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. Yesþ    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

CMS Energy Corporation:

Consumers Energy Company:

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, 2008:

This combined Form 10-Q is separately filed by CMS Energy Corporation and Consumers Energy Company. Information in this combined Form 10-Q relating to each individual registrant is filed by such registrant on its own behalf. Consumers Energy Company makes no representation regarding information relating to any other companies affiliated with CMS Energy Corporation other than its own subsidiaries. None of CMS Energy Corporation, CMS Enterprises Company nor any of CMS Energy Corporation’s other subsidiaries (other than Consumers Energy Company) has any obligation in respect of Consumers Energy Company’s debt securities and holders of such securities should not consider the financial resources or results of operations of CMS Energy Corporation, CMS Enterprises Company nor any of CMS Energy Corporation’s subsidiaries (other than Consumers Energy Company and its own subsidiaries (in relevant circumstances)) in making a decision with respect to Consumers Energy Company’s debt securities. Similarly, Consumers Energy Company has no obligation in respect of debt securities of CMS Energy Corporation.

This report should be read in its entirety. No one section of this report deals with all aspects of the subject matter of this report. This report should be read in conjunction with the consolidated financial statements and related notes and with Management’s Discussion and Analysis included in the 2007 Form 10-K for CMS Energy Corporation and Consumers Energy Company.

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

This MD&A is a consolidated report of CMS Energy. 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, 2007.

This Form 10-Q and other written and oral statements that we make contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Our intention with the use of words such 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 or control:

For additional information regarding these and other uncertainties, see the “Outlook” section included in this MD&A, Note 4, 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 several subsidiaries including Consumers and Enterprises. Consumers is a combination electric and gas utility company serving in Michigan’s Lower Peninsula. Enterprises, through its 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, gas distribution, transmission, and storage, and other energy-related services. Our businesses are affected primarily by:

During the past several years, our business strategy has emphasized improving our consolidated balance sheet and maintaining focus on our core strength: utility operations and service.

A key aspect of our strategy with respect to our utility operations is our Balanced Energy Initiative. The initiative is designed to meet the growing customer demand for electricity over the next 20 years with energy efficiency, demand management, expanded use of renewable energy, and development of new power plants and pursuit of additional power purchase agreements to complement existing generating sources.

The Michigan Senate approved several bills in June 2008 that would revise the Customer Choice Act, introduce energy efficiency programs, modify the timing of rate increase requests, mandate cost allocation methodology and customer rate design (deskewing), establish mandatory renewable energy standards, and provide for other regulatory changes. The Michigan Senate’s bills differ from the bills passed by the Michigan House of Representatives in April 2008. We cannot predict whether the differences can be resolved or whether the Michigan governor will approve any compromise package.

In June 2008, the MPSC approved a settlement agreement that provides for an amended and restated MCV PPA and resolves the issues concerning our exercise of the September 2007 regulatory-out provision. The revised MCV PPA also provides for our access to 1,240 MW of the MCV Facility capacity through March 2025. The amended and restated MCV PPA will take effect when at least four boilers being installed to provide steam and electric energy at the MCV Facility are operational.

As we work to implement plans to serve our customers in the future, the cost of energy and managing cash flow continue to challenge us. Natural gas prices and eastern coal prices have been increasing substantially. These costs are recoverable from our utility customers; however, as prices increase, the amount we pay for these commodities will require additional liquidity due to the lag in cost recoveries.

In July 2008, we implemented an integrated business software system for customer billing, finance, work management, and other systems. Consistent with our commitment to our Balanced Energy Initiative, we are also developing an advanced metering system that will provide enhanced controls and information about our customer energy usage and notification of service interruptions. We expect to develop integration software and pilot new technology over approximately the next two years.

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 the downturn in Michigan’s automotive industry and limited growth in the non-manufacturing sectors of the state’s economy. There also has been softness in the capital markets resulting from the subprime mortgage crisis, energy price increases, and other market weaknesses. Although we have not identified any material impacts on our financial condition, we will continue to monitor developments for potential implications for our business.

For the three months ended June 30, 2008, our net income was $46 million, a $13 million increase versus 2007. Compared with the second quarter of 2007, net income from our combined electric and gas utility segments increased, reflecting the positive impact of MPSC rate orders and the elimination of certain costs from the power purchase agreement with the MCV Partnership, partially offset by lower weather-driven deliveries. The increase in net income from our Enterprises and corporate interest and other segments is primarily due to the absence of charges related to asset impairments and charges associated with the rescission of a contract with Quicksilver. Partially offsetting these increases was the reduction in net income from discontinued operations.

Specific changes to net income available to common stockholders for the three months ended June 30, 2008 versus 2007 are:

For the six months ended June 30, 2008, our net income was $149 million, a $331 million increase versus 2007. Compared with the first half of 2007, net income from our combined electric and gas utility segments increased, reflecting the positive impact of MPSC rate orders and the elimination of certain costs from the power purchase agreement with the MCV Partnership, partially offset by lower deliveries. The increase in net income from our combined Enterprises and corporate interest and other segments is primarily due to the absence of charges related to asset impairments and charges associated with the rescission of a contract with Quicksilver. Further increasing net income was the absence of a net loss on the disposal of discontinued operations.

Specific changes to net income (loss) available to common stockholders for the six months ended June 30, 2008 versus 2007 are:

Electric deliveries and rate increase: For the three months ended June 30, 2008, electric delivery revenues increased by $10 million versus 2007 primarily due to additional revenue of $30 million from the inclusion of the Zeeland power plant in rates and from the June 2008 rate order. The increase was partially offset by decreased electric revenue of $20 million due to lower deliveries primarily related to weather. Deliveries to end-use customers were 9.1 billion kWh, a decrease of 0.4 billion kWh or 4 percent versus 2007. For additional details on the June 2008 rate order, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters.”

For the six months ended June 30, 2008, electric delivery revenues increased by $27 million versus 2007 primarily due to additional revenue of $48 million from the inclusion of the Zeeland power plant in rates and from the June 2008 rate order. The increase was partially offset by decreased electric revenue of $21 million due to lower deliveries. Deliveries to end-use customers were 18.5 billion kWh, a decrease of 0.5 kWh or 3 percent versus 2007.

Surcharge revenue: For the three months and six months ended June 30, 2008, surcharge revenue increased by $10 million versus 2007. The increase was primarily due to the April 2008 MPSC order allowing recovery of certain retirement benefits through a surcharge. Consistent with the recovery of these costs, we recognized a similar amount of benefit expense. For additional details, see Other operating expenses within this section and Note 8, Retirement Benefits.

Palisades revenue to PSCR: Consistent with the MPSC order associated with the April 2007 sale of Palisades, base rate revenue related to Palisades was used to offset costs incurred under our power purchase agreement with Entergy. For additional information, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters.”

Power supply costs and related revenue: PSCR revenue increased $10 million for the three months ended June 30, 2008 and $7 million for the six months ended June 30, 2008. The increase primarily reflects the 2007 reduction to revenue that was made in response to the MPSC’s position that PSCR discounts given to our Transitional Primary Rate customers could not be recovered under the PSCR mechanism.

Other operating expenses, other income and non-commodity revenue: For the three months ended June 30, 2008, other operating expenses decreased $4 million, other income decreased $17 million, and non-commodity revenue decreased $3 million versus 2007. For the six months ended June 30, 2008, other operating expenses decreased $73 million, other income decreased $17 million, and non-commodity revenue decreased $11 million versus 2007.

For the three months ended June 30, 2008, the decrease of $4 million in other operating expenses was primarily due to the absence, in 2008, of certain costs that are no longer incurred under our power purchase agreement with the MCV Partnership, and the termination of the METC transmission service agreement. The decrease was partially offset by higher retirement benefit expense due to the April 2008 MPSC order allowing recovery of certain costs through a surcharge and higher depreciation. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Consumers’ Electric Utility Contingencies.”

For the six months ended June 30, 2008, the decrease of $73 million in other operating expenses was primarily due to the absence of expenses associated with the sale of Palisades in April 2007, certain costs that are no longer incurred under our power purchase agreement with the MCV Partnership, and the termination of the METC transmission service agreement. Also decreasing expenses was the MPSC’s order allowing us to retain a portion of the proceeds from the sale of certain sulfur dioxide allowances. The decrease was partially offset by higher retirement benefit expense due to the April 2008 MPSC order allowing recovery of certain costs through a surcharge and higher depreciation. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Consumers’ Electric Utility Contingencies.”

For the three months and six months ended June 30, 2008, the decrease in other income of $17 million was primarily due to reduced interest income and the MPSC’s June 2008 order which did not allow us to recover all of our costs associated with the sale of Palisades. The decrease also reflects a lower 2008 return on certain regulatory assets.

Non-commodity revenue decreased $3 million for the three months ended June 30, 2008 and $11 million for the six months ended June 30, 2008. The decreases were primarily due to the absence, in 2008, of METC transmission services revenue.

General taxes: General tax expense decreased $4 million for the three months ended June 30, 2008 and $8 million for the six months ended June 30, 2008. The decreases were primarily due to the absence, in 2008, of MSBT, which was replaced with the Michigan Business Tax effective January 1, 2008. The decreases were partially offset by higher property tax expense.

Interest charges: Interest charges decreased $10 million for the three months ended June 30, 2008 and $5 million for the six months ended June 30, 2008. These decreases were primarily due to lower 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 balances. Also contributing to the decrease was the absence, in 2008, of interest charges related to an IRS settlement.

Income taxes: For the three months ended June 30, 2008, income taxes increased $15 million versus 2007. The increase reflects $13 million due to higher earnings and $2 million due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008.

For the six months ended June 30, 2008, income taxes increased $27 million versus 2007. The increase reflects $22 million due to higher earnings, $4 million due to the inclusion of the Michigan Business Tax, and $1 million due to the loss of the benefit from the tax-exempt interest related to nuclear decommissioning in 2007.

Gas deliveries and rate increase: For the three months ended June 30, 2008, gas delivery revenues increased $5 million versus 2007 primarily due to additional revenue of $7 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by lower gas deliveries, including miscellaneous transportation to end-use customers, totaling 43 bcf, a decrease of 3 bcf or 6 percent. The decrease in gas deliveries was primarily due to warmer weather in the second quarter of 2008 versus 2007 and resulted in a decrease in gas delivery revenue of $2 million.

For the six months ended June 30, 2008, gas delivery revenues increased $18 million versus 2007 primarily due to additional revenue of $28 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by lower gas deliveries, including miscellaneous transportation to end-use customers, totaling 180 bcf, a decrease of 3 bcf or 2 percent versus 2007. Lower gas deliveries resulted in a decrease in gas delivery revenue of $10 million.

Gas wholesale and retail services, other gas revenues and other income: Gas wholesale and retail services, other gas revenues and other income decreased $7 million for the three months ended June 30, 2008 and $11 million for the six months ended June 30, 2008. These decreases were primarily due to lower interest income and lower pipeline capacity optimization revenue.

Operation and maintenance: Operation and maintenance expenses increased $6 million for the three months ended June 30, 2008 and $9 million for the six months ended June 30, 2008. These increases were primarily due to higher operating expense across our storage, transmission and distribution systems.

General taxes and depreciation: For the three months ended June 30, 2008, general taxes and depreciation decreased $1 million versus 2007. General taxes decreased by $2 million due to the absence, in 2008, of MSBT, which was replaced by the Michigan Business Tax effective January 1, 2008. The decrease was partially offset by increased depreciation expense of $1 million.

For the six months ended June 30, 2008, general taxes and depreciation increased $1 million versus 2007. Depreciation expense increased $6 million and general taxes decreased $5 million due to the absence, in 2008, of MSBT, which was replaced by the Michigan Business Tax effective January 1, 2008.

Interest charges: Interest charges decreased $2 million for the three months ended June 30, 2008 and $6 million for the six months ended June 30, 2008. These decreases were primarily due to lower average debt levels and a lower average interest rate.

Income taxes: For the three months ended June 30, 2008, income taxes decreased $3 million versus 2007 primarily due to lower quarterly earnings.

Operating revenues: For the three months ended June 30, 2008, operating revenues increased $27 million versus 2007. The increase was due to the absence, in 2008, of the write-off of $40 million of derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, and the absence, in 2008, of losses recorded from financial settlements of $7 million. Also contributing to the increase were higher gas sales of $5 million. These increases were partially offset by lower power sales of $13 million and lower net mark-to-market gains on power and gas contracts of $12 million.

For the six months ended June 30, 2008, operating revenues decreased $15 million versus 2007. The decrease was due to the absence, in 2008, of gas sales of $41 million resulting primarily from the termination of a gas sales contract, lower net mark-to-market gains on power and gas contracts of $18 million, reduced power sales of $5 million and the absence, in 2008, of revenue of $1 million from assets sold in 2007. These decreases were partially offset by the absence, in 2008, of the write-off of $40 million of derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, and the absence, in 2008, of losses recorded from financial settlements of $10 million.

Fuel for electric generation, cost of gas and purchased power: For the three months ended June 30, 2008, fuel for electric generation, cost of gas and purchased power decreased $21 million versus 2007. The decrease was due to a reduction in fuel for electric generation of $13 million resulting from the decrease in purchases partially offset by higher prices and mark-to-market gains on gas and power supply contracts of $8 million.

For the six months ended June 30, 2008, fuel for electric generation, cost of gas and purchased power decreased $69 million versus 2007. The decrease was due to the absence, in 2008, of gas purchases of $37 million resulting primarily from the termination of a gas supply contract, mark-to-market gains on gas and power supply contracts of $14 million, reduced fuel for electric generation of $10 million and a decrease in purchased power costs of $8 million.

Earnings from equity method investees: For the three months ended June 30, 2008, earnings from equity method investees decreased $18 million versus 2007. The decrease was due to the absence, in 2008, of $16 million of earnings from our investments in Africa, the Middle East, and India that were sold in May 2007, our investment in GasAtacama that was sold in August 2007 and our investment in Jamaica that was sold in October 2007. Also contributing to the decrease was a mark-to-market derivative loss of $2 million from our investment in North Carolina.

For the six months ended June 30, 2008, earnings from equity method investees decreased $38 million versus 2007. The decrease was due to the absence, in 2008, of $32 million of earnings from our investments in Africa, the Middle East, and India that were sold in May 2007, and our

investment in Jamaica that was sold in October 2007. Also contributing to the decrease was a mark-to-market derivative loss of $3 million from our investment in North Carolina and the absence, in 2008, of $3 million of earnings associated with our remaining asset in Argentina.

Gain (loss) on sale of assets: For the three months ended June 30, 2008, we recognized a gain on asset sales of $8 million related to our interests in TGN granted to MEI, an affiliate of Lucid Energy, in connection with the sale in 2007 of our Argentine and Michigan assets. For the three months ended June 30, 2007, the net loss on asset sales was $14 million. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

For the six months ended June 30, 2008, we recognized the $8 million gain on asset sales related to our interests in TGN, as described in the preceding paragraph. For the six months ended June 30, 2007, the net loss on asset sales was $2 million. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Operation and maintenance: For the three months ended June 30, 2008, operation and maintenance expenses decreased $17 million versus 2007. The decrease was due to the absence, in 2008, of $14 million of expenses associated with assets sold during 2007 and the reimbursement, in 2008, of $3 million of arbitration costs at CMS Gas Transmission.

For the six months ended June 30, 2008, operation and maintenance expenses decreased $33 million versus 2007. The decrease was due to the absence, in 2008, of $30 million of expenses associated with assets sold during 2007 and the reimbursement, in 2008, of $3 million of arbitration costs at CMS Gas Transmission.

2007 asset impairment charges: For the three months ended June 30, 2007, we recorded asset impairment charges of $21 million for the reduction in fair value of our equity investment in GasAtacama due to the sale agreement entered into June 2007.

For the six months ended June 30, 2007, we recorded asset impairment charges of $263 million for the reduction in fair value of our investments in TGN, GasAtacama, Jamaica and PowerSmith. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Fixed charges: For the six months ended June 30, 2008, fixed charges decreased due to lower interest expenses from subsidiary debt resulting from asset sales in 2007.

Minority interests: The allocation of profits to minority owners decreases our net income, and the allocation of losses to minority owners increases net income. For 2008, minority owners shared in a portion of decreased earnings at our subsidiaries versus 2007.

Income taxes: For the three months ended June 30, 2008, income tax expense increased $28 million versus 2007. The increase reflects $31 million of additional tax expense on higher earnings. These increases were offset by the absence of $3 million of tax expense recorded in 2007 on earnings associated with the recognition of previously unremitted foreign earnings of subsidiaries sold.

For the six months ended June 30, 2008, income tax expense increased $67 million versus 2007. The increase reflects $114 million of additional tax expense on higher earnings. These increases were offset by the absence of $47 million of tax expense recorded in 2007 on earnings associated with the recognition of previously unremitted foreign earnings of subsidiaries sold.

For the three months ended June 30, 2008, corporate interest and other net expenses were $22 million, a decrease of $26 million versus 2007. The decrease in net expenses of $26 million primarily reflects the absence, in 2008, of the reduction in fair value of notes receivable from GasAtacama, and premiums paid on the early retirement of CMS Energy debt in June 2007.

For the six months ended June 30, 2008, corporate interest and other net expenses were $46 million, an increase of $51 million versus 2007. The increase in net expenses of $51 million primarily reflects the absence, in 2008, of the recognition of certain tax benefits related to the sale of our international operations. Partially offsetting the increase was the absence, in 2008, of the reduction in fair value of notes receivable from GasAtacama, and premiums paid on the early retirement of CMS Energy debt in June 2007. Also contributing to the decrease was reduced interest expense due to lower debt levels in 2008.

For the three months ended June 30, 2008, net loss from discontinued operations was $1 million, compared with net income of $91 million in 2007. The decrease of $92 million was primarily due to the absence of a net gain on the disposal of international businesses sold in 2007 and income related to these businesses, which more than offset the absence of foreign currency losses. For additional details, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

For the six months ended June 30, 2008, net loss from discontinued operations was $1 million, compared with a net loss of $87 million in 2007. The increase of $86 million was primarily due to the absence of a net loss on the disposal of international businesses sold in 2007.

Derivative Instruments: We account for derivative instruments in accordance with SFAS No. 133. If a contract is a derivative and does not qualify for the normal purchases and sales exception under SFAS No. 133, we record it on our consolidated balance sheet at its fair value.

We measure fair value in accordance with SFAS No. 157. We use a modeling method to value the most material of our derivative liabilities, an electricity sales agreement held by CMS ERM. Because this electricity sales agreement extends beyond the term for which quoted electricity prices are available, our valuation model incorporates a proprietary forward pricing curve for power based on forward gas prices and an implied heat rate. Our model incorporates discounting, credit, and modeling risks. The model is sensitive to power and gas forward prices, and the fair value of this derivative liability will increase as these forward prices increase. We adjust our model each quarter to incorporate market data as it becomes available. The fair value of this derivative liability has increased by $9 million since December 31, 2007. For additional details on how we determine the fair values of our derivatives, see Note 2, Fair Value Measurements. Except as noted in the following paragraph, there have been no significant changes since December 31, 2007 in the amount or types of derivatives that we hold or to how we account for derivatives.

CMS ERM Contracts: In the past, CMS ERM has generally classified all of its derivatives that result in

physical delivery of commodities as non-trading contracts and all of its derivatives that financially settle as trading contracts. Following the restructuring of our DIG investment and the resulting streamlining of CMS ERM’s risk management activities in the first quarter of 2008, we reevaluated the classification of CMS ERM’s derivatives as trading versus non-trading. We determined that all of CMS ERM’s derivatives are held for purposes other than trading. Therefore, during 2008, we have accounted for all of CMS ERM’s derivatives as non-trading derivatives.

For additional details on our derivative activities, see Note 7, Financial and Derivative Instruments.

Factors affecting our liquidity and capital requirements include:

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

Our cash management plan includes controlling operating expenses and capital expenditures and evaluating market conditions for financing opportunities, if needed.

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

In April 2008, Consumers redeemed two of its tax-exempt debt issues with $96 million of refinancing proceeds. Also in April 2008, Consumers converted $35 million of tax-exempt debt previously backed by municipal bond insurers to variable rate demand bonds. These transactions have eliminated Consumers’ variable rate debt backed by municipal bond insurers.

Our operating, investing, and financing activities meet consolidated cash needs. At June 30, 2008, we had $555 million of consolidated cash, which includes $28 million of restricted cash and $12 million held by entities consolidated under FIN 46(R).

Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. During the six months ended June 30, 2008, Consumers paid $168 million in common stock dividends to CMS Energy. For details on dividend restrictions, see Note 5, Financings and Capitalization.

Our Consolidated Statements of Cash Flows include amounts related to discontinued operations through

the date of disposal. The sale of our discontinued operations had no material adverse effect on our liquidity, as we used the sales proceeds to invest in our utility business and to reduce debt. For additional details on discontinued operations, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

For the six months ended June 30, 2008, net cash provided by operating activities was $651 million, an increase of $250 million versus 2007. In addition to an increase in earnings, the increase was primarily due to timing of cash receipts from accounts receivable. We accelerate our collections from customer billings through the sale of accounts receivable. The sale of accounts receivable at the end of 2006 reduced our collections from customers during the first half of 2007. At the end of 2007, we did not rely on sales of accounts receivable and collected customer billings throughout the first half of 2008. This increase was partially offset by a payment made by CMS ERM in February 2008 to terminate electricity sales agreements and the impact of higher gas prices on inventory purchases at Consumers.

For the six months ended June 30, 2008, net cash used in investing activities was $344 million, an increase of $1.823 billion versus 2007. This increase reflects the absence of asset sale proceeds in 2008.

For the six months ended June 30, 2008, net cash used in financing activities was $128 million, a decrease of $214 million versus 2007. This was primarily due to a decrease in net retirements of long-term debt. For additional details on long-term debt activity, see Note 5, Financings and Capitalization.

Revolving Credit Facilities: For details on our revolving credit facilities, see Note 5, Financings and Capitalization.

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 indemnification provisions within certain agreements, surety bonds, letters of credit, and financial and performance guarantees. For additional details on these and other guarantee arrangements, see Note 4, Contingencies, “Other Contingencies – Guarantees and Indemnifications.”

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

Our primary focus will be to continue to invest in our utility system to enable us to meet our customer commitments, to comply with increasingly demanding environmental performance standards, to improve system performance, and to maintain adequate supply and capacity. Our primary focus with respect to our non-utility businesses will be to optimize cash flow and to maximize the value of our assets.

Electric Deliveries: In 2008, we are anticipating a decrease in electric deliveries of approximately one and a half percent. This outlook can be attributed to a decline in industrial economic activity, the cancellation of one wholesale customer contract, and other usage differences primarily due to weather conditions.

Beginning in 2009 and for the four years following, we are projecting an increase in electric deliveries averaging one percent annually. This outlook assumes a modestly growing customer base, implementation of energy efficiency programs, and a stabilizing Michigan economy after 2009. 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. Actual growth from year to year may vary from this trend due to the following:

Electric Customer Revenue Outlook: Michigan’s economy has suffered from closures and restructuring of automotive manufacturing facilities and those of related suppliers and by the sluggish housing market. The Michigan economy also has been harmed by facility closures in the non-manufacturing sector and limited growth. Although our electric utility results are not dependent upon a single customer, or even a few customers, those in the automotive sector represented five percent of our total 2007 electric revenue and three percent of our 2007 electric operating income. We cannot predict the financial impact of the Michigan economy on our electric customer revenue.

Electric Reserve Margin: To reduce the risk of high power supply costs during peak demand periods and to achieve our Reserve Margin target, we purchase electric capacity and energy for the physical delivery of electricity primarily in the summer months. We have purchased capacity and energy covering our Reserve Margin requirements for 2008 and a portion of our Reserve Margin requirements for 2009 and 2010. We currently have a planning Reserve Margin of 13.7 percent for summer 2008, resulting in planned supply resources equal to 113.7 percent of projected firm summer peak load. Of the 2008 supply resources target, we expect 94 percent to come from our electric generating plants and long-term power purchase contracts, with other contractual arrangements making up the remainder. We expect capacity costs for these electric capacity and energy contractual arrangements to be $18 million for 2008.

Electric Transmission Expenses: In 2008, we expect the transmission charges we incur to increase by $42 million compared with 2007 primarily due to a 33 percent increase in METC transmission rates. This increase was included in our 2008 PSCR plan filed with the MPSC in September 2007, which we self-implemented in January 2008.

Balanced Energy Initiative: In January 2007, the governor of Michigan received the MPSC’s 21st Century Electric Energy Plan stating that Michigan would need new base load capacity by 2015. The plan called for the use of more renewable energy resources, the creation of an energy efficiency program, and review procedures for proposed new generation facilities.

In response to the 21st Century Electric Energy Plan, we filed with the MPSC our “Balanced Energy Initiative” which provides a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements. 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. Implementation of the Balanced Energy Initiative will require significant reform of the Customer Choice Act.

In September 2007, we filed with the MPSC an update to our Balanced Energy Initiative, which includes our plan to build an 800 MW advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan. Construction of the proposed new clean coal plant is contingent on obtaining environmental permits and the MPSC’s approval. The Michigan Attorney General filed a motion with the MPSC to dismiss the Balanced Energy Initiative case, claiming that the MPSC lacks jurisdiction over the matter, which the ALJ denied. The Michigan Attorney General and another intervenor have filed an appeal of that decision with the MPSC.

Proposed Energy Legislation: The Michigan legislature is considering various bills related to mandatory renewable energy standards. If enacted, these bills generally would require electric utilities either to obtain a certain percentage of their power from renewable sources or make alternative compliance payments, or purchase allowances in lieu of obtaining the renewable resources. The Michigan legislature is also considering several bills that would reform the Customer Choice Act, introduce energy efficiency programs, modify the timing of rate increase requests, mandate cost allocation methodology and customer rate design, and provide for other regulatory changes. The Michigan Senate approved several bills in June 2008 that differ from the bills passed by the Michigan House of Representatives in April 2008. In July 2008, the Michigan legislature sent the bills to conference committees to resolve these differences. The differences in the bills have to be resolved and the resulting legislation approved by the Michigan House, the Michigan Senate and the Michigan governor before being enacted. We cannot predict whether any of these bills will be enacted or what form the final legislation might take.

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

Electric Environmental Estimates: Our operations are subject to various state and federal environmental laws and regulations. We have been able to recover in customer rates our costs to operate our facilities in compliance with these laws and regulations.

Clean Air Act: We continue to focus on complying with the federal Clean Air Act and the numerous resulting state and federal regulations. From 1998 through June 2008, we have incurred $789 million in capital expenditures to comply with Michigan’s Nitrogen Oxides Implementation Plan. We plan to spend an additional $780 million for equipment installation through 2015 to comply with a number of

environmental regulations, including regulations limiting nitrogen oxides and sulfur dioxide emissions. We expect to recover these costs in customer rates.

Clean Air Interstate Rule: In March 2005, the EPA adopted CAIR, which required additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. CAIR was appealed to the U.S. Court of Appeals for the District of Columbia and on July 11, 2008, the Court issued its decision, vacating CAIR and the CAIR federal implementation plan in their entirety. The decision remands CAIR back to the EPA to form a new rule, which will likely take considerable time. If the decision stands and no further appeals are pursued, this mandate may affect our numerous air regulatory initiatives currently underway. We cannot predict the likelihood of any motions or appeals that may affect the final order vacating CAIR.

State and Federal Mercury Air Rules: In March 2005, the EPA issued the CAMR, which required initial reductions of mercury emissions from coal-fired electric generating plants by 2010 and further reductions by 2018. A number of states and other entities appealed certain portions of the CAMR to the U.S. Court of Appeals for the District of Columbia. The U.S. Court of Appeals for the District of Columbia decided the case in February 2008, and determined that the rules developed by the EPA were not consistent with the Clean Air Act. We continue to monitor the development of federal regulations in this area.

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. If this plan is made effective, we estimate the costs associated with Michigan’s mercury plan will be approximately $530 million by 2015. A draft of the state rule is expected to be issued for comment sometime in 2008.

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 their plants. We responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance.” If the EPA finds that our interpretation is incorrect, we could be required to install additional pollution controls at some or all of our coal-fired electric generating plants and to pay fines. Additionally, we would need to assess the viability of continuing operations at certain plants. We cannot predict the financial impact or outcome of this issue.

Greenhouse Gases: The United States Congress has introduced proposals that would require reductions in emissions of greenhouse gases, including carbon dioxide. These laws, or similar state laws or rules, if enacted, could require us to replace equipment, install additional equipment for pollution controls, purchase allowances, curtail operations, or take other steps. Although associated capital or operating costs relating to greenhouse gas regulation or legislation could be material, and cost recovery cannot be assured, we expect to have an opportunity to recover these costs and capital expenditures in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.

Water: In July 2004, the EPA issued rules that govern existing electric generating plant cooling water intake systems (“Phase II Rule”). These rules require a significant reduction in the number of fish harmed by intake structures at large existing power plants. The EPA compliance options in the rule were challenged before the United States Court of Appeals for the Second Circuit. 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 United States Court of Appeals for the Second Circuit’s ruling is expected to increase significantly the cost of complying with this rule, but we will not know the cost to comply until the EPA’s reconsideration is complete. In April 2008, the U.S. Supreme Court agreed to hear this case, thereby extending the time before this issue is finally resolved.

We cannot estimate the effect of federal or state environmental policies on our future consolidated results of operations, cash flows, or financial position due to the uncertain nature of the policies. We will continue to monitor these developments and respond to their potential implications for our business operations.

For additional details on electric environmental matters, see Note 4, Contingencies, “Consumers’ Electric Utility Contingencies — Electric Environmental Matters.”

Electric ROA: 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 2008, alternative electric suppliers were providing 342 MW of generation service to ROA customers, which is 4 percent of our total distribution load and represents an increase of 13 percent compared with the ROA load at June 2007 of 302 MW.

In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred in 2002 and 2003 through a surcharge applied to ROA customers. Since the MPSC order, we have experienced a downward trend in ROA customers, although recently this trend has slightly reversed. A decline in the number of ROA customers may affect negatively our ability to recover these Stranded Costs in a timely manner, and we may require legislative or regulatory assistance to recover these Stranded Costs fully.

Electric Rate Case: During 2007, we filed applications with the MPSC seeking an 11.25 percent authorized return on equity and, as revised, an annual increase in revenues of $265 million. The filings sought recovery of the costs associated with increased plant investment, including the purchase of the Zeeland power plant, increased equity investment, higher operation and maintenance expenses, recovery of transaction costs from the sale of Palisades, and the approval of an energy efficiency program.

In June 2008, the MPSC issued an order authorizing us to increase base rates by $28 million. This is lower than our revised position primarily due to the MPSC’s authorized return on equity of 10.7 percent and the final determination of our Zeeland plant revenue requirement.

Palisades Regulatory Proceedings: We sold Palisades to Entergy in April 2007. The MPSC order approving the transaction requires that we credit $255 million of excess sale proceeds and decommissioning amounts to our retail customers by December 2008. There are additional excess sales proceeds and decommissioning fund balances of $135 million above the amount in the MPSC order. The MPSC order in our electric rate case instructed us to offset the excess sales proceeds and decommissioning fund balances with $26 million of transaction costs from the Palisades sale and credit the remaining balance over a nine-month period beginning in August 2008.

For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters.”

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers for 35 years beginning in 1990. In June 2008, the MPSC approved an amended and restated MCV PPA. The amended and restated MCV PPA provides for:

This resolves the issues concerning our exercise of the September 2007 regulatory-out provision in the MCV PPA.

For additional details on the MCV PPA, see Note 4, Contingencies, “Other Consumers’ Electric Utility Contingencies — The MCV PPA.”

Gas Deliveries: We expect that gas deliveries in 2008 will decline approximately one percent, on a weather-adjusted basis, relative to 2007 due to continuing conservation and overall economic conditions in Michigan. We expect gas deliveries to average a decline of one-half of one percent annually over the next five years. Actual delivery levels from year to year may vary from this trend due to the following:

Several gas business trends and uncertainties may affect our future financial results and financial condition. These trends and uncertainties could have a material impact on future revenues and 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 4, 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 prudence in annual plan and reconciliation proceedings. For additional details on GCR, see Note 4, Contingencies, “Consumers’ Gas Utility Rate Matters – Gas Cost Recovery.”

Gas Depreciation: In June 2007, the MPSC issued its final order in a generic ARO accounting case and modified the filing requirement for our next gas depreciation case. The order changed the filing requirement date from 90 days after the issuance of that order to no later than August 1, 2008. On August 1, 2008, we filed a gas depreciation case using 2007 data and the ordered variations on traditional cost-of-removal methodologies. We cannot predict the outcome of this matter.

If a final order in our 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 a surcharge, which may be either positive or negative.

2007 Gas Rate Case: In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate increase of $50 million, including an authorized return on equity of 10.75 percent. In September 2007, the MPSC reopened the record in the case to allow all interested parties to be heard concerning the approval of an energy efficiency program, which we proposed in our original filing. In April 2008, the MPSC approved a settlement agreement withdrawing the proposed energy efficiency program and closed the case.

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million based on an 11 percent authorized return on equity. The MPSC staff and intervenors are scheduled to file testimony in August 2008.

Lost and Unaccounted for Gas: Gas utilities typically lose a portion of gas as it is injected into and withdrawn from storage and sent through transmission and distribution systems. We recover the cost of lost and unaccounted for gas through general rate cases, which have traditionally provided recovery, based on an average of the previous five years of actual losses. To the extent that we experience lost and unaccounted for gas that exceeds the previous five-year average, we may be unable to recover these amounts in rates.

Our primary focus with respect to our remaining non-utility businesses is to optimize cash flow and maximize the value of our assets.

In connection with the sale of our Argentine and Michigan assets to Lucid Energy in March 2007, we entered into agreements that granted MEI, an affiliate of Lucid Energy, rights to certain awards or proceeds that we may receive in the future. These included the right to any proceeds from an assignment of the ICSID award associated with TGN, as well as an option to purchase CMS Gas Transmission’s ownership interests in TGN.

In May 2008, the Republic of Argentina had not paid the ICSID award as due, causing its option to purchase our interests in TGN to expire. In June 2008, we executed an agreement with MEI and a third party to assign the ICSID award and to sell our interests in TGN directly to the third party. In accordance with the agreements executed in March 2007, the proceeds from the assignment of the ICSID award and the sale of TGN were passed on to MEI. In light of these events, during the second quarter we recognized in earnings an $8 million deferred gain on the assignment of the ICSID award. For additional details, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

At June 30, 2008, $7 million remains as a deferred credit on our Consolidated Balance Sheets related to MEI’s right to proceeds that Enterprises will receive if it sells its stock interest in CMS Generation San Nicolas Company.

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

Software Implementation: In July 2008, we implemented an integrated business software system for customer billing, finance, purchasing/supply chain, human resources and payroll, and utility asset construction and maintenance work management. We expect the new business software to improve customer service and reduce operating system risk. The total project cost for the initial implementation was $16 million in operating expenses and $174 million in capital expenditures.

Advanced Metering Infrastructure: We are developing an advanced metering system that will provide enhanced controls and information about our customer energy usage and notification of service interruptions. The system also will allow customers to make decisions about energy efficiency and conservation, provide other customer benefits, and reduce costs. We expect to develop integration software and pilot new technology over approximately the next two years, and incur capital expenditures of approximately $800 million over the next seven years. Over the long-term, we do not expect this project to affect customer rates significantly.

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, 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 4, Contingencies and Part II, Item 1. Legal Proceedings.

SFAS No. 157, Fair Value Measurements: This standard, which was effective for us January 1, 2008, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. The implementation of this standard did not have a material effect on our consolidated financial statements. For additional details on our fair value measurements, see Note 2, Fair Value Measurements.

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, implemented in December 2006, required us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase two, implemented in January 2008, required us to change our plan measurement date from November 30 to December 31, effective for the year ending December 31, 2008. For additional details, see Note 8, Retirement Benefits.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: This standard, which was effective for us January 1, 2008, gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We have not elected 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, which was effective for us January 1, 2008. This standard permits us to offset the fair value of derivative instruments held under master netting arrangements with cash collateral received or paid for those derivatives. Adopting this standard resulted in an immaterial reduction to both our total assets and total liabilities. There was no impact on earnings from adopting this standard. We applied the standard retrospectively for all periods presented in our consolidated financial statements. For additional details, see Note 7, Financial and Derivative Instruments, “CMS ERM Contracts.”

EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards:EITF Issue 06-11 requires companies to recognize, as an increase to additional paid-in capital, 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. We implemented EITF Issue 06-11 on January 1, 2008. This implementation did not have a material effect on our consolidated financial statements.

SFAS No. 141(R), Business Combinations: In December 2007, the FASB issued SFAS No. 141(R), which replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes how an acquiring entity should measure and recognize assets acquired, liabilities assumed, and noncontrolling interests acquired through a business combination. The standard also establishes how goodwill or gains from bargain purchases should be measured and recognized and what information the acquirer should disclose to enable users of the financial statements to evaluate the nature and financial effects of a business combination. Costs of an acquisition are to be recognized separately from the business combination. We will apply SFAS No. 141(R) prospectively to any business combination for which the date of acquisition is on or after January 1, 2009.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51: Under SFAS No. 160, effective for us January 1, 2009, ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements. For additional details, see Note 1, Corporate Structure and Accounting Policies.

SFAS No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133: In March 2008, the FASB issued SFAS No. 161, effective for us January 1, 2009. This standard will require entities to provide enhanced disclosures about how and why derivatives are used, how derivatives and related hedged items are accounted for under SFAS No. 133, and how derivatives and related hedged items affect financial position, financial performance, and cash flows. This standard will have no effect on our consolidated financial statements.

FSP FAS 142-3, Determination of the Useful Life of Intangible Assets: In April 2008, the FASB issued FSP FAS 142-3, effective for us January 1, 2009. This standard amends SFAS No. 142,Goodwill and Other Intangible Assets, to require expanded consideration of expected future renewals or extensions of intangible assets when determining their useful life. This standard will be applied prospectively for intangible assets acquired after the effective date. We are evaluating the impact this standard will have on our consolidated financial statements.

FSP APB 14-1, Accounting for Convertible Debt Instruments That May Be Settled In Cash Upon Conversion (Including Partial Cash Settlement): In April 2008, the FASB issued FSP APB 14-1, effective for us January 1, 2009. This standard will apply retroactively to our convertible debt securities, and will require us to account for the liability and equity components separately and in a manner that will reflect our borrowing rate for nonconvertible debt. We are evaluating the impact this standard will have on our consolidated financial statements. For additional details on our convertible debt instruments, see Note 5, Financings and Capitalization.

FSP EITF 03-6-1, Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities: In June 2008, the FASB issued FSP EITF 03-6-1, effective for us January 1, 2009. Under this standard, awards that accrue cash dividends (whether paid or unpaid) when common shareholders receive dividends are considered participating securities if the dividends do not need to be returned to the company when the employee forfeits the award. We have unvested restricted stock awards outstanding that will be considered participating securities and thus will be included in the computation of basic EPS. We are evaluating the impact this standard will have on our consolidated financial statements.

EITF Issue 07-5, Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock: In June 2008, the FASB ratified EITF Issue 07-5, effective for us January 1, 2009. This standard establishes criteria for determining whether freestanding instruments or embedded features are considered “indexed to an entity’s own stock.” This guidance will be relevant to us in assessing the equity conversion features in our contingently convertible senior notes and preferred stock. These conversion features have been exempted from derivative accounting because they are indexed to our own stock and would be classified in stockholders’ equity. We will have to assess whether they are still considered indexed to our own stock under this new guidance. The standard applies to all outstanding instruments at January 1, 2009, with any transition impacts recognized as a cumulative effect adjustment to the opening balance of retained earnings. We are evaluating the impact, if any, this standard will have on our consolidated financial statements.

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