CMS Energy - 10-Q quarterly report FY

 

Indicate by check mark whether the Registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.

CMS Energy Corporation:       Large accelerated filer þ       Accelerated filer o       Non-Accelerated filer o

Consumers Energy Company:       Large accelerated filer o       Accelerated filer o       Non-Accelerated filer þ

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
CMS Energy Corporation:       Yes o No þ       Consumers Energy Company: Yes o No þ

Indicate the number of shares outstanding of each of the issuer’s classes of common stock at July 31, 2007:CMS Energy Corporation:

 

 

This combined Form 10-Q is separately filed by CMS Energy Corporation and Consumers Energy Company. Information contained herein relating to each individual registrant is filed by such registrant on its own behalf. Accordingly, except for its subsidiaries, Consumers Energy Company makes no representation as to information relating to any other companies affiliated with CMS Energy Corporation.

Certain terms used in the text and financial statements are defined below

This MD&A is a consolidated report of CMS Energy and Consumers. The terms “we” and “our” as used in this report refer to CMS Energy and its subsidiaries as a consolidated entity, except where it is clear that such term means only CMS Energy. This MD&A has been prepared in accordance with the instructions to Form 10-Q and Item 303 of Regulation S-K. This MD&A should be read in conjunction with the MD&A contained in CMS Energy’s Form 10-K for the year ended December 31, 2006 and the Form 8-K filed June 4, 2007 amending CMS Energy’s 2006 financial statements to reflect certain discontinued operations resulting from recent asset sales.

This Form 10-Q and other written and oral statements that we make contain forward-looking statements as defined in Rule 3b-6 under the Securities Exchange Act of 1934, as amended, Rule 175 under the Securities Act of 1933, as amended, and relevant legal decisions. Our intention with the use of such words as “may,” “could,” “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict and (or) control:

For additional information regarding these and other uncertainties, see the “Outlook” section included in this MD&A, Note 3, Contingencies, and Part II, Item 1A. Risk Factors.

CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving Michigan’s Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged primarily in domestic independent power production. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises.

We earn our revenue and generate cash from operations by providing electric and natural gas utility services, electric power generation, and gas distribution, transmission, and storage. Our businesses are affected primarily by:

During the past several years, our business strategy has involved improving our consolidated balance sheet and maintaining focus on our core strength: utility operations and service. As an indication of our commitment to our utility business, we have invested $650 million in Consumers during the first half of 2007.

We expect to complete the sale of our international Enterprises assets by the end of 2007. Proceeds from asset sales are used to retire debt and to invest in our utility business. Asset sales completed in 2007 include:

We have also entered into an agreement to sell our investment in Jamaica to AEI for $14 million, which we expect to close by the end of 2007.

We also made important progress at Consumers to reduce business risk and to meet the future needs of our customers. We sold Palisades to Entergy in April 2007 for $380 million. The final purchase price is subject to various closing adjustments resulting in us receiving $364 million as of June 30, 2007. The sale resulted in an immediate improvement in our cash flow, a reduction in our nuclear operating and decommissioning risk, and an improvement in our financial flexibility to support other utility investments.

After September 15, 2007, we expect to claim relief under the regulatory-out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. If we are successful in exercising the regulatory-out provision, the MCV Partnership may, under certain circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA, which could affect our need to build or purchase additional generating capacity.

We introduced our Balanced Energy Initiative, a comprehensive plan to meet customer energy needs over the next 20 years, in May 2007. The plan, as filed with the MPSC, is designed to meet the growing customer demand for electricity with energy efficiency, demand management, expanding the use of renewable energy, and developing new power plants to complement existing generating sources.

In May 2007, we entered an agreement to buy a 946 MW natural gas-fired power plant located in Zeeland, Michigan from Broadway Gen Funding LLC, an affiliate of LS Power Group, for $517 million. The purchase is subject to approvals from the MPSC and other regulatory bodies and is expected to close in early 2008.

We took an important step in our business plan in January 2007 by reinstating a quarterly dividend of $0.05 per share on our common stock, after a four-year suspension. We paid $11 million in common stock dividends in February 2007 and $11 million in common stock dividends in May 2007. We also took steps toward resolving a long-outstanding litigation issue. In January 2007, we reached a preliminary agreement to settle two class action lawsuits related to round-trip trading by CMS MST. We believe that eliminating this business uncertainty is in the best interests of our shareholders.

We are also in the process of restructuring our investment in DIG. This restructuring may involve renegotiation or possible buyout of the DIG power sales contracts as well as other measures. These options may require material cash payments. We believe that resolving the issues associated with the unfavorable supply contracts will allow us to maximize future benefits from our DIG investment.

In the future, we will focus our strategy on:

As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been hampered by negative developments in Michigan’s automotive industry and limited growth in the non-automotive sectors of the state’s economy. The return of ROA customer load has offset some of these negative effects. At June 30, 2007, alternative electric suppliers were providing 302 MW of generation service to ROA customers. This is 3 percent of our total distribution load and represents a decrease of 3 percent of ROA load compared to June 30, 2006.

For the three months ended June 30, 2007, our net income was $33 million, a $39 million reduction from our 2006 second quarter net income. Compared with the second quarter of 2006, net income from our gas and electric utility segments increased slightly, reflecting benefits from an MPSC gas rate order and favorable weather impacts. At our Enterprises and Corporate segments, the net positive impact of our asset sales was more than offset by the absence of 2006 tax benefits and increased legal costs.

Specific changes to net income available to common stockholders for the three months ended June 30, 2007 versus 2006 are:

For the six months ended June 30, 2007, our net loss was $182 million, a $227 million reduction in net income from our first half of 2006. Compared with the first six months of 2006, net income from our gas and electric utility segments increased a combined $52 million, reflecting benefits from an MPSC gas rate order and favorable weather impacts. The positive utility results were more than offset by currency translation adjustments on asset sales, the absence of 2006 tax benefits and increased legal costs.

Specific changes to net income (loss) available to common stockholders for the six months ended June 30, 2007 versus 2006 are:

Electric deliveries: For the three months ended June 30, 2007, electric delivery revenues increased $16 million versus 2006, as deliveries to end-use customers were 9.5 billion kWh, an increase of 0.3 billion kWh or 3 percent versus 2006. The increase in electric deliveries for the three months ended June 30, 2007 is primarily due to favorable weather, which resulted in an increase in electric delivery revenue of $13 million. For the six months ended June 30, 2007, electric delivery revenues increased $40 million versus 2006, as deliveries to end-use customers were 19.0 billion kWh, an increase of 0.5 billion kWh or 3 percent versus 2006. The increase in electric deliveries for six months ended June 30, 2007 is primarily due to favorable weather, which resulted in an increase in electric delivery revenue of $30 million.

In the first quarter of 2006, we started collecting a surcharge that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This surcharge increased electric delivery revenue by $3 million for the three months ended June 30, 2007 and $8 million for the six months ended June 30, 2007 versus the same periods in 2006. The increase was primarily due to higher surcharge factors in 2007 versus the same period in 2006.

The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At June 30, 2007, alternative electric suppliers were providing 302 MW of generation service to ROA customers. This amount represents a decrease of 3 percent compared to June 30, 2006. The return of former ROA customers to full-service rates increased electric delivery revenue less than $1 million for the three months ended June 30, 2007 and $2 million for the six months ended June 30, 2007 versus the same periods in 2006.

Palisades revenue to PSCR: For the three months and six months ended June 30, 2007, as a result of the sale of Palisades, electric revenue of $41 million related to the recovery of the Palisades and Big Rock costs has been used to offset costs incurred under our power purchase agreement with Entergy.

Power supply costs and related revenue: For the three months and six months ended June 30, 2007, PSCR revenue decreased by $12 million versus 2006. The decrease primarily reflects a reduction in amounts to be recovered under the PSCR mechanism.

Other operating expenses, other income and non-commodity revenue: For the three months ended June 30, 2007, other operating expenses decreased $48 million, other income increased $10 million, and non-commodity revenue decreased $3 million versus 2006. For the six months ended June 30, 2007, other operating expenses decreased $49 million, other income increased $16 million, and non-commodity revenue decreased $1 million versus 2006.

The decrease in other operating expenses was primarily due to lower operating and maintenance expense, including reductions to certain workers’ compensation and injuries and damages expense. These decreases were offset partially by higher depreciation and amortization expense. Operating and maintenance expense decreased primarily due to the absence, in 2007, of costs incurred in 2006 related to a planned refueling outage at Palisades, and lower overhead, line maintenance, and storm restoration costs. Also contributing to the decrease was the sale of Palisades in April 2007. Depreciation and amortization expense increased due to higher non-nuclear plant in service and greater amortization of certain regulatory assets.

For the three months ended June 30, 2007, the increase in other income was primarily due to higher interest income. For the six months ended June 30, 2007, the increase in other income was primarily due to higher interest income and higher income associated with our Section 10d(4) Regulatory Asset. The increase on our Section 10d(4) Regulatory Asset reflects the absence, in 2007, of the impact of the MPSC’s final order in this case.

General taxes: For the three months ended June 30, 2007, general tax expense increased due to higher property tax and sales and use tax expense, offset partially by lower MSBT expense. For the six months ended June 30, 2007, general tax expense increased due to higher property tax and sales and use tax expense.

Interest charges: For the three months and six months ended June 30, 2007, interest charges increased primarily due to interest associated with amounts to be refunded to customers as a result of the sale of Palisades. The MPSC order approving the Palisades power purchase agreement with Entergy directed us to record interest on the unrefunded balance.

Income taxes: For the three months ended June 30, 2007, income taxes increased versus 2006 primarily due to the absence, in 2007, of the resolution of an IRS income tax audit which resulted in an income tax benefit primarily for the utilization or restoration of income tax credits. For the six months ended June 30, 2007, income taxes increased primarily due to higher earnings by the electric utility versus 2006.

Gas deliveries: For the three months ended June 30, 2007, gas delivery revenues increased by $3 million versus 2006, as gas deliveries, including miscellaneous transportation to end-use customers, were 46 bcf, an increase of 4 bcf or 9 percent. The increase in gas deliveries was primarily due to favorable weather in the second quarter of 2007 versus 2006.

For the six months ended June 30, 2007, gas delivery revenues increased by $17 million over 2006, as gas deliveries, including miscellaneous transportation to end-use customers, were 183 bcf, an increase of 18 bcf or 10 percent. The increase in gas deliveries was primarily due to favorable weather.

Gas rate increase: In November 2006, the MPSC issued an order authorizing an annual rate increase of $81 million. As a result of this order, gas revenues increased $12 million for the three months ended June 30, 2007 and $45 million for the six months ended June 30, 2007.

Gas wholesale and retail services, other gas revenues and other income: For the three and six months ended June 30, 2007, the increase was primarily due to higher interest income.

Operation and maintenance: For the three months and six months ended June 30, 2007, operation and maintenance expenses increased versus 2006 primarily due to higher uncollectible accounts expense and contributions, beginning in November 2006 pursuant to a November 2006 MPSC order, to a fund that provides energy assistance to low-income customers.

General taxes and depreciation: For the three months ended June 30, 2007, depreciation expense increased versus 2006 primarily due to higher plant in service. The increase in general taxes reflects higher MSBT expense. For the six months ended June 30, 2007 depreciation expense increased versus 2006 primarily due to higher plant in service. The increase in general taxes reflects higher property tax expense, offset partially by lower MSBT expense.

Interest charges: For the three months ended June 30, 2007, interest charges reflect lower average debt levels versus 2006. For the six months ended June 30, 2007, interest charges reflect higher interest on our GCR overrecovery balance and higher associated company interest, offset partially by lower average debt levels versus 2006.

Income taxes: For the three and six months ended June 30, 2007, income taxes increased versus 2006 primarily due to higher earnings by the gas utility.

Operating revenues: For the three months ended June 30, 2007, operating revenues decreased $9 million versus 2006 primarily due to lower revenues at CMS ERM resulting from a write off of derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, losses from third party financial settlements and decreased third party gas sales. These decreases were partially offset by mark-to-market gains in power and gas contracts compared to losses on such items in 2006, and increased power sales.

For the six months ended June 30, 2007, operating revenues increased $7 million versus 2006 primarily due to higher revenues at CMS ERM resulting from mark-to-market gains on power and gas contracts compared to losses on such items in 2006 and increased power sales. These were offset partially by the write off of derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, losses from third party financial settlements and decreased third party gas sales.

Cost of gas and purchased power: For the three months ended June 30, 2007, cost of gas and purchased power increased $4 million versus 2006. The increase was primarily due to increased cost of gas resulting from increased usage and higher prices. The increase was offset partially by a decrease in power purchases from the MISO market.

For the six months ended June 30, 2007, cost of gas and purchased power decreased $19 million versus 2006. The decrease was primarily due to a decrease in power purchases from the MISO market, offset partially by higher cost of gas resulting from increased usage and higher prices.

Earnings from equity method investees: For the three months ended June 30, 2007, earnings from equity method investees increased versus 2006. The increase was primarily due to increased earnings at Jorf Lasfar related to a revised estimate of Jorf Lasfar’s tax reserves during the second quarter 2007, which decreased their tax expense by $11 million.

For the six months ended June 30, 2007 earnings from equity method investees decreased versus 2006. The decrease was primarily due to the sale of our investments in Africa, the Middle East and India in May 2007, offset by the absence in 2007 of a 2006 provision for higher foreign taxes in Argentina.

Loss on sale of assets: For the three months ended June 30, 2007, the net loss on asset sales was $14 million from the sale of our equity investment in Africa, the Middle East and India to TAQA. This loss was offset by a gain recorded in Income (Loss) from Discontinued Operations, for an overall net gain on the sales transaction. There were no gains or losses on asset sales for the three months ended June 30, 2006.

For the six months ended June 30, 2007, the net loss on asset sales was $2 million. There were no gains or losses on asset sales for the six months ended June 30, 2006. The net loss consisted of a loss on the sale of our equity investments in Africa, the Middle East and India to TAQA, and a loss on the sale of our equity investment in TGM and our Bay Area Pipeline in Michigan to Lucid Energy. These losses were partially offset by a gain on sale of our equity investment in El Chocon to Endesa S.A. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Operation and maintenance: For the three months ended June 30, 2007, operation and maintenance expenses increased $3 million due to higher professional fees related to the sale of equity investments and higher separation benefits associated with asset sales.

For the six months ended June 30, 2007, operation and maintenance expenses increased $6 million due to the higher professional fees and separation benefits associated with the asset sales.

General taxes, depreciation, and other income, net: For the three months ended June 30, 2007, the net of general taxes, depreciation, and other income increased operating income compared to 2006 due to higher general taxes recorded in 2006 primarily related to our South American holdings.

Asset impairment charges: For the three months ended June 30, 2007, asset impairment charges were $21 million. There were no asset impairment charges for the three months ended June 30, 2006. The increase was primarily due to the reduction in fair value of our investment in GasAtacama due to the sale agreement entered into June 2007.

For the six months ended June 30, 2007, asset impairment charges were $263 million. There were no asset impairment charges for the six months ended June 30, 2006. The increase was primarily due to the recognition of the reduction in fair value of our investment in TGN, which included $197 million of cumulative currency translation loss, and the recognition of an additional reduction in the fair value of our investment in GasAtacama.

Fixed charges: For the three and six months ended June 30, 2007, fixed charges decreased due to lower interest expenses from subsidiary debt due to asset sales in 2007.

Income taxes: For the three months ended June 30, 2007, income tax benefit increased $14 million versus the same period in 2006. The increase is primarily due to the tax benefits related to asset impairment charges, in 2007, offset partially by the absence, in 2007, of the 2006 resolution of an IRS income tax examination, which resulted in an income tax benefit for the utilization or restoration of income tax credits.

For the six months ended June 30, 2007, income tax benefit increased $35 million versus the same period in 2006. The increase is primarily due to the tax benefit related to asset impairment charges, in 2007, offset by a provision on the cumulative undistributed earnings of foreign subsidiaries expected to be sold during 2007. This was offset partially by the absence, in 2007, of the 2006 resolution of an IRS income tax examination, which resulted in an income tax benefit for the utilization or restoration of income tax credits.

The MCV Partnership: Due to the November 2006 sale of our ownership interests in the MCV Partnership, we have condensed their consolidated results of operations for the three and six months ended June 30, 2006 for discussion purposes. The decrease in losses from our ownership interest in the MCV Partnership is primarily due to the absence, in 2007, of mark-to-market losses on certain long-term contracts and financial hedges.

For the three months ended June 30, 2007, net loss from corporate interest and other was $69 million, versus net income of $42 million in 2006. The $111 million decrease primarily reflects the absence, in 2007, of a tax benefit due to the resolution of an IRS income tax audit, higher income tax expenses in 2007, and the absence of an insurance reimbursement received in June 2006 for previously incurred legal expenses. Also contributing to the decrease was the recognition of the reduction in fair value of our investment in GasAtacama and premiums paid on the early retirement of CMS Energy debt in June 2007.

For the six months ended June 30, 2007, net loss from corporate interest and other was $16 million versus net income of $6 million in 2006. The $22 million decrease primarily reflects the absence, in 2007, of a tax benefit due to the resolution of an IRS income tax audit, higher income tax expense in 2007, and the absence of an insurance reimbursement received in June 2006 for previously incurred legal expenses. Also contributing to the decrease was the recognition of the reduction in fair value of our investment in GasAtacama and premiums paid on the early retirement of CMS Energy debt in June 2007. Partially offsetting the decrease was the reversal of certain deferred tax valuation allowances in March 2007 that were no longer required due to the sale of our international operations.

Discontinued Operations: For the three months ended June 30, 2007, net income from discontinued operations was $91 million compared to net income of $12 million in 2006. The increase is primarily due to the gains on the sale of assets which more than offset foreign currency losses, the absence of income related to these businesses, and a $5 million adjustment to tax expense related to previously permanently deferred undistributed foreign earnings.

For the six months ended June 30, 2007, the net loss from discontinued operations was $87 million compared to $21 million in net income in 2006. The $108 million change is primarily due to the net loss on the disposal of international businesses in 2007, which replaced earnings recorded for these businesses in 2006.

The following accounting policies are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies.

We use estimates and assumptions in preparing our consolidated financial statements that may affect reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, and contingencies. For example, we estimate the rate of return on plan assets and the cost of future health-care benefits to determine our annual pension and other postretirement benefit costs. Actual results may differ from estimated results due to factors such as changes in the regulatory environment, competition, foreign exchange, regulatory decisions, and lawsuits.

Contingencies: We are involved in various regulatory and legal proceedings that arise in the ordinary course of our business. We record a liability for contingencies based upon our assessment that a loss is probable and the amount of loss can be reasonably estimated. We use the principles in SFAS No. 5 when recording estimated liabilities for contingencies. We consider many factors in making these assessments, including the history and specifics of each matter.

The amount of income taxes we pay is subject to ongoing audits by federal, state, and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe we have provided adequately for any likely outcome related to these matters. However, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments expire. As a result, our effective tax rate may fluctuate significantly on a quarterly basis. The FASB issued a new interpretation on the recognition and measurement of uncertain tax positions that we adopted on January 1, 2007. For additional details, see the “Implementation of New Accounting Standards” section included in this MD&A.

Discontinued Operations: We have determined that certain consolidated subsidiaries meet the criteria of assets held for sale under SFAS No. 144. At December 31, 2006, these subsidiaries included our Argentine businesses sold in March 2007, a majority of our Michigan non-utility businesses sold in March 2007, CMS Energy Brasil S.A., Takoradi, SENECA, and certain associated holding companies. There were no assets held for sale at June 30, 2007. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Financial Instruments: Debt and equity securities classified as available-for-sale are reported at fair value determined from quoted market prices. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of AOCL. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary. Unrealized gains or losses on our nuclear decommissioning investments are reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized gains or losses would not affect our consolidated earnings.

Derivative Instruments: We account for derivative instruments in accordance with SFAS No. 133. Except as noted within this section, since the year ended December 31, 2006, there have been no significant changes in the amount or types of derivatives that we hold or to how we account for derivatives. For additional details on our derivatives, see Note 6, Financial and Derivative Instruments.

To determine the fair value of our derivatives, we use information from external sources (i.e., quoted market prices and third party valuations), if available. For certain contracts, this information is not available and we use mathematical valuation models to value our derivatives. These models require various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The following table summarizes the interest rate and volatility rate assumptions we used to value these contracts at June 30, 2007:

Changes in forward prices or volatilities could significantly change the calculated fair value of our derivative contracts. The cash returns we actually realize on these contracts may vary, either positively or negatively, from the results that we estimate using these models. As part of valuing our derivatives at market, we maintain reserves, if necessary, for credit risks arising from the financial condition of our counterparties.

Derivative Contracts Associated with Equity Investments: In May 2007, we sold our ownership interest in businesses in the Middle East, Africa, and India. Certain of these businesses held interest rate contracts and foreign exchange contracts that were derivatives. Before the sale, we recorded our proportionate share of the change in fair value of these contracts in AOCL if the contracts qualified for cash flow hedge accounting; otherwise, we recorded our share in Earnings from Equity Method Investees.

At the date of the sale, we had accumulated a net loss of $13 million, net of tax, in AOCL representing our proportionate share of mark-to-market gains and losses from cash flow hedges held by the equity method investees. After the sale, we reclassified this amount and recognized it in earnings as a reduction of the gain on the sale. For additional details on the sale of our interest in these equity method investees, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

CMS ERM Contracts: CMS ERM enters into and owns energy contracts that support CMS Energy’s ongoing operations. We include the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The following tables provide a summary of these contracts at June 30, 2007:

Market Risk Information: The following is an update of our risk sensitivities since December 31, 2006. These sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical adverse change in

market rates or prices of 10 percent. Changes in excess of the amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift used for the analyses.

Interest Rate Risk Sensitivity Analysis (assuming an increase in market interest rates of 10 percent):

Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market prices of 10 percent):

Investment Securities Price Risk Sensitivity Analysis (assuming an adverse change in market prices of 10 percent):

For additional details on market risk and derivative activities, see Note 6, Financial and Derivative Instruments.

Other accounting policies important to an understanding of our results of operations and financial condition include:

These accounting policies were disclosed in our 2006 Form 10-K and there have been no subsequent material changes.

Factors affecting our liquidity and capital requirements are:

During the summer months, we purchase natural gas and store it for resale primarily during the winter heating season. Although our prudent natural gas costs are recoverable from our customers, the amount paid for natural gas stored as inventory requires additional liquidity due to the lag in cost recovery.

Our current financial plan includes controlling operating expenses and capital expenditures, executing on asset sales and evaluating market conditions for financing opportunities, if needed.

We believe the following items will be sufficient to meet our liquidity needs:

In the second quarter of 2007, Moody’s and S&P upgraded long-term credit ratings of CMS Energy and Consumers and revised the rating outlook to stable from positive.

Our operating, investing, and financing activities meet consolidated cash needs. At June 30, 2007, we had $1.944 billion consolidated cash, which includes $53 million of restricted cash and $5 million from entities consolidated pursuant to FIN 46(R).

Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For the six months ended June 30, 2007, Consumers paid $135 million in common stock dividends to CMS Energy.

Operating Activities: For the six months ended June 30, 2007, net cash provided by operating activities was $401 million, a decrease of $95 million versus 2006. The decrease in operating cash flow was a result of the timing of our collection of increased billings in 2007 due to recent regulatory actions and weather-driven demand. Also decreasing our operating cash flow was the absence of the return of funds formerly held as collateral under certain gas hedging arrangements and other timing differences. An increase in earnings at our electric and gas utility segments partially reduced these decreases. The absence of payments for higher priced gas made during the first part of 2006, the absence of the MCV Partnership gas supplier funds on deposit and increased usage of gas already in storage during 2007, as the milder winter in 2006 allowed us to accumulate more gas in our storage facilities, also offset decreases in operating cash flow.

Investing Activities: For the six months ended June 30, 2007, net cash provided by investing activities was $1.479 billion, an increase of $1.729 billion versus 2006. This increase was primarily due to proceeds from asset sales and proceeds from nuclear decommissioning trust funds.

Financing Activities: For the six months ended June 30, 2007, cash used in financing activities was $342 million, an increase of $99 million versus 2006. This was primarily due to an increase in debt retirements and payment of common stock dividends. For additional details on long-term debt activity, see Note 4, Financings and Capitalization.

Our cash flow statements include amounts related to discontinued operations through the date of disposal. For additional details on discontinued operations, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Revolving Credit Facilities: For details on our revolving credit facilities, see Note 4, Financings and Capitalization.

Dividend Restrictions: For details on dividend restrictions, see Note 4, Financings and Capitalization.

Off-Balance Sheet Arrangements: CMS Energy and certain of its subsidiaries enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, letters of credit, surety bonds, and financial and performance guarantees.

We enter into agreements containing indemnifications standard in the industry and indemnifications specific to a transaction, such as the sale of a subsidiary. Indemnifications are usually agreements to

reimburse other companies if those companies incur losses due to third party claims or breach of contract terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a third party. Letters of credit substitute the bank’s credit for ours and reduce credit risk for the third party beneficiary. We monitor these obligations and believe it is unlikely that we would be required to perform or otherwise incur any material losses associated with these guarantees. For additional details on these and other guarantee arrangements, see Note 3, Contingencies, “Other Contingencies — FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”

In May 2007, we sold our ownership interests in businesses in the Middle East, Africa, and India to TAQA. TAQA has assumed all contingent obligations related to our project-financing security agreements. For more details on the sale of our ownership interests to TAQA, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for securitized financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see Note 4, Financings and Capitalization.

Our business strategy will focus on continued investment in our utility business, reducing parent debt, and growing earnings while controlling operating costs.

Our primary focus with respect to our non-utility businesses is to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets. We intend to complete the sale of our international Enterprises assets by the end of 2007. We plan to use the proceeds from asset sales to invest in our utility business and reduce parent company debt.

Our primary focus with respect to our utility business is to continue to invest in our utility system to enable us to meet our customer commitments, comply with increasing environmental performance standards, and maintain adequate supply and capacity.

In January 2007, we reinstated a dividend on our common stock after a four-year suspension at $0.05 per share. We paid $11 million in common stock dividends in February 2007 and $11 million in common stock dividends in May 2007. On July 20, 2007, we declared a dividend of $0.05 per share on our common stock payable August 31, 2007 to shareholders of record on August 10, 2007.

Growth: In 2007, we expect electric deliveries to grow about one percent compared to 2006 levels. The outlook for 2007 assumes a small decline in industrial economic activity and normal weather conditions throughout the remainder of the year.

Over the next five years, we expect electric deliveries to grow at an average rate of about 1.5 percent per year. This outlook assumes a modestly growing customer base and a stabilizing Michigan economy after 2007. This growth rate includes both full-service sales and delivery service to customers who choose to

buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. This growth rate reflects a long-range expected trend of growth. Growth from year to year may vary from this trend due to customer response to the following:

Electric Customer Revenue Outlook: Michigan’s economy has been hampered by automotive manufacturing facility closures and restructurings. The Michigan economy has also had limited growth in the non-automotive sector. Although our electric utility results are not dependent upon a single customer, or even a few customers, customers in the automotive sector represented five percent of our total 2006 electric revenue.

Electric Reserve Margin: We have a reserve margin of approximately 11 percent for summer 2007, or supply resources equal to 111 percent of projected firm summer peak load. Of the 2007 supply resources of 111 percent, 96 percent comes from our electric generating plants and long-term power purchase contracts, and 15 percent comes from other contractual arrangements. Our 15-year power purchase agreement with Entergy for 100 percent of the Palisades facility’s current electric output will offset the reduction in the owned capacity represented by the sale of Palisades in April 2007. We have purchased capacity and energy contracts covering the reserve margin requirements for 2007 and covering partially the estimated reserve margin requirements for 2008 through 2010.

After September 15, 2007, we expect to exercise the regulatory-out provision in the MCV PPA, resulting in a reduction in the amount paid to the MCV Partnership to equal the amount we are allowed to recover in the rate charged to customers. If we are successful in exercising this provision, the MCV Partnership may, under certain circumstances, have the right to terminate the MCV PPA, which could affect our reserve margin status. The MCV PPA represents 13 percent of our 2007 supply resources.

Electric Transmission Expenses: METC, which provides electric transmission service to us, increased substantially the transmission rates it charged us in 2006. The revenue collected by METC under those rates is subject to refund pending a FERC ruling. In January 2007, the parties filed a settlement agreement with the FERC. This settlement, if approved by the FERC, will result in a refund of 2006 transmission charges of $18 million and a corresponding reduction of our power supply costs. For additional details on power supply costs, see Note 3, Contingencies, “Consumers’ Electric Utility Rate Matters – Power Supply Costs.”

21st Century Electric Energy Plan: In January 2007, the chairman of the MPSC proposed three major policy initiatives to the governor of Michigan. The initiatives involve the use of more renewable energy resources by all load-serving entities such as Consumers, the creation of an energy efficiency program, and a procedure for reviewing proposals to construct new generation facilities. The January proposal indicated that Michigan needs new base-load capacity by 2015 and recommends measures to make it easier to predict customer demand and revenues. The proposed initiatives will require changes to current legislation. We will continue to participate as the MPSC, legislature, and other stakeholders address future electric resource needs.

Balanced Energy Initiative: In May 2007, we filed a “Balanced Energy Initiative” with the MPSC providing a comprehensive energy resource plan to meet our projected short-term and long-term electric

power requirements. The plan is responsive to the 21st Century Electric Energy Plan and assumes that Michigan will implement a state-wide energy efficiency program and a renewable energy portfolio standard. The filing requests the MPSC to rule that the Balanced Energy Initiative represents a reasonable and prudent plan for the acquisition of necessary electric utility resources.

As acknowledged in the 21st Century Electric Energy Plan, implementation of the Balanced Energy Initiative will require legislative repeal or significant reform of the Customer Choice Act. In addition, we endorse the 21st Century Electric Energy Plan recommendation to adopt a new, up-front certification policy for major power plant investments. Our filing requests the MPSC to find that the addition of 500 MW of gas-fired combined cycle generating capacity is reasonable and prudent. The filing also recommends construction of a new 750 MW clean coal generating facility on an existing Consumers site to begin operation in 2015. Ownership of 250 MW of the total capacity is assumed to be allocated to municipal entities or other interested parties, resulting in 500 MW dedicated to our use.

Proposed Power Plant Purchase: In May 2007, we reached an agreement with Broadway Gen Funding LLC, an affiliate of LS Power Group, to buy a 946 MW gas-fired power plant located in Zeeland, Michigan for $517 million. The power plant will help meet the growing energy needs of our customers. We expect to close on the purchase in early 2008, subject to MPSC and other regulatory approvals and other closing conditions.

Proposed Renewable Energy Legislation: There are various bills introduced into the U.S. Congress and the Michigan legislature relating to mandatory renewable energy standards. If enacted, these bills generally would require electric utilities to acquire a certain percentage of their power from renewable sources or otherwise pay fees or purchase allowances in lieu of having the resources. We cannot predict whether any such bill will be enacted or in what form.

Several electric business trends or uncertainties may affect our financial condition and future results of operations. These trends or uncertainties have, or we reasonably expect could have, a material impact on revenues or income from continuing electric operations.

Electric Environmental Estimates: Our operations are subject to environmental laws and regulations. Costs to operate our facilities in compliance with these laws and regulations generally have been recovered in customer rates.

Clean Air Act: Compliance with the federal Clean Air Act and resulting regulations continues to be a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $835 million. From 1998 to present, we have incurred $782 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $53 million of capital expenditures will be made in 2007 through 2011. These expenditures include installing selective catalytic reduction control technology on four of our coal-fired electric generating units. The key assumptions in the capital expenditure estimate include:

Our current capital cost estimates include an escalation rate of 2.6 percent and an AFUDC capitalization rate of 7.8 percent.

In addition to modifying coal-fired electric generating plants, our compliance plan includes the use of nitrogen oxide emission allowances until all of the control equipment is operational in 2011. The nitrogen oxide emission allowance annual expense is projected to be $2 million per year, which we expect to recover from our customers through the PSCR process. The projected annual expense is based on market price forecasts and forecasts of regulatory provisions, known as progressive flow control, that restrict the usage in any given year of allowances banked from previous years. The allowances and their cost are accounted for as inventory. The allowance inventory is expensed at the rolling average cost as the electric generating plants emit nitrogen oxide.

Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. We plan to meet the nitrogen oxide requirements of this rule by year-round operation of our selective catalytic reduction control technology units, installation of low nitrogen oxide burners, and purchasing emission allowances. We plan to meet the sulfur dioxide requirements of this rule using sorbent injection, installation of flue gas desulfurization scrubbers and purchasing emission allowances. Our total cost for equipment installation is expected to reach approximately $700 million by 2015. Additional purchases of sulfur dioxide emission allowances in 2012 and 2013 will be needed for an estimated cost of $12 million per year, which we expect to recover from our customers through the PSCR process.

The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of Columbia by a number of utilities and other companies. Final briefs are due September 5, 2007, with a decision expected in 2008. We cannot predict the outcome of these appeals.

Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury Rule, which requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010 and further reductions by 2018. The Clean Air Mercury Rule was appealed to the U.S. Court of Appeals by a number of states and other entities. Final briefs were due July 13, 2007, with a decision expected in 2008. We cannot predict the outcome of these appeals.

In April 2006, Michigan’s governor announced a plan that would result in mercury emissions reductions of 90 percent by 2015. We are currently working with the MDEQ on the details of this rule; however, we have developed preliminary cost estimates and a mercury emissions reduction scenario based on our best knowledge of control technology options and initially proposed requirements.

The following table compares the federal Clean Air Mercury Rule to the proposed state mercury rule:

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to modify the plant. We have received and responded to information requests from the EPA on this subject. We believe that we have properly interpreted the requirements of “routine maintenance.” If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric generating plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation could be called into question.

Greenhouse gases: Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, including carbon dioxide. On April 2, 2007, the U.S. Supreme Court ruled that the Clean Air Act gives the EPA the authority to regulate emissions of carbon dioxide and other greenhouse gases from automobiles. In its decision, the court ordered the EPA to revisit its contention that it has the discretion not to regulate greenhouse gas emissions from automobiles.

To the extent that greenhouse gas emission reduction rules come into effect, the mandatory emissions reduction requirements could have far-reaching and significant implications for the energy sector. We cannot estimate the effect of federal or state greenhouse gas policy on our future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies at this time. However, we will continue to monitor greenhouse gas policy developments and assess and respond to their potential implications on our business operations.

Water: In March 2004, the EPA issued rules that govern electric generating plant cooling water intake systems. The rules require significant reduction in fish killed by operating equipment. EPA compliance options in the rule were challenged in court. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The court’s ruling is expected to increase significantly the cost of complying with this rule. However, the cost to comply will not be known until the EPA’s reconsideration is complete. At this time, the EPA has not established a schedule to address the court decision.

For additional details on electric environmental matters, see Note 3, Contingencies, “Consumers’ Electric Utility Contingencies — Electric Environmental Matters.”

Competition and Regulatory Restructuring: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At June 30, 2007, alternative electric suppliers were providing 302 MW of generation service to ROA customers. This is 3 percent of our total distribution load and represents a decrease of 3 percent of ROA load compared to June 30, 2006. We recover Stranded Costs incurred from 2002 through 2003 through a surcharge applied to ROA customers. If downward ROA trends continue, it will extend the time it takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends, which affect our ability to recover timely these Stranded Costs.

Electric Rate Case: In March 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity and an annual increase in revenues of $157 million. The increase seeks recovery of the costs associated with increased plant investment, increased equity investment, and greater operation and maintenance expenses. In May 2007, we filed supplemental testimony with the MPSC to include transaction costs from the sale of Palisades. In July 2007, we filed an amended application with the MPSC to include the proposed purchase of the Zeeland power plant, the approval of an energy efficiency program, and to make other revisions. The revised application seeks an annual increase in revenues of $282 million.

In July 2007, we also filed a motion for partial and immediate rate relief that seeks the removal of costs associated with Palisades, the approval of partial and immediate rate relief for certain items, including the proposed purchase of the Zeeland power plant, and the approval of a plan to distribute $127 million of excess proceeds from the sale of Palisades to customers. The case schedule will allow for an MPSC order on our Zeeland request and on our request for partial and immediate rate relief by the end of 2007 and a final rate order in mid-2008. We cannot predict the amount or timing of any MPSC decision on the requests.

For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, “Consumers’ Electric Utility Rate Matters.”

The MCV Partnership: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990.

Underrecoveries related to the MCV PPA: The cost that we incur under the MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity and fixed energy payments of $39 million in 2007. However, we use the direct savings from the RCP, after allocating a portion to customers, to offset a portion of our capacity and fixed energy underrecoveries expense. After September 15, 2007, we expect to claim relief under the regulatory-out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. This action would eliminate our underrecoveries of capacity and fixed energy payments.

The MCV Partnership has notified us that it opposes our intended exercise of the regulatory-out provision after September 15, 2007. We believe that the provision is valid and fully effective, but cannot assure that we will prevail in the event of a dispute. If we are successful in exercising the regulatory-out provision, the MCV Partnership may, under certain circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA. If the MCV Partnership terminates the MCV PPA or reduces the amount of capacity sold under the MCV PPA, we would seek to replace the lost capacity to maintain an

adequate electric reserve margin. This could involve entering into a new PPA and (or) entering into electric capacity contracts on the open market. We cannot predict our ability to enter into such contracts at a reasonable price. We are also unable to predict regulatory approval of the terms and conditions of such contracts, or that the MPSC would allow full recovery of our incurred costs.

To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC, which asked the MPSC to make a determination regarding whether it wished to reconsider the amount of the MCV PPA payments that we recover from customers. Also, in May 2007, the MCV Partnership filed an application with the MPSC seeking approval to increase our recovery of costs incurred under the MCV PPA. We are unable to predict the outcome of these requests. For additional details on the MCV Partnership, see Note 3, Contingencies, “Other Consumers’ Electric Utility Contingencies — The MCV PPA.”

Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million. The final purchase price is subject to various closing adjustments resulting in us receiving $364 million as of June 30, 2007. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. Because of the sale of Palisades, we also paid the NMC, the former operator of Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC.

The MPSC order approving the Palisades transaction allowed us to recover the book value of Palisades. This results in us refunding estimated proceeds in excess of book value of $66 million to our customers through credits applied from June 2007 through December 2008. The final proceeds in excess of the book value are subject to closing adjustments and review by the MPSC. The MPSC order deferred ruling on the recovery of transaction costs, including the NMC exit fees, and the $30 million payment to Entergy related to the Big Rock ISFSI until the next general rate case.

Entergy assumed responsibility for the future decommissioning of Palisades and for storage and disposal of spent nuclear fuel located at Palisades and the Big Rock ISFSI sites. We transferred $252 million in trust fund assets to Entergy. We are refunding estimated excess decommissioning funds of $189 million to our retail customers through credits applied from June 2007 through December 2008. Access to additional decommissioning fund balances above the estimates in the MPSC order resulted in excess decommissioning funds of $122 million. We have proposed a plan to refund these balances to our retail customers and this plan is under review by the MPSC in our current electric rate case filing.

As part of the transaction, Entergy will sell us 100 percent of the plant’s output up to its current annual average capacity of 798 MW under a 15-year power purchase agreement. Because of the Palisades power purchase agreement and our continuing involvement with the Palisades assets, we account for the disposal of Palisades as a financing for accounting purposes and not a sale. This resulted in the recognition of a finance obligation of $197 million.

For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Growth: In 2007, we project gas deliveries will decline slightly, on a weather-adjusted basis, from 2006 levels due to continuing conservation and overall economic conditions in the state of Michigan. Over the next five years, we expect gas deliveries to decline by less than one-half of one percent annually. Actual gas deliveries in future periods may be affected by:

Several gas business trends or uncertainties may affect our future financial results and financial condition. These trends or uncertainties could have a material impact on future revenues or income from gas operations.

Gas Environmental Estimates: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 3, Contingencies, “Consumers’ Gas Utility Contingencies — Gas Environmental Matters.”

Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudency in annual plan and reconciliation proceedings. For additional details on gas cost recovery, see Note 3, Contingencies, “Consumers’ Gas Utility Rate Matters – Gas Cost Recovery.”

Gas Depreciation: In June 2007, the MPSC issued its final order in the generic ARO accounting case and modified the filing requirement for our next gas depreciation case. The original filing requirement date was changed from 90 days after the issuance of this order to no later than August 1, 2008. Additionally, we have been ordered to use 2007 data and prepare a cost of removal depreciation study with five alternatives using the MPSC’s prescribed methods.

If a final order in our next gas depreciation case is not issued concurrently with a final order in a general gas rate case, the MPSC may incorporate the results of the depreciation case into general gas rates through use of a surcharge mechanism (which may be either positive or negative).

2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity along with an $88 million annual increase in our gas delivery and transportation rates. We have proposed the use of a Revenue Decoupling and Conservation Incentive Mechanism for residential and general service rate classes, which partially separates the collection of fixed costs from gas sales and enhances the utility’s ability to recover its fixed costs.

The MPSC Staff and intervenors filed testimony on July 20, 2007. In its testimony, the MPSC Staff recommended a 10.5 percent authorized return on equity with a $35 million annual increase in our gas delivery and transportation rates. The schedule established by the MPSC for processing this case could allow for a final order by the end of 2007.

Our primary focus with respect to our non-utility businesses is to optimize cash flow and further reduce our business risk and leverage through the sale of non-strategic assets.

We completed the sale of a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy for $130 million in March 2007.

In connection with the sale of our Argentine and Michigan assets, we entered into agreements that grant Lucid Energy:

Under these agreements, we have essentially sold our rights to certain awards or proceeds that we may receive in the future. A portion of the consideration received in the sale has been allocated to these agreements. We have recorded $32 million as a deferred credit in Other Non-current Liabilities on our Consolidated Balance Sheets.

We also sold our interest in El Chocon, an Argentine hydroelectric generating business, to Endesa, S.A. for $50 million in March 2007.

We sold our ownership interest in SENECA and certain associated generating equipment to Petroleos de Venezuela, S.A., which is owned by the Bolivarian Republic of Venezuela, for gross cash proceeds of $106 million in April 2007.

We sold our ownership interest in businesses in the Middle East, Africa, and India to TAQA for $900 million in May 2007. Gross proceeds from the sale were $792 million in cash and TAQA’s assumption of $108 million in debt. Businesses included in the sale were Taweelah, Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi.

In June 2007, we sold CMS Energy Brasil S.A. to CPFL Energia S.A., a Brazilian utility, for $211 million, which included $201 million in cash proceeds and CPFL Energia S.A.’s assumption of a $10 million tax liability.

We entered into an agreement to sell our investment in GasAtacama to Endesa S.A. for gross cash proceeds of $80 million in July 2007. We closed on the sale of GasAtacama in August 2007.

We entered into an agreement to sell our investment in Jamaica to AEI for gross cash proceeds of $14 million in June 2007. We expect to close on the sale by the end of 2007.

For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Uncertainties: Trends or uncertainties that could have a material impact on our consolidated income, cash flows, or balance sheet and credit improvement include:

Prairie State: In October 2006, we signed agreements with Peabody Energy to co-develop the Prairie State Energy Campus (Prairie State), a 1,600 MW power plant and coal mine in southern Illinois. In April 2007, we withdrew from Prairie State because it did not meet our investment criteria, including the level of power purchase agreements for our share of output from Prairie State.

Litigation and Regulatory Investigation: We are the subject of an investigation by the DOJ regarding round-trip trading transactions by CMS MST. Also, we are named as a party in various litigation matters including, but not limited to, securities class action lawsuits and several lawsuits regarding alleged false natural gas price reporting and price manipulation. Additionally, the SEC is investigating the actions of former CMS Energy subsidiaries in relation to Equatorial Guinea. For additional details regarding these and other matters, see Note 3, Contingencies and Part II, Item 1. Legal Proceedings.

Fixed Price Contracts: DIG and CMS ERM are parties to long-term requirements contracts to provide steam and (or) electricity based on a fixed price schedule. The price of natural gas, the primary fuel used by DIG, is volatile and has increased substantially in recent years. Because the prices charged under DIG’s contracts do not reflect current natural gas prices, DIG’s and CMS ERM’s financial performance has been impacted negatively. However, since not all of its capacity is committed under these contracts, DIG has been able to sell a portion of its electric capacity and (or) energy on the market at a profit, or, through CMS ERM, engage in a hedging strategy to minimize its losses. DIG and CMS ERM may take various actions such as seeking restructuring or buyout of the contracts, which may require material cash payments. CMS Energy may also take other measures to address the unfavorable returns.

Michigan Business Tax Act: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan Business Tax Act, which imposes a business income tax of 4.95 percent and a modified gross receipts tax of 0.8 percent. The bill provides for a number of tax credits and incentives, geared towards those companies investing and employing in Michigan. The Michigan Business Tax, which is effective January 1, 2008, replaces the state’s current Single Business Tax that expires on December 31, 2007. We are currently evaluating the impact this new tax will have on us. We do not expect an increase to our State tax

liability. Absent any State legislative or regulatory action, however, we may need to record a material non-cash deferred tax charge for this new tax.

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans - - an amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS No. 158. Phase one of this standard required us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase one was implemented in December 2006. Phase two of this standard requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of phase two of this standard will have a material effect on our consolidated financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008.

FIN 48, Accounting for Uncertainty in Income Taxes: We adopted the provisions of FIN 48 on January 1, 2007. This interpretation provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management’s best judgment, it is greater than 50 percent likely that we will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return.

As a result of the implementation of FIN 48, we have identified additional uncertain tax benefits of $11 million as of January 1, 2007. Included in this amount is an increase in our valuation allowance of $100 million, decreases to tax reserves of $61 million and a decrease to deferred tax liabilities of $28 million.

CMS Energy and its subsidiaries file a consolidated U.S. federal income tax return as well as unitary and combined income tax returns in several states. CMS Energy and its subsidiaries also file separate company income tax returns in several states. The only significant state tax paid by CMS Energy is in Michigan. However, since the Michigan Single Business Tax is not an income tax, it is not part of the FIN 48 analysis. For the U.S. federal income tax return, CMS Energy completed examinations by federal taxing authorities for its taxable years prior to 2002. The federal income tax returns for the years 2002 through 2005 are open under the statute of limitations.

We have reflected a net interest liability of $3 million related to our uncertain income tax positions on our Consolidated Balance Sheets as of January 1, 2007. We have not accrued any penalties with respect to uncertain tax benefits. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

As of the date of adoption of FIN 48, we had valuation allowances against certain U.S. and foreign deferred tax assets totaling $216 million and other uncertain tax positions of $31 million, resulting in total unrecognized benefits of $247 million. Of this amount, $217 million would result in a decrease in our effective tax rate, if recognized. We released $81 million of our valuation allowance in the first quarter of 2007, reducing our effective tax rate, due to the anticipated sales of our foreign investments. During the second quarter of 2007, we reversed $63 million of valuation allowance attributable to additional foreign asset sales. This reversal had no income impact, as an identical amount of deferred tax asset was also

reversed. As we continue to market our foreign investments, it is reasonably possible that additional valuation allowance adjustments could be made.

SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us January 1, 2008. The standard provides a revised definition of “fair value” and gives guidance on how to measure the fair value of assets and liabilities. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value in any new circumstances. However, additional disclosures will be required on the impact and reliability of fair value measurements reflected in our consolidated financial statements. The standard will also eliminate the existing prohibition of recognizing “day one” gains or losses on derivative instruments, and will generally require such gains and losses to be recognized through earnings. We are presently evaluating the impacts, if any, of implementing SFAS No. 157. We currently do not hold any derivatives that would involve day one gains or losses.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard will give us the option to select certain financial instruments and other items, which otherwise are not required to be measured at fair value, and measure those items at fair value. If we choose to elect the fair value option for an item, we would recognize unrealized gains and losses associated with changes in the fair value of the item over time. The statement will also require disclosures for items for which the fair value option has been elected. We are presently evaluating whether we will choose to elect the fair value option for any financial instruments or other items.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39: In April 2007, the FASB issued FSP FIN 39-1, effective for us January 1, 2008. This standard will permit us to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. As a result, we will be permitted to record one net asset or liability that represents the total net exposure of all derivative positions under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. We presently record the net fair value of derivative assets and liabilities for those contracts held by CMS ERM that are subject to master netting arrangements, and separately record amounts for cash collateral received or paid for these instruments. Under this standard, as a result of offsetting the collateral amounts against the fair value of derivative assets and liabilities, both our total assets and total liabilities could be reduced. The standard is to be applied retrospectively by adjusting the financial statements for all periods presented. There will be no impact to earnings from adopting this standard.

EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards:In June 2007, the FASB ratified EITF Issue 06-11, effective for us on a prospective basis beginning January 1, 2008. EITF 06-11 requires companies to recognize the income tax benefit realized from dividends or dividend equivalents that are charged to retained earnings and paid to employees for non-vested equity-classified employee share-based payment awards as an increase to additional paid-in capital. We do not believe that implementation of this standard would have a material effect on our financial statements.