power from existing competitors or new market entrants as a result of the development of new generation plants, expansion of existing plants or additional transmission capacity;

•	regulatory constraints on pricing (current or future) or the functioning of the energy trading markets and energy trading generally;

•	environmental regulations and legislation;

•	weather conditions, including extreme weather conditions, and seasonal fluctuations;

•	electric supply disruptions including plant outages;

•	basis risk from transmission losses and congestion and changes in power transmission infrastructure;

•	development of new technologies for the production of natural gas;

•	fuel price volatility;

•	economic conditions; and

•	increased competition or price pressure driven by generation from renewable sources.

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•	incur additional indebtedness;

•	pay dividends, repurchase or redeem stock or make investments in certain entities;

•	enter into related party transactions;

•	create certain liens;

•	enter into any agreements which limit the ability of certain subsidiaries to make dividends or otherwise transfer cash or assets to us or certain other subsidiaries;

•	consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; and

•	sell and acquire assets.

•	the ability to obtain required regulatory and other approvals;

•	the need to integrate acquired or combined operations with our operations;

•	potential loss of key employees;

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•	difficulty in evaluating the assets, operating costs, infrastructure requirements, environmental and other liabilities and other factors beyond our control;

•	potential lack of operating experience in new geographic/power markets or with different fuel sources;

•	an increase in our expenses and working capital requirements;

•	management’s attention may be temporarily diverted; and

•	the possibility that we may be required to issue a substantial amount of additional equity and/or debt securities or assume additional debt in connection with any such transactions.

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(1)	We completed the AER Acquisition effective December 2, 2013; therefore, the results of our IPH segment are only included subsequent to December 2, 2013. Please read Note 3—Merger and Acquisitions—AER Transaction Agreement for further discussion.

(2)	We completed the DMG Acquisition effective June 5, 2012; therefore, the results of our Coal segment are only included subsequent to June 5, 2012. Please read Note 3—Merger and Acquisitions—DMG Transfer and Acquisition for further discussion.

(3)	We completed the DMG Transfer effective September 1, 2011; therefore, the results of our Coal segment are only included prior to September 1, 2011. Please read Note 23—Dispositions and Discontinued Operations for further discussion.

(4)	Includes $11 million, $21 million and $46 million of debt extinguishment costs for the years ended December 31, 2013, 2011 and 2009, respectively.

(5)	Discontinued operations include the results of operations from the following businesses:

•	The DNE Debtor Entities (please read Note 23—Dispositions and Discontinued Operations for further discussion of the sale of the DNE facilities);

•	The Arlington Valley and Griffith power generation facilities (collectively, the “Arizona power generation facilities”) (sold fourth quarter 2009);

•	Bluegrass power generating facility (sold fourth quarter 2009); and

•	Heard County power generating facility (sold second quarter 2009).

(6)	Although Legacy Dynegy’s shares were publicly traded, DH did not have any publicly traded shares prior to the merger; therefore, no earnings (loss) per share is presented for the Predecessor.

(7)	As a result of the DH Chapter 11 Cases, we reclassified approximately $3.6 billion in long-term debt to LSTC as of December 31, 2011. These liabilities were settled upon our emergence from bankruptcy on the Plan Effective Date. Please read Note 21—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

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•	Prices for power, natural gas, coal and fuel oil, 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.

•	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 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 for further discussion);

•	Market supply conditions resulting from federal and regional renewable power mandates and initiatives;

•	Our ability to maintain sufficient coal inventories, which is dependent upon the continued performance of the mines, railroads and barges for deliveries of coal in a consistent and timely manner, and its impact on our ability to serve the critical winter and summer on-peak loads;

•	Costs of transportation related to coal deliveries;

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

•	Changes in MISO market design or associated rules;

•	Changes in the existing bilateral MISO capacity markets and any resulting effect on future capacity revenues;

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

•	Our ability to mitigate impacts associated with expiring RMR and/or capacity contracts;

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•	Our ability to maintain the necessary permits to continue to operate our Moss Landing facility with once-through, seawater cooling systems;

•	The costs incurred to demolish and/or remediate the South Bay and Vermilion facilities;

•	Changes in the existing bilateral CAISO resource adequacy markets and any resulting effect on future capacity revenues;

•	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.

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(1)	Includes Cash and cash equivalents of $190 million related to Genco.

(2)	As previously discussed, due to the ring-fenced nature of IPH, cash at the IPH and Genco entities may not be moved out of these entities without meeting certain criteria. However, cash at these entities is available to support current operations of these entities.

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(1)	Includes broker margin as well as other collateral postings included in Prepayments and other current assets on our consolidated balance sheets. As of December 31, 2013 and December 31, 2012, $4 million and $8 million of cash posted as collateral were netted against Liabilities from risk management activities on our consolidated balance sheets.

(2)	Includes cash of $1 million related to Genco as of December 31, 2013.

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(1)

On September 1, 2011, we completed the DMG Transfer. On June 5, 2012, we completed the DMG Acquisition. Therefore, capital expenditures are included only from June 6, 2012 to October 1, 2012 for the 2012 Predecessor Period and from January 1, 2011 through August 31, 2011 for the year ended December 31, 2011. For the 2012 Predecessor Period and the year ended December 31, 2011, including the periods that Coal was not included in our consolidated financial statements, Coal capital expenditures were $75 million and $184 million, respectively.

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(1)	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.

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(1)	The table above includes projected payments through 2018 assuming the contracts remain in full force and effect; however, we currently estimate these agreements will be in effect for a period of 15 or more years. Our minimum obligation related to these agreements is limited to the termination payments.

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•	Demolition and restoration obligations related to our retired power generation facilities of $17 million;

•	Severance and retention obligations of $12 million as of December 31, 2013 in connection with a reduction in workforce and the closure of certain power generation facilities. Please read Note 24—Restructuring Charges for further discussion.

•	Obligations of $4 million for harbor support and utility work in connection with Moss Landing;

•	Obligations of $4 million related to information technology-related contracts;

•	Obligations of $3 million primarily for Morro Bay city improvements in connection with our Morro Bay facility; and

•	Obligations of $2 million primarily for a water supply agreement and other contracts for our Ontelaunee facility.

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(1)	Relates to costs associated with the AER Transaction Agreement. Please read Note 3—Merger and Acquisitions for further discussion.

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(1)

Our 2012 consolidated results reflect the results of our accounting predecessor, DH. Therefore, the results of our Coal segment are not included in our consolidated results for the period from January 1, 2012 through June 5, 2012. However, we have included the Adjusted EBITDA related to the Coal segment for the period from January 1, 2012 through June 5, 2012 in this adjustment because it is part of our ongoing business and management uses Adjusted EBITDA to evaluate the operating performance of our entire power generation fleet.

(2)

For purposes of presenting Adjusted EBITDA for the year ended December 31, 2012, we combined the 2012 Successor Period and the 2012 Predecessor Period in order to reconcile our non-GAAP measure to its nearest comparable GAAP measure. The combined Successor and Predecessor periods are also non-GAAP due to fresh-start accounting. Therefore, the following table is provided to reconcile the combined amounts to the separate Successor and Predecessor periods.

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(1)

Our 2011 consolidated results reflect the results of our accounting predecessor, DH. Therefore, the results of our Coal segment are not included in our consolidated results for the period from September 1, 2011 through December 31, 2011. However, we have included the Adjusted EBITDA related to the Coal segment for the period from September 1, 2011 through December 31, 2011 in this adjustment because it is part of our ongoing business and management uses Adjusted EBITDA to evaluate the operating performance of our entire power generation fleet.

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(2)	Legacy Dynegy’s adjusted EBITDA was $20 million for the period January 1, 2012 through June 5, 2012 and $48 million for the period September 1, 2011 through December 31, 2011.

(3)	Reflects production volumes in million MWh generated during the periods Coal was included in our consolidated results. Generation volumes were 19.9 million MWh and 22.2 million MWh for the full twelve months ended December 31, 2012 and 2011, respectively.

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(1)	Other includes financial settlements, ancillary services and other miscellaneous items.

(2)	Reflects production volumes in million MWh generated during the period IPH was included in our consolidated results.

(3)	Reflects the percentage of generation available during the period IPH was included in our consolidated results.

(4)	Reflects the average of day-ahead quoted prices for the period IPH was included in our consolidated results and does not necessarily reflect prices we realized.

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(1)	Other includes ancillary services, RMR, tolls, natural gas, financial settlements, option premiums and other miscellaneous items.

(2)	Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility.

(3)	Reflects the percentage of generation available when market prices are such that these units could be profitably dispatched.

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

(5)	Reflects the average of our on- or off-peak spark spreads at the following facilities: Commonwealth Edison (NI Hub), PJM West, North of Path 15 (NP 15), New York - Zone A and Mass Hub.

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

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•	Revenue Recognition and Derivative Instruments;

•	Fair Value Measurements;

•	Accounting for Income Taxes; and

•	Business Combinations and Fresh-Start Accounting.

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•	Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as listed equities.

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Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standard models or other valuation methodologies, in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options, and swaps.

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Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

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

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•	manage and hedge our fixed-price purchase and sales commitments;

•	reduce our exposure to the volatility of cash market prices; and

•	hedge our fuel requirements for our generating facilities.

•	commodity price risks result from exposures to changes in spot prices, forward prices and volatilities in commodities, such as electricity, natural gas, coal, fuel oil, emissions and other similar products; and

•	interest rate risks primarily result from exposures to changes in the level, slope and curvature of the yield curve and the volatility of interest rates.

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(1)	The calculation period for $250 million of the interest rate swaps began June 30, 2013, and the calculation period for the remaining $546 million began October 31, 2013.

(2)	The $1,400 million interest rate caps were terminated in July 2013.

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(i)	pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets;

(ii)	provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of our company are being made only in accordance with authorizations of our management and directors; and

(iii)	provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on the financial statements.

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(1)	The plan that is approved by our security holders is the 2012 Long Term Incentive Plan. Please read Note 17—Capital Stock—Stock Award Plans for further discussion.

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*	Pursuant to Item 6.01(b)(2) of Regulation S-K exhibits and schedules are omitted. Dynegy agrees to furnish to the Commission supplementally a copy of any omitted schedule or exhibit upon request of the Commission.

**

XBRL information is furnished and not filed for purposes of Section 11 and 12 of the Securities Act of 1933 and Section 18 of the Securities Exchange Act of 1934, and is not subject to liability under those sections, is not part of any registration statement or prospectus to which it relates and is not incorporated or deemed to be incorporated by reference into any registration statement, prospectus or other document.

****	Pursuant to a request for confidential treatment, portions of this Exhibit have been redacted and filed separately with the SEC as required by Rule 24b-2 under the Securities Exchange Act of 1934, as amended.

††	Management contract or compensation plan.

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(1)

During 2013, we revised our ARO upward by $36 million based on observed trends in Illinois primarily related to ash pond closures and groundwater monitoring. During the 2012 Predecessor Period, we revised the South Bay ARO downward by $16 million based on revised cost estimates related to the plant demolition. During 2011, we revised our ARO downward by $24 million based on revised cost estimates related to remediation of asbestos, plant demolition and ash ponds.

(2)	As a result of the AER Acquisition on December 2, 2013, the AROs associated with the IPH segment were assumed.

(3)

As a result of the DMG Transfer (as defined in Note 3—Merger and Acquisitions—DMG Transfer and DMG Acquisition) on September 1, 2011, the AROs associated with the Coal segment (including DMG) were transferred from DH to Legacy Dynegy and subsequently, as a result of the DMG Acquisition (as defined in Note 3—Merger and Acquisitions—DMG Transfer and DMG Acquisition), the AROs were reacquired on June 5, 2012.

(4)	As a result of the deconsolidation of the DNE Debtor Entities, the related AROs are no longer reflected as liabilities on our consolidated balance sheets.

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Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and U.S. government treasury securities.

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Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using industry-standards models or other valuation methodologies, in which substantially all assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter forwards, options and swaps.

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Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. Level 3 instruments include those that may be more structured or otherwise tailored to our needs. At each balance sheet date, we perform an analysis of all instruments and include in Level 3 all of those whose fair value is based on significant unobservable inputs.

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(1)	Includes both asset and liability risk management positions, but excludes margin and collateral netting, as discussed below.

(2)	Mainly comprised of swaps, options and physical forwards. Electricity derivatives also include FTRs.

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(1)	Represents forward financial and physical transactions at illiquid pricing locations.

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(1)	For purposes of these tables, we define settlements as the beginning of period fair value of contracts that settled during the period.

(2)	The interest rate contracts classified within Level 3 in the Predecessor period include an implied credit fee that impacted the day one value of the instruments. We revalued the credit fee in connection with the application of fresh-start accounting. As a result, these instruments are classified within Level 2 in the Successor period.

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(1)	Carrying amount includes an unamortized discount of $4 million as of December 31, 2013. Please read Note 12—Debt for further discussion.

(2)	Carrying amount of commodity-based derivative contracts excludes $4 million and $8 million of cash posted as collateral, as of December 31, 2013 and December 31, 2012, respectively.

(3)	Carrying amount includes an unamortized premium of $43 million as of December 31, 2012. Please read Note 12—Debt for further discussion.

(4)	Carrying amount includes an unamortized premium of $18 million as of December 31, 2012. Please read Note 12—Debt for further discussion.

(5)	Combined carrying amounts as of December 31, 2013 include unamortized discounts of $142 million related to the AER Acquisition. Please read Note 12—Debt and Note 3—Merger and Acquisitions—AER Transaction Agreement for further discussion.

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(1)	Amount related to the reclassification of mark-to-market gains on cash flow hedging activities, net and was recorded in Revenues on our consolidated statements of operations.

(2)	Amount related to the DNE pension curtailment gain and was recorded in Income (loss) from discontinued operations, net of tax on our consolidated statements of operations. Please read Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

(3)	Amounts are associated with our defined benefit pension and other post-employment benefit plans and are included in the computation of net periodic pension cost. Please read Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

(4)	Amount related to the transfer of certain defined benefit pension and other post-employment benefit plans as a part of the DMG Transfer on September 1, 2011 and subsequent DMG Acquisition on June 5, 2012. Please read Note 18—Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans for further discussion.

(5)	Represents the fresh-start adjustment to eliminate the historical accumulated other comprehensive loss of the Predecessor.

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(1)	These expenditures related primarily to changes in our accruals related to capital expenditures for all years presented. Please read Note 16—Commitments and Contingencies for further discussion.

(2)	Represents transactions with Legacy Dynegy in the normal course of business, primarily the reallocation of deferred taxes between legal entities in accordance with the applicable IRS regulations.

(3)	Represents a promissory note received in exchange for the DMG Transfer on September 1, 2011.

(4)	Represents the consideration given by us related to acquisitions. Please read Note 3—Merger and Acquisitions for further discussion.

(1)	This inventory is held as collateral by one of our counterparties as part of a financing arrangement. Refer to Note 12—Debt for further details related to the Emissions Repurchase Agreements.

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(1)	The amortization expense of these contracts is recognized in Revenues in our consolidated statements of operations.

(2)	The amortization expense of these contracts is recognized in Cost of sales in our consolidated statements of operations.

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(1)	For purposes of calculating Net Debt, we may only apply a maximum of $150 million in cash to our outstanding secured debt.

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(1)	As of the date of the restricted payment, as defined, the minimum ratio must have been achieved for the most recently ended four fiscal quarters and projected by management to be achieved for each of the subsequent four six-month periods.

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(1)	Includes cash posted to support the respective letter of credit reimbursement and collateral agreements.

(2)	Amounts are restricted and used for future collateral posting requirements or released per the terms of the applicable credit agreement. As a result of terminating the DPC and DMG credit agreements, all of our restricted cash was released.

(3)	Includes cash posted to support a letter of credit and collateral for the corporate card program.

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(1)	We incurred a state tax benefit for the year ended December 31, 2011 due to current year losses and a $6 million audit adjustment offset by a $2 million expense due to a change in Illinois tax law.

(2)

We recorded a valuation allowance of $41 million during the 2012 Successor Period to reserve our net deferred tax assets. In connection with the DMG Transfer, we recognized a deferred tax asset of approximately $466 million and subsequently recorded a valuation allowance for the full amount. We do not believe we will produce sufficient taxable income, nor are there tax planning strategies available to realize the tax benefit. The AER Acquisition in 2013 caused a change in judgment about the realizability of our deferred tax assets. As a result, we recorded a $35 million reduction to our valuation allowance during 2013 in connection with the AER Acquisition.

(3)	Pre-tax income from components other than continuing operations provided a source of income that allowed for the reduction of the valuation allowance from continuing operations.

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(1)	Entities with a net loss from continuing operations are prohibited from including potential common shares in the computation of diluted per share amounts. Accordingly, we have utilized the basic shares outstanding amount to calculate both basic and diluted loss per share for all periods presented.

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Dynegy 2012 Long Term Incentive Plan. This plan is a broad-based plan and provides for the issuance of approximately 6.1 million authorized shares through October 2022. The maximum number of shares of common stock that may be subject to options, restricted stock awards, stock unit awards, stock appreciation rights, phantom stock awards and performance awards, denominated in shares of common stock granted to any one individual during any calendar year may not exceed approximately 1.2 million shares or the equivalent of approximately 1.2 million shares of common stock (subject to adjustment in accordance with the provisions of the 2012 Long Term Incentive Plan). The maximum amount of compensation that may be paid under all performance awards denominated in cash (including the fair market value of any shares of common stock paid in satisfaction of such performance awards) granted to any one individual during any calendar year may not exceed a fair market value of $10 million. Any options granted under the plan will expire no later than 10 years from the date of the grant.

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Dynegy 2000 Long Term Incentive Plan. This annual compensation plan, created for all employees upon Illinova’s merger with us, provided for the issuance of 2 million authorized shares through June 2009. Grants from this plan vested in equal annual installments over a three-year period, and options expired 10 years from the date of the grant. All outstanding awards were cancelled on the Plan Effective Date.

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Dynegy 2001 Non-Executive Long Term Incentive Plan. This plan was a broad-based plan and provided for the issuance of 2 million authorized shares through September 2011. Grants from this plan vested in equal annual installments over a three-year period, and options expired no later than 10 years from the date of the grant. This plan was frozen as to issuance of new awards. All outstanding awards were cancelled on the Plan Effective Date.

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Dynegy 2002 Long Term Incentive Plan. This annual compensation plan provided for the issuance of 2 million authorized shares through May 2012. Grants from this plan vested in equal annual installments over a three-year period, and options expired no later than 10 years from the date of the grant. Following the approval of the Dynegy 2010 Long Term Incentive Plan, this plan was frozen as to issuance of new awards. All outstanding awards were cancelled on the Plan Effective Date.

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•	Dynegy 2010 Long Term Incentive Plan. This plan was a broad-based plan and provided for the issuance of 3.7 million authorized shares through May 2020. Any options granted under the plan were to expire no later than 10 years from the date of the grant. All outstanding awards were cancelled on the Plan Effective Date.

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•	Three-year performance period (2013 through 2015);

•	Payout opportunity of 0-200 percent of target, intended to be settled in shares;

•	Cumulative TSR percentile ranking calculated at end of performance period and applied to the payout scale to determine the number of earned/vested PSUs; and

•	If absolute TSR is negative, PSU award payouts will be capped at 100 percent of the target number of PSUs granted, regardless of relative TSR positioning.

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Dynegy Inc. 401(k) Plan.  This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the U.S. Generally, all employees of designated Dynegy subsidiaries are eligible to participate in this plan. Except for certain represented employees, employee pre-tax and Roth contributions to the plan are matched by the Company at 100 percent, up to a maximum of five percent of base pay (subject to IRS limitations) and vesting in company contributions is based on years of service with 50 percent vesting per full year of service. Effective December 2, 2013, IPH employees participate in this plan and effective January 1, 2014, EEI employees participate in this plan. This plan also allows for a discretionary contribution to eligible employee accounts for each plan year, subject to the sole discretion of the Compensation and Human Resources Committee of the Board of Directors. No discretionary contributions were made for any of the years in the three-year period ended December 31, 2013.

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Restoration 401(k) Savings Plan. In 2008, we adopted the Dynegy Inc. Restoration 401(k) Savings Plan, a nonqualified plan that supplements or restores benefits lost by certain of our highly compensated employees under the Dynegy Inc. 401(k) Plan as a result of IRC limitations that apply to qualified plans. Benefits under this plan are paid as a lump sum. However, effective for periods on and after January 1, 2012, participation in and benefit accruals under this plan were frozen.

•	EEI Bargaining Unit 401(k) Plan. Under this plan we match 50 percent of employee pre-tax contributions up to eight percent of base pay for EEI union employees, subject to IRS limitations. Effective January 1, 2014, plan benefits were frozen and contributions stopped as of that date and participants became eligible to participate in the Dynegy Inc. 401(k) Plan.

•	EEI Management 401(k) Plan. Under this plan we match we match 50 percent of employee pre-tax contributions up to eight percent of base pay for EEI management employees, subject to IRS limitations. Effective January 1, 2014, plan benefits were frozen and contributions stopped as of that date and participants became eligible to participate in the Dynegy Inc. 401(k) Plan.

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(1)	The curtailment gain was related to the DNE pension plan and resulted from the Roseton sale and the termination of a majority of the Danskammer employees.

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(1)	The curtailment loss for the year ended December 31, 2013 was related to the EEI post-employment benefit plan and resulted from a plan amendment and post-close terminations expected due to the AER Acquisition.

(1)	We utilized a yield curve approach to determine the discount. Projected benefit payments for the plans were matched against the discount rates in the yield curve.

(2)	The rate of compensation increase used for other post-employment benefits for the year ended December 31, 2013 is specifically related to the EEI post-employment plans.

(1)	The average expected return on EEI’s other post-employment plan assets was 6 percent for the year ended December 31, 2013. The expected return on EEI’s other post-employment plan assets was 6.50 percent for EEI union employees and 5.50 percent for EEI salaried employees for the year ended December 31, 2013.

(2)	The rate of compensation increase used for other post-employment benefits for the year ended December 31, 2013 is specifically related to the EEI post-employment plans.

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(1)	This category comprises a domestic common collective trust not actively managed that tracks the Dow Jones total U.S. stock market.

(2)	This category comprises a common collective trust not actively managed that tracks the MSCI All Country World Ex-U.S. Index.

(3)	This category comprises actively managed common collective trusts that hold U.S. and foreign equities. These trusts track the MSCI World Index.

(4)	This category includes a mutual fund and a trust that invest primarily in investment grade corporate bonds.

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(1)	Includes a loss from Bankruptcy reorganization items, net and an Impairment of Undertaking receivable, affiliate of approximately $247 million and $832 million, respectively. Please read Note 22—Condensed Combined Financial Statements of the Debtor Entities and Note 13—Related Party Transactions for further discussion.

(2)	Includes a gain from Bankruptcy reorganization items, net of approximately $1.1 billion associated with our emergence from bankruptcy. Please read Note 21—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

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•	On the Plan Effective Date, all of Dynegy’s equity interests, including Dynegy’s old common stock, were cancelled.

•	Each holder of Allowed General Unsecured Claims received its Pro Rata Share of (a) 99 million shares of Dynegy Common Stock and (b) a $200 million cash payment (the “Plan Cash Payment”).

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In full satisfaction of the Dynegy Administrative Claim (otherwise referred to herein as the “Administrative Claim”), the beneficial holders thereof (which were the holders of Dynegy’s old common stock) received their Pro Rata Share of (a) one million shares of Dynegy Common Stock and (b) warrants to purchase approximately 15.6 million shares of Dynegy Common Stock for an exercise price of $40 per share (subject to adjustment) expiring on October 2, 2017 (the “Warrants”).

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In addition, each holder of an Allowed General Unsecured Claim received, as applicable, their Pro Rata Share of the proceeds of the sale of the Roseton and Danskammer generation facilities (the “Facilities”) allocated to Dynegy (the “Facilities Sale”) according to the Settlement Agreement; provided that, the Lease Trustee (on behalf of itself and the Lease Certificate Holders) will not receive a distribution of any amounts paid pursuant to the Facilities Sale in its capacity as holder of the Lease Guaranty Claim.

•	8.75 percent senior notes due 2012;

•	7.5 percent senior unsecured notes due 2015;

•	8.375 percent senior unsecured notes due 2016;

•	7.125 percent senior debentures due 2018;

•	7.75 percent senior unsecured notes due 2019;

•	7.625 percent senior notes due 2026; and

•	Series B 8.316 percent subordinated debentures due 2027 (the “2027 Notes”).

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(a)	Represents the consolidated balance sheet of our Predecessor as of October 1, 2012.

(b)

Reflects the deconsolidation of the DNE Debtor Entities as of October 1, 2012. The DNE Debtor Entities did not emerge from protection under Chapter 11 of the Bankruptcy Code; therefore, the DNE Debtor Entities were deconsolidated as of October 1, 2012. These adjustments (i) remove the balances associated with the DNE Debtor Entities from our October 1, 2012 balance sheet; (ii) impair the $13 million note receivable, which was included in Prepayments and other current assets, related to the debtor-in-possession financing provided by us to the DNE Debtor Entities; and (iii) moves balances related to service agreements and risk management activities to affiliate accounts.

(c)

Represents amounts recorded for the implementation of the Plan on the Plan Effective Date. This includes the settlement of liabilities subject to compromise through a cash payment of approximately $200 million, the authorization and distribution of New Common Stock and Warrants, and the cancellation of the Old Common Stock. Additionally, these adjustments remove the historical accumulated deficit of the predecessor. The following reflects the calculation of the total pre-tax gain (amounts in millions):

(d)	Represents the adjustments of assets and liabilities to fair value in conjunction with the application of fresh-start accounting.

(e)	Reflects an adjustment to prepayments related to professional fees.

(f)	Reflects adjustments to the Claims reserve. The Claims reserve is included in Accrued liabilities and other current liabilities on our consolidated balance sheet and primarily consists of accruals for professional fees. The following reflects the components of the Claims reserve as of the Plan Effective Date (amounts in millions):

(g)	Reflects the issuance of Warrants pursuant to our Plan of Reorganization. Please read Note 17—Capital Stock for further discussion.

(h)	Reflects the impact of the reorganization adjustments (amounts in millions):

(i)	Reflects a reclassification of receivables to Other long-term assets.

(j)	Reflects the fair value adjustment related to inventory.

(k)

In the application of fresh-start accounting, the Successor changed its accounting policy related to the presentation of certain derivative contracts. We have elected to present these contracts on a net basis where the right of offset exists. As a result, we recorded reductions to Assets from risk-management activities (current), Broker margin account, and Assets from risk management activities (long-term) of $522 million, $13 million, and $9 million, respectively. In addition, we recorded reductions to Liabilities from risk management activities (current) and Liabilities from risk management activities (long-term) of $561 million and $9 million, respectively.

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(l)	Reflects the fair value adjustment for short-term and long-term identifiable intangible assets of $60 million and $42 million, respectively. These contracts consist of favorable capacity contracts, tolling agreements and rail transportation contracts, which were valued based on comparing contract terms to market prices.

(n)	Represents the adjustment required to present Property, plant and equipment at its estimated fair value of approximately $3 billion as of October 1, 2012.

(o)	Reflects the re-measurement of the Company’s deferred tax assets and liabilities, unrecognized tax benefits and other tax related accounts as a result of implementing the Plan and the application of fresh-start accounting.

(p)	Reflects a $22 million reclassification of receivables as discussed in (i) above offset by the $17 million adjustment to eliminate historical long-term deferred financing costs.

(s)	Reflects a $9 million increase in the liability related to our interest rate swaps as a result of a change in the calculation of the credit reserve offset by a reduction of $9 million due to the net presentation of our risk management positions as discussed in (k) above.

(t)	Reflects the fair value adjustment to other long-term liabilities which is comprised of a $42 million increase in our pension and other post-retirement benefit liabilities and a $5 million increase in our AROs, partially offset by a $7 million decrease in liabilities related to the long-term portion of unfavorable contracts as discussed in (q) above.

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(1)	Amount represents adjustments to our estimate of the probable allowed claim associated with the DNE leases. Amount in 2011 also includes the write-off of deferred rent that had accumulated over time as the historical lease payments exceeded the annual rent expense.

(2)	The estimated allowable claims related to the Subordinated Capital Income Securities were adjusted in 2012 based on the terms of the Settlement Agreement. Please read Note 21—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

(3)	During 2012, it was determined that no claim related to the Note payable, affiliate would be made. Therefore, the estimated amount was reduced to zero.

(4)	Approximately $217 million of the gain on settlement of claims is included in Income (loss) from discontinued operations on our consolidated statement of operations in the 2012 Predecessor Period.

(5)	The Administrative Claim was issued on the effective date of the Settlement Agreement. Please read Note 4—Risk Management Activities, Derivatives and Financial Instruments and Note 21—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

(6)	Professional fees relate primarily to the fees of attorneys and consultants working directly on the Chapter 11 Cases.

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(1)	Expense during the year ended December 31, 2013, the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011 includes $3 million, less than $1 million, $4 million and $2 million in retention benefits, respectively.

(2)	On September 1, 2011, we completed the DMG Transfer. Please read Note 3—Merger and Acquisitions—DMG Transfer and DMG Acquisition for further discussion.

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