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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 have historically been included in our Coal segment, as these facilities were retired effective January 7, 2013. Additionally, we have also not included the DNE facilities, consisting of approximately 1,700 MW, as these facilities were deconsolidated effective October 1, 2012, and are under agreement to be sold. The sales are expected to close during 2013. Please read Note 6—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)	Represents Units 3 and 4 generating capacity. Units 1 and 2, with a combined net generating capacity of 352 MW, are currently in mothball status and out of operation.

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

•	Operational Excellence—Operating our power plants in a safe, reliable, and environmentally compliant manner with a particular focus on increasing cash flow and optimizing availability;

•	Commercial Execution—Optimizing the commercial results of the assets through proactive management of our power, fuel, capacity, and ancillary service positions with short-, medium-, and long-term agreements and hedging arrangements;

•	Corporate and Organizational Support—Maximizing organizational effectiveness and efficiency through continuous business process improvements, operational enhancements, and cost management; and

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

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•	our ability to consummate the acquisition of certain power generation facilities from Ameren Corporation;

•	our ability to consummate the Facilities Sale Transactions in accordance with the Settlement Agreement, the Chapter 11 Joint Plan of Liquidation and the Danskammer and Roseton APAs (each as defined herein);

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

•	beliefs and assumptions relating to our liquidity, available borrowing capacity and capital resources generally, including the extent to which such liquidity could be affected by poor economic and financial market conditions or new regulations and any resulting impacts on financial institutions and other current and potential counterparties;

•	limitations on our ability to utilize previously incurred federal net operating losses or alternative minimum tax credits;

•	expectations regarding our compliance with the DMG and DPC Credit Agreements and DPC’s Revolving Credit Agreement, including collateral demands, interest expense, financial ratios and other payments;

•	the timing and anticipated benefits of any refinancing of the DMG and DPC Credit Agreements;

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

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

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

•

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 impact on such prices from shale gas proliferation 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 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;

•	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 and assumptions regarding the outcome of the SCE contract terminations dispute and the impact of such terminations on the timing and amount of future cash flows;

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

•	beliefs about the outcome of legal, administrative, legislative and regulatory matters, including the impact of final rules regarding derivatives issued by the CFTC under the Dodd-Frank Act; and

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•	expectations and estimates regarding capital and maintenance expenditures.

•	economic conditions;

•	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;

•	basis risk from transmission losses and congestion;

•	the proliferation of advanced shale gas drilling increasing domestic natural gas supplies;

•	fuel price volatility; 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 sale and leaseback transactions;

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

•	create unrestricted subsidiaries;

•	impair the security interests;

•	issue certain capital stock;

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

•	sell and acquire assets.

•	covenants in our existing credit agreements;

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•	investor confidence in us and the regional wholesale power markets;

•	our financial performance and the financial performance of our subsidiaries;

•	our levels of debt;

•	our requirements for posting collateral under various commercial agreements;

•	our credit ratings;

•	our cash flow;

•	our long-term business prospects; and

•	general economic and capital market conditions, including the timing and magnitude of any market recovery.

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•	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;

•	difficulty in evaluating the power 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 DMG Acquisition effective June 5, 2012; therefore, the results of our Coal segment are only included subsequent to June 5, 2012. Please read Note 4—Merger and Acquisition for further discussion.

(2)	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 6—Dispositions and Discontinued Operations for further discussion.

(3)	Includes $21 million and $46 million of debt extinguishment costs for the year ended December 31, 2011 and 2009, respectively.

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

•	The DNE Debtor Entities (please read Note 6—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);

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

•	Calcasieu power generating facility (sold first quarter 2008); and

•	DMSLP, our former midstream business (sold fourth quarter 2005).

(5)	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.

(6)	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 3—Emergence from Bankruptcy and Fresh-Start Accounting and Note 17—Liabilities Subject to Compromise 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 proliferation of advanced shale gas drilling has increased domestic natural gas supplies which has caused a decline in power prices;

•	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 and railroads 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;

•	Our ability to maintain the necessary permits to continue to operate our Moss Landing and Morro Bay facilities 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

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

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(1)	Other cash consists of zero and zero at Coal Holdco; $1 million and $1 million at Dynegy Gas Holdco, LLC; $5 million and $10 million at Dynegy Administrative Services Company; and $295 million and $306 million at Dynegy Inc. as of March 8, 2013 and December 31, 2012, respectively.

(2)

The LC facilities were collateralized with cash proceeds received under our existing credit agreements. The amount of the LC availability plus any unused required reserves of 3 percent of the unused capacity, may be withdrawn from the LC facilities with three days written notice for unrestricted use in the operations of the applicable entity. LC capacity as of March 8, 2013 and December 31, 2012 reflects a reduction in capacity for DMG and DPC following the requested release of unused cash collateral from restricted cash. Actual commitment amounts under each credit agreement have not been reduced, and DMG and DPC can increase the LC capacity up to the original commitment amount in the future by posting additional cash collateral.

(3)	The collateral posting account included in the above liquidity tables is restricted per the DMG Credit Agreement and the DPC Credit Agreement and may be used for future collateral posting requirements or released per the terms of the applicable credit agreement.

(4)	Does not reflect our ability to use the first lien structure as described in Operating Activities—“Collateral Postings”.

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

(2)	As a result of the DMG Transfer on September 1, 2011, DMG was owned by Legacy Dynegy and was not included in our consolidated financial statements as of December 31, 2011. As of December 31, 2011, DMG had $11 million and $38 million in cash and letters of credit posted as collateral, respectively.

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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)	Our unsecured obligations as of December 31, 2011 were subject to compromise as a result of our bankruptcy filing on November 7, 2011 and were settled in connection with our emergence from bankruptcy on the Plan Effective Date. Please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

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(1)	Included based on nature of purchase obligations under associated contracts.

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•	Demolition and restoration obligations related to our retired power generation facilities and related assets of $20 million;

•	Obligations of $4 million primarily for Morro Bay city improvements in connection with our Morro Bay facility;

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

•	Reserves of $1 million recorded in connection with uncertain tax positions. Please read Note 20—Income Taxes—Unrecognized Tax Benefits for further discussion;

•	Obligations of $3 million primarily for a water supply agreement and other contracts for our Ontelaunee facility;

•	Obligations of $1 million related to information technology related contracts; and

•	Severance and retention obligations of $3 million as of December 31, 2012 in connection with a reduction in workforce and the closure of certain power generation facilities. Please read Note 7—Impairment and Restructuring Charges—Restructuring Charges for further discussion.

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(1)

The amount in the Coal segment in the 2012 Predecessor Period relates to intangible assets and liabilities related to rail transportation and coal contracts, respectively, recorded in connection with the DMG Acquisition. The amount in the Gas segment in the 2012 Predecessor Period is related to the intangible assets related to the 2005 Sithe acquisition. The amounts in the Successor Period related to intangible assets and liabilities related to rail transportation, coal contracts, gas revenue contracts and gas transportation contracts recorded in connection with the application of fresh-start accounting. Please read Note 16—Intangible Assets and Liabilities for further discussion.

(2)

Our 2012 consolidated results reflect the results of our accounting predecessor, DH, which was our wholly-owned subsidiary until the Merger on September 30, 2012. Therefore, certain results related to Legacy Dynegy are not included in our consolidated results for the 2012 Predecessor Period. Additionally, effective June 5, 2012, we completed the DMG Acquisition. As a result, the results of our Coal segment, as well as certain items in the Other 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 Legacy Dynegy for the 2012 Predecessor Period and the Coal segment for the period from January 1, 2012 through June 5, 2012 in this adjustment because management uses enterprise-wide Adjusted EBITDA to evaluate the operating performance of our entire power generation fleet.

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(1)

Our 2011 consolidated results reflect the results of our accounting predecessor, DH, which was our wholly-owned subsidiary until the Merger on September 30, 2012. Therefore, certain results related to Legacy Dynegy are not included in our consolidated results for the year ended December 31, 2011. Additionally, effective September 1, 2011, we completed the DMG Transfer. As a result, the results of our Coal segment, as well as certain items in the Other 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 Legacy Dynegy for the year ended December 31, 2011 and the Coal segment for the period from September 1, 2011 through December 31, 2011 in this adjustment because management uses enterprise-wide Adjusted EBITDA to evaluate the operating performance of our entire power generation fleet.

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•

DMG Transfer—The amounts in the tables add back the results of our Coal segment for the period of time that our Coal segment was not included in the consolidated results due to the DMG Transfer. For 2012, this amount includes the results of operations related to the Coal segment for the period from January 1, 2012 through June 5, 2012. For 2011, this amount includes the results of operations related to the Coal segment for the period from September 1, 2011 through December 31, 2011.

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DMG Acquisition—The DMG Acquisition was accounted for as a business combination. Therefore, the acquired assets and liabilities were recorded at their estimated fair values as of the acquisition date. As a result, 2012 results include the amortization of intangible assets and liabilities that did not exist in 2011. In addition, the property, plant and equipment associated with the Coal segment had a significantly lower basis in 2012 as a result of the purchase price allocation. The amounts in the tables below remove the impact of purchase price adjustments included in 2012 results that have no corresponding amounts in 2011 results.

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Fresh-Start Adjustments—Upon emergence from bankruptcy on the Plan Effective Date, we applied fresh-start accounting which resulted in adjusting our assets and liabilities to their estimated fair values. As a result, 2012 results include the amortization of intangible assets and liabilities that did not exist in 2011. In addition, our property, plant and equipment had a significantly lower basis in 2012 as a result of the fresh-start adjustments. The amounts in the tables below remove the impact of the fresh-start adjustments included in 2012 results that have no corresponding amounts in 2011 results.

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(2)	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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Energy revenue decreased by $197 million and the corresponding cost of sales decreased by $14 million, for a total decrease in energy margin of $183 million. The decrease in energy revenue is due to lower market prices, an increase in basis differentials and more planned outages, which led to lower volumes produced. The decrease in cost of sales is due to lower generation volumes caused by higher planned outages and less generation in off peak periods.

•	Settlement revenue decreased by $49 million primarily due to a decrease in settlement revenue associated with power swaps.

•	Mark-to-market revenue increased by $92 million due to a net change in mark-to-market losses of $91 million in the year ended December 31, 2011 to mark-to-market revenues of $1 million in the year ended December 31, 2012.

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

(2)	Includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility for the year ended December 31, 2012 and 2011, respectively.

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

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

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Energy revenue and the corresponding cost of sales increased by $121 million and $30 million, respectively, for a net increase in energy margin of $91 million. Energy revenue and cost of sales increased due to higher volumes generated. Volumes were up due to higher spark spreads at Moss Landing, Independence and Kendall during the year ended December 31, 2012 compared to the year ended December 31, 2011. Volumes were also up due to fewer outage hours at Moss Landing and Casco Bay in 2012 compared to 2011. Both plants experienced significant planned and unplanned outages in 2011 due to required turbine blade repairs. There were no such outages in 2012. Additionally, the increases to both energy revenue and cost of sales caused by higher generation volumes were partially offset by lower power and gas pricing across our fleet.

•	Mark-to-market revenue increased by $217 million due to a net change in mark-to-market losses of $61 million during the year ended December 31, 2011 compared to mark-to-market revenues of $156 million during the year ended December 31, 2012. The increase in mark-to-market revenue was primarily driven by the roll off of liability positions.

•	Capacity revenue decreased by $13 million primarily due to a decrease in capacity pricing in the PJM market, partially offset by the timing of the termination of certain contractual arrangements related to our Gas assets in the West.

•	Tolling revenue decreased by $27 million primarily due to the cancellation of the Morro Bay tolling agreement.

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Gas revenue decreased by $45 million due to lower volumes sold and lower gas pricing for the year ended December 31, 2012 compared to the year ended December 31, 2011. As we lack gas storage capabilities, all gas purchased must be used in generation or sold back to the market. Higher generation across the gas fleet in 2012 led to less gas available for resale and therefore less gas revenue. The cost of the gas is included in cost of sales.

•	Settlement revenue decreased by $63 million primarily due to an increase in settlement expense associated with the settlement of gas positions executed in prior periods.

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Approximately $224 million related to the difference between mark-to-market losses on forward sales of power and other derivatives in 2011, compared to mark-to-market gains in 2010. Such losses totaled $142 million for the year ended December 31, 2011, compared to $82 million of mark-to-market gains for the year ended December 31, 2010. The mark-to-market losses for the year ended December 31, 2011 included novation fees of approximately $8 million paid related to changing brokers in connection with the internal reorganization.

•	Approximately $317 million related to lower generated volumes and market prices as well as less revenue from capacity sales, RMR agreements, option premiums and the financial settlement of derivative instruments, as further described in our Discussion of Segment Results of Operations below.

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

•	Capacity revenue decreased by $7 million due to lower capacity prices in the MISO capacity market in 2011 compared to 2010.

•	Mark-to-market revenue decreased by $181 million due to a net change from mark-to-market revenue from $105 million in 2010 to a mark-to-market loss of $76 million in 2011.

•	Settlements revenue decreased by $26 million due to fewer volumes hedged in 2011 compared to 2010. Settlements revenue also decreased due to the average value of our hedging positions being lower in 2011 compared to 2010.

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

(2)	Includes hours generated for the full year 2011 and 2010 and also includes our ownership percentage in the MWh generated by our investment in the Black Mountain power generation facility.

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

(4)	Reflects the simple average of the spark spread available to a 7.0 MMBtu/MWh heat rate generator or an 11.0 MMBtu/MWh heat rate fuel oil-fired generator selling power at day-ahead prices and buying delivered natural gas or fuel oil at a daily cash market price and does not reflect spark spreads available to us.

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

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Energy revenue and the corresponding cost of sales decreased by $130 million and $78 million, respectively, for a net decrease in energy margin of $52 million. Energy revenue and cost of sales decreased due to lower market pricing across the region and lower volumes generated. Volumes were down due to lower spark spreads at Moss Landing and Casco Bay in 2011 compared to 2010. Volumes were also down due to more outages at Moss Landing and Casco Bay in 2011 compared to 2010. Both plants experienced significant outages in 2011 due to required turbine blade repairs. These decreases were partially offset by increases in volumes at Kendall and Ontelaunee which both saw an increase in generation volumes due to fewer outages and derates in 2011 compared to 2010 as well as improved spark spreads in 2011.

•	Capacity revenue decreased by $18 million due to lower capacity prices in the NYISO, PJM and Mass Hub markets in 2011 compared to 2010. Capacity prices have decreased significantly year over year due to excess capacity in the market.

•	RMR revenue decreased by $39 million due to the expiration of the South Bay RMR agreement. The CAISO elected not to renew the agreement for 2011 and the facility was permanently retired on December 31, 2010.

•	Tolling revenue decreased by $6 million due to the termination of the Kendall Constellation toll in 2010. In connection with the termination of the Kendall toll in 2010, we received a termination payment which was not repeated in 2011. The decrease from the 2010 cancellation payment was partially offset by higher revenues from the Moss Landing toll which was renewed with higher rates for 2011.

•	Mark-to-market revenue decreased by $50 million due to a net change in mark-to-market losses from $11 million in 2010 compared to $61 million in 2011.

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Premium revenue decreased by $108 million due to fewer options sold and fewer premiums collected in 2011 compared to 2010 due to a decline in price volatilities. Market volatilities have been in decline for the past two years, reducing the value of options on a unit basis and diminishing the revenue opportunities from their sale. Additionally, fewer option sales have resulted from our strategy of leaving more of our portfolio open to a market recovery expected over the next few years while we opportunistically hedge short-term cash flows.

•	Natural gas revenue increased by $24 million due to an increase in volumes sold in 2011 compared to 2010. The increase in volumes sold is due to lower 2011 power generation primarily at Independence. The decrease in power generation made more gas available to be sold back to the market as it was not required for production.

•	Other revenue increased by $18 million primarily due to an increase in ancillary pricing in the PJM market and increased 2011 off-peak generation at Ontelaunee which provided the opportunity to supply more ancillary services.

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•	Fresh-Start Accounting;

•	Revenue Recognition and Derivative Instruments;

•	Fair Value Measurements;

•	Estimated Useful Lives;

•	Impairment of Long-Lived Assets and Unconsolidated Investments;

•	Accounting for Contingencies, Guarantees and Indemnifications;

•	Accounting for Variable Interest Entities;

•	Accounting for Income Taxes; and

•	Valuation of Pension and Other Post-Retirement Plans Assets and Liabilities.

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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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•	significant underperformance relative to historical or projected future operating results;

•	significant changes in the manner of our use of the assets or the strategy for our overall business, including an expectation that the asset will be sold or retired before the end of its estimated useful life;

•	significant negative industry or economic trends; and

•	significant declines in stock value for a sustained period.

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

(2)	The market quotations and prices based on models categorization differ from the categories of Level 1, Level 2 and Level 3 used in our fair value disclosures due to the application of the different methodologies.  Please read Note 8—Risk Management Activities, Derivatives and Financial Instruments for further discussion.

(3)	Excludes $4 million of margin and $4 million of collateral that has been netted against Risk management liabilities on our consolidated balance sheet. Please read Note 8—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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(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 as follows: 2012 Long Term Incentive Plan. Please read Note 23—Capital Stock—Stock Award Plans of the Notes to Consolidated Financial Statements in our Annual Report on Form 10-K for the year ended December 31, 2012 for a brief description of our equity compensation plan, including this plan.

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*

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.

***	Certain exhibits, attachments or schedules to the exhibits filed herewith were never prepared or used by the parties in connection with the transactions that are the subject of the filed exhibit and therefore no actual exhibit, attachment or schedule exists.

****	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)	For convenience purposes, we have included the results of operations, excluding the Effects of the Plan, for October 1, 2012 in the Successor Period.

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(1)

During the 2012 Predecessor Period, we revised the South Bay ARO obligation downward by $16 million based on revised cost estimates related to the plant demolition. During 2011, we revised our ARO obligation downward by $24 million based on revised cost estimates related to remediation of asbestos, plant demolition and ash ponds. During 2010, we revised our ARO obligation downward by $5 million based on revisions to the timing of the remediation obligations within our Coal fleet and by $5 million at the Danskammer facility based on revised cost estimates.

(2)	As a result of the DMG Transfer 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, the AROs were reacquired on June 5, 2012.

(3)	As a result of the deconsolidation of the DNE Debtor Entities, the related ARO obligations are no longer reflected as liabilities on our consolidated balance sheet.

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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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•	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 will receive, 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

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(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 23—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.

(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.

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(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 3—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 8—Risk Management Activities, Derivatives and Financial Instruments and Note 3—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 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011 includes 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 1—Organization and Operations—DMG Transfer and DMG Acquisition for further discussion.

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(1)	Mainly comprised of swaps, options and physical forwards.

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(1)

In connection with the application of fresh-start accounting, we elected to present our derivative positions on a net basis, which includes offsetting broker margin and collateral against risk management liabilities. Approximately $8 million of broker margin and collateral were offset against risk management liabilities as of December 31, 2012. Risk management positions were presented on a gross basis as of December 31, 2011. Please read Note 2—Summary of Significant Accounting Policies for further discussion.

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(1)	The fair value of the Undertaking receivable is classified within Level 3 of the fair value hierarchy. Our December 31, 2011 estimate of the fair value of the Undertaking receivable represents the $750 million fair value as of November 7, 2011, less the $22 million payment in December 2011. Pursuant to the Settlement Agreement on June 5, 2012, the

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(2)	Included in both current and non-current assets and liabilities on the consolidated balance sheets.

(3)	Carrying amount includes unamortized premiums and discounts of $43 million and $21 million at December 31, 2012 and 2011, respectively. The fair value of the DPC Credit Agreement is classified within Level 2 of the fair value hierarchy.

(4)	Includes unamortized premiums of $18 million as of December 31, 2012. The fair value of the DMG Credit Agreement is classified within Level 2 of the fair value hierarchy.

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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 22—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 the DMG Acquisition. Please read Note 4—Merger and Acquisition for further discussion.

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(1)	On January 1, 2010, we adopted ASU No. 2009-17 which resulted in a deconsolidation of our investment in PPEA Holding. Please read Note 15—Variable Interest Entities—PPEA Holding Company LLC for further discussion.

(2)	The total amount of $295 million consists of $271 million in short-term Intangible assets, $71 million in long-term Intangible assets, $17 million in Accrued liabilities and other current liabilities, and $30 million in Other long-term liabilities on our consolidated balance sheet.

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(1)	LSTC were approximately $4,290 million as of the Plan Effective Date. Please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

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

(2)	Amounts are restricted and may be used for future collateral posting requirements or released per the terms of the applicable credit agreement. On November 9, 2012, we used the funds in the Collateral Posting Account to repay $325 million of the debt outstanding under the DPC and DMG Credit Agreements.

(3)	Includes cash posted to support the letter of credit reimbursement and collateral agreements under the DMG LC facility. Please read “Letter of Credit Facilities” above for further discussion.

(4)	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. We incurred a state tax benefit for the year ended December 31, 2010 due to current year losses that will reduce future state cash taxes as well as changes in our state sales profile and a change in California tax law.

(2)

We recorded a valuation allowance of $41 million during the 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.

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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.

•	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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Dynegy Inc. 401(k) Savings Plan.  This plan and the related trust fund are established and maintained for the exclusive benefit of participating employees in the United States. Generally, all employees of designated Dynegy subsidiaries are eligible to participate in the plan. 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. Generally, vesting in company contributions is based on years of service with 50 percent vesting per full year of service. The 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. Matching and discretionary contributions, if any, were previously allocated in the form of units in the Dynegy common stock fund. However, effective as of the first payroll period on or after January 1, 2012, the matching contributions to the plan are being made in cash rather than being invested as units in the Dynegy common stock fund. Matching contributions

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Dynegy 401(k) Plan, formerly known as the Dynegy Midwest Generation, LLC 401(K) Savings Plan (formerly the Illinois Power Company Incentive Savings Plan) and Dynegy Midwest Generation, LLC 401(K) Savings Plan for Employees Covered Under a Collective Bargaining Agreement (formerly the Illinois Power Company Incentive Savings Plan for Employees Covered Under A Collective Bargaining Agreement). For union employees we match 50 percent of employee pre-tax and Roth contributions to the plans, up to a maximum of six percent of base pay, subject to IRS limitations. However, for non-union employees participating in the Dynegy Midwest Generation, LLC 401(k) Savings Plan, benefits were frozen as of December 31, 2011, with all contributions stopping after that date. Effective January 1, 2012, such participants instead became eligible to participate in the Dynegy Inc. 401(k) Savings Plan (assuming all applicable eligibility criteria are met). Employees are immediately 100 percent vested in all contributions. The Plan also provides for an annual discretionary contribution to eligible employee accounts for a plan year, subject to the sole discretion of the Compensation and Human Resources Committee of the Board of Directors. Matching contributions and discretionary contributions, if any, to the plans are initially allocated in the form of units in the Dynegy common stock fund. However, effective as of the first payroll period on or after January 1, 2012, the matching contributions to the plan are being made in cash rather than being invested as units in the Dynegy common stock fund. Matching contributions may be invested according to the employee’s investment discretion. During the years ended December 31, 2011 and 2010, we issued 0.2 million and 0.2 million shares, respectively, of our common stock in the form of matching contributions to the plans. Effective March 13, 2012, however, the Dynegy common stock fund was eliminated from the plan and the plan sold all shares of Dynegy common stock held by the plan. No discretionary contributions were made for any of the years in the three-year period ended December 31, 2012. Effective April 14, 2012, the Dynegy Midwest Generation, Inc. 401(k) Savings Plan for Employees Covered under a Collective Bargaining Agreement and the Dynegy Inc. 401(k) Savings Plan were merged with the Dynegy 401(k) Plan. In addition, effective April 14, 2012, the accounts for all non-union participants under the Dynegy Northeast Generation, Inc. Savings Incentive Plan were transferred to the plan. At that time the Dynegy 401(k) Plan was amended to add provisions necessary to preserve various non-forfeitable benefits, rights and features related to the Dynegy 401(k) Savings Plan and the Dynegy Northeast Generation, Inc. Savings Incentive Plan.

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Dynegy Northeast Generation, Inc. Savings Incentive Plan.  Under this plan we match 50 percent of employee pre-tax contributions up to six percent of base pay for union employees and 50 percent of employee contributions up to eight percent of base pay for non-union employees, in each case subject to IRS limitations. However, for non-union employees participating in the Dynegy Northeast Generation, Inc. Savings Incentive Plan, benefits were frozen as of December 31, 2011, with all contributions stopping after that date. Effective January 1, 2012, such participants instead became eligible to participate in the Dynegy Inc. 401(k) Savings Plan (assuming all applicable eligibility criteria are met). Effective April 14, 2012, the accounts for all non-union employees were transferred to the Dynegy Midwest Generation, Inc. 401(k) Savings Plan (which was subsequently renamed the Dynegy 401(k) Plan). Employees are immediately 100 percent vested in our contributions. Matching contributions to this plan are made in cash and invested according to the employee’s investment discretion. Effective March 13, 2012, however, the Dynegy common stock fund was eliminated from the plan and the plan sold all shares of Dynegy common stock held by the plan.

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(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.

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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.

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(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 5—Condensed Combined Financial Statements of the Debtor Entities and Note 19—Related Party Transactions for further discussion.

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(2)	Includes a gain from Bankruptcy reorganization items, net of approximately $1.1 billion associated with our emergence from bankruptcy. Please read Note 3—Emergence from Bankruptcy and Fresh-Start Accounting for further discussion.

(3)	Includes debt extinguishment costs of $21 million incurred in connection with the termination of the Sithe Senior Notes. Please read Note 18—Debt—Sithe Senior Notes for further discussion.

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(1)	The allowance for doubtful accounts was decreased to zero in connection with the application of fresh-start accounting on the Plan effective date.

(2)	The allowance for doubtful accounts decreased by $7 million due to the sale of a receivable from a counterparty in bankruptcy and the settlement of a disputed balance in 2010.