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.

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 April 30, 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’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 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, 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 House of Representatives passed a package of 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, establish mandatory renewable energy standards, and provide for other regulatory changes. These bills are currently awaiting action from the Michigan Senate. In addition, the U.S. Congress is considering various bills relating to mandatory renewable energy standards.

We are implementing an integrated business software system for finance, work management, and other systems. We expect the new business software to be in use in the second half of 2008. 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 the next two years.

In September 2007, we exercised the regulatory-out provision in the MCV PPA, thus limiting the amount we pay the MCV Partnership for capacity and fixed energy to the amount recoverable from our customers. The MCV Partnership may have the right under certain circumstances 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. The MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision.

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 and other market weakness. Although we have not identified any material impacts to our financial condition, we will continue to monitor developments for potential impacts on our business.

For the three months ended March 31, 2008, our net income was $103 million, a $318 million increase versus 2007. The increase relates primarily to the absence in 2008 of charges associated with the exit from our international businesses net of the absence of earnings from these businesses. The change also reflects an increase in net income from our electric and gas utility segments due to favorable impacts from MPSC rate orders.

Specific changes to net income (loss) available to common stockholders for the three months ended March 31, 2008 versus 2007 are:

Electric deliveries and rate increase: For the three months ended March 31, 2008, electric delivery revenues increased by $17 million versus 2007 primarily due to additional revenue of $18 million from the inclusion of the Zeeland power plant in rates. The increase was partially offset by decreased electric revenues of $1 million due to lower deliveries. Deliveries to end-use customers were 9.4 billion kWh, a decrease of 0.1 billion kWh or 1 percent versus 2007.

Palisades revenue to PSCR: Consistent with the MPSC order associated with the April 2007 sale of Palisades, $46 million of base rate revenue related to Palisades is being 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: For the three months ended March 31, 2008, power supply costs and related revenue decreased $3 million versus 2007. This decrease reflects amounts excluded from recovery in the 2006 PSCR reconciliation case.

Operating expenses, other income and non-commodity revenue: For the three months ended March 31, 2008, operating expenses decreased $69 million and non-commodity revenue decreased $8 million versus 2007.

The decrease in operating expenses was primarily due to lower other operating and maintenance expense that resulted from the sale of Palisades in April 2007 and the reduction in operating expense due to the MPSC’s order allowing us to retain a portion of the proceeds from the sale of certain sulfur dioxide allowances. Also decreasing expense was the absence, in 2008, of certain costs which 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 depreciation resulting from an increase in plant in service. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Consumers’ Electric Utility Contingencies.”

The decrease in non-commodity revenue was primarily due to the absence, in 2008, of METC transmission services revenue.

General taxes: For the three months ended March 31, 2008, general tax expense decreased $4 million versus 2007. The decrease was primarily due to the absence, in 2008, of MSBT, which was replaced with the Michigan Business Tax effective January 1, 2008. The decrease was partially offset by higher property tax expense.

Interest charges: For the three months ended March 31, 2008, interest charges increased $5 million versus 2007. The increase was 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 March 31, 2008, income taxes increased $12 million versus 2007. The increase reflects $10 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.

Gas deliveries and rate increase: For the three months ended March 31, 2008, gas delivery revenues increased $13 million versus 2007 due to additional revenue of $21 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by $8 million due to lower system efficiency. Gas deliveries, including miscellaneous transportation to end-use customers, were 137 bcf, a decrease of less than 0.1 bcf or less than 0.1 percent versus 2007.

Gas wholesale and retail services, other gas revenues, and other income: For the three months ended March 31, 2008, gas wholesale and retail services, other gas revenues and other income decreased $4 million versus 2007. The decrease reflects lower pipeline capacity optimization revenue.

Operating expenses: For the three months ended March 31, 2008, other operating expenses increased $3 million versus 2007. The increase was primarily due to higher customer service expense, which reflected an increase in uncollectible accounts expense, and higher operating expense across our storage, transmission and distribution systems.

General taxes and depreciation: For the three months ended March 31, 2008, general taxes and depreciation increased $2 million versus 2007. Depreciation expense increased $5 million due to an increase in plant in service, partially offset by reduced general taxes of $3 million due to the absence, in 2008, of MSBT, which was replaced by the Michigan Business Tax effective January 1, 2008.

Interest charges: For the three months ended March 31, 2008, interest charges decreased $4 million versus 2007 primarily due to lower average debt levels and a lower average interest rate.

Income taxes: For the three months ended March 31, 2008, income taxes increased $3 million versus 2007. The increase reflects $3 million due to higher earnings and $3 million due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008. These increases were partially offset by a decrease of $3 million primarily related to the treatment of property, plant and equipment, as required by the MPSC orders.

Operating revenues: For the three months ended March 31, 2008, operating revenues decreased $42 million versus 2007. The decrease was due to the absence, in 2008, of third-party gas sales of $46 million resulting primarily from the termination of a gas sales contract, lower mark-to-market gains of $6 million related to power and gas sales contracts versus 2007, and the absence, in 2008, of revenue of $1 million from assets sold in 2007. These decreases were partially offset by increased power sales of $8 million and gains recorded from third-party financial settlements of $3 million.

Cost of gas and purchased power: For the three months ended March 31, 2008, cost of gas and purchased power decreased $48 million versus 2007. The decrease was due to the absence, in 2008, of third-party gas purchases of $41 million resulting primarily from the termination of a gas supply contract, mark-to-market losses of $5 million on gas supply contracts, and a decrease in purchased power costs of $2 million.

Earnings from equity method investees: For the three months ended March 31, 2008, equity earnings decreased $20 million versus 2007. The decrease was due to the absence of $16 million of earnings from our investments in Africa, the Middle East and India that were sold in May 2007. Also contributing to the decrease was the absence, in 2008, of $3 million of earnings associated with our remaining asset in Argentina and $1 million of earnings from our investment in Jamaica that was sold in October 2007.

Gain on sale of assets, net: For the three months ended March 31, 2008, there were no gains or losses on asset sales. For the three months ended March 31, 2007 the net gain on asset sales was $12 million. For additional details, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Operation and maintenance: For the three months ended March 31, 2008, operation and maintenance expenses decreased $16 million versus 2007 due to the absence, in 2008, of expenses associated with assets sold during 2007.

2007 asset impairment charges: For the three months ended March 31, 2007, we recorded asset impairment charges of $242 million for the reduction in fair value of our investments in TGN, Jamaica and PowerSmith. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Fixed charges: For the three months ended March 31, 2008, fixed charges decreased $3 million versus 2007 due to the absence of interest expense at businesses sold in 2007.

Income taxes: For the three months ended March 31, 2008, income tax expense increased $39 million versus 2007. The increase reflects $83 million of additional tax expense on higher earnings, partially offset by the absence of $44 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 March 31, 2008, net loss from corporate interest and other was $24 million, versus net income of $53 million in 2007. The decrease in net income of $77 million is primarily due to the one-time recognition, in 2007, of certain tax benefits related to the sale of our international operations.

For the three months ended March 31, 2008, there was no net income from discontinued operations. The $178 million net loss for March 31, 2007 was primarily due to losses related to the March 2007 sale of Argentine businesses and non-utility natural gas assets in Michigan. For additional details, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

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. The most material of our derivative liabilities, an electricity sales agreement at CMS ERM, is valued using a modeling method. Because this electricity sales agreement extends beyond the term for which quoted electricity prices are available, our valuation model incorporates a proprietary forward power pricing curve that is based on forward gas prices and an implied heat rate. Our model incorporates discounting, credit, and model risks. The model is sensitive to power and gas forward prices, and the fair value of this derivative liability will increase with increases in these forward prices. We adjust our model each quarter to incorporate market data as it becomes available.

There has been no material change in the fair value of the derivative liability since December 31, 2007. For further discussion of 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 a commodity as non-trading contracts and all of its derivatives that financially settle as trading contracts. Following the recent restructuring of our DIG investment and the resulting streamlining of CMS ERM’s risk management activities, 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 the first quarter of 2008, we 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 placed in escrow accounts. Also in April 2008, Consumers converted $35 million of tax-exempt debt previously backed by monoline insurers to variable rate demand bonds. These transactions have eliminated our variable rate debt backed by monoline insurers.

Our operating, investing, and financing activities meet consolidated cash needs. At March 31, 2008, we had $964 million of consolidated cash, which includes $123 million of restricted cash and $4 million held by entities consolidated under FIN 46(R).

Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For the three months ended March 31, 2008, Consumers paid $113 million in common stock dividends to CMS Energy. For details on dividend restrictions, see Note 5, Financings and Capitalization.

Our cash flow statements 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 three months ended March 31, 2008, net cash provided by operating activities was $474 million, an increase of $159 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 quarter of 2007. During the first quarter of 2008, we did not rely on sales of accounts receivable and collected customer billings throughout the period. This increase was partially offset by a payment made by CMS ERM in February 2008 to terminate electricity sales agreements.

For the three months ended March 31, 2008, net cash used in investing activities was $152 million, an increase of $158 million versus 2007. This increase was a result of the absence of asset sale proceeds in 2008, offset partially by a decrease in capital expenditures at Consumers.

For the three months ended March 31, 2008, net cash provided by financing activities was $171 million, an increase of $228 million versus 2007. This was primarily due to an increase in net proceeds from the issuance 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 investment 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 remaining assets.

Growth: We expect electric deliveries to decline in 2008 by three-quarters of a percent compared with 2007 levels. This outlook assumes a decline in industrial economic activity and normal weather conditions throughout the remainder of the year, and reflects the cancellation of one wholesale customer contract effective in January 2008.

We expect growth in electric deliveries to average approximately one percent annually over the next five years. 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. 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 a portion of our Reserve Margin requirements for 2008 through 2010. We are currently planning for a Reserve Margin of 13.7 percent for summer 2008, resulting in a planned supply resources target 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.

In September 2007, we exercised the regulatory-out provision in the MCV PPA, thus limiting the amount we pay the MCV Partnership for capacity and fixed energy to the amount recoverable from our customers. The MCV Partnership may have the right under certain circumstances to terminate the MCV PPA, which could affect our ability to achieve our Reserve Margin target for 2008. The MCV PPA represents 13 percent of our 2008 expected supply resources. For additional details, see “The MCV PPA” within this MD&A.

Electric Transmission Expenses: In 2008, we expect the transmission charges we incur to increase by $42 million due primarily 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.

In September 2007, the FERC approved a proposal to include 100 percent of the costs of network upgrades associated with new generator interconnections in the rates of certain MISO transmission owners, including METC. Previously, those transmission owners shared interconnection network upgrade costs with generators. Consumers, Detroit Edison, the MPSC, and other parties filed a request for rehearing of the FERC order, which was denied in April 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 legislative repeal or 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. Our current plan is for the plant to begin operating in 2015 and to use 500 MW of the plant’s output to serve Consumers’ customers and commit the remaining 300 MW to others. We estimate our share of the cost at $1.6 billion including financing costs. 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 U.S. Congress and the Michigan legislature are considering various bills related to mandatory renewable energy standards. If enacted, these bills generally would require electric utilities either to attain a certain percentage of their power from renewable sources or pay fees, or purchase allowances in lieu of having 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. In April 2008, the Michigan House of Representatives passed a package of bills that are now awaiting action from the Michigan Senate. 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 resulting state and federal regulations. From 1998 to present, we have incurred $787 million in capital expenditures to comply with Michigan’s Nitrogen Oxides Implementation Plan.

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. The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of Columbia. We are expecting a decision on this rule during 2008 and cannot predict the outcome of this matter.

We plan to spend an additional $835 million for equipment installation through 2015, which we expect to recover in customer rates. The key assumptions in the capital expenditure estimate include:

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 $500 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. 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 granted certiorari in this matter, which will likely extend 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 March 2008, alternative electric suppliers were providing 330 MW of generation service to ROA customers, which is 4 percent of our total distribution load and represents an increase of 17 percent compared with the ROA load at March 2007 of 283 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 March 2008, the ALJ’s Proposal for Decision recommended that base rates be set to produce revenues $40 million lower than our filed position. The difference is primarily due to the ALJ’s lower recommended return on equity of 10.42 percent.

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 has not yet addressed the distribution of these additional amounts. In addition, recovery of our transaction costs of $28 million is under review by the MPSC in our current electric rate case.

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 electricity to Consumers for 35 years beginning in 1990. In September 2007, we exercised the regulatory-out provision in the MCV PPA, thus limiting the amount we pay the MCV Partnership for capacity and fixed energy to the amount recoverable from our customers. The MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision. We believe that the provision is valid and fully effective and have not recorded any reserves, but we cannot predict whether we would prevail in the event of litigation on this issue.

As a result of our exercise of the regulatory-out provision, the MCV Partnership may have the right under certain circumstances to terminate the MCV PPA or reduce the amount of capacity sold under the MCV PPA. If the MCV Partnership terminates or reduces the amount of capacity sold under the MCV PPA, we will seek to replace the lost capacity to maintain an adequate electric Reserve Margin. This could involve entering into a new power purchase agreement and (or) entering into electric capacity contracts on the open market. We cannot predict whether we could enter into such contracts at a reasonable price. We are also unable to predict whether we would receive regulatory approval of the terms and conditions of such contracts, or whether the MPSC would allow full recovery of our incurred costs.

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

Growth: We expect that gas deliveries in 2008 will remain flat, 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 prudency 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. Additionally, the order requires us to use 2007 data and to prepare a cost-of-removal depreciation study with five alternatives using the MPSC’s prescribed methods. We cannot predict the outcome of the analysis.

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 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 to remove the 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 and an 11 percent authorized return on equity.

Lost and Unaccounted for Gas: Gas utilities typically lose a portion of gas as it is sent through transmission, storage 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 grant Lucid Energy rights to certain awards or proceeds that we may receive in the future. These rights include the right to any proceeds from and assignment of the ICSID award regarding TGN, as well as an option to purchase CMS Gas Transmission’s ownership interests in TGN. As of March 31, 2008, $15 million remains as a deferred credit on our Consolidated Balance Sheets related to these agreements.

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

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 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.

Software Implementation: We are implementing an integrated business software system for finance, purchasing/supply chain, customer billing, human resources and payroll, and utility asset construction and maintenance work management. We expect the new business software, scheduled to be in use in the second half of 2008, to improve customer service and reduce operating system risk. Including work performed to date, we expect the total project cost to be $16 million in operating expenses and $174 million in capital expenditures for the initial implementation.

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 became effective 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 further 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 on 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 further 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 how the acquirer determines what information should be disclosed 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 combinations 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 further 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 FASB Statement 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 FSP FAS 142-3 will have on our consolidated financial statements.

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These interim Consolidated Financial Statements have been prepared by CMS Energy in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. As a result, CMS Energy has condensed or omitted certain information and footnote disclosures normally included in consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States. CMS Energy has reclassified certain prior year amounts to conform to the presentation in the current year, including certain amounts reclassified to discontinued operations. Therefore, the consolidated financial statements for the three months ended March 31, 2007 have been updated for amounts previously reported. In management’s opinion, the unaudited information contained in this report reflects all adjustments of a normal recurring nature necessary to ensure the fair presentation of financial position, results of operations and cash flows for the periods presented. The Notes to Consolidated Financial Statements and the related Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and related Notes contained in CMS Energy’s Form 10-K for the year ended December 31, 2007. Due to the seasonal nature of CMS Energy’s operations, the results presented for this interim period are not necessarily indicative of results to be achieved for the fiscal year.

Corporate Structure: 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 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.

Principles of Consolidation: The consolidated financial statements comprise CMS Energy, Consumers, Enterprises, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with FIN 46(R). We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. We eliminate intercompany transactions and balances.

Use of Estimates: We prepare our consolidated financial statements in conformity with U.S. GAAP. We are required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates.

We record estimated liabilities for contingencies in our consolidated financial statements when it is probable that a liability has been incurred, and when the amount of loss can be reasonably estimated. For additional details, see Note 4, Contingencies.

Revenue Recognition Policy: We recognize revenues from deliveries of electricity and natural gas, and from the transportation, processing, and storage of natural gas when services are provided. We record unbilled revenues for the estimated amount of energy delivered to customers but not yet billed. Our estimate of unbilled revenues at March 31, 2008 is more significant than at December 31, 2007 because of changes in our customer meter reading schedules to accomodate the launch of our new billing systems in the second half of 2008. This is reflected in our unbilled receivables of $520 million at March 31, 2008 and $490 million at December 31, 2007. We record sales tax on a net basis and exclude it from revenues. We recognize revenues on sales of marketed electricity, natural gas, and other energy products at delivery. For contracts that qualify as derivatives, we recognize changes in the fair value of those contracts (mark-to-market gains and losses) in earnings as the changes occur.

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Reclassifications: We have reclassified certain prior-period amounts on our Consolidated Financial Statements to conform to the presentation for the current period. These reclassifications did not affect consolidated net loss or cash flows for the periods presented. The most significant of these reclassifications is related to certain subsidiaries reclassified as Discontinued Operations in our Consolidated Statements of Income (Loss). For additional details, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges, “Discontinued Operations.”

New Accounting Standards Not Yet Effective: 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 interest acquired through a business combination. The standard also establishes how goodwill or gains from bargain purchases should be measured and recognized and how the acquirer determines what information should be disclosed 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 combinations 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: In December 2007, the FASB issued 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. Any changes in our ownership interests while control is retained will be treated as equity transactions. In addition, this standard requires presentation and disclosure of the allocation between controlling and noncontrolling interests’ income from continuing operations, discontinued operations, and comprehensive income and a reconciliation of changes in the consolidated statement of equity during the reporting period. The presentation and disclosure requirements of the standard will be applied retrospectively for all periods presented. All other requirements will be applied prospectively. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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 FASB Statement 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 FSP FAS 142-3 will have on our consolidated financial statements.

SFAS No. 157, which became effective January 1, 2008, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. It does not require any new fair value measurements, but applies to those fair value measurements recorded or disclosed under other accounting standards. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants, and requires that fair value measurements incorporate all assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. The standard also eliminates the prohibition against

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recognizing “day one” gains and losses on derivative instruments. We did not hold any derivatives with “day one” gains or losses during the quarter ended March 31, 2008. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we held during the quarter ended March 31, 2008.

SFAS No. 157 establishes a fair value hierarchy that prioritizes inputs used to measure fair value according to their observability in the market. The three levels of the fair value hierarchy are as follows:

To the extent possible, we use quoted market prices or other observable market pricing data in valuing assets and liabilities measured at fair value under SFAS No. 157. If such information is unavailable, we use market-corroborated data or reasonable estimates about market participant assumptions. We classify fair value measurements within the fair value hierarchy based on the lowest level of input that is significant to the fair value measurement in its entirety.

The FASB has issued a one-year deferral of SFAS No. 157 for nonfinancial assets and liabilities, except those that are recorded or disclosed at fair value on a recurring basis. Under this partial deferral, SFAS No. 157 will not be effective until January 1, 2009 for fair value measurements in the following areas:

SFAS No. 157 was effective January 1, 2008 for our derivative instruments and available-for-sale investment securities. The implementation of this standard did not have a material effect on our consolidated financial statements.

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The following table summarizes, by level within the fair value hierarchy, our assets and liabilities accounted for at fair value on a recurring basis at March 31, 2008.