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DYNEGY INC. - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations(Edgar Glimpses Via Acquire Media NewsEdge) The following discussion should be read together with the consolidated financial statements and the notes thereto included in this report. OVERVIEW We are a holding company and conduct substantially all of our business operations through our subsidiaries. Our current business operations are focused primarily on the power generation sector of the energy industry. We report the results of our power generation business as three separate segments in our consolidated financial statements: (i) Coal, (ii) IPH and (iii) Gas. In connection with our emergence from bankruptcy on the Plan Effective Date, we deconsolidated the DNE Debtor Entities, which constituted our previously reported DNE segment, and began accounting for our investment in the DNE Debtor Entities using the cost method. Accordingly, we have reclassified the results of the previously reported DNE segment as discontinued operations in the consolidated financial statements for all periods presented. AER Transaction Agreement On December 2, 2013, pursuant to the AER Transaction Agreement by and between IPH and Ameren, IPH completed the AER Acquisition. Pursuant to the AER Transaction Agreement, IPH indirectly acquired Illinois Power Resources, LLC's, formerly AER, subsidiaries, including (i) Illinois Power Generating Company, formerly AEGC, (ii) Illinois Power Resources Generating, LLC, formerly AERG, (iii) Illinois Power Fuels and Services Company, formerly Ameren Energy Fuels and Services Company, and (iv) Illinois Power Marketing Company, formerly AEM. The acquisition added 4,062 MW of generation in Illinois and also included the Homefield Energy retail business. There was no cash consideration or stock issued as part of the purchase price. In connection with the AER Acquisition, Ameren retained certain historical obligations of IPR and its subsidiaries, including certain historical environment and tax liabilities. Genco's approximately $825 million in aggregate principal amount of notes remain outstanding as an obligation of Genco. Additionally, Ameren is required to maintain its existing credit support, including all of its collateral obligations with respect to IPM, for a period not to exceed two years following closing. As discussed below, IPH and its direct and indirect subsidiaries are organized into ring-fenced groups and maintain corporate separateness from Dynegy and our other legal entities. Please read Note 3-Merger and Acquisitions-AER Transaction Agreement for further discussion. Refinancing of Debt Obligations During the year ended December 31, 2013, we refinanced existing indebtedness and materially reduced our future cash interest payments, providing us greater financial flexibility. New Credit Agreement. On April 23, 2013, Dynegy entered into $1.775 billion in new credit facilities including $1.3 billion in new senior, secured term loans and a $475 million corporate revolver. The proceeds of the term loans were used, together with cash on hand, to repay the former DMG and DPC credit agreements and fund related transaction costs. Senior Notes. On May 20, 2013, Dynegy and its Subsidiary Guarantors entered into an Indenture pursuant to which Dynegy issued $500 million in aggregate principal amount of Senior Notes. Borrowings under the Senior Notes were used to repay in full and terminate commitments under a portion of the senior, secured term loans. In connection with the issuance and sale of the Senior Notes, Dynegy and the Subsidiary Guarantors entered into a registration rights agreement with Morgan Stanley and Credit Suisse (the "Senior Notes Registration Rights Agreement"). Pursuant to the Senior Notes Registration Rights Agreement, Dynegy and the Subsidiary Guarantors have agreed for the benefit of the holders of the Senior Notes to use commercially reasonable efforts to register with the SEC a new issue of senior notes due 2023 having substantially identical terms as the Senior Notes as part of an offer to exchange freely tradable exchange notes for the Senior Notes. Pursuant to the Senior Notes Registration Rights Agreement, Dynegy and the Subsidiary Guarantors have agreed to use commercially reasonable efforts to (i) cause a registration statement relating to such exchange offer to be declared effective within 360 days after May 20, 2013 and (ii) if required under certain circumstances, file a shelf registration statement with the SEC covering resales of the Senior Notes. On December 9, 2013, Dynegy and the Subsidiary Guarantors filed a Form S-4 registration statement and filed an amendment to such Form S-4 on January 23, 2014. Please read Note 12-Debt for further discussion. 37-------------------------------------------------------------------------------- Table of Contents Collective Bargaining Agreement - IBEW Local 51 In March 2013, we began negotiations with the union ("IBEW Local 51") regarding its collective bargaining agreement, which expired, following an extension, on July 8, 2013. This agreement covers approximately 400 represented employees at our four Coal plants located in Illinois. On August 1, 2013, we and IBEW Local 51 reached a tentative agreement on a new collective bargaining agreement. On September 20, 2013, following a voting process conducted by IBEW Local 51, the tentative agreement was successfully ratified by union employees and resulted in amendments to certain pension and other post-employment benefit plans. As a result of these amendments and resulting remeasurements, we significantly reduced our benefit obligations under the affected plans. This new agreement, which expires on June 30, 2017, further aligns our near-term and long-term strategic priorities. Business Discussion The following is a brief discussion of each of our segments, including a list of key factors that have affected, and are expected to continue to affect, their respective earnings and cash flows. We also present a brief discussion of our corporate-level expenses. Power Generation Business We generate earnings and cash flows in the three segments within our power generation business through sales of electric energy, capacity and ancillary services. Primary factors affecting our earnings and cash flows in the power generation business include: • 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 tomitigate short- and medium- term earnings volatility and our ability to manage our liquidity requirements resulting from potential changes in collateral requirements as prices move. Other factors that have affected, and are expected to continue to affect, earnings and cash flows for this business include: • Transmission constraints, congestion, and other factors that can affect the price differential between the locations where we deliver generated power and the liquid market hub; • Our ability to control capital expenditures, which primarily include maintenance, safety, environmental and reliability projects, and to control operating expenses through disciplined management; • Our ability to optimize our assets by maintaining a high in-market availability, reliable run-time and safe, low-cost operations; • Our ability to 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 futureenvironmental 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; 38-------------------------------------------------------------------------------- Table of Contents • 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 SouthBay 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. Please read "Item 1A. Risk Factors" for additional factors that could affect our future operating results, financial condition and cash flows. LIQUIDITY AND CAPITAL RESOURCESOverview In this section, we describe our liquidity and capital requirements including our sources and uses of liquidity and capital resources. Our liquidity and capital requirements are primarily a function of our debt maturities and debt service requirements, fixed capacity payments and contractual obligations, capital expenditures (including required environmental expenditures) and working capital needs. Examples of working capital needs include purchases and sales of commodities and associated margin and collateral requirements, facility maintenance costs and other costs such as payroll. Our primary sources of liquidity are cash flows from operations, cash on hand and amounts available under the revolver. IPH and its direct and indirect subsidiaries are organized into ring-fenced groups in order to maintain corporate separateness from Dynegy and our other legal entities. Certain of the entities in the IPH segment, including Genco, have an independent director whose consent is required for certain corporate actions, including material transactions with affiliates. Further, entities within the IPH segment present themselves to the public as separate entities. They maintain separate books, records and bank accounts and separately appoint officers. Furthermore, they pay liabilities from their own funds, conduct business in their own names and have restrictions on pledging their assets for the benefit of certain other persons. These provisions restrict our ability to move cash out of these entities without meeting certain requirements as set forth in the governing documents. On April 23, 2013, Dynegy entered into the Credit Agreement, which consists of (i) a $500 million Tranche B-1 Term Loan, (ii) an $800 million Tranche B-2 Term Loan and (iii) a $475 million Revolving Facility. Borrowings under the Credit Agreement, together with a portion of our cash on hand, were used to repay in full and terminate commitments under: (i) the DPC Credit Agreement and DMG Credit Agreement, (ii) the DPC Revolving Credit Agreement, (iii) the DPC Letter of Credit Reimbursement and Collateral Agreement, (iv) the DMG Letter of Credit Reimbursement and Collateral Agreement, (v) the Dynegy Letter of Credit Reimbursement and Collateral Agreement and (vi) the Dynegy CS Letter of Credit Agreement. As a result of repaying these credit agreements, we no longer have any restricted cash. On May 20, 2013, Dynegy and its Subsidiary Guarantors entered into an Indenture pursuant to which Dynegy issued $500 million in aggregate principal amount of Senior Notes. Borrowings under the Senior Notes were used to repay in full and terminate commitments under a portion of the senior, secured term loans (as discussed above). On December 2, 2013, in connection with the AER Acquisition, Genco's approximately $825 million in aggregate principal amount of unsecured senior notes (the "Genco Senior Notes") remained outstanding as an obligation of Genco. The Genco Senior Notes bear interest at rates from 6.30 percent per annum to 7.95 percent per annum and mature between 2018 and 2032. Additionally, Ameren is required to maintain its existing credit support, including all of its collateral obligations with respect to IPM, for a period not to exceed two years. Please read Note 12-Debt for further discussion. 39-------------------------------------------------------------------------------- Table of Contents Current Liquidity. The following table summarizes our liquidity position at December 31, 2013. December 31, 2013 (amounts in millions) Dynegy Inc. IPH (1) (2) Total Revolver capacity $ 475 $ - $ 475 Less: Outstanding letters of credit (157 ) - (157 ) Revolver availability 318 - 318 Cash and cash equivalents 628 215 843 Total available liquidity $ 946 $ 215 $ 1,161 __________________________________________ (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. Operating Activities Historical Operating Cash Flows. Our cash flow provided by operations totaled $175 million for the year ended December 31, 2013. During the period, our power generation business provided cash of $199 million primarily due to the operation of our power generation facilities, partially offset by interest payments to service debt related to the DPC and DMG credit agreements. Corporate and other operations used cash of approximately $80 million primarily due to interest payments to service debt related to our Credit Agreement and Senior Notes, payments to advisors, employee-related payments and other general and administrative expense. This use of cash was partially offset by $56 million in positive changes in working capital, which includes $34 million for the return of collateral. Our cash flow used in operations totaled $44 million for the 2012 Successor Period. During the period, our power generation business used cash of $55 million primarily due to losses incurred during the period. Corporate and other operations used cash of approximately $23 million primarily due to payments to advisors, employee-related payments and other general and administrative expense. These uses of cash were partially offset by $34 million in positive changes in working capital, which includes $30 million for the return of collateral. Our cash flow used in operations totaled $37 million for the 2012 Predecessor Period. During the period, our power generation business used cash of $56 million primarily due to increased collateral postings to satisfy our counterparty collateral demands and other negative working capital. Corporate and other operations provided cash of approximately $19 million primarily due to interest payments received from Legacy Dynegy on the Undertaking, partially offset by payments to advisors and other general and administrative expense. Our cash flow used in operations totaled $1 million for the year ended December 31, 2011. During the period, our power generation business provided positive cash flow from operations of $348 million primarily due to the operation of our power generation facilities and positive changes in working capital, which includes decreased collateral postings for the return of collateral, partially offset by interest payments to service debt. Corporate and other operations used cash of $349 million primarily due to interest payments to service debt, employee-related payments and restructuring costs. Future Operating Cash Flows. Our future operating cash flows will vary based on a number of factors, many of which are beyond our control, including the price of power, the prices of natural gas, coal, and fuel oil and their correlation to power prices, collateral requirements, the value of capacity and ancillary services, the run time of our generating facilities, the effectiveness of our commercial strategy, legal, environmental and regulatory requirements, and our ability to achieve the cost savings contemplated in PRIDE improvement programs. 40-------------------------------------------------------------------------------- Table of Contents Collateral Postings. We use a portion of our capital resources in the form of cash and letters of credit to satisfy counterparty collateral demands. The following table summarizes our collateral postings to third parties by legal entity at December 31, 2013 and December 31, 2012: (amounts in millions) December 31, 2013 December 31, 2012 Dynegy Inc.: Cash (1) $ 22 $ 64 Letters of credit 157 252 Total Dynegy Inc. 179 316 IPH: Cash (1) (2) 7 - Total IPH 7 - Total $ 186 $ 316 __________________________________________ (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. In addition to cash and letters of credit posted as collateral, we have granted additional permitted first priority liens on assets already subject to first priority liens under our former and new credit agreements. The additional liens were granted as collateral under certain of our derivative agreements in order to reduce the cash collateral and letters of credit that we would otherwise be required to provide to the counterparties under such agreements. Collateral postings decreased from December 31, 2012 to December 31, 2013 primarily due to new first lien contracts for fuel and other commodity purchases being executed with counterparties, amending our contractual service agreements, a reduction in collateral from tolling agreements, a reduction in collateral supporting our DNE operations and overall changes in our commercial activity. The fair value of our derivatives collateralized by first priority liens included liabilities of $145 million and $100 million at December 31, 2013 and December 31, 2012, respectively. We expect counterparties' future collateral demands to continue to reflect changes in commodity prices, including seasonal changes in weather-related demand, as well as their views of our creditworthiness. Our ability to use forward economic hedging instruments could be limited due to the potential collateral requirements of such instruments. Investing Activities Capital Expenditures. We had capital expenditures of approximately $98 million during the year ended December 31, 2013 and $46 million, $63 million and $196 million during the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011, respectively. Our capital spending by reportable segment was as follows: Successor Predecessor October 2 January 1 Year Ended Through Through December 31, December 31, October 1, Year Ended (amounts in millions) 2013 2012 2012 December 31, 2011 Coal (1) $ 42 $ 26 $ 33 $ 115 IPH 1 - - - Gas 53 19 23 79 DNE - - - 2 Other 2 1 7 - Total $ 98 $ 46 $ 63 $ 196 41-------------------------------------------------------------------------------- Table of Contents __________________________________________ (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. Capital spending in our Coal segment primarily consisted of environmental and maintenance capital projects. Capital spending in our IPH segment primarily consisted of environmental capital projects. Capital spending in our Gas segment primarily consisted of maintenance projects. We expect capital expenditures for 2014 to be approximately $181 million, which is comprised of $46 million, $63 million, $66 million and $6 million in Coal, IPH, Gas and Other, respectively. The capital budget is subject to revision as opportunities arise or circumstances change. In November 2012, we finished the Baldwin Unit 2 scrubber installation, marking the completion of the environmental capital compliance requirements under the Consent Decree. We spent approximately $923 million through December 31, 2013 and expect no material remaining costs in 2014 related to these Consent Decree projects. Other Investing Activities. During the year ended December 31, 2013, there was a $335 million cash inflow related to restricted cash balances due to the release of cash collateral associated with the DPC LC and DMG LC facilities. A portion of these proceeds were used to repay in full and terminate commitments under the DMG and DPC credit agreements as further discussed below. As a result of repaying these credit agreements, all of our restricted cash was released. In addition, in connection with the AER Acquisition, we acquired $234 million in cash. Please read Note 3-Merger and Acquisitions for further discussion. During the 2012 Successor Period, there was a $311 million cash inflow related to restricted cash balances due to a reduction in the Collateral Posting account. These proceeds were used to fund a portion of the repayment of the DMG and DPC Credit Agreement as further discussed below. In connection with the DMG Acquisition on June 5, 2012, we acquired $256 million in cash and received $16 million in principal payments related to the Undertaking during the 2012 Predecessor Period. There was an $88 million cash inflow related to restricted cash balances associated with the DPC LC facilities and DPC Credit Agreement during the 2012 Predecessor Period. In addition, during the 2012 Predecessor Period, we requested the release of unused cash collateral related to the DPC LC facilities. These inflows were offset by a reduction of $22 million in cash as a result of the deconsolidation of the DNE Debtor Entities. There was a $441 million cash outflow related to the DMG Transfer on September 1, 2011. There was a $222 million net cash inflow related to restricted cash balances during the year ended December 31, 2011 primarily due to increases of approximately $1 billion related to the repayment of our former Fifth Amended and Restated Credit Agreement, the Sithe Tender Offer and the return of collateral, partially offset by decreases of $792 million related to the DPC Credit Agreement, the DMG Credit Agreement and a Letter of Credit Reimbursement and Collateral Agreement. Cash outflows for purchases of short-term investments during the year ended December 31, 2011 totaled $244 million. Cash inflows related to maturities of short-term investments for the year ended December 31, 2011 totaled $419 million. Other included $10 million of property insurance claim proceeds during the year ended December 31, 2011. Financing Activities Historical Cash Flow from Financing Activities. Cash flow used in financing activities totaled $154 million during the year ended December 31, 2013 due to (i) $1.913 billion in repayments of borrowings in full on the DMG and DPC Credit Agreements and the Tranche B-1 Term Loan, including $59 million in prepayment penalties associated with the early termination of the DMG and DPC Credit Agreements, (ii) $4 million in principal payments of borrowings on the Tranche B-2 Term Loan and (iii) $5 million in interest rate swap settlement payments during the fourth quarter 2013, offset by (i) $1.751 billion in proceeds from borrowings on the Credit Agreement and Senior Notes, net of financing costs and (ii) $17 million in proceeds associated with repurchase agreements related to emissions credits. Please read Note 12-Debt for further discussion. Cash flow used in financing activities totaled $328 million during the 2012 Successor Period due to repayments of borrowings on the DMG and the DPC credit agreements. Cash flow used in financing activities totaled $184 million for the 2012 Predecessor Period due to $200 million paid to unsecured creditors upon our emergence from bankruptcy on the Plan Effective Date and $11 million in repayments of borrowings on the DMG and the DPC credit agreements, offset by an increase of $27 million in connection with the recapitalization of Legacy Dynegy. 42-------------------------------------------------------------------------------- Table of Contents Cash flow provided by financing activities totaled $375 million for the year ended December 31, 2011. Proceeds from long-term borrowings of $2 billion, net of $44 million of debt issuance costs, consisted of borrowing under the DPC Credit Agreement, DMG Credit Agreement and our former Fifth Amended and Restated Credit Agreement. These borrowings were partially offset by repayments of borrowings of $1.6 billion on our former Fifth Amended and Restated Credit Agreement, Sithe senior debt and our 6.875 percent senior notes. Summarized Debt and Other Obligations. The following table depicts our third party debt obligations, and the extent to which they are secured as of December 31, 2013 and 2012: (amounts in millions) December 31, 2013 December 31, 2012 Dynegy: Secured obligations $ 796 $ 1,354 Unsecured obligations 500 - Emissions Repurchase Agreements 17 - Unamortized (discount)/premium (4 ) 61 Genco: Unsecured obligations 825 - Unamortized discount (142 ) - Total long-term debt $ 1,992 $ 1,415 Financing Trigger Events. Our debt instruments and certain of our other financial obligations and all the Genco Senior Notes include provisions which, if not met, could require early payment, additional collateral support or similar actions. The trigger events include the violation of covenants (including, in the case of the Credit Agreement under certain circumstances, the senior secured leverage ratio covenant discussed below), defaults on scheduled principal or interest payments, including any indebtedness to the extent linked to it by reason of cross-default or cross-acceleration provisions, insolvency events, acceleration of other financial obligations and, in the case of the Credit Agreement, change of control provisions. We do not have any trigger events tied to specified credit ratings or stock price in our debt instruments and are not party to any contracts that require us to issue equity based on credit ratings or other trigger events. Financial Covenants Credit Agreement. On April 23, 2013, we entered into the Credit Agreement. The Credit Agreement contains customary events of default and affirmative and negative covenants, subject to certain specified exceptions, including financial covenants specifying required thresholds for our senior secured leverage ratio calculated on a rolling four quarters basis. Under the Credit Agreement, if Dynegy has utilized 25 percent or more of its Revolving Facility, Dynegy must be in compliance with the following ratios for the respective periods: Consolidated Senior Secured Net Debt to Consolidated Adjusted Compliance Period EBITDA (1) September 30, 2013 through December 31, 2013 5.00: 1.00 March 31, 2014 through December 31, 2014 4.00: 1.00 March 31, 2015 through December 31, 2015 4.75: 1.00 March 31, 2016 through December 31, 2016 3.75: 1.00 March 31, 2017 and Thereafter 3.00: 1.00 __________________________________________ (1) For purposes of calculating Net Debt, we may only apply a maximum of $150 million in cash to our outstanding secured debt. Our revolver usage at December 31, 2013 was 33 percent of the aggregate revolver commitment due to outstanding letters of credit; therefore, we were required to test the covenant. Based on the calculation outlined in the Credit Agreement, we are in compliance at December 31, 2013. 43-------------------------------------------------------------------------------- Table of Contents Genco Senior Notes. On December 2, 2013, in connection with the AER Acquisition, Genco Senior Notes remained outstanding as an obligation of Genco, a subsidiary of IPH. Genco's indenture includes provisions that require Genco to maintain certain interest coverage and debt-to-capital ratios in order for Genco to pay dividends, to make principal or interest payments on subordinated borrowings, to make loans to or investments in affiliates or to incur additional external, third-party indebtedness. The following table summarizes these required ratios: Required Ratio Restricted payment interest coverage ratio (1) ?1.75 Additional indebtedness interest coverage ratio ?2.50 Additional indebtedness debt-to-capital ratio ?60% __________________________________________ (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. Based on December 31, 2013 results, Genco's interest coverage ratios are less than the minimum ratios required for Genco to pay dividends and borrow additional funds from external, third-party sources. Based on our projections, we expect that Genco's interest coverage ratios will be less than the minimum ratios required for Genco to pay dividends and incur additional third-party indebtedness until at least 2016. Please read Note 12-Debt for further discussion. Dividends on Common Stock. We have paid no cash dividends on our common stock and have no current intention of doing so. Any future determinations to pay cash dividends will be at the discretion of our Board of Directors, subject to applicable limitations under Delaware law, and will be dependent upon our results of operations, financial condition, contractual restrictions and other factors deemed relevant by our Board of Directors. Credit Ratings Our credit rating status is currently "non-investment grade" and our current ratings are as follows: Standard & Moody's Poor's Dynegy Inc.: Corporate Family Rating B2 B Senior Secured B1 BB- Senior Unsecured B3 B+ Genco: Senior Unsecured B3 CCC+ Disclosure of Contractual Obligations We have incurred various contractual obligations and financial commitments in the normal course of our operations and financing activities. Contractual obligations include future cash payments required under existing contractual arrangements, such as debt and lease agreements. These obligations may result from both general financing activities and from commercial arrangements that are directly supported by related revenue-producing activities. 44-------------------------------------------------------------------------------- Table of Contents The following table summarizes the contractual obligations of the Company and its consolidated subsidiaries as of December 31, 2013. Cash obligations reflected are not discounted and do not include accretion or dividends. Expiration by Period Less than More than (amounts in millions) Total 1 Year 1 - 3 Years 3 - 5 Years 5 Years Long-term debt (including current portion) $ 2,138 $ 14 $ 27 $ 316 $ 1,781 Interest payments on debt 1,241 146 278 275 542 Coal commitments 691 357 287 47 - Coal transportation 323 42 60 63 158 Operating leases 53 18 18 7 10 Gas transportation payments 126 37 39 25 25 Interconnection obligations 14 1 2 2 9 Contractual service agreements (1) 136 22 82 32 - Pension funding obligations 100 4 20 38 38 Other obligations 42 32 4 2 4 Total contractual obligations $ 4,864 $ 673 $ 817 $ 807 $ 2,567 __________________________________________ (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. Long-Term Debt (Including Current Portion). Long-term debt includes amounts related to the Senior Notes, the Credit Agreement, the Genco Senior Notes and the Emissions Repurchase Agreements. Amounts do not include unamortized discounts. Please read Note 12-Debt for further discussion. Interest Payments on Debt. Interest payments on debt represent estimated periodic interest payment obligations associated with the Senior Notes, the Credit Agreement, the Genco Senior Notes and the Emissions Repurchase Agreements. Amounts include the impact of interest rate swap agreements. Please read Note 12-Debt for further discussion. Coal Commitments. At December 31, 2013, our subsidiaries had contracts in place to purchase coal for various generation facilities. The amounts in the table reflect our minimum purchase obligations. To the extent forecasted volumes have not been priced but are subject to a price collar structure, the obligations have been calculated using the minimum purchase price of the collar. Coal Transportation. At December 31, 2013, we had long-term coal transportation contracts in place. We also had long-term rail car leases in place. The amounts included in Coal transportation reflect our minimum purchase obligations based on the terms of the contracts. Operating Leases. Operating leases include minimum lease payment obligations associated with office and office equipment leases. Also included in operating leases are two charter agreements related to VLGCs previously utilized in our former global liquids business. The primary term of one charter expired at the end of September 2013 but will be extended for a second consecutive year. The primary term of the second charter is through September 2014 but will be extended for a period of one year at the sole option of the counterparty. Both of these VLGCs have been sub-chartered to a wholly-owned subsidiary of Transammonia Inc. on terms that are identical to the terms of the original charter agreements. The aggregate minimum base commitments of the charter party agreements are approximately $14 million and $11 million for the years ended December 31, 2014 and 2015, respectively. To date, the subsidiary of Transammonia Inc. has complied with the terms of the sub-charter agreement. Gas Transportation Payments. Gas transportation payments include fixed capacity obligations totaling approximately $126 million associated with fuel procurement for our Gas plants. Interconnection Obligations. Interconnection obligations represent an obligation with respect to interconnection services for the Ontelaunee facility. This agreement expires in 2027. The obligation under this agreement is approximately $1 million per year through the term of the contract. Contractual Service Agreements. Contractual service agreements represent obligations with respect to long-term plant maintenance agreements. In June 2013, we amended our maintenance agreements. The amendments substantially reduced collateral postings, restructured and reduced maintenance costs, extended the term of the agreements, decreased our risk from a catastrophic turbine failure and included technology upgrades for our equipment. We currently estimate these agreements will be 45-------------------------------------------------------------------------------- Table of Contents in effect for a period of 15 or more years. The table above includes our current estimate of payments under the contracts through 2018 based on anticipated timing of outages and are subject to change as outage dates move. As of December 31, 2013, our minimum obligation with respect to these agreements is limited to the termination payments, which are approximately $149 million and $218 million in the event all contracts are terminated by us or the counterparty, respectively. Please read Note 16-Commitments and Contingencies-Other Commitments and Contingencies for further discussion. Pension Funding Obligations. Amounts include our minimum required contributions to our defined benefit pension plans through 2023 as determined by our actuary and are subject to change based on actual results of the plan. We may elect to make voluntary contributions in 2014 which would decrease future funding obligations. Please read Note 18-Employee Compensation, Savings, Pension and Other Post-Employment Benefit Plans-Pension and Other Post-Employment Benefits-Obligations and Funded Status for further discussion. Other Obligations. Other obligations primarily include the following items: • 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. Commitments and Contingencies Please read Note 16-Commitments and Contingencies, which is incorporated herein by reference, for further discussion of our material commitments and contingencies. Off-Balance Sheet Arrangements We had no off-balance sheet arrangements at December 31, 2013. 46-------------------------------------------------------------------------------- Table of Contents RESULTS OF OPERATIONS Overview and Discussion of Comparability of Results. In this section, we discuss our results of operations, both on a consolidated basis and, where appropriate, by segment, for the year ended December 31, 2013, the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011. At the end of this section, we have included our business outlook for each segment. We report the results of our power generation business primarily as three separate segments in our consolidated financial statements: (i) Coal, (ii) IPH and (iii) Gas. In connection with our emergence from bankruptcy, we deconsolidated the DNE Debtor Entities, which constituted our previously reported DNE segment, and began accounting for our investment in the DNE Debtor Entities using the cost method. Accordingly, we have reclassified the results of the previously reported DNE segment as discontinued operations in the consolidated financial statements for all periods presented. Subsequent to our emergence from bankruptcy, management does not consider general and administrative expense when evaluating the performance of our Coal, IPH and Gas segments, but instead evaluates general and administrative expense on an enterprise-wide basis. Accordingly, we have recast our segments to present general and administrative expense in Other for all periods presented. On December 2, 2013, we completed the AER Acquisition. Therefore, the results of our IPH segment are included in our 2013 consolidated results for the period of December 2, 2013 through December 31, 2013. Please read Note 3-Merger and Acquisitions-AER Transaction Agreement for further discussion. We applied fresh-start accounting as of the Plan Effective Date. Fresh-start accounting requires us to allocate the reorganization value to our assets and liabilities in a manner similar to the acquisition method of accounting for business combinations. Under the provisions of fresh-start accounting, a new entity has been created for financial reporting purposes. As such, our financial information for the Successor is presented on a basis different from, and is therefore not comparable to, our financial information for the Predecessor for the period ended and as of October 1, 2012 or for prior periods. Please read Note 21-Emergence from Bankruptcy and Fresh-Start Accounting for further discussion. For financial reporting purposes, close of business on October 1, 2012, represents the date of our emergence from bankruptcy. As used herein, the following terms refer to the Company and its operations: "Predecessor" The Company, pre-emergence from bankruptcy "2012 Predecessor Period" The Company's operations, January 1, 2012 - October 1, 2012 "Successor" The Company, post-emergence from bankruptcy "2012 Successor Period" The Company's operations, October 2, 2012 - December 31, 2012 On September 1, 2011, we completed the DMG Transfer. Therefore, the results of our Coal segment (including DMG) were included in our 2011 consolidated results for the period of January 1, 2011 through August 31, 2011. Additionally, on June 5, 2012, we reacquired DMG through the DMG Acquisition. Therefore, the results of our Coal segment (including DMG) are included in our 2012 consolidated results for the period of June 6, 2012 through December 31, 2012. 47-------------------------------------------------------------------------------- Table of Contents Consolidated Summary Financial Information-Year Ended December 31, 2013, 2012 Successor Period, 2012 Predecessor Period and Year Ended December 31, 2011 The following table provides summary financial data regarding our consolidated results of operations for the year ended December 31, 2013, the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011, respectively: Successor Predecessor Year Ended October 2 Through January 1 Through Year Ended (amounts in millions) December 31, 2013 December 31, 2012 October 1, 2012 December 31, 2011 Revenues $ 1,466 $ 312 $ 981 $ 1,333 Cost of sales (1,145 ) (268 ) (662 ) (866 ) Gross margin, exclusive of depreciation shown separately below 321 44 319 467 Operating and maintenance expense, exclusive of depreciation shown separately below (308 ) (81 ) (148 ) (254 ) Depreciation expense (216 ) (45 ) (110 ) (295 ) Other charges - - - (5 ) Gain on sale of assets, net 2 - - - General and administrative expense (97 ) (22 ) (56 ) (102 ) Acquisition and integration costs (20 ) - - - Operating income (loss) (318 ) (104 ) 5 (189 ) Bankruptcy reorganization items, net (1 ) (3 ) 1,037 (52 ) Earnings from unconsolidated investments 2 2 - - Interest expense (97 ) (16 ) (120 ) (348 ) Loss on extinguishment of debt (11 ) - - (21 ) Impairment of Undertaking receivable, affiliate - - (832 ) - Other income and expense, net 8 8 31 35 Income (loss) from continuing operations before income taxes (417 ) (113 ) 121 (575 ) Income tax benefit (Note 14) 58 - 9 144 Income (loss) from continuing operations (359 ) (113 ) 130 (431 ) Income (loss) from discontinued operations, net of taxes 3 6 (162 ) (509 ) Net loss (356 ) (107 ) (32 ) (940 ) Less: Net income (loss) attributable to noncontrolling interests - - - - Net loss attributable to Dynegy Inc. $ (356 ) $ (107 ) $ (32 ) $ (940 ) 48-------------------------------------------------------------------------------- Table of Contents The following tables provide summary financial data regarding our operating income (loss) by segment for the year ended December 31, 2013, the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011, respectively: Successor Year Ended December 31, 2013 (amounts in millions) Coal IPH Gas Other Total Revenues $ 467 $ 67 $ 932 $ - $ 1,466 Cost of sales (459 ) (46 ) (640 ) - (1,145 ) Gross margin, exclusive of depreciation shown separately below 8 21 292 - 321 Operating and maintenance expense, exclusive of depreciation expense shown separately below (167 ) (15 ) (125 ) (1 ) (308 ) Depreciation expense (50 ) (3 ) (160 ) (3 ) (216 ) Gain on sale of assets, net 2 - - - 2 General and administrative expense - - - (97 ) (97 ) Acquisition and integration costs (1) - (20 ) - - (20 ) Operating income (loss) $ (207 ) $ (17 ) $ 7 $ (101 ) $ (318 ) __________________________________________ (1) Relates to costs associated with the AER Transaction Agreement. Please read Note 3-Merger and Acquisitions for further discussion. Successor October 2 Through December 31, 2012 (amounts in millions) Coal Gas Other Total Revenues $ 107 $ 205 $ - $ 312 Cost of sales (110 ) (158 ) - (268 ) Gross margin, exclusive of depreciation shown separately below (3 ) 47 - 44 Operating and maintenance expense, exclusive of depreciation and expense shown separately below (38 ) (42 ) (1 ) (81 ) Depreciation expense (8 ) (36 ) (1 ) (45 ) General and administrative expense - - (22 ) (22 ) Operating loss $ (49 ) $ (31 ) $ (24 ) $ (104 ) Predecessor January 1 Through October 1, 2012 (amounts in millions) Coal Gas Other Total Revenues $ 166 $ 815 $ - $ 981 Cost of sales (161 ) (501 ) - (662 ) Gross margin, exclusive of depreciation shown separately below 5 314 - 319 Operating and maintenance expense, exclusive of depreciation expense shown separately below (55 ) (95 ) 2 (148 ) Depreciation expense (13 ) (91 ) (6 ) (110 ) General and administrative expense - - (56 ) (56 ) Operating income (loss) $ (63 ) $ 128 $ (60 ) $ 5 49-------------------------------------------------------------------------------- Table of Contents Predecessor Year Ended December 31, 2011 (amounts in millions) Coal Gas Other Total Revenues $ 460 $ 872 $ 1 $ 1,333 Cost of sales (237 ) (629 ) - (866 ) Gross margin, exclusive of depreciation shown separately below 223 243 1 467 Operating and maintenance expense, exclusive of depreciation shown separately below (105 ) (148 ) (1 ) (254 ) Depreciation expense (156 ) (132 ) (7 ) (295 ) Other charges - - (5 ) (5 ) General and administrative expense - - (102 ) (102 ) Operating loss $ (38 ) $ (37 ) $ (114 ) $ (189 ) Discussion of Consolidated Results of Operations Successor Revenues. During the year ended December 31, 2013, revenues were $1,466 million. Revenues for the year were primarily the result of $1,233 million in power revenues with contributions of $519 million, $65 million and $649 million from the Coal, IPH and Gas segments, respectively. These revenues were associated with 20 million MWh, 2 million MWh and 16 million MWh of power generation during the year by the Coal, IPH and Gas segments, respectively. Also contributing to revenue was $162 million in capacity revenue, $39 million in tolling revenue, $46 million in ancillary and other revenue and $88 million in gas revenue, each primarily generated by the Gas segment. These contributions were offset by mark-to-market losses of $38 million consisting of $26 million, $8 million and $4 million in the Coal, IPH and Gas segments, respectively, as well as $64 million in negative financial settlements. During the 2012 Successor Period, revenues were $312 million. Revenues for the period were primarily the result of $223 million in power revenues with contributions of $105 million and $118 million from the Coal and Gas segments, respectively. These revenues were associated with 5 million MWh and 4 million MWh of power generation during the period by the Coal and Gas segments, respectively. Also contributing to revenue was $31 million in capacity revenue, $11 million in tolling revenue, $8 million in ancillary and other revenue and $49 million in gas revenue, each primarily generated by the Gas segment. Additionally, revenues included $6 million and $39 million in mark-to-market gains from the Coal and Gas segments, respectively. These contributions were offset by $55 million in settlement losses due to the negative settlement of legacy put options, primarily in the Gas segment. Cost of Sales. During the year ended December 31, 2013, cost of sales was $1,145 million. Cost of sales for the year primarily consisted of $640 million in Gas segment fuel costs which consist primarily of natural gas purchase and transportation costs and $459 million in Coal segment fuel costs and $46 million in IPH segment fuel costs which all consist of primarily coal purchase and transportation costs. During the 2012 Successor Period, costs of sales were $268 million. Cost of sales for the period primarily consisted of $158 million in Gas segment fuel costs, which consist primarily of natural gas purchase and transportation costs, and $110 million in Coal segment fuel costs, which consist primarily of coal purchase and transportation costs. Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. During the year ended December 31, 2013, operating and maintenance expense was $308 million. Operating and maintenance expense for the period primarily consisted of labor, direct operating and maintenance costs related to our facilities, outage costs related to planned and unplanned outages and other costs, which include fuel handling and environmental costs. The Coal segment accounted for $167 million, the IPH segment accounted for $15 million, the Gas segment accounted for $125 million and Other accounted for $1 million. During the 2012 Successor Period, operating and maintenance expense was $81 million. Operating and maintenance expense for the period primarily consisted of labor, direct operating and maintenance costs related to our facilities, outage costs related to planned and unplanned outages and other costs, which include fuel handling and environmental costs. Operating and maintenance expense for the period was $38 million for the Coal segment, $42 million for the Gas segment and $1 million in Other. Depreciation Expense. During the year ended December 31, 2013, depreciation expense was $216 million. Depreciation expense for the period was $50 million for the Coal segment, $3 million for the IPH segment, $160 million for the Gas segment and $3 million for Other. 50-------------------------------------------------------------------------------- Table of Contents During the 2012 Successor Period, depreciation expense was $45 million. Depreciation expense for the period was $8 million for the Coal segment, $36 million for the Gas segment and $1 million for Other. As part of fresh-start accounting on October 1, 2012, our fixed assets were recorded at fair value and this new basis will be depreciated over the remaining useful lives. General and Administrative Expense. During the year ended December 31, 2013, general and administrative expense was $97 million. General and administrative expense for the period primarily consisted of $72 million in labor and benefit costs, $7 million in legal and professional fees, $5 million in insurance costs, $3 million in office leases and $10 million in office expenses and other costs. During the 2012 Successor Period, general and administrative expense was $22 million. General and administrative expense for the period primarily consisted of $16 million in labor and benefit costs, $1 million in professional service fees and $5 million in office expenses and other costs. Acquisition and Integration Costs. During the year ended December 31, 2013, acquisition and integration costs were $20 million, which were incurred in connection with the AER Acquisition and consisted of $9 million in severance expenses, $7 million in legal and consulting fees and $4 million in other costs. Please read Note 3-Merger and Acquisitions for further discussion. Interest Expense. During the year ended December 31, 2013, interest expense was $97 million. Interest expense primarily consisted of (i) $24 million and $15 million in interest on the DPC and DMG credit agreements, respectively, which were terminated in April 2013, (ii) $22 million in interest expenses on the Tranche B-2 Term Loan, (iii) $18 million in interest expense on the Senior Notes, (iv) $5 million in interest expense on the Genco Senior Notes, (v) $7 million in mark-to-market gains on interest rate swaps, (vi) $5 million in fees related to the Revolving Facility and (vii) $1 million in interest expense on the Tranche B-1 Term Loan, which was terminated on May 20, 2013. During the 2012 Successor Period, interest expense was $16 million. Interest expense primarily consisted of $22 million and $13 million of interest on the DPC and DMG credit agreements, respectively, partially offset by $3 million in amortization of the premium and $16 million in accelerated amortization of the premium related to the early repayment of $325 million, in aggregate, of the DPC and DMG credit agreements. Please read Note 12-Debt for further discussion. Loss on Extinguishment of Debt. During the year ended December 31, 2013, loss on extinguishment of debt totaled $11 million. The loss was incurred in connection with the termination of the DPC and DMG credit agreements and the Term Loan B-1. The amount is comprised of (i) a prepayment penalty of approximately $59 million, (ii) $2 million for the accelerated amortization of the discount on the Term Loan B-1 and (iii) $6 million in accelerated amortization of debt issuance costs related to the DPC Revolving Credit Facility and the Term Loan B-1, offset by (iv) $56 million in non-cash gains for the accelerated amortization of the remaining premium related to the DPC and DMG credit agreements. Please read Note 12-Debt for further discussion. Other Income and Expense, Net. During the year ended December 31, 2013, other income and expense, net was an $8 million gain, which primarily consisted of insurance proceeds, partially offset by a change in the fair value of our common stock warrants issued upon emergence from bankruptcy in October 2012. During the 2012 Successor Period, other income and expense, net was an $8 million gain due to change in the fair value of our common stock warrants issued upon emergence from bankruptcy in October 2012. Income Tax Benefit. We reported an income tax benefit of $58 million and zero for the year ended December 31, 2013 and the 2012 Successor Period, respectively. The effective tax rate for the year ended December 31, 2013 and the 2012 Successor Period was 14 percent and zero percent, respectively. For the year ended December 31, 2013, the difference between the effective rate of 14 percent and the statutory rate of 35 percent resulted primarily due to a change in our valuation allowance. During 2013, we recognized a tax benefit of $32 million in continuing operations for pre-tax income from components other than continuing operations that resulted in a reduction of the valuation allowance. In addition, a tax benefit of $35 million was also recognized in continuing operations that resulted from the tax impact of the AER Acquisition which also reduced our valuation allowance. The benefit of these valuation allowance adjustments was partially offset by $9 million of tax expense associated with current federal and state taxes. As of December 31, 2013, we do not believe we will produce sufficient future taxable income, nor are there tax strategies available, to realize our net deferred tax assets not otherwise realized by reversing temporary differences. For the 2012 Successor Period, the difference between the effective rate of zero percent and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. Please read Note 14-Income Taxes for further discussion. 51-------------------------------------------------------------------------------- Table of Contents Income from Discontinued Operations, Net of Tax. During the year ended December 31, 2013, income from discontinued operations, net of tax was $3 million. Income from discontinued operations primarily consisted of a $7 million DNE pension curtailment gain due to the termination of a majority of the Danskammer employees and closing the Roseton sale, partially offset by a $2 million loss related to legacy capacity contracts executed with the Roseton facility which terminated upon the sale of the facility and $2 million in tax expense. During the 2012 Successor Period, income from discontinued operations, net of tax was $6 million, which related to the release of a franchise tax liability related to our former midstream business on which the statute of limitations expired. Please read Note 23-Dispositions and Discontinued Operations for further discussion. Predecessor Revenues. During the 2012 Predecessor Period, revenues were $981 million. Revenues for the period were primarily the result of $675 million in power revenues with contributions of $183 million and $492 million from the Coal and Gas segments, respectively. These revenues were associated with 7 million MWh and 17 million MWh of power generation during the period by the Coal and Gas segments, respectively. Also contributing to revenue was $166 million in capacity revenues primarily in the Gas segment, $117 million in mark-to-market gains in the Gas segment, partially offset by $14 million in Coal segment mark-to-market losses. Additionally, revenues include $100 million in natural gas revenue, $79 million in tolling revenues, and $34 million of ancillary and other revenue, each primarily generated by the Gas segment. These contributions were offset by negative financial settlements of $7 million for the Coal segment and $169 million for the Gas segment primarily due to legacy put options. During the year ended December 31, 2011, revenues were $1,333 million. Revenues for the period were primarily the result of $1,000 million in power revenues with contributions of $512 million and $488 million from the Coal and Gas segments, respectively. These revenues were associated with 16 million MWh and 12 million MWh of power generation during the period by the Coal and Gas segments, respectively. Also contributing to the revenue total was $221 million in capacity revenue, $131 million in tolling revenue, $44 million in ancillary and other revenue, and $197 million in gas revenue, each primarily generated by the Gas segment. These contributions were offset by mark-to-market losses of $76 million, $67 million and $4 million from the Coal, Gas and Other segments, respectively, and $113 million in negative financial settlements, primarily related to the Gas segment. Cost of Sales. During the 2012 Predecessor Period, cost of sales was $662 million. Cost of sales for the period primarily consisted of $501 million in Gas segment fuel costs which consist primarily of natural gas purchase and transportation costs and $161 million in Coal segment fuel costs which consist primarily of coal commodity and transportation costs. These costs were driven by power generation during the period discussed above. During the year ended December 31, 2011, cost of sales was $866 million. Cost of sales for the period primarily consisted of $629 million in Gas segment fuel costs which consist primarily of natural gas purchase and transportation costs and $237 million in Coal segment fuel costs which consist primarily of coal commodity and transportation costs. These costs were driven by power generation during the period discussed above. Operating and Maintenance Expense, Exclusive of Depreciation Shown Separately Below. During the 2012 Predecessor Period, operating and maintenance expense was $148 million. Operating and maintenance expense for the period primarily consisted of labor, direct operating and maintenance costs related to our facilities, outage costs related to planned and unplanned outages and other costs, which include fuel handling and environmental costs. Operating and maintenance expense for the period primarily consisted of $55 million in the Coal segment, $95 million in the Gas segment. During the year ended December 31, 2011, operating and maintenance expense was $254 million. Operating and maintenance expense for the period primarily consisted of labor, direct operating and maintenance costs related to our facilities, outage costs related to planned and unplanned outages and other costs, which include fuel handling and environmental costs. Operating and maintenance expense for the period primarily consisted of $105 million in the Coal segment, $148 million in the Gas segment and $1 million in Other. Depreciation Expense. During the 2012 Predecessor Period, depreciation expense was $110 million. Depreciation expense was $13 million for the Coal segment, $91 million for the Gas segment and $6 million for Other. Depreciation expense for the period primarily consisted of the allocation of the historical costs of our assets over their useful lives and was partially offset by a reduction in our asset retirement obligations associated with the South Bay facility. During the year ended December 31, 2011, depreciation expense was $295 million. Depreciation expense was $156 million for the Coal segment, $132 million for the Gas segment and $7 million for Other. Depreciation expense for the period primarily consisted of the allocation of the historical costs of our assets over their useful lives. 52-------------------------------------------------------------------------------- Table of Contents Other Charges. During the year ended December 31, 2011, other charges were $5 million, which primarily consisted of restructuring costs. General and Administrative Expense. During the 2012 Predecessor Period, general and administrative expense was $56 million. General and administrative expense for the period primarily consisted of $50 million in labor and benefit costs and $6 million in legal and professional fees and other costs. During the year ended December 31, 2011, general and administrative expense was $102 million. General and administrative expense for the period primarily consisted of $66 million in labor and benefit costs, $29 million in legal and professional fees and $7 million in office expenses and other costs. Bankruptcy Reorganization Items, net. During the 2012 Predecessor Period, bankruptcy reorganization items, net were a gain of $1,037 million. Bankruptcy reorganization items, net consisted of a pre-tax gain of $1,197 million related to the settlement of liabilities subject to compromise as a result of emergence from bankruptcy, a reduction of $161 million and $10 million in the estimated allowable claims related to the subordinated debt and other items, respectively, and a $17 million change in the value of the Administrative Claim. The gains were offset by $299 million in fresh-start adjustments primarily due to the adjustment of assets and liabilities to fair value as a result of the application of fresh-start accounting and $49 million related to the write-off of deferred financing costs and debt discount related to our long-term debt. During the year ended December 31, 2011, bankruptcy reorganization items, net were a loss of $52 million. Bankruptcy reorganization items, net primarily consisted of the write-off of deferred financing costs related to our unsecured notes and debentures and costs related to our bankruptcy advisors. Please read Note 21-Emergence from Bankruptcy and Fresh-Start Accounting for further discussion. Interest Expense. During the 2012 Predecessor Period, interest expense was $120 million. Interest expense primarily consisted of (i) $77 million and $19 million in interest on the DPC and DMG credit agreements, respectively, (ii) $23 million in mark-to-market gains on interest rate swaps, (iii) $4 million in amortization of financing costs and (iv) $2 million in commitment and other fees, offset by $5 million in capitalized interest related to the Coal segment Consent Decree. During the year ended December 31, 2011, interest expense was $348 million, which primarily consisted of (i) $243 million in interest on our notes and debentures prior to the bankruptcy filing on November 7, 2011, (ii) $56 million and $4 million in interest on the DPC and DMG credit agreements, respectively, (iii) $23 million in interest on Letter of Credit and Revolving Facilities, (iv) $22 million in amortization of financing costs, (v) $7 million in mark-to-market gains on interest rate swaps and (vi) $5 million in commitment fees, offset by $12 million in capitalized interest related to the Coal segment Consent Decree. Loss on Extinguishment of Debt. During the year ended December 31, 2011, loss on extinguishment of debt was $21 million, which was incurred in connection with the termination of the Sithe senior debt. Impairment of Undertaking Receivable, affiliate. During the 2012 Predecessor Period, impairment of Undertaking receivable, affiliate was $832 million. As a result of entering into the Settlement Agreement, the Undertaking receivable was impaired to $418 million as of March 31, 2012, resulting in a charge of approximately $832 million. The carrying value of the Undertaking was adjusted to the value received in the DMG Acquisition plus interest payments received subsequent to March 31, 2012. The Undertaking was settled upon execution of the Settlement Agreement. Please read Note 3-Merger and Acquisitions-DMG Transfer and DMG Acquisition for further discussion. Other Income and Expense, net. During the 2012 Predecessor Period, other income and expense, net was a gain of $31 million. Other income and expense, net primarily consisted of $24 million of interest income on the Undertaking receivable, affiliate, a $5 million distribution received related to our retained profits interest in Plum Point and $2 million in certain insurance proceeds. During the year ended December 31, 2011, other income and expense, net was a gain of $35 million. Other income and expense, net primarily consisted of interest income on the Undertaking receivable, affiliate. Income Tax Benefit. We reported an income tax benefit of $9 million for the 2012 Predecessor Period compared to an income tax benefit of $144 million for the year ended December 31, 2011. The effective tax rate for the 2012 Predecessor Period was seven percent compared to 25 percent for the year ended December 31, 2011. For the 2012 Predecessor Period, the difference between the effective rates of seven percent and the statutory rate of 35 percent resulted primarily from a valuation allowance to eliminate our net deferred tax assets partially offset by the impact of state taxes. 53-------------------------------------------------------------------------------- Table of Contents For the year ended December 31, 2011, the difference between the effective rate of 25 percent and the statutory rate of 35 percent is primarily due to the impact of state taxes partially offset by a change in our valuation allowance. Loss from Discontinued Operations, Net of Tax. During the 2012 Predecessor Period, loss from discontinued operations, net of tax was $162 million. Loss from discontinued operations, net of tax primarily related to Bankruptcy reorganization items, net, which included a $395 million charge related to the estimated claim for the rejection of the DNE Facilities Lease and $5 million in other charges, partially offset by a gain of $217 million on the settlement of the DNE lease guaranty claim and a $43 million gain on the deconsolidation of the DNE Entities. Additionally the loss from discontinued operations consisted of $22 million related to the DNE operations. For the year ended December 31, 2011, loss from discontinued operations, net of tax was $509 million, which primarily consisted of DNE operations. Discussion of Adjusted EBITDA Non-GAAP Performance Measures. In analyzing and planning for our business, we supplement our use of GAAP financial measures with non-GAAP financial measures, including EBITDA and Adjusted EBITDA. These non-GAAP financial measures reflect an additional way of viewing aspects of our business that, when viewed with our GAAP results and the accompanying reconciliations to corresponding GAAP financial measures included in the tables below, may provide a more complete understanding of factors and trends affecting our business. These non-GAAP financial measures should not be relied upon to the exclusion of GAAP financial measures and are by definition an incomplete understanding of Dynegy, and must be considered in conjunction with GAAP measures. We believe that the historical non-GAAP measures disclosed in our filings are only useful as an additional tool to help management and investors make informed decisions about our financial and operating performance. By definition, non-GAAP measures do not give a full understanding of Dynegy; therefore, to be truly valuable, they must be used in conjunction with the comparable GAAP measures. In addition, non-GAAP financial measures are not standardized; therefore, it may not be possible to compare these financial measures with other companies' non-GAAP financial measures having the same or similar names. We strongly encourage investors to review our consolidated financial statements and publicly filed reports in their entirety and not rely on any single financial measure. EBITDA and Adjusted EBITDA. We define EBITDA as earnings (loss) before interest expense, income tax expense (benefit) and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA adjusted to exclude (i) gains or losses on the sale of certain assets, (ii) the impacts of mark-to-market changes on derivatives related to our generation portfolio, as well as interest rate swaps and warrants, (iii) the impact of impairment charges and certain other costs such as those associated with the acquisition of AER, internal reorganization and bankruptcy proceedings, (iv) income or loss associated with discontinued operations and (v) income or expense on up front premiums received or paid for financial options in periods other than the strike periods. Our Adjusted EBITDA for the year ended December 31, 2011 is based on our prior methodology which did not include (i) adjustments for up front premiums, (ii) mark-to-market adjustments for financial activity not related to our generation portfolio or (iii) the elimination of income or loss associated with discontinued operations. Adjusted EBITDA includes the Adjusted EBITDA for Legacy Dynegy for the periods prior to the Merger. We believe EBITDA and Adjusted EBITDA provide meaningful representations of our operating performance. We consider EBITDA as another way to measure financial performance on an ongoing basis. Adjusted EBITDA is meant to reflect the operating performance of our entire power generation fleet for the period presented; consequently, it excludes the impact of mark-to-market accounting, impairment charges, gains and losses on sales of assets, and other items that could be considered "non-operating" or "non-core" in nature. Because EBITDA and Adjusted EBITDA are financial measures that management uses to allocate resources, determine our ability to fund capital expenditures, assess performance against our peers and evaluate overall financial performance, we believe they provide useful information for our investors. In addition, many analysts, fund managers, and other stakeholders that communicate with us typically request our financial results in an EBITDA and Adjusted EBITDA format. As prescribed by the SEC, when Adjusted EBITDA is discussed in reference to performance on a consolidated basis, the most directly comparable GAAP financial measure to EBITDA and Adjusted EBITDA is Net income (loss). Management does not analyze interest expense and income taxes on a segment level; therefore, the most directly comparable GAAP financial measure to Adjusted EBITDA when performance is discussed on a segment level is Operating income (loss). 54-------------------------------------------------------------------------------- Table of Contents The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2013: Successor Year Ended December 31, 2013 (amounts in millions) Coal IPH Gas Other Total Net loss attributable to Dynegy Inc. $ (356 ) Income from discontinued operations, net of tax (3 ) Income tax benefit (58 ) Bankruptcy reorganization items, net 1 Interest expense 97 Loss on extinguishment of debt 11 Earnings from unconsolidated investments (2 ) Other items, net (8 ) Operating income (loss) $ (207 ) $ (17 ) $ 7 $ (101 ) $ (318 ) Depreciation expense 50 3 160 3 216 Bankruptcy reorganization items, net - - - (1 ) (1 ) Amortization of intangible assets and liabilities 126 (2 ) 127 - 251 Earnings from unconsolidated investments - - 2 - 2 Other items, net - - 2 6 8 EBITDA (31 ) (16 ) 298 (93 ) 158 Bankruptcy reorganization items, net - - - 1 1 Acquisition and integration costs - 20 - - 20 Mark-to-market loss, net 25 8 4 - 37 Change in fair value of common stock warrants - - - 1 1 Restructuring costs and other expenses - - - 8 8 Other 2 - - - 2 Adjusted EBITDA $ (4 ) $ 12 $ 302 $ (83 ) $ 227 55-------------------------------------------------------------------------------- Table of Contents The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2012, which includes the 2012 Successor and 2012 Predecessor periods: Combined (2) Year Ended December 31, 2012 (amounts in millions) Coal Gas Other Total Net loss $ (139 ) Loss from discontinued operations, net of tax 156 Income tax benefit (9 ) Impairment of Undertaking receivable, affiliate 832 Bankruptcy reorganization items, net (1,034 ) Interest expense 136 Earnings from unconsolidated investments (2 ) Other items, net (39 ) Operating income (loss) $ (112 ) $ 97 $ (84 ) $ (99 ) Impairment of Undertaking receivable, affiliate - - (832 ) (832 ) Bankruptcy reorganization items, net - - 1,034 1,034 Depreciation expense 21 127 7 155 Amortization of intangible assets and liabilities 78 61 - 139 Earnings from unconsolidated investments - 2 - 2 Other items, net 5 2 32 39 EBITDA (8 ) 289 157 438 Impairment of Undertaking receivable, affiliate - - 832 832 Bankruptcy reorganization items, net - - (1,034 ) (1,034 ) Interest income on Undertaking receivable - - (24 ) (24 ) Restructuring costs and other expense - - 3 3 Mark-to-market (gain) loss, net 7 (166 ) - (159 ) Premium adjustment 1 (1 ) - - Changes in fair value of common stock warrants - - (8 ) (8 ) Adjusted EBITDA from Dynegy - 122 (74 ) 48 Adjusted EBITDA from Legacy Dynegy (1) 20 - (11 ) 9 Adjusted EBITDA $ 20 $ 122 $ (85 ) $ 57 __________________________________________ (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. 56-------------------------------------------------------------------------------- Table of Contents Successor Predecessor January 1 October 2 Through Through October (amounts in millions) December 31, 2012 1, 2012 Total Net loss $ (107 ) $ (32 ) $ (139 ) Loss from discontinued operations, net of tax (6 ) 162 156 Income tax benefit - (9 ) (9 ) Impairment of Undertaking receivable, affiliate - 832 832 Bankruptcy reorganization items, net 3 (1,037 ) (1,034 ) Interest expense 16 120 136 Earnings from unconsolidated investments (2 ) - (2 ) Other items, net (8 ) (31 ) (39 ) Operating income (loss) (104 ) 5 (99 ) Impairment of Undertaking receivable, affiliate - (832 ) (832 ) Bankruptcy reorganization items, net (3 ) 1,037 1,034 Depreciation expense 45 110 155 Amortization of intangible assets and liabilities 60 79 139 Earnings from unconsolidated investments 2 - 2 Other items, net 8 31 39 EBITDA $ 8 $ 430 $ 438 The following table provides summary financial data regarding our Adjusted EBITDA by segment for the year ended December 31, 2011: Predecessor Year Ended December 31, 2011 (amounts in millions) Coal Gas Other Total Net loss $ (940 ) Loss from discontinued operations, net of tax 509 Income tax benefit (144 ) Interest expense and debt extinguishment costs 369 Bankruptcy reorganization items, net 52 Other items, net (35 ) Operating loss $ (38 ) $ (37 ) $ (114 ) $ (189 ) Bankruptcy reorganization items, net - - (52 ) (52 ) Other items, net 2 2 31 35 Depreciation expense 156 132 7 295 EBITDA from continuing operations 120 97 (128 ) 89 Merger termination fee, restructuring costs and other expenses (1 ) 7 25 31 Bankruptcy reorganization items, net - - 52 52 Mark-to-market loss, net 76 51 4 131 Adjusted EBITDA from Dynegy 195 155 (47 ) 303 Adjusted EBITDA from Legacy Dynegy (1) 48 - (51 ) (3 ) Adjusted EBITDA from continuing operations $ 243 $ 155 $ (98 ) $ 300 Adjusted EBITDA from discontinued operations (19 ) Adjusted EBITDA $ 281 57-------------------------------------------------------------------------------- Table of Contents __________________________________________ (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. Adjusted EBITDA Adjusted EBITDA increased by $170 million from $57 million for the year ended December 31, 2012 to $227 million for the year ended December 31, 2013. The increase was primarily related to an increase of $169 million in our Gas segment Adjusted EBITDA due to the absence of negative settlements associated with legacy commercial positions which adversely impacted 2012 results, $12 million of IPH Adjusted EBITDA for the month of December and $8 million of decreased operations and maintenance costs for our Coal and Gas segments. Offsetting these increases was a $19 million decrease in realized energy margin in our Coal segment due to lower realized prices on hedged generation. Adjusted EBITDA decreased by $224 million from $281 million for the year ended December 31, 2011 to $57 million for the year ended December 31, 2012. The decrease is primarily due to lower overall market prices and an increase in basis differentials in our Coal segment, which resulted in a $183 million decrease in physical energy margin, $60 million in lower capacity and tolling revenues in our Gas segment due to a decrease in capacity pricing and the cancellation of the Morro Bay toll and Moss Landing resource adequacy contract and the settlement of legacy commercial positions, which resulted in $65 million in higher settlement expense in 2012 compared to 2011. Offsetting these decreases is a $39 million increase in energy margin in our Gas segment due to improved spark spreads and fewer outages and $57 million due to changes in methodology associated with amortization expense and no longer including DNE in Adjusted EBITDA in 2012 as a result of DNE being classified in discontinued operations. Adjusted EBITDA for 2011 includes amortization expense related to the Sithe acquisition and negative Adjusted EBITDA for DNE. These amounts were excluded in 2012. 58-------------------------------------------------------------------------------- Table of Contents Discussion of Segment Adjusted EBITDA Coal Segment. Both on-peak and off-peak power prices were higher in the year ended December 31, 2013 compared to the year ended December 31, 2012, resulting in higher gross margin. Both on-peak and off-peak power prices were lower in the year ended December 31, 2012 compared to the year ended December 31, 2011. As a result of the DMG Acquisition, 2012 results only include the results of the Coal segment for the period June 6, 2012 through December 31, 2012. Additionally, as a result of the DMG Transfer, 2011 results only include the results of the Coal segment for the period January 1, 2011 through August 31, 2011. The following table provides summary financial data regarding our Coal segment results of operations for the year ended December 31, 2013, the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011, respectively. Successor Predecessor (dollars in millions, except for price Year Ended October 2 Through January 1 Through Year Ended information) December 31, 2013 December 31, 2012 October 1, 2012 December 31, 2011 Operating Revenues Energy $ 519 $ 105 $ 184 $ 512 Mark-to-market gain (loss), net (25 ) 7 (14 ) (76 ) Other (1) (27 ) (5 ) (4 ) 24 Total operating revenues 467 107 166 460 Operating costs Cost of sales (333 ) (82 ) (112 ) (237 ) Contract amortization (126 ) (28 ) (49 ) - Total operating costs (459 ) (110 ) (161 ) (237 ) Gross margin 8 (3 ) 5 223 Operating and maintenance expense (167 ) (38 ) (55 ) (105 ) Depreciation expense (50 ) (8 ) (13 ) (156 ) Gain on sale of assets, net 2 - - - Operating loss (207 ) (49 ) (63 ) (38 ) Depreciation expense 50 8 13 156 Amortization of intangible assets and liabilities 126 29 49 - Other items, net - - 5 2 EBITDA (31 ) (12 ) 4 120 Mark-to-market (gain) loss, net 25 (6 ) 13 76 Other expenses 2 1 - (1 ) Adjusted EBITDA (2) $ (4 ) $ (17 ) $ 17 $ 195 Million Megawatt Hours Generated (3) 20.4 4.7 6.6 15.6 In Market Availability for Coal Fired Facilities (4) 89 % 86 % 93 % 92 % Average Quoted Market Power Prices ($/MWh) (5): On-Peak: Indiana (Indy Hub) $ 38.04 $ 34.76 $ 39.72 $ 44.80 Off-Peak: Indiana (Indy Hub) $ 27.50 $ 25.94 $ 23.88 $ 30.36 59-------------------------------------------------------------------------------- Table of Contents ________________________________________ (1) Other includes financial settlements, ancillary services and other miscellaneous items. (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. (4) Reflects the percentage of generation available during the period Coal was included in our consolidated results. In Market Availability for Coal Fired Facilities was 92 percent for the full twelve months ended December 31, 2012 and 2011. (5) Reflects the average of day-ahead quoted prices for the periods Coal was included in our consolidated results and does not necessarily reflect prices we realized. The average of day-ahead quoted prices was $34.61 and $41.34 for the full twelve months ended December 31, 2012 and 2011, respectively. (6) The market reference for 2011 was Cinergy (Cin Hub). At the end of 2011, the Cin Hub pricing point in MISO ceased to exist when the Ohio portion of the market point became part of PJM. Beginning in 2012, Indy Hub became MISO's major market point and is considered a direct correlation to the old Cin Hub and has been accepted as a replacement for Cin Hub in commercial contracts. Operating loss for the year ended December 31, 2013 was $207 million, $49 million for the 2012 Successor Period, $63 million for the 2012 Predecessor Period and $38 million for the year ended December 31, 2011. Adjusted EBITDA was a loss of $4 million for the year ended December 31, 2013, which was primarily comprised of $188 million in energy margin and $6 million in other items, offset by $31 million in settlement expense and $167 million in operating expense. Adjusted EBITDA was $20 million for the year ended December 31, 2012, which includes the 2012 Successor Period, the 2012 Predecessor Period and Legacy Dynegy, and was primarily comprised of $158 million in energy margin, $5 million in other items and $19 million in settlement revenue offset by $162 million in operating expenses. Adjusted EBITDA was $243 million for the year ended December 31, 2011, which includes Legacy Dynegy, and was primarily comprised of $341 million in energy margin, $6 million in other items and $66 million in settlement revenue, offset by $170 million in operating expenses. The decrease in Adjusted EBITDA between 2013 and 2012 was primarily driven by lower realized prices on hedged positions while the decrease between 2012 and 2011 was primarily driven by lower overall realized prices. 60-------------------------------------------------------------------------------- Table of Contents IPH Segment. The IPH segment includes the results of its wholesale and retail operations since the acquisition on December 2, 2013. Successor (dollars in millions, except for Year Ended price information) December 31, 2013 Operating Revenues Energy $ 65 Mark-to-market loss, net (8 ) Contract amortization (3 ) Other (1) 13 Total operating revenues 67 Operating Costs Cost of sales (51 ) Contract amortization 5 Total operating costs (46 ) Gross margin 21 Operating and maintenance expense (15 ) Depreciation expense (3 ) Acquisition and integration costs (20 ) Operating loss (17 ) Depreciation expense 3 Amortization of intangible assets and liabilities (2 ) EBITDA (16 ) Mark-to-market loss, net 8 Acquisition and integration costs 20 Adjusted EBITDA $ 12 Million Megawatt Hours Generated (2) 2.4 In Market Availability for Coal Fired Facilities (3) 90 % Average Quoted Market Power Prices ($/MWh) (4): On-Peak: Indiana (Indy Hub) $ 40.32 Off-Peak: Indiana (Indy Hub) $ 30.82 ________________________________________ (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. Operating loss for the year ended December 31, 2013 was $17 million. Adjusted EBITDA was income of $12 million for the year ended December 31, 2013, which consisted of energy margin and revenue from financial settlements, partially offset by operating expenses. Gas Segment. Spark spreads were higher in the year ended December 31, 2013 compared to the year ended December 31, 2012 primarily at our Moss Landing and Independence facilities. Spark spreads were also higher in the year ended December 31, 2012 compared to the year ended December 31, 2011 primarily at our Moss Landing, Independence and Kendall facilities. 61-------------------------------------------------------------------------------- Table of Contents The following table provides summary financial data regarding our Gas segment results of operations for the year ended December 31, 2013, the 2012 Successor Period, the 2012 Predecessor Period and the year ended December 31, 2011, respectively: Successor Predecessor (dollars in millions, except for Year Ended October 2 Through January 1 Through Year Ended price information) December 31, 2013 December 31, 2012 October 1, 2012 December 31, 2011 Operating Revenues Energy $ 649 $ 118 $ 492 $ 489 Capacity 237 50 194 257 Mark-to-market gain (loss), net (4 ) 39 117 (61 ) Contract amortization (135 ) (34 ) (32 ) (43 ) Other (1) 185 32 44 230 Total operating revenues 932 205 815 872 Operating Costs Cost of sales (648 ) (160 ) (504 ) (634 ) Contract amortization 8 2 3 5 Total operating costs (640 ) (158 ) (501 ) (629 ) Gross margin 292 47 314 243 Operating and maintenance expense (125 ) (42 ) (95 ) (148 ) Depreciation expense (160 ) (36 ) (91 ) (132 ) Operating income (loss) 7 (31 ) 128 (37 ) Depreciation expense 160 36 91 132 Amortization of intangible assets and liabilities 127 32 29 - Earnings from unconsolidated investments 2 2 - - Other items, net 2 - 2 2 EBITDA 298 39 250 97 Mark-to-market (gain) loss, net 4 (39 ) (127 ) 51 Premium adjustment - (2 ) 1 - Other expenses - - - 7 Adjusted EBITDA $ 302 $ (2 ) $ 124 $ 155 Million Megawatt Hours Generated (2) 16.2 3.5 16.9 12.3 In Market Availability for Combined Cycle Facilities (3) 97 % 83 % 98 % 94 % Average Capacity Factor for Combined Cycle Facilities (4) 43 % 36 % 57 % 21 % Average Market On-Peak Spark Spreads ($/MWh) (5) $ 15.71 $ 13.05 $ 15.04 $ 12.74 Average Market Off-Peak Spark Spreads ($/MWh) (5) $ 3.50 $ 3.15 $ 4.71 $ 0.62 Average natural gas price-Henry Hub ($/MMBtu) (6) $ 3.72 $ 3.39 $ 2.53 $ 3.99 __________________________________________ (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. 62-------------------------------------------------------------------------------- Table of Contents Operating income for the year ended December 31, 2013 was $7 million, a loss of $31 million for the 2012 Successor Period, income of $128 million for the 2012 Predecessor Period and a loss of $37 million for the year ended December 31, 2011. Adjusted EBITDA totaled $302 million during the year ended December 31, 2013, which was primarily comprised of $334 million of capacity and tolling revenue, $90 million of physical energy margin and $42 million of ancillary services and other items, offset by $125 million of operating expense and $39 million in negative financial settlements. Adjusted EBITDA was $122 million for the year ended December 31, 2012, which includes the 2012 Successor Period, the 2012 Predecessor Period and Legacy Dynegy, and was primarily comprised of $328 million of capacity and tolling revenue, $93 million of physical energy margin and $48 million of ancillary services and other items, offset by $209 million in negative financial settlements and $138 million of operating expense. Adjusted EBITDA was $155 million for the year ended December 31, 2011, which includes Legacy Dynegy, and was primarily comprised of $388 million of capacity and tolling revenue, $47 million of physical energy margin and $50 million of ancillary services and other items, offset by $148 million of operating expense, $144 million in negative financial settlements and $38 million in amortization expense which was included in 2011 Adjusted EBITDA. Outlook We expect that our future financial results will continue to be impacted by fuel and commodity prices, especially natural gas prices. Other factors to which our future financial results will remain sensitive include market structure and prices for electric energy, capacity and ancillary services, including pricing at our plant locations relative to pricing at their respective trading hubs, the volatility of fuel and electricity prices, transportation and transmission logistics, weather conditions and IMA. Further, there is a trend toward greater environmental regulation of all aspects of our business. As this trend continues, it is possible that we will experience additional costs associated with the handling and disposal of coal ash, how water used by our power generation facilities is withdrawn and treated before being discharged and more stringent air emission standards. Coal. The Coal segment consists of four plants, all located in the MISO region, and totaling 2,980 MW. As of February 21, 2014, our Coal expected generation volumes are 51 percent hedged volumetrically for 2014 and approximately 10 percent hedged volumetrically for 2015. We plan to continue our hedging program for Coal over a one- to three-year period using various instruments, which includes the sale of natural gas swaps as a cross-commodity correlated hedge for our power revenue. As a result of the offsetting risks of our Coal and Gas segments, we are able to reduce the costs associated with hedging by executing a portion of Coal's hedges with an internal affiliate. The internal hedges are cross-commodity hedges and we intend to expand this in the future. Beyond 2014, the portfolio is largely open, positioning Coal to benefit from possible future power market pricing improvements. Due to declining correlations between our plant LMP prices and trading hub prices, we plan to mitigate the risk of a breakdown between these prices through participation in FTR markets and busbar basis swaps to the extent they are economically available. Furthermore, Coal's hedge levels are likely to be lower than the hedge levels in prior years. As of February 21, 2014, our expected coal requirements are 93 percent contracted and priced in 2014. Our forecasted coal requirements for 2015 are 68 percent contracted and 14 percent priced. Our coal transportation requirements are fully contracted and priced for the next several years. We continue to explore various alternative contractual commitments and financial options, as well as facility modifications, to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies. The MISO filed proposed Resource Adequacy Enhancements with FERC on July 20, 2011. The FERC conditionally approved MISO's proposal on June 11, 2012, leaving much of MISO's proposal in place. The new tariff provisions replace the monthly construct with a full planning year product (June 1 - May 31) and further recognize zonal deliverability capacity requirements. The first zonal auction was held in March 2013. For the 2013-2014 planning year, capacity cleared at $1.05 per MW-day for all zones. This low clearing price was likely caused by excess capacity conditions prevailing in MISO for the term of the planning year. In the future, the potential retirement of marginal MISO coal capacity due to poor economics or expected environmental mandates and confirmed future capacity exports from MISO to PJM could also affect MISO capacity and energy pricing. MISO's annual Loss of Load Expectation ("LOLE") study was published in early November 2013. The LOLE study is a critical input to the annual MISO Planning Resource Auction ("PRA"). The LOLE study employed meaningful changes for the planning year 2014-2015 to reflect the integration of Entergy into MISO and to reflect modeling enhancements required to stabilize the planning reserve margin and reliability requirements in MISO. The LOLE also utilizes a revised methodology to calculate import and export capabilities between Local Resource Zones ("LRZ") which may have an impact on intra-zonal balances. On February 6, 2014, MISO announced revisions to its November 2013 LOLE analysis. These revisions impacted LRZ 4 and 5 63-------------------------------------------------------------------------------- Table of Contents (where our facilities are located). The planning year 2014-2015 MISO auction will take place in late March, with results expected to be released no later than April 15, 2014. Based on analysis of historical constraints near our generating facilities, we have identified opportunities to invest in transmission facilities upgrades which will help to mitigate the impact of congestion around our Baldwin plant. We are working with the Transmission Owner to potentially implement these upgrades. We continue to assess grid constraints impacting our other facilities to identify other opportunities to reduce congestion and improve LMPs at our Coal and newly acquired IPH facilities. IPH. The IPH segment consists of five plants, totaling 4,062 MW. The Coffeen, Edwards, Duck Creek and Newton facilities are located in the MISO region. Joppa is located within its own control area, known as EEI. Joppa sells all of its net power into three connected control areas: MISO, TVA and LGE. As of February 21, 2014, our IPH expected generation volumes are 78 percent hedged volumetrically for 2014 and approximately 47 percent hedged volumetrically for 2015. The IPH hedging program will continue to use our retail business, Homefield Energy, to hedge a portion of the output from our IPH facilities. The retail hedges are well correlated to our facilities due to the close proximity of the hedge and through participation in FTR markets. We also plan to use other instruments to hedge the power revenue. Future new business and recontracting of existing business will impact IPH's hedge levels in the future. As of February 21, 2014, our expected coal requirements for IPH are 95 percent contracted and 84 percent priced for 2014. Our forecasted coal requirements for 2015 are 44 percent contracted and 22 percent priced. Our coal transportation requirements are fully contracted and priced for the next several years. We continue to explore various alternative contractual commitments and financial options to ensure stable and competitive fuel supplies and to mitigate further supply risks for near- and long-term coal supplies. Gas. The Gas segment consists of seven plants, geographically diverse in five markets, totaling 6,121 MW. Approximately 70 percent of our power plant capacity in the CAISO market is contracted through 2014 under tolling agreements with LSEs and a RMR agreement. A significant portion of the remaining capacity is sold as a resource adequacy product in the CAISO market. The CAISO capacity market is bilateral in nature. The LSEs are required to procure sufficient resources for their peak load plus a fifteen percent reserve margin. The CAISO footprint currently has a capacity surplus due to a weak economy and increased participation from renewable resources. The CAISO faces challenges to ensure system reliability as well as adequate ancillary services in the future with the mandate to have 33 percent renewable resources by 2020. The combination of bilateral markets, one-off utility procurements and short-term requirements make this a larger concern than in other markets where multi-year forward requirements and more transparent markets are in place. The CAISO and CPUC recently released a joint proposal for a multi-year forward capacity market called the Joint Reliability Framework. This proposal would fill the gap between the Resource Adequacy (one-year requirement) and the LTPP (ten-year plan) to establish a multi-year forward resource adequacy requirement on LSEs, provide a CAISO administered multi-year forward capacity market, and a market-based backstop mechanism to procure reliability services (both capacity and flexibility). A flexible capacity requirement has been imposed on CPUC jurisdictional load-serving entities via the Resource Adequacy proceeding and will be mandatory for 2015. The CAISO is currently working on the rules for how the flexible capacity will be counted and how it must be offered into the CAISO markets. The CPUC and CAISO have updated their proposals and appear to have abandoned any potential solution that results in a multi-year forward centrally-administered capacity market. There is little chance that a CAISO administered multi-year forward capacity market will be considered again until 2016. The estimated useful lives of our generation facilities consider environmental regulations currently in place. With respect to Units 6 and 7 at our Moss Landing facility, we are continuing to review the potential impact of the California Water Intake Policy. We are currently depreciating these units through 2024; however, depending on (i) a final determination of the compliance term and requirements of the California Water Intake Policy and (ii) our ability to secure energy and/or capacity contracts in the future, we could decide to reduce operations or cease to operate the units prior to 2024. The Morro Bay facility was retired on February 5, 2014; we are currently evaluating alternatives for the site including developing renewable energy shaping technologies as well as preferred renewable resources, as defined by California laws and regulations. In New England, eight forward capacity auctions have been held since the ISO-NE transitioned to a forward capacity market in June 2010. The highest clearing price of $15/kW-month occurred in the most recent auction for the 2017-2018 market period. However, the "insufficient competition" clause in the ISO-NE tariff was triggered, resulting in existing generation receiving an administrative cap price of $2.95 per kW-month was seen for the 2013-2014 market period. Due to oversupply conditions, the seven prior annual auctions cleared at the designated floor. Changes made to the forward capacity market design removed the auction floor price and implemented a minimum offer price rule that set a floor price for new entrants based on technology type. For the eighth auction, the floor price was removed. However, the auction cleared at the high mark, with existing generation receiving the administrative cap due to significant capacity retirements in the region. ISO-NE is developing additional changes to the forward capacity market including performance incentives and a sloped demand curve which are expected to be in place f 64-------------------------------------------------------------------------------- Table of Contents or the ninth forward capacity auction in 2015. In PJM, where the Kendall and Ontelaunee combined-cycle plants are located, ten forward capacity auctions (known as RPM or Reliability Pricing Model) have been held since the transition from a daily capacity market in June 2007. RPM clearing prices have ranged from $0.50 per kW-month (Kendall, 2012-2013 Planning Year) and $1.24 per kW-month (Ontelaunee, 2007-2008 Planning Year) to $5.30 per kW-month (Kendall, 2010-2011 Planning Year) and $6.88 per kW-month (Ontelaunee, 2013-2014 Planning Year). The latest RPM auction was for the 2016-2017 Planning Year, which cleared at $1.81 per kW-month (Kendall) and $3.62 per kW-month (Ontelaunee). Capacity pricing for the NYISO seems to be recovering from the low point in 2011. The most recent summer and winter auctions have cleared higher than the previous auctions with summer 2013 at $4.20 per kW-month and winter 2013-2014 at $2.58 per kW-month for the rest of state market. We attribute the rebound in part to the FERC Order on buyer-side mitigation and retirements impacting 2013. Approximately 70 percent of the capacity revenue for our Independence facility has been contracted at a favorable premium compared to current market prices through October 31, 2014. Excluding volumes subject to tolling agreements, as of February 21, 2014, our Gas portfolio is 58 percent hedged volumetrically through 2014 and approximately 15 percent hedged volumetrically for 2015. As a result of the offsetting risks of our Gas and Coal segments, we are able to reduce the costs associated with hedging by executing a portion of our natural gas hedges with an internal affiliate. As discussed above, we intend to expand this in the future. We continue to manage our remaining commodity price exposure to changing fuel and power prices in accordance with our risk management policy. SEASONALITY Our revenues and operating income are subject to fluctuations during the year, primarily due to the impact seasonal factors have on sales volumes and the prices of power and natural gas. Power marketing operations and generating facilities have higher volatility and demand, respectively, in the summer cooling months. This trend may change over time as demand for natural gas increases in the summer months as a result of increased natural gas-fired electricity generation. Further, to the extent that climate change may affect weather patterns, this could result in more extreme weather patterns which could impact demand for our products. CRITICAL ACCOUNTING POLICIES Our Accounting Department is responsible for the development and application of accounting policy and control procedures. This department conducts these activities independent of any active management of our risk exposures, is independent of our business segments and reports to the Chief Financial Officer. The process of preparing financial statements in accordance with GAAP requires our management to make estimates and judgments. It is possible that materially different amounts could be recorded if these estimates and judgments change or if actual results differ from these estimates and judgments. We have identified the following critical accounting policies that require a significant amount of estimation and judgment and are considered important to the portrayal of our financial position and results of operations: • Revenue Recognition and Derivative Instruments; • Fair Value Measurements; • Accounting for Income Taxes; and • Business Combinations and Fresh-Start Accounting. Revenue Recognition and Derivative Instruments We earn revenue from our facilities in three primary ways: (i) the sale of energy, including fuel, through both physical and financial transactions; (ii) sale of capacity; and (iii) sale of ancillary services, which are the products of a generation facility that support the transmission grid operation, allow generation to follow real-time changes in load and provide emergency reserves for major changes to the balance of generation and load. We recognize revenue from these transactions when the product or service is delivered to a customer, unless they meet the definition of a derivative. Please read "Derivative Instruments-Generation" below for further discussion of the accounting for these types of transactions. Derivative Instruments-Generation. We enter into commodity contracts that meet the definition of a derivative. These contracts are often entered into to mitigate or eliminate market and financial risks associated with our generation business. These contracts include forward contracts, which commit us to sell commodities in the future; futures contracts, which are generally broker-cleared standard commitments to purchase or sell a commodity; option contracts, which convey the right to buy or sell a commodity; and swap agreements, which require payments to or from counterparties based upon the differential between two prices for a predetermined quantity. There are three different ways to account for these types of contracts: (i) as an accrual contract, if the criteria for the "normal purchase, normal sale" exception are met and documented; (ii) as a cash flow or fair value hedge, if the criteria are met and documented; or (iii) as a mark-to-market contract with changes in fair value recognized in current period earnings. All derivative commodity contracts that do not qualify for the "normal purchase, normal sale" exception are recorded at fair value in risk management assets and liabilities on the consolidated balance sheets with the associated changes in fair value recorded currently in earnings. Dynegy does not elect hedge accounting for any of its derivative instruments. Entities may choose whether or not to offset related assets and liabilities and report the net amounts on their consolidated balance sheet if the right of offset exists. We elect to offset fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement and we elected to offset the fair value of amounts recognized for the Daily Cash Settlements paid or received against the fair value of amounts recognized for derivative instruments executed with the same counterparty under a master netting agreement. As a result, our consolidated balance sheets present derivative assets and liabilities, as well as the related cash collateral paid or received, on a net basis. 65-------------------------------------------------------------------------------- Table of Contents Derivative Instruments-Financing Activities. We are exposed to changes in interest rate risk through our variable rate debt. In order to manage our interest rate risk, we enter into interest rate swap agreements that meet the definition of a derivative. All derivative instruments are recorded at their fair value on the consolidated balance sheet with the changes in fair value recorded to interest expense. Our interest-based derivative instruments are not designated as hedges of our variable debt. Fair Value Measurements Fair Value Measurements. Accounting standards define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. In estimating fair value, we use discounted cash-flow projections, recent comparable market transactions, if available, or quoted prices. We consider assumptions that third parties would make in estimating fair value, including the highest and best use of the asset. There is a significant amount of judgment involved in cash-flow estimates, including assumptions regarding market convergence, discount rates and capacity prices. The assumptions used by another party could differ significantly from our assumptions. Our estimate of fair value reflects the impact of credit risk. We utilize market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs are classified as readily observable, market corroborated or generally unobservable. We primarily apply the market approach for recurring fair value measurements and endeavor to utilize the best available information. Accordingly, we utilize valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. We classify fair value balances based on the classification of the inputs used to calculate the fair value of a transaction. The inputs used to measure fair value have been placed in a hierarchy based on priority. The hierarchy gives the highest priority to unadjusted, readily observable quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are classified as follows: • 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. • 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. • 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. Fair Value Measurements-Risk Management Activities. The determination of the fair value for each derivative contract incorporates various factors. These factors include not only the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), but also the impact of our nonperformance risk on our liabilities. Valuation adjustments are generally based on capital market implied ratings evidence when assessing the credit standing of our counterparties and when applicable, adjusted based on management's estimates of assumptions market participants would use in determining fair value. Assets and liabilities from risk management activities may include exchange-traded derivative contracts and OTC derivative contracts. Exchange-traded derivatives, as discussed above, are generally classified as Level 1; however, some exchange-traded derivatives are valued using broker or dealer quotations or market transactions in either the listed or OTC markets. In such cases, these exchange-traded derivatives are classified within Level 2. OTC derivative trading instruments include swaps, forwards and options. In certain instances, these instruments may utilize models to measure fair value. Generally, we use a similar model to value similar instruments. Valuation models utilize various inputs that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, other observable inputs for the asset or liability and market-corroborated inputs. Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. Other OTC derivatives trade in less active markets with a lower availability of pricing information. In addition, complex or structured transactions, such as heat-rate call options, can introduce the need for internally-developed model inputs that might not be observable in or corroborated by the market. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized in Level 3. 66-------------------------------------------------------------------------------- Table of Contents Accounting for Income Taxes We file a consolidated U.S. federal income tax return. We use the asset and liability method of accounting for deferred income taxes and provide deferred income taxes for all significant differences. As part of the process of preparing our consolidated financial statements, we are required to estimate our income taxes in each of the jurisdictions in which we operate. This process involves estimating our actual current tax payable and related tax expense together with assessing temporary differences resulting from differing tax and accounting treatment of certain items, such as depreciation, for tax and accounting purposes. These differences can result in deferred tax assets and liabilities, which are included within our consolidated balance sheet. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Because we operate and sell power in many different states, our effective annual state income tax rate may vary from period to period because of changes in our sales profile by state, as well as jurisdictional and legislative changes by state. As a result, changes in our estimated effective annual state income tax rate can have a significant impact on our measurement of temporary differences. We project the rates at which state tax temporary differences will reverse based upon estimates of revenues and operations in the respective jurisdictions in which we conduct business. The guidance related to accounting for income taxes requires that a valuation allowance be established when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income of the appropriate character during the periods in which those temporary differences are deductible. In making this determination, management considers all available positive and negative evidence affecting specific deferred tax assets, including our past and anticipated future performance, the reversal of deferred tax liabilities and the implementation of tax planning strategies. We do not believe we will produce sufficient future taxable income, nor are there tax planning strategies available to realize the tax benefits from, net deferred tax assets not otherwise realized by reversing temporary differences. Therefore, a valuation allowance was placed against our net deferred tax assets as of December 31, 2013 and 2012. Any change in the valuation allowance would impact our income tax benefit (expense) and net income (loss) in the period in which the change occurs. Accounting for uncertainty in income taxes requires that we determine whether it is more-likely-than-not that a tax position we have taken will be sustained upon examination. If we determine that it is more likely than not that the position will be sustained, we recognize the largest amount of the benefit that is greater than 50 percent likely of being realized upon settlement. There is a significant amount of judgment involved in assessing the likelihood that a tax position will be sustained upon examination and in determining the amount of the benefit that will ultimately be realized. We recognize accrued interest expense and penalties related to unrecognized tax benefits as income tax expense. Please read Note 14-Income Taxes for further discussion of our accounting for income taxes, uncertain tax positions and changes in our valuation allowance. Business Combinations and Fresh-Start Accounting U.S. GAAP requires that the purchase price for an acquisition, such as our AER Acquisition, be assigned and allocated to the individual assets and liabilities based upon their fair value (or in the case of fresh-start accounting, the reorganization value as approved by the Bankruptcy Court). Generally, the amount recorded in the financial statements for an acquisition is the purchase price (value of the consideration paid), but a purchase price that exceeds the fair value of the assets acquired will result in the recognition of goodwill. In addition to the potential for the recognition of goodwill, differing fair values will impact the allocation of the purchase price to the individual assets and liabilities and can impact the gross amount and classification of assets and liabilities recorded on our consolidated balance sheets and can impact the timing and the amount of depreciation and amortization expense recorded in any given period. We utilize our best effort to make our determinations and review all information available including estimated future cash flows and prices of similar assets when making our best estimate. We also may hire independent appraisers to help us make this determination as we deem appropriate under the circumstances. There is a significant amount of judgment in determining the fair value of the acquisitions and in allocating value to individual assets and liabilities. Had different assumptions been used, our investment value in the entities acquired could have been significantly higher or lower with a corresponding increase or reduction in our asset and liability values. Refer to Note 3-Merger and Acquisitions for further discussion of the AER Acquisition. On the Plan Effective Date, we applied fresh-start accounting in accordance with guidance under the applicable reorganization accounting rules. These rules require that we allocate the reorganization value of the Successor to its assets and 67-------------------------------------------------------------------------------- Table of Contents liabilities based upon their estimated fair values determined in conformity with the guidance for the acquisition method of accounting for business combinations. We recorded the fair value of some assets and liabilities at cost, which was an appropriate measure of fair value (i.e. cash, restricted cash, accounts payable). Other assets and liabilities were adjusted to fair value based on then-current market prices (i.e. inventory). The fair value of our outstanding long-term debt was fair valued based upon the trading price of the debt on the Plan Effective Date. There is a significant amount of judgment in determining the reorganization value and in allocating value to individual assets and liabilities. Had different assumptions been used, our reorganization value could have been significantly higher or lower, which could have resulted in goodwill or a reduction in our asset values. Refer to Note 21-Emergence from Bankruptcy and Fresh-Start Accounting-Accounting Impact of Emergence for further discussion. RECENT ACCOUNTING PRONOUNCEMENTSPlease read Note 2-Summary of Significant Accounting Policies for further discussion of accounting principles adopted and accounting principles not yet adopted. RISK MANAGEMENT DISCLOSURESThe following table provides a reconciliation of the risk management data on the consolidated balance sheets on a net basis: (amounts in millions) Fair value of portfolio at December 31, 2012 $ (50 ) Risk management losses recognized through the statement of operations in the period, net (46 ) Contracts realized or otherwise settled during the period 8 AER Acquisition 30 Change in collateral/margin netting (4 ) Fair value of portfolio at December 31, 2013 $ (62 ) The net risk management liability of $62 million is the aggregate of the following line items on our consolidated balance sheets: Current Assets-Assets from risk management activities, Other Assets-Assets from risk management activities, Current Liabilities-Liabilities from risk management activities and Other Liabilities-Liabilities from risk management activities. Risk Management Asset and Liability Disclosures. The following table provides an assessment of net contract values by year as of December 31, 2013, based on our valuation methodology: Net Fair Value of Risk Management Portfolio (amounts in millions) Total 2014 2015 2016 2017 2018 Thereafter Market quotations (1) (2) $ (76 ) $ (47 ) $ (17 ) $ (11 ) $ (6 ) $ 1 $ 4 Prices based on models (2) 10 2 6 2 - - - Total (3) $ (66 ) $ (45 ) $ (11 ) $ (9 ) $ (6 ) $ 1 $ 4 _________________________________________ (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. 68-------------------------------------------------------------------------------- Table of Contents |