Depreciation expense increased from $6 million for the first quarter 2007 to $13 million for the first quarter 2008 as a result of the addition of the Casco Bay and Bridgeport plants.
Cost of sales for the three months ended March 31, 2008 included the release of a $9 million liability associated with an assignment of a natural gas transportation contract. Operating and maintenance expense for the three months ended March 31, 2008 included the release of an $8 million of sales and use tax liability.
Dynegy’s consolidated general and administrative expenses were $39 million and $53 million for the three months ended March 31, 2008 and 2007, respectively. General and administrative expenses for the three months ended March 31, 2007 included legal and settlement charges of $17 million resulting from additional activities during the period that negatively affected management’s assessment of the probable and estimable losses associated with the applicable proceedings.
DHI’s other operating loss for the three months ended March 31, 2008 was $24 million, compared to an operating loss of $42 million for the three months ended March 31, 2007. Operating losses in both periods were comprised primarily of general and administrative expenses and results from our former customer risk management business.
Cost of sales for the three months ended March 31, 2008 included the release of a $9 million reserve associated with natural gas transportation contracts. Operating and maintenance expense for the three months ended March 31, 2008 included the release of an $8 million of sales and use tax liability.
DHI’s consolidated general and administrative expenses were $39 million and $36 million for the three months ended March 31, 2008 and 2007, respectively.
Dynegy’s losses from unconsolidated investments were $9 million for the three months ended March 31, 2008, including a $5 million loss related to the GEN-WE investment in Sandy Creek. The remaining $4 million loss related to its investment in DLS Power Development, included in Other. Earnings from unconsolidated investments for the three months ended March 31, 2007 were zero.
DHI’s losses from unconsolidated investments of $5 million for the three months ended March 31, 2008 related to the GEN-WE investment in Sandy Creek. Earnings from unconsolidated investments for the three months ended March 31, 2007 were zero.
Other Items, Net
Dynegy’s other items, net, totaled $20 million of income for the three months ended March 31, 2008, compared to $8 million of income for the three months ended March 31, 2007. Approximately $6 million of the increase was associated with higher interest income due to larger cash balances in 2008. In addition, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets.
DHI’s other items, net, totaled $20 million of net income for the three months ended March 31, 2008, compared to $4 million of income for the three months ended March 31, 2007. Approximately $7 million of the increase was primarily associated with higher interest income due to larger cash balances in 2008. In addition, during the first quarter 2008, we recognized income of $6 million related to insurance proceeds received in excess of the book value of damaged assets.
Interest Expense
Dynegy’s and DHI’s interest expense totaled $109 million for the three months ended March 31, 2008, compared to $67 million for the three months ended March 31, 2007. The increase was primarily attributable to the issuance of the $1.65 billion of Senior Unsecured Notes on May 24, 2007, which replaced the project debt assumed in connection with the Merger, and secondarily to the associated growth in the size and utilization of our Fifth Amended and Restated Credit Facility.
Income Tax Benefit (Expense)
Dynegy reported an income tax benefit from continuing operations of $96 million for the three months ended March 31, 2008, compared to an income tax expense from continuing operations of $6 million for the three months ended March 31, 2007. The 2008 effective tax rate was 39 percent, compared to 27 percent in 2007.
DHI reported an income tax benefit from continuing operations of $91 million for the three months ended March 31, 2008, compared to an income tax expense of $11 million from continuing operations for the three months ended March 31, 2007. The 2008 effective tax rate was 37 percent, compared to 31 percent in 2007.
In general, differences between these effective rates and the statutory rate of 35 percent resulted primarily from the effect of state income taxes in the taxing jurisdictions in which our assets operate.
Discontinued Operations
Loss From Discontinued Operations Before Taxes
During the three months ended March 31, 2008, our pre-tax loss from discontinued operations was $1 million, which consisted of a $1 million loss on the sale of the Calcasieu power generation facility. During the three months ended March 31, 2007, our pre-tax loss from discontinued operations was $3 million, which consisted of losses of $3 million from the operation of the CoGen Lyondell power generation facility.
Income Tax Benefit From Discontinued Operations
We recorded an income tax benefit from discontinued operations of $1million and $1 million, respectively, during the three months ended March 31, 2008 and 2007. The effective rates for the three months ended March 31, 2008 and 2007 were 100 percent and 33 percent, respectively. FIN No. 18, “Accounting for Income Taxes in Interim Periods an interpretation of APB Opinion No. 28” requires a detailed methodology of allocating income taxes between continuing and discontinued operations. This methodology often results in an effective rate for discontinued operations significantly different from the statutory rate of 35 percent.
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Outlook
We expect that our future financial results will continue to reflect sensitivity to fuel and commodity prices, market structure and prices for electric energy, ancillary services and capacity, transportation and transmission logistics, weather conditions and IMA. Our commercial team actively manages commodity price risk associated with our unsold power production by trading in the forward markets that are correlated with our assets. We also participate in various regional auctions and bilateral opportunities. Our regional commercial strategies are particularly driven by the types of units that we have within a given region and the operating characteristics of those units.
Our fleet includes a diverse mixture of assets with various fuel, dispatch and merit order characteristics within each of our three regions. Our forward sales decisions are based on market fundamentals relative to each regional fleet profile. Our portfolio of sales agreements include short-term, medium-term and long-term contracts that range to five years and longer. These long-term contracts are generally intended to run to term and may include tolls or long-term power sale agreements related to our development projects. These contracts include terms designed to mitigate risks related to commodity prices and operation of the facilities such as a pass through of fuel costs and limited penalties for unavailability. Medium-term contracts, which range from two to five years, include structured deals and financial products, including options, and are intended to capture value from mid-term price trends but still provide some exposure to expected longer term upward price trends. We seek to commercialize the remainder of our fleet’s output via short-term sales, financial products, including options, spot sales and contract sales, all with a duration of less than two years. We actively manage these positions, which are primarily associated with our baseload facilities, in an attempt to capitalize on commodity price volatility and other value capture opportunities. As a result, our fleet-wide forward sales profile is fluid and subject to change over time.
We entered the year with a substantial portion of the output from our fleet of power generation facilities contracted for 2008. We commercialized nearly all of our output for the remainder of 2008 as we moved forward through the first quarter of 2008 and prices increased. As we look forward to 2009 and beyond, we are actively transacting in 2009 positions and expect to enter 2009 with a substantial portion of the output of our fleet contracted. Based on specific market conditions, at any point in time we may be above or below this level since we actively manage our near-term market positions of less than two years.
To the extent that we choose not to enter into forward sales, the gross margin from our assets is a function of price movements in the coal, natural gas, fuel oil, electric energy and capacity markets.
The following summarizes unique business issues impacting our individual regions’ outlook.
GEN-MW. Our Midwest consent decree requires substantial emission reductions from our Illinois coal-fired power plants and the completion of several supplemental environmental projects in the Midwest. We have achieved all emission reductions scheduled to date under the Consent Decree and are developing plans to install additional emission control equipment to meet future Consent Decree emission limits. We expect our costs associated with the Midwest consent decree projects, which we expect to incur through 2012, to be approximately $960 million, which includes approximately $134 million spent to date. This estimate includes a number of assumptions and uncertainties beyond our control, including an assumption that labor and material costs will increase at four percent per year over the remaining project term.
Our Midwest coal requirements are 100 percent contracted through 2010. For 2008, the prices associated with these contracts are fixed. The new prices that will apply to the 25 percent of our post-2008 requirements that are currently unpriced will become effective January 1, 2009. However, we expect that any price changes will be consistent with DMG’s historical price trend over the past several years.
PJM recently implemented a forward capacity auction, the Reliability Pricing Model. The auction has resulted in a dramatic increase in the value of capacity in not only PJM, but in the neighboring MISO as well. The increase in prices indicates a projected tightening of the supply/demand balance in the near future. More immediately, we benefited from participating in the auction process, resulting in sales of capacity for the following planning years:
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| | | | |
| Planning Year | | Net Capacity | |
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| | | (in MWs) | |
| 2008-2009 | | 1,300 | |
| 2009-2010 | | 2,650 | |
| 2010-2011 | | 2,750 | |
The MISO has delayed implementation of its Ancillary Services Market until September 2008. Upon implementation MISO will administer the Ancillary Services Market through which load-serving entities will procure regulation and contingency reserves.
GEN-WE. Our Arizona facilities recently won competitive solicitations for 10 year term tolling agreements by local utilities beginning with deliveries in 2008 and 2010.
GEN-NE. The majority of our coal supply requirements for 2008 are contracted at a fixed price. We procure certain quantities of coal from various South American suppliers, where political conditions could potentially result in interruptions of commodity exports. However, we continue to maintain sufficient coal and oil inventories and contractual commitments intended to provide us with a stable fuel supply and are considering options to further mitigate cost and supply risks for near and long-term coal supplies.
In New England, the ISO-NE is in the process of restructuring its capacity market and will be transitioning to a forward capacity market in 2010. During the transition from the pre-existing capacity markets in ISO-NE to the forward capacity market, all listed Installed Capacity (“ICAP”) resources will receive monthly capacity payments, adjusted for each Power Year. The transitional payments for capacity commenced in December 2006, with a price of 3.05/KW-month, and gradually rise to $4.10/KW-month through June 1, 2010, when the forward capacity market will be fully effective. The first auction for the 2010 Power Year was held in February 2008, and capacity prices cleared at $4.50/KW-month. The second auction for the 2011 Power Year is planned for the fall of 2008.
Recently, we arrived at a settlement with one of the local taxing jurisdictions in connection with the assessed value of our Roseton and Danskammer generating facilities. While the amount of actual tax savings resulting from the reduction in the assessed value of these facilities will depend on future budgets of the various taxing jurisdictions, the projected savings in property taxes for the period 2008-2012 is approximately $55 million. We will also receive a refund of $3 million for prior years’ property tax payments. We continue to work with local authorities to consider additional settlements relating to taxes paid in prior years.
Regulatory Matters
Climate Change and Greenhouse Gases. The federal government, and many states where we have generation facilities, are considering or implementing regulatory programs intended to reduce emissions of CO2 as a means of addressing climate change issues. The adoption of regulatory programs mandating a substantial reduction in C02 emissions may have a significant impact on us and others in the power generating industry. However, at this time, we are unable to provide an accurate assessment of the extent of the impact that CO2 emission reduction programs will have on us. Any CO2 emission limits that are implemented, whether by the federal or state governments, could have the effect of altering the manner in which generating facilities are dispatched. The extent to which the costs of meeting mandated emission reductions would be borne by power generators, or the ultimate users of electricity, is not known. The specific requirements and timing of any future federal program to regulate CO2 emissions cannot be confidently predicted at this time; however, various states where we have generating facilities have proposed or are in the process of considering or developing regulatory programs to limit CO2 emissions.
GEN-WE. Our assets in California will be subject to various state initiatives. As previously disclosed, we continue to be subject to the California Global Warming Solutions Act, effective January 1, 2007, which requires development of a greenhouse gas control program that will reduce the state’s greenhouse gas emissions to their 1990 levels by 2020. Regulations to achieve required emission reductions are to be adopted by January 2011.
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The California State Water Resources Control Board has issued proposed regulations that would require all power plants utilizing sea water for once-through cooling to reduce their intake flow and intake velocity to a level commensurate with that which can be attained by a closed-cycle cooling system. If adopted as proposed, it is likely that South Bay, Morro Bay and Moss Landing Units 6 & 7 would be required to retrofit with a closed-cycle cooling system by 2015 and the Moss Landing Units 1 & 2 by 2018.
GEN-NE. Our assets in New York, Connecticut and Maine are expected to become subject to a state-driven greenhouse gas program known as the Regional Greenhouse Gas Initiative (“RGGI”) as soon as 2009. The participating RGGI states have developed a model rule for regulating greenhouse gas using a cap-and-trade program to reduce carbon emissions by at least 10 percent of current emission levels by the year 2018.
The RGGI rules proposed in Maine and New York would implement CO2 cap-and-trade programs, capping total authorized CO2 emissions from affected power generators beginning in 2009. The proposed rules would require that each affected power generator hold CO2 emission allowances equal to its annual CO2 emissions. Beginning in 2015, the CO2 emission caps and available allowances would be reduced each year until 2018. Compliance with the allowance requirement under a cap-and-trade program could be achieved by reducing emissions, purchasing allowances or securing offset allowances from an approved offset project. Allowances would be distributed to power generators through state auctions. Although the rules governing the procedures and structure of the auctions are still being developed, the intent is to conduct the first auction of CO2 allowances in 2008.
The State of Connecticut also enacted legislation in June 2007 that mandates a cap and trade program for CO2, including a requirement that affected generators purchase the carbon credits needed to operate their facilities through an auction process. The rules governing the procedures and structure of the Connecticut auction process are still being developed.
Please read Note 9—Commitments and Contingencies—Danskammer State Pollutant Discharge Elimination System Permit and —Commitments and Contingencies—Roseton State Pollutant Discharge Elimination System Permit, respectively, for further discussion.
Cash Flow Disclosures
Operating Cash Flow
Dynegy. Dynegy’s cash flow provided by operations totaled $146 million for the three months ended March 31, 2008. During the three months ended March 31, 2008, our power generation business provided positive cash flow from operations of $234 million from the operation of our power generation facilities. Other includes a use of approximately $88 million in cash primarily due to interest payments to service debt, general and administrative expenses and a legal settlement payment previously reserved, partially offset by interest income.
Dynegy’s cash flow provided by operations totaled $44 million for the three months ended March 31, 2007. During the quarter, our power generation business provided positive cash flow from operations of $140 million due to positive earnings for the period. Other includes a net use of approximately $96 million in cash primarily due to interest payments to service debt, general and administrative expenses and cash payments associated with our former customer risk management business.
DHI. DHI’s cash flow provided by operations totaled $146 million for the three months ended March 31, 2008. During the three months ended March 31, 2008, our power generation business provided positive cash flow from operations of $234 million from the operation of our power generation facilities. Other includes a use of approximately $88 million in cash primarily due to interest payments to service debt, general and administrative expense and a legal settlement payment previously reserved, partially offset by interest income.
DHI’s cash flow provided by operations totaled $43 million for the three months ended March 31, 2007. During the quarter, our power generation business provided positive cash flow from operations of $140 million due to positive earnings for the period. Other includes a net use of approximately $97 million in cash primarily due to interest payments to service debt, general and administrative expenses and cash payments associated with our former customer risk management business.
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Capital Expenditures and Investing Activities
Dynegy. Dynegy’s cash used in investing activities during the three months ended March 31, 2008 totaled $95 million. Capital spending of $131 million was primarily comprised of $115 million, $3 million and $10 million for our GEN-MW, GEN-WE and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $54 million associated with the construction of the Plum Point facility, which is provided by non-recourse project financing. The remaining capital spending for the GEN-MW segment primarily related to maintenance and environmental projects, while spending in the GEN-NE and GEN-WE segments primarily related to maintenance projects. In addition, there was approximately $3 million of capital expenditures in Other. Dynegy also made $6 million in contributions to DLS Power Holdings during the three months ended March 31, 2008. Additionally, there was a $25 million cash outflow due to changes in restricted cash balances. These cash outflows were partially offset by $56 million of proceeds, net of transaction costs, from the sale of the Calcasieu power generating facility, $6 million of insurance proceeds and $4 million of proceeds from the liquidation of an investment.
Dynegy’s cash used in investing activities during the three months ended March 31, 2007 totaled $26 million. Capital spending of $34 million was primarily comprised of $23 million, $5 million and $3 million in the GEN-MW, GEN-WE and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $3 million of capital expenditures in Other related to corporate information technology projects. Cash outflows associated with capital spending were partly offset by a $9 million decrease in the Independence restricted cash balance.
DHI. DHI’s cash used in investing activities during the three months ended March 31, 2008 totaled $92 million. Capital spending of $131 million was primarily comprised of $115 million, $3 million and $10 million for our GEN-MW, GEN-WE and GEN-NE segments, respectively. Capital spending for the GEN-MW segment includes $54 million associated with the construction of the Plum Point facility, which is provided by non-recourse project financing. The remaining capital spending for the GEN-MW segment primarily related to maintenance and environmental projects, while spending in the GEN-NE and GEN-WE segments primarily related to maintenance projects. In addition, there was approximately $3 million of capital expenditures in Other. Additionally, there was a $25 million cash outflow due to changes in restricted cash balances. These cash outflows were partially offset by $56 million of proceeds, net of transaction costs, from the sale of the Calcasieu power generating facility, $1 million of affiliate transactions and $6 million of insurance proceeds.
DHI’s cash used in investing activities during the three months ended March 31, 2007 totaled $33 million. Capital spending of $34 million was primarily comprised of $23 million, $5 million and $3 million in the GEN-MW, GEN-WE and GEN-NE segments, respectively. The capital spending for each segment primarily related to maintenance and environmental capital projects. In addition, there was approximately $3 million of capital expenditures in Other related to corporate information technology projects. Cash outflows associated with capital spending were partly offset by a $9 million decrease in the Independence restricted cash balance.
Financing Activities
Dynegy. Dynegy’s cash provided by financing activities during the three months ended March 31, 2008 totaled $50 million, which primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.
Dynegy’s cash used in financing activities during the three months ended March 31, 2007 totaled $20 million, resulting primarily from a principal payment on the Sithe Energies debt.
DHI. DHI’s cash provided by financing activities during the three months ended March 31, 2008 totaled $50 million, which primarily related to proceeds from long-term borrowings under the Plum Point Credit Agreement Facility.
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DHI’s cash used in financing activities during the three months ended March 31, 2007 totaled $70 million, resulting primarily from a $50 million dividend payment to Dynegy and a $19 million principal payment on the Sithe Energies debt.
RISK-MANAGEMENT DISCLOSURES
The following table provides a reconciliation of the risk-management data on the unaudited condensed consolidated balance sheets:
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| | As of and for the
Three Months
Ended March 31,
2008 | |
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| | (in millions) | |
Balance Sheet Risk-Management Accounts | | | | |
Fair value of portfolio at January 1, 2008 | | $ | (100 | ) |
Risk-management losses recognized through the income statement in the period, net | | | (271 | ) |
Cash paid related to risk-management contracts settled in the period, net | | | 1 | |
Changes in fair value as a result of a change in valuation technique (1) | | | — | |
Non-cash adjustments and other (2) | | | (33 | ) |
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Fair value of portfolio at March 31, 2008 | | $ | (403 | ) |
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(1) | Our modeling methodology has been consistently applied. |
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(2) | This amount consists of changes in value associated with fair value and cash flow hedges on debt. |
The net risk management liability of $403 million is the aggregate of the following line items on our unaudited condensed 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. During the period from December 31, 2007 to March 31, 2008, our Current Assets—Assets from risk-management activities and Current Liabilities—Liabilities from risk-management activities increased by $1.4 billion and $1.6 billion, respectively. This increase was primarily a result of increased volumes of purchases and sales of commodities via financial instruments. These amounts are reflected gross on our condensed consolidated balance sheets, as we do not offset fair value amounts recognized for derivative instruments executed with the same counterparties under a master netting agreement. However, a substantial portion of the financial instruments are with the same counterparty, resulting in a significantly smaller increase in our net risk-management liability, as denoted above. For further information regarding our counterparty credit exposure associated with risk-management accounts, please see Item 3. Quantitative and Qualitative Disclosures about Market Risk—Credit Risk.
Risk-Management Asset and Liability Disclosures. The following tables depict the mark-to-market value and cash flow components of our net risk-management liabilities at March 31, 2008 and December 31, 2007. As opportunities arise to monetize positions that we believe will result in an economic benefit to us, we may receive or pay cash in periods other than those depicted below:
Mark-to-Market Value of Net Risk-Management Liabilities (1)
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| | Total | | 2008 (2) | | 2009 | | 2010 | | 2011 | | 2012 | | Thereafter | |
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| | (in millions) | |
March 31, 2008 | | $ | (335 | ) | $ | (242 | ) | $ | (85 | ) | $ | (15 | ) | $ | 2 | | $ | 1 | | $ | 4 | |
December 31, 2007 | | | (66 | ) | | (30 | ) | | (29 | ) | | (12 | ) | | 1 | | | 1 | | | 3 | |
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Increase (decrease) (3) | | $ | (269 | ) | $ | (212 | ) | $ | (56 | ) | $ | (3 | ) | $ | 1 | | $ | — | | $ | 1 | |
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(1) | The table reflects the fair value of our net risk-management liability position, which considers time value, credit, price and other reserves necessary to determine fair value. These amounts exclude the fair value |
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| associated with certain derivative instruments designated as hedges. The net risk-management liabilities at March 31, 2008 of $403 million on the unaudited condensed consolidated balance sheets include the $335 million herein as well as hedging instruments. Cash flows have been segregated between periods based on the delivery date required in the individual contracts. |
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(2) | Amounts represent April 1 to December 31, 2008 values in the March 31, 2008 row and January 1 to December 31, 2008 values in the December 31, 2007 row. |
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(3) | The increase in the net risk management liability is due to an increase in the volume of outstanding positions during the three months ended March 31, 2008 as well as a significant increase in the prices associated with these positions. |
Cash Flow Components of Net Risk-Management Liabilities
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| | Three Months
Ended
March 31,
2008 | | Nine Months
Ended
December 31,
2008 | | Total
2008 | | 2009 | | 2010 | | 2011 | | 2012 | | Thereafter | |
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| | (in millions) | |
March 31, 2008 (1) | | $ | (6 | ) | $ | (225 | ) | $ | (231 | ) | $ | (80 | ) | $ | (14 | ) | $ | 1 | | $ | 1 | | $ | 5 | |
December 31, 2007 | | | | | | | | | (28 | ) | | (27 | ) | | (12 | ) | | 2 | | | 1 | | | 5 | |
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Increase (decrease) | | | | | | | | $ | (203 | ) | $ | (53 | ) | $ | (2 | ) | $ | (1 | ) | $ | — | | $ | — | |
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(1) | The cash flow values for 2008 reflect realized cash flows for the three months ended March 31, 2008 and anticipated undiscounted cash inflows and outflows by contract based on the tenor of individual contract position for the remaining periods. These anticipated undiscounted cash flows have not been adjusted for counterparty credit or other reserves. These amounts exclude the cash flows associated with certain derivative instruments designated as hedges. |
The following table provides an assessment of net contract values by year as of March 31, 2008, based on our valuation methodology:
Net Fair Value of Risk-Management Portfolio
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| | Total | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | Thereafter | |
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| | (in millions) | |
Market quotations (1) | | $ | (344 | ) | $ | (278 | ) | $ | (68 | ) | $ | (5 | ) | $ | 2 | | $ | 1 | | $ | 4 | |
Prices based on models | | | (59 | ) | | (32 | ) | | (17 | ) | | (10 | ) | | — | | | — | | | — | |
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Total (2) | | $ | (403 | ) | $ | (310 | ) | $ | (85 | ) | $ | (15 | ) | $ | 2 | | $ | 1 | | $ | 4 | |
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(1) | Prices obtained from actively traded, liquid markets for commodities other than natural gas positions. All natural gas positions for all periods are contained in this line based on available market quotations. |
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(2) | The market quotations and prices based on models categorization differs from the SFAS No. 157 categories of Level 1, Level 2 and Level 3 due to the application of the different methodologies. Please see Note 4—Risk Management Activities, Derivatives and Financial Instruments—Fair Value Measurements for further discussion. |
UNCERTAINTY OF FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-Q/A includes statements reflecting assumptions, expectations, projections, intentions or beliefs about future events that are intended as “forward-looking statements” by both Dynegy and DHI. All statements included or incorporated by reference in this quarterly report, other than statements of historical fact, that address activities, events or developments that we or our management expect, believe or anticipate will or may occur in the future are forward-looking statements. These statements represent our reasonable judgment on the future based on various factors and using numerous assumptions and are subject to known and unknown risks, uncertainties and other factors that could cause our actual results and financial position to differ materially from those contemplated
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by the statements. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as “anticipate”, “estimate”, “project”, “forecast”, “plan”, “may”, “will”, “should”, “expect” and other words of similar meaning. In particular, these include, but are not limited to, statements relating to the following:
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| • | beliefs about commodity pricing and generation volumes; |
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| • | sufficiency of and access to coal, fuel oil and natural gas inventories and transportation; |
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| • | beliefs and assumptions about market competition, fuel supply, generation capacity and regional supply and demand characteristics of the wholesale power generation market; |
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| • | strategies to capture opportunities presented by rising commodity prices and strategies to manage our exposure to energy price volatility; |
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| • | beliefs and assumptions about weather, economic conditions and the demand for electricity; |
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| • | expectations regarding environmental matters, including costs of compliance, availability and adequacy of emission credits, and the impact of ongoing proceedings and potential regulations, including those relating to climate change; |
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| • | projected operating or financial results, including anticipated cash flows from operations, revenues and profitability; |
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| • | strategies to address our substantial leverage or to access the capital markets; |
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| • | beliefs and assumptions relating to liquidity; |
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| • | beliefs and expectations regarding financing, development and timing of any and all joint venture projects; |
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| • | anticipated benefits of diversifying our operations; |
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| • | expectations regarding capital expenditures, interest expense and other payments; |
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| • | our focus on safety and our ability to efficiently operate our assets so as to maximize our revenue generating opportunities and operating margins; |
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| • | beliefs about the outcome of legal, regulatory, administrative and legislative matters; |
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| • | expectations and estimates regarding the Midwest consent decree and the associated costs; and |
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| • | efforts to position our power generation business for future growth and pursuing and executing acquisition, disposition or combination opportunities. |
Any or all of our forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks, uncertainties and other factors, many of which are beyond our control, including those set forth under Part II–Other Information, Item 1A-Risk Factors.
RECENT ACCOUNTING PRONOUNCEMENTS
See Note 1—Accounting Policies to the unaudited condensed consolidated financial statements for a discussion of recently issued accounting pronouncements affecting us.
CRITICAL ACCOUNTING POLICIES
Please read “Critical Accounting Policies” of Dynegy’s and DHI’s Form 10-K for a complete description of our critical accounting policies, with respect to which there have been no other material changes since the filing of such Form 10-K.
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Item 4—CONTROLS AND PROCEDURES—DYNEGY INC. AND DYNEGY HOLDINGS INC.
Evaluation of Disclosure Controls and Procedures
As of the end of the period covered by this report, an evaluation was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer, of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). This evaluation included consideration of the various processes carried out under the direction of Dynegy’s disclosure committee in an effort to ensure that information required to be disclosed in the consolidated enterprise’s SEC reports is recorded, processed, summarized and reported within the time periods specified by the SEC. This evaluation also considered the work completed as of the end of the first quarter 2008 relating to Dynegy’s and DHI’s compliance with Section 404 of the Sarbanes-Oxley Act of 2002.
In connection with the restatement of our unaudited condensed consolidated financial statements for the quarter ended March 31, 2008 to correct a misstatement of revenues that was offset in cost of sales, we reevaluated our disclosure controls and procedures. In connection with the preparation of this Form 10-Q/A, an evaluation of the effectiveness of the design and operation of the consolidated enterprise’s disclosure controls and procedures was carried out under the supervision and with the participation of Dynegy’s and DHI’s management, including their Chief Executive Officer and their Chief Financial Officer. In making this evaluation, our management considered the material weakness below. Based on this evaluation, Dynegy’s and DHI’s CEO and CFO concluded that Dynegy’s and DHI’s disclosure controls and procedures were not effective as of March 31, 2008.
Notwithstanding the material weakness that existed at March 31, 2008, management believes, based on its knowledge, that the financial statements and other financial information included in this report, fairly present, in all material respects in accordance with GAAP, our financial condition, results of operations and cash flows as of and for the periods presented in this report.
Material Weakness Related to Revenues and Cost of Sales
Subsequent to the filing of our Quarterly Report on Form 10-Q for the period ended March 31, 2008, we identified a misstatement of revenues that was offset in cost of sales for the three months ended March 31, 2008. Accordingly, in this Form 10-Q/A, we have restated our unaudited condensed consolidated financial statements. For further information, please see the Introductory Note in the accompanying unaudited condensed consolidated financial statements.
As a result of this misstatement, we have concluded that we did not maintain effective controls as of March 31, 2008 over the accuracy of our revenues and cost of sales amounts. Our processes, procedures and controls related to the calculation and analysis of the presentation of revenues and cost of sales related to energy trading
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activities on a net basis were not effective to ensure that the revenues and cost of sales amounts were accurately reflected in the financial statements at March 31, 2008. This control deficiency resulted in the restatement of our March 31, 2008 financial statements by a material amount. Therefore, we concluded that this control deficiency, as of March 31, 2008, constitutes a material weakness.
In order to remediate this material weakness, we have implemented the following steps: (i) further formalized and documented the change management procedures surrounding the quarterly revenue netting calculation; (ii) expanded the management review of the calculation; and (iii) formalized and documented additional analysis to be performed on our revenues and cost of sales amounts.
Changes in Internal Controls Over Financial Reporting
Other than as noted above in this Item 4, there were no changes in the consolidated enterprise’s internal control over financial reporting that have materially affected or are reasonably likely to materially affect the consolidated enterprise’s internal control over financial reporting during the first quarter 2008.
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DYNEGY INC. and DYNEGY HOLDINGS INC.
PART II. OTHER INFORMATION
Item 6—EXHIBITS—DYNEGY INC. AND DYNEGY HOLDINGS INC.
The following documents are included as exhibits to this Form 10-Q/A:
| | | |
| Exhibit
Number | | Description |
|
| |
|
| 10.1 | | Dynegy Inc. Executive Severance Pay Plan, as amended and restated, effective January 1, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443). |
| | | |
| 10.2 | | Dynegy Inc. Executive Change in Control Severance Pay Plan effective April 3, 2008 (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K of Dynegy Inc. filed on April 8, 2008, File No. 001-33443). |
| | | |
| *10.3 | | Dynegy Inc. Change in Control Severance Pay Plan effective April 3, 2008. |
| | | |
| 10.4 | | Dynegy Excise Tax Reimbursement Policy, effective January 1, 2008 (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K of Dynegy Inc. filed on January 4, 2008, File No. 001-33443). |
| | | |
| *10.5 | | Form of Non-Qualified Stock Option Award Agreement Between Dynegy Inc., all of its affiliates and Bruce A. Williamson. |
| | | |
| *10.6 | | Form of Non-Qualified Stock Option Award Agreement Between Dynegy Inc., all of its affiliates and Jason Hochberg. |
| | | |
| *10.7 | | Form of Restricted Stock Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson. |
| | | |
| *10.8 | | Form of Restricted Stock Award Agreement between Dynegy Inc., all of its affiliates and Jason Hochberg. |
| | | |
| *10.9 | | Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Bruce A. Williamson. |
| | | |
| *10.10 | | Form of Performance Award Agreement between Dynegy Inc., all of its affiliates and Jason Hochberg. |
| | | |
| *10.11 | | Form of Non-Qualified Stock Option Award Agreement. |
| | | |
| *10.12 | | Form of Restricted Stock Award Agreement (Managing Director and Above). |
| | | |
| *10.13 | | Form of Restricted Stock Award Agreement (Directors and Below). |
| | | |
| *10.14 | | Form of Performance Award Agreement. |
| | | |
| *10.15 | | Twelfth Amendment to the Dynegy Inc. 401(K) Savings Plan. |
| | | |
| *10.16 | | Thirteenth Amendment to the Dynegy Inc. 401(K) Savings Plan. |
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| | | |
| Exhibit
Number | | Description |
|
| |
|
| *10.17 | | Fourteenth Amendment to the Dynegy Inc. 401(K) Savings Plan. |
| | | |
| *10.18 | | Fifteenth Amendment to the Dynegy Inc. 401(K) Savings Plan |
| | | |
| *10.19 | | Sixth Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan |
| | | |
| *10.20 | | Seventh Amendment to the Dynegy Northeast Generation, Inc. Savings Incentive Plan |
| | | |
| *10.21 | | Ninth Amendment to the Dynegy Midwest Generation, Inc. 401(K) Savings Plan |
| | | |
| *10.22 | | Ninth Amendment to the Dynegy Midwest Generation, Inc. 401(K) Savings Plan for Employees Covered Under a Collective Bargaining Agreement |
| | | |
| *10.23 | | Ninth Amendment to the Extant, Inc. 401(K) Plan |
| | | |
| *10.24 | | Tenth Amendment to the Extant, Inc. 401(K) Plan |
| | | |
| *10.25 | | Tenth Amendment to the Dynegy Inc. Retirement Plan |
| | | |
| *10.26 | | Eleventh Amendment to the Dynegy Inc. Retirement Plan |
| | | |
| *10.27 | | Twelfth Amendment to the Dynegy Inc. Retirement Plan |
| | | |
| *10.28 | | Thirteenth Amendment to the Dynegy Inc. Retirement Plan |
| | | |
| *10.29 | | Fourteenth Amendment to the Dynegy Inc. Retirement Plan |
| | | |
| *10.30 | | Seventh Amendment to the Dynegy Midwest Generation, Inc. Retirement Income Plan for Employees Covered Under a Collective Bargaining Agreement |
| | | |
| *10.31 | | Eighth Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan |
| | | |
| *10.32 | | Ninth Amendment to the Dynegy Northeast Generation, Inc. Retirement Income Plan |
| | | |
| *10.33 | | Amended and Restated Dynegy Inc. Severance Pay Plan |
| | | |
| **31.1 | | Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | |
| **31.1(a) | | Chief Executive Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | |
| **31.2 | | Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
| | | |
| **31.2(a) | | Chief Financial Officer Certification Pursuant to Rule 13a-14(a) and 15d-14(a), As Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |
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| | |
| * | Previously filed with the Quarterly Report on Form 10-Q for the period ended March 31, 2008 filed on May 8, 2008. |
| | |
| ** | Filed herewith. |
| | |
| † | Pursuant to Securities and Exchange Commission Release No. 33-8238, this certification will be treated as “accompanying” this report and not “filed” as part of such report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or the Exchange Act, or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act. |
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DYNEGY INC. and DYNEGY HOLDINGS INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
| | |
| | DYNEGY INC. |
| | |
Date: July 25, 2008 | By: | /s/ HOLLI C. NICHOLS |
| |
|
| | Holli C. Nichols |
| | Executive Vice President and Chief Financial Officer
(Duly Authorized Officer and Principal Financial Officer) |
| | |
| | DYNEGY HOLDINGS INC. |
| | |
Date: July 25, 2008 | By: | /s/ HOLLI C. NICHOLS |
| |
|
| | Holli C. Nichols |
| | Executive Vice President and Chief Financial Officer
(Duly Authorized Officer and Principal Financial Officer) |
60
