UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-Q

þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2007

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

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

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act.
CMS Energy Corporation : Large accelerated filer  þ      Accelerated filer  o      Non-Accelerated filer  o
Consumers Energy Company : Large accelerated filer  o      Accelerated filer  o      Non-Accelerated filer  þ

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock at October 30, 2007:

 

 

CMS Energy Corporation
and
Consumers Energy Company

Quarterly reports on Form 10-Q to the
United States Securities and Exchange Commission
for the Quarter Ended September 30, 2007

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

TABLE OF CONTENTS

		Page
Glossary		3
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements
CMS Energy Corporation
Consolidated Statements of Income (Loss)		CMS – 33
Consolidated Statements of Cash Flows		CMS – 35
Consolidated Balance Sheets		CMS – 36
Consolidated Statements of Common Stockholders’ Equity		CMS – 38
Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies		CMS – 39
2. Asset Sales, Discontinued Operations and Impairment Charges		CMS – 42
3. Contingencies		CMS – 58
4. Financings and Capitalization		CMS – 61
5. Earnings Per Share		CMS – 64
6. Financial and Derivative Instruments		CMS – 65
7. Retirement Benefits		CMS – 69
8. Income Taxes		CMS – 70
9. Asset Retirement Obligations		CMS – 72
10. Equity Method Investments		CMS – 74
11. Reportable Segments		CMS – 75
Consumers Energy Company
Consolidated Statements of Income		CE – 25
Consolidated Statements of Cash Flows		CE – 26
Consolidated Balance Sheets		CE – 27
Consolidated Statements of Common Stockholder’s Equity		CE – 29
Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies		CE – 31
2. Asset Sales		CE – 33
3. Contingencies		CE – 35
4. Financings and Capitalization		CE – 45
5. Financial and Derivative Instruments		CE – 46
6. Retirement Benefits		CE – 47
7. Asset Retirement Obligations		CE – 49
8. Income Taxes		CE – 51
9. Reportable Segments		CE – 53

TABLE OF CONTENTS
(Continued)

		Page
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
CMS Energy Corporation
Forward-Looking Statements and Information		CMS	– 1
Executive Overview		CMS	– 4
Results of Operations		CMS	– 6
Critical Accounting Policies		CMS	– 15
Capital Resources and Liquidity		CMS	– 19
Outlook		CMS	– 21
Implementation of New Accounting Standards		CMS	– 30
New Accounting Standards Not Yet Effective		CMS	– 31
Consumers Energy Company
Forward-Looking Statements and Information		CE	– 1
Executive Overview		CE	– 4
Results of Operations		CE	– 6
Critical Accounting Policies		CE	– 11
Capital Resources and Liquidity		CE	– 13
Outlook		CE	– 15
Implementation of New Accounting Standards		CE	– 23
New Accounting Standards Not Yet Effective		CE	– 24
Item 3. Quantitative and Qualitative Disclosures about Market Risk		CO	– 1
Item 4. Controls and Procedures		CO	– 1
PART II – OTHER INFORMATION
Item 1. Legal Proceedings		CO	– 1
Item 1A. Risk Factors		CO	– 6
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		CO	– 9
Item 3. Defaults Upon Senior Securities		CO	– 9
Item 4. Submission of Matters to a Vote of Security Holders		CO	– 9
Item 5. Other Information		CO	– 9
Item 6. Exhibits		CO	– 10
Signatures		CO	– 11
CMS Energy Corporation Bylaws
Consumers Energy Company Bylaws
Form of Indemnification Agreement between CMS Energy Corporation & its Directors
Form of Indemnification Agreement between Consumers Energy Company & its Directors
CMS Energy Corporation's Certification of the CEO pursuant to Section 302
CMS Energy Corporation's Certification of the CFO pursuant to Section 302
Consumers Energy Corporation's Certification of the CEO pursuant to Section 302
Consumers Energy Corporation's Certification of the CFO pursuant to Section 302
CMS Energy Corporation's Certifications pursuant to Section 906
Consumers Energy Corporation's Certifications pursuant to Section 906

CMS Energy Corporation

Management’s Discussion and Analysis

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

Forward-looking statements and information

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

	•		the price of CMS Energy Common Stock, capital and financial market conditions, and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets, including availability of financing to CMS Energy, Consumers, or any of their affiliates, and the energy industry,
	•		market perception of the energy industry, CMS Energy, Consumers, or any of their affiliates,
	•		the ability of CMS Energy affiliates with interests in the DIG power plant to effectively restructure power supply agreements on a timely basis,
	•		factors affecting utility and diversified energy operations, such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints,
	•		the impact of possible regulations or laws regarding carbon dioxide and other greenhouse gas emissions,
	•		national, regional, and local economic, competitive, and regulatory policies, conditions and developments,
	•		adverse regulatory or legal decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such decisions, including but not limited to those that may affect Bay Harbor,

•

potentially adverse regulatory treatment and (or) regulatory delay or failure to receive timely regulatory orders concerning a number of significant questions presently or potentially before the MPSC, including:

	•		recovery of Clean Air Act capital and operating costs and other environmental and safety-related expenditures,
	•		recovery of power supply and natural gas supply costs when fuel prices are increasing and (or) fluctuating,
	•		timely recognition in rates of additional equity investments in Consumers,
	•		adequate and timely recovery of additional electric and gas rate-based investments,
	•		adequate and timely recovery of higher MISO energy and transmission costs,
	•		recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers,
	•		recovery of Palisades plant sale-related costs,
	•		authorization of Zeeland power plant purchase costs, and
	•		authorization of a new clean coal plant,

	•		the effects on our ability to purchase capacity to serve our customers and fully recover the cost of these purchases, if the owners of the MCV Facility exercise their right to terminate the MCV PPA,
	•		the ability of Consumers to utilize its regulatory out rights as it pertains to the MCV PPA,
	•		the ability of Consumers to recover Big Rock decommissioning funding shortfalls and nuclear fuel storage costs due to the DOE’s failure to accept spent nuclear fuel on schedule, including the outcome of pending litigation with the DOE,
	•		federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of market-based sales authorizations in wholesale power markets without price restrictions,
	•		energy markets, including availability of capacity and the timing and extent of changes in commodity prices for oil, coal, natural gas, natural gas liquids, electricity and certain related products due to lower or higher demand, shortages, transportation problems, or other developments,
	•		our ability to collect accounts receivable from our customers,
	•		earnings volatility as a result of the GAAP requirement that we utilize mark-to-market accounting on certain energy commodity contracts and interest rate swaps, which may have, in any given period, a significant positive or negative effect on earnings, which could change dramatically or be eliminated in subsequent periods,
	•		the effect on our utility and utility revenues of the direct and indirect impacts of the continued economic downturn experienced by the Michigan economy,
	•		potential disruption or interruption of facilities or operations due to accidents, war, terrorism, or changing political environment, and the ability to obtain or maintain insurance coverage for such events,
	•		technological developments in energy production, delivery, and usage,

	•		achievement of capital expenditure and operating expense goals,
	•		changes in financial or regulatory accounting principles or policies,
	•		changes in domestic or foreign tax laws, or new IRS or foreign governmental interpretations of existing or past tax laws,
	•		changes in federal or state regulations or laws that could have an impact on our business,
	•		outcome, cost, and other effects of legal or administrative proceedings, settlements, investigations or claims, including claims, damages, and fines resulting from round-trip trading and alleged inaccurate commodity price reporting, including the outcome of investigations by the DOJ regarding round-trip trading and price reporting,
	•		disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance and performance bonds,
	•		potential assertion of indemnity or warranty claims with respect to previously owned assets and businesses,
	•		credit ratings of CMS Energy, Consumers, or any of their affiliates,
	•		other business or investment considerations that may be disclosed from time to time in CMS Energy’s or Consumers’ SEC filings, or in other publicly issued written documents, and
	•		other uncertainties that are difficult to predict, many of which are beyond our control.

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

Executive Overview

CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving 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, and gas distribution, transmission, and storage. Our businesses are affected primarily by:

	•		weather, especially during the normal heating and cooling seasons,
	•		economic conditions, primarily in Michigan,
	•		regulation and regulatory issues that affect our electric and gas utility operations,
	•		energy commodity prices,
	•		interest rates, and
	•		our debt credit rating.

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

We have completed the sale of all of our international Enterprises assets, using the proceeds to retire debt and to invest in our utility business. Asset sales completed in 2007 include:

	•		a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy for $130 million in March 2007,
	•		our ownership interest in El Chocon, an Argentine hydroelectric generating business, to Endesa, S.A. for $50 million in March 2007,
	•		our ownership interest in SENECA and certain associated generating equipment to PDVSA for $106 million in April 2007,
	•		our ownership interest in businesses in the Middle East, Africa, and India to TAQA for $900 million in May 2007,
	•		CMS Energy Brasil S.A. to CPFL Energia S.A., a Brazilian utility, for $211 million in June 2007,
	•		our investment in GasAtacama to Endesa S.A. for $80 million in August 2007, and
	•		our investment in Jamaica to AEI for $14 million in October 2007.

We also made important progress at Consumers to reduce business risk and to meet the future needs of our customers. We sold Palisades to Entergy in April 2007 for $380 million. The final purchase price, subject to various closing adjustments, resulted in us receiving $363 million as of September 30, 2007. The sale also resulted in an immediate improvement in our cash flow, a reduction in our nuclear operating and decommissioning risk, and an improvement in our financial flexibility to support other utility investments.

In September 2007, we claimed relief under the regulatory-out provision in the MCV PPA, thereby limiting our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. As a result of our exercise of the regulatory-out provision, the MCV Partnership may,

under certain circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA, which could affect our need to build or purchase additional generating capacity. The MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision.

We introduced our Balanced Energy Initiative, a comprehensive plan to meet customer energy needs over the next 20 years, in May 2007. The plan, as filed with the MPSC, is designed to meet the growing customer demand for electricity with energy efficiency, demand management, expansion of the use of renewable energy, and development of new power plants to complement existing generating sources. In September 2007, we filed the second phase of our Balanced Energy Initiative with the MPSC, which contains our plan for construction of a new 800 MW clean coal plant at an existing site located near Bay City, Michigan. Our plan calls for 500 MW of the plant’s output to be used for our customers in Michigan and to commit the remaining 300 MW to others. We expect the plant to enter operation in 2015 with our share of the cost estimated at $1.3 billion excluding financing costs and $1.6 billion with financing costs.

In May 2007, we entered an agreement to buy a 946 MW natural gas-fired power plant located in Zeeland, Michigan from Broadway Gen Funding LLC, an affiliate of LS Power Group, for $517 million. We expect to close by early 2008, subject to approval from the MPSC.

We took an important step in our business plan in January 2007 by reinstating a quarterly dividend of $0.05 per share on our common stock, after a four-year suspension. For the nine months ended September 30, 2007, we paid $34 million in common stock dividends. We also resolved a long-outstanding litigation issue. In September 2007, we settled two class action lawsuits related to round-trip trading by CMS MST. We believe that eliminating this business uncertainty was in the best interests of our shareholders.

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

In the future, we will focus our strategy on:

	•		reducing parent debt,
	•		continued investment in our utility business,
	•		growing earnings while controlling operating costs, and
	•		principles of safe, efficient operations, customer value, fair and timely regulation, and consistent financial performance.

As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been hampered by negative developments in Michigan’s automotive industry and limited growth in the non-automotive sectors of the state’s economy.

Results of Operations

CMS Energy Consolidated Results of Operations

In Millions (except for per share amounts)
Three months ended September 30		2007				2006				Change
Net Income (Loss) Available to Common Stockholders		$	82			$	(103	)		$	185
Basic Earnings (Loss) Per Share		$	0.37			$	(0.47	)		$	0.84
Diluted Earnings (Loss) Per Share		$	0.34			$	(0.47	)		$	0.81
Electric Utility		$	67			$	93			$	(26	)
Gas Utility			(8	)			(20	)			12
Enterprises (Includes the MCV Partnership and FMLP interests)			58				(133	)			191
Corporate Interest and Other			(35	)			(54	)			19
Discontinued Operations			—				11				(11	)
Net Income (Loss) Available to Common Stockholders		$	82			$	(103	)		$	185

For the three months ended September 30, 2007, our net income was $82 million, a $185 million increase compared to our 2006 third quarter net loss. Compared with the third quarter of 2006, net loss from our gas utility decreased, reflecting the positive effect of an MPSC gas rate order. At our Enterprises and Corporate segments, the positive impacts from the recognition of an insurance award, the recognition of a gain related to our sale of assets to Lucid, and the absence of a 2006 asset impairment charge more than offset the absence of a 2006 property tax refund at the MCV Partnership. Net income was negatively impacted by decreased Palisades-related earnings at our electric utility and the absence of earnings from discontinued operations.

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

In Millions
	•			absence of a 2006 asset impairment of our investment in GasAtacama,			169
	•			recognition of an insurance reimbursement related to the non-payment by the Argentine government of our ICSID award,			48
	•			increase in earnings from our gas utility primarily due to the positive effect of an MPSC gas rate order,			12
	•			recognition of a gain associated with the sale of our Argentine and Michigan assets to Lucid Energy,			11
	•			increase in earnings from Enterprises primarily due to decreased operating and maintenance expenses, and mark-to-market gains at CMS ERM compared to losses in 2006, partially offset by the absence of earnings from equity method investments that were sold in 2007,			8
	•			absence of a 2006 property tax refund at the MCV Partnership,			(26	)
	•			decreased Palisades-related earnings at our electric utility partially offset by lower operating and maintenance expenses, and			(26	)
	•			reduction in earnings from discontinued operations.			(11	)
Total Change						$	185

In Millions (except for per share amounts)
Nine months ended September 30		2007				2006				Change
Net Loss Available to Common Stockholders		$	(100	)		$	(58	)		$	(42	)
Basic Loss Per Share		$	(0.45	)		$	(0.26	)		$	(0.19	)
Diluted Loss Per Share		$	(0.45	)		$	(0.26	)		$	(0.19	)
Electric Utility		$	158			$	159			$	(1	)
Gas Utility			53				14				39
Enterprises (Includes the MCV Partnership and FMLP interests)			(173	)			(215	)			42
Corporate Interest and Other			(51	)			(48	)			(3	)
Discontinued Operations			(87	)			32				(119	)
Net Loss Available to Common Stockholders		$	(100	)		$	(58	)		$	(42	)

For the nine months ended September 30, 2007, our net loss was $100 million, a $42 million increase in net loss compared to 2006. Compared with the nine months ended September 30, 2006, net income from our gas and electric utilities increased, reflecting the positive effect of an MPSC gas rate order, an increase in gas deliveries due to weather, and lower operating and maintenance expenses. These impacts were partially offset by decreased Palisades-related earnings at our electric utility. At our Enterprises and Corporate segments, the positive impacts from a reduction in net asset impairment charges, and gains from mark-to-market activity compared to losses in 2006, more than offset the net negative impact of taxes and the absence of earnings from equity investments sold in 2007. Net income was negatively impacted by activities associated with discontinued operations as the net loss on the disposal of international businesses in 2007 replaced earnings recorded for these businesses in 2006.

Specific changes to net loss available to common stockholders for the nine months ended September 30, 2007 versus 2006 are:

In Millions
	•			impairments of our investments in TGN, GasAtacama, Jamaica, and PowerSmith,		$	(181	)
	•			impact of activities associated with discontinued operations as the net loss on the disposal of international businesses in 2007 replaced earnings recorded for these businesses in 2006,			(119	)
	•			absence of tax benefits recorded at Corporate and Enterprises in 2006 from the resolution of an IRS income tax audit,			(54	)
	•			the establishment of a tax provision on the cumulative undistributed earnings of foreign subsidiaries sold in 2007, compared to tax benefits recorded in 2006,			(67	)
	•			absence of earnings from our equity method investments that were sold in 2007,			(17	)
	•			absence of an insurance reimbursement received for previously incurred legal expenses,			(15	)
	•			premiums paid on the early retirement of corporate debt,			(6	)
	•			absence of a 2006 GasAtacma impairment,			169
	•			reduction to our corporate deferred tax valuation allowances associated with capital loss carryforwards and foreign basis differences primarily due to the sale of international businesses in 2007 compared to an increase in the valuation allowance in 2006,			94
	•			recognition of an insurance reimbursement related to the non-payment by the Argentine government of our ICSID award,			48
	•			increase in earnings at our gas and electric utility segments,			38
	•			absence of mark-to-market losses net of operating earnings from our investment in the MCV Partnership, and			35
	•			additional increase in earnings at Enterprises primarily due to mark-to-market gains at CMS ERM compared to losses in 2006 and gains associated with asset sales.			33
Total Change						$	(42	)

Electric deliveries: For the three months ended September 30, 2007, electric delivery revenues decreased $6 million versus 2006, as deliveries to end-use customers were 10.5 billion kWh, a decrease of less than 0.1 billion kWh or less than 1 percent versus 2006. The decrease in electric deliveries for the three months ended September 30, 2007 is primarily due to unfavorable weather. For the nine months ended September 30, 2007, electric delivery revenues increased $26 million versus 2006, as deliveries to end-use customers were 29.5 billion kWh, an increase of 0.5 billion kWh or 2 percent versus 2006. The increase in electric deliveries for the nine months ended September 30, 2007 is primarily due to favorable weather.

Surcharge revenue : In the first quarter of 2006, we started collecting a surcharge that the MPSC authorized under Section 10d(4) of the Customer Choice Act. The surcharge factors increased in January 2007 pursuant to a MPSC order. The increase in the surcharge factors increased electric delivery revenue by $3 million for the three months ended September 30, 2007 and $11 million for the nine months ended September 30, 2007 versus 2006.

Palisades revenue to PSCR: As a result of the sale of Palisades, electric revenue of $50 million for the three months ended September 30, 2007 and $91 million for the nine months ended September 30, 2007, related to Palisades rate base is now designated toward recovery of PSCR costs.

Power supply costs and related revenue: PSCR revenue decreased by $6 million for the three months ended September 30, 2007 and $18 million for the nine months ended September 30, 2007 versus 2006. These decreases primarily reflect amounts excluded from recovery in the 2006 PSCR Reconciliation case. A portion of these excluded costs are instead being recovered through Electric Delivery Revenue. The decrease also reflects the absence, in 2007, of an increase in Power Supply Revenue associated with the 2005 PSCR Reconciliation case.

Other operating expenses, other income and non-commodity revenue: For the three months ended September 30, 2007, other operating expenses decreased $30 million, other income increased $10 million, and non-commodity revenue decreased $7 million versus 2006. For the nine months ended September 30, 2007, other operating expenses decreased $79 million, other income increased $26 million, and non-commodity revenue decreased $8 million versus 2006.

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

For the three months ended September 30, 2007, the increase in other income was primarily due to higher interest income mainly due to the proceeds from the sale of Palisades and equity infusions from the parent. For the nine months ended September 30, 2007, the increase in other income was primarily due to higher interest income and higher income associated with our Section 10d(4) Regulatory Asset. The increase on our Section 10d(4) Regulatory Asset reflects the absence, in 2007, of the impact of the MPSC’s final order in this case.

General taxes: For the three months ended September 30, 2007, general tax expense increased primarily due to higher property tax and MSBT tax expense. For the nine months ended September 30, 2007, general tax expense increased primarily due to higher property tax, sales and use tax expense, and MSBT tax expense.

Interest charges: For the three months ended September 30, 2007, interest charges increased $7 million versus 2006. For the nine months ended September 30, 2007, interest charges increased $13 million versus 2006. 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 and nine months ended September 30, 2007, income taxes decreased versus 2006 primarily due to lower earnings.

Gas deliveries: For the three months ended September 30, 2007, gas deliveries decreased less than 1 bcf or 1 percent versus 2006. Despite lower gas deliveries, gas delivery revenue increased by $5 million due to higher estimated system efficiency.

For the nine months ended September 30, 2007, gas delivery revenues increased by $22 million versus 2006 as gas deliveries, including miscellaneous transportation to end-use customers, were 207 bcf, an increase of 18 bcf or 9 percent. The increase in gas deliveries was primarily due to favorable weather.

Gas rate increases: In November 2006, the MPSC issued an order authorizing an annual rate increase of $81 million. In August 2007, the MPSC issued an order authorizing an annual rate increase of $50 million. As a result of these orders, gas revenues increased $11 million for the three months ended September 30, 2007 and $56 million for the nine months ended September 30, 2007.

Gas wholesale and retail services, other gas revenues and other income: For the three and nine months ended September 30, 2007, the increase was primarily due to higher pipeline capacity optimization revenue.

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

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

Interest charges: For the three months and nine months ended September 30, 2007, interest charges reflect lower average debt levels versus 2006.

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

Operating revenues: For the three months ended September 30, 2007, operating revenues increased $17 million versus 2006 primarily due to $22 million of mark-to-market gain in power and gas contracts compared to losses on such items in 2006 at CMS ERM. Partially offsetting these increases were decreases of $5 million in third party power and gas sales.

For the nine months ended September 30, 2007, operating revenues increased $24 million versus 2006 primarily due to higher revenues at CMS ERM resulting from mark-to-market gains of $89 million on power and gas contracts compared to losses on such items in 2006 and increased power sales of $25 million. These were offset partially by the write off of $40 million derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, absence of 2006 third party financial settlements of $22 million, and decreased third party gas sales of $28 million.

Cost of gas and purchased power: For the nine months ended September 30, 2007, cost of gas and purchased power decreased $20 million versus 2006. The decrease was primarily due to a decrease of $32 million in power purchases from the MISO market, offset partially by higher cost of gas of $12 million resulting from increased usage and higher prices.

Earnings from equity method investees: For the three months ended September 30, 2007, earnings from equity method investees decreased by $19 million versus 2006. The decrease was due to the absence of $17 million of earnings associated with our investments in Africa, the Middle East and India that were sold in May 2007 and a $2 million reduction in earnings associated with our investment in GasAtacama.

For the nine months ended September 30, 2007 earnings from equity method investees decreased by $26 million versus 2006. The decrease was due to the absence of $41 million of earnings associated with sale of our investments in Africa, the Middle East and India in May 2007, and a $5 million reduction in earnings associated with our investment in GasAtacama due to the shortage of gas from Argentina, offset by the absence in 2007 of a $20 million provision for higher foreign taxes in Argentina recorded in 2006.

Gain on sale of assets: For the three months ended September 30, 2007, the net gain on asset sales was $18 million. $17 million of the net gain resulted from the settlement of certain legal proceedings associated with the sale of our Argentine and Michigan assets to Lucid Energy. We also recorded $1 million in gains from the sale of various assets at CMS ERM. There were no gains or losses on asset sales for the three months ended September 30, 2006. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

For the nine months ended September 30, 2007, the net gain on asset sales was $16 million. The net gain consisted of $34 million from the sale of our equity investment in El Chocon to Endesa S.A. and $1 million in gains from the sale of various assets at CMS Energy. These gains were partially offset by a $14 million net loss on the sale of our equity investments in Africa, the Middle East and India to TAQA and a $5 million net loss on the sale of our Argentine and Michigan assets to Lucid Energy. There were no gains or losses on asset sales for the nine months ended September 30, 2006. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Operation and maintenance: For the three months ended September 30, 2007, operation and maintenance expenses decreased $13 million versus 2006 due to the absence, in 2007, of a $6 million loss recorded on the termination of the remaining prepaid gas contracts at CMS ERM, reimbursement of $3 million in arbitration costs at CMS Gas Transmission, and a $4 million net reduction in other expenses primarily due to the absence of expenses associated with assets sold during the first six months of 2007.

For the nine months ended September 30, 2007, operation and maintenance expenses decreased $7 million versus 2006 due to the absence, in 2007, of a $6 million loss recorded on the termination of the remaining prepaid gas contracts at CMS ERM, reimbursement of $3 million in arbitration costs at CMS Gas Transmission, partially offset by a $2 million net increase in other expenses primarily due to expenses associated with assets sold during the first six months of 2007.

General taxes, depreciation, and other income, net: For the three months ended September 30, 2007, the net of general taxes, depreciation, and other income increased operating income by $6 million versus 2006 due to lower accretion expense related to the termination of the prepaid gas contracts at CMS ERM.

For the nine months ended September 30, 2007, the net of general taxes, depreciation, and other income increased operating income by $6 million versus 2006 due to lower accretion expense of $4 million related to the termination of the prepaid gas contracts at CMS ERM, and lower expense due to asset sales of $2 million.

Asset impairment charges, net of insurance reimbursement: For the three months ended September 30, 2007, asset impairment charges, net of insurance reimbursement, decreased $288 million versus 2006. The decrease in impairment charges relates to a $75 million credit recorded in September 2007 to recognize a prior insurance award associated with our ownership interest in TGN, and the absence, in 2007, of a $213 million impairment of our equity investment in GasAtacama and related notes receivable recorded in 2006. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

For the nine months ended September 30, 2007, asset impairment charges, net of insurance reimbursement, decreased $25 million versus 2006. For the nine months ended September 30, 2007, we recorded net impairment charges of $204 million that included $277 million of charges for the reduction in fair value of our investments in TGN, Jamaica, GasAtacama and PowerSmith, and a $75 million credit to recognize a

prior insurance award associated with our ownership interest in TGN. For the nine months ended September 30, 2006, we recorded a $212 million charge for the reduction in the fair value of our equity investment in GasAtacama and related notes receivable. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

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

Minority Interest: The allocation of profits to minority owners decreases our net income, and the allocation of losses to minority owners increases our net income. For the three months ended September 30, 2007, minority owners shared in a portion of the profits at our subsidiaries. For the three months ended September 30, 2006, minority owners shared in a portion of losses at our subsidiaries.

For the nine months ended September 30, 2007, minority owners shared in a portion of greater profits at our subsidiaries versus profits shared in 2006.

Income taxes: For the three months ended September 30, 2007, income tax expense increased $103 million versus 2006. The increase reflects $113 million of tax expense on higher earnings and the absence of $4 million in tax benefits recorded in 2006 related to foreign subsidiaries subsequently sold in 2007, offset by $14 million of tax benefit primarily related to lower tax reserves in 2007.

For the nine months ended September 30, 2007, income tax expense increased $68 million versus 2006. The increase reflects the $68 million net increase in tax expense on earnings associated with the recognition of previously unremitted foreign earnings of subsidiaries sold in 2007. Also increasing tax expense was $26 million of tax expense on higher earnings. These expenses were offset by $26 million of tax benefits primarily related to lower tax reserves in 2007.

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

For the three months ended September 30, 2007, corporate interest and other net expenses were $35 million, a decrease of $19 million versus 2006. The $19 million decrease primarily reflects the absence, in 2007, of a portion of the reduction in fair value of our investment in GasAtacama recognized in 2006 and reduced interest expense due to lower debt levels in 2007. Partially offsetting the decrease were premiums on the early retirement of CMS Energy debt paid in 2007.

For the nine months ended September 30, 2007, corporate interest and other net expense were $51 million, an increase of $3 million versus 2006. The $3 million increase primarily reflects the absence, in 2007, of a tax benefit due to the resolution of an IRS income tax audit, higher income tax expense in 2007, and the absence of an insurance reimbursement received in June 2006 for previously incurred legal expenses. Also contributing to the increase was the recognition of a portion of the reduction in fair value of our investment in GasAtacama and premiums paid on the early retirement of CMS Energy

debt in June 2007. Partially offsetting the increase was the reduction of certain deferred tax valuation allowances in March 2007 that were no longer required due to the sale of our international operations.

Discontinued Operations: For the three months ended September 30, 2007, there was no net income from discontinued operations compared to net income of $11 million in 2006.

For the nine months ended September 30, 2007, the net loss from discontinued operations was $87 million compared to $32 million in net income in 2006. The $119 million change is primarily due to the net loss on the disposal of international businesses in 2007, which replaced earnings recorded for these businesses in 2006.

Critical Accounting Policies

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

Use of Estimates and Assumptions

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

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

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

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

Accounting for Financial and Derivative Instruments, Trading Activities, and Market Risk Information

Financial Instruments: Debt and equity securities classified as available-for-sale are reported at fair value determined from quoted market prices. Unrealized gains or losses resulting from changes in fair value of certain available-for-sale debt and equity securities are reported, net of tax, in equity as part of AOCL. Unrealized gains or losses are excluded from earnings unless the related changes in fair value are determined to be other than temporary.

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

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

		Interest Rates (%)				Volatility Rates (%)
Electricity-related option contracts			3.6				68 — 113

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

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

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

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

(a) Reflects only the initial premium payments (receipts) for new contracts. No unrealized gains or losses were recognized at the inception of any new contracts.

(b) The fair value of CMS ERM’s trading contracts has increased significantly from December 31, 2006 due to the termination of certain gas contracts. CMS ERM had recorded derivative liabilities, representing cumulative unrealized mark-to-market losses, associated with these contracts.

(c) Reflects changes in the fair value of contracts over the period, as well as increases or decreases to credit reserves. For CMS ERM’s non-trading contracts, this amount also reflects the rescission of a natural gas contract with Quicksilver. CMS ERM had recorded a derivative asset, representing cumulative unrealized mark-to-market gains, associated with this contract. See Note 3, Contingencies, “Other Contingencies — Quicksilver Resources, Inc.” for additional details.

Market Risk Information: The following is an update of our risk sensitivities since December 31, 2006. These sensitivities indicate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical adverse change in market rates or prices of 10 percent. Changes in excess of the amounts shown in the sensitivity analyses could occur if changes in market rates or prices exceed the 10 percent shift used for the analyses.

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

						In Millions
		September 30, 2007				December 31, 2006
Variable-rate financing — before-tax annual earnings exposure		$	2			$	4
Fixed-rate financing — potential reduction in fair value (a)			181				193

(a)     Fair value reduction could only be realized if we repurchased all of our fixed-rate financing.

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

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

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

Other

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

	•		accounting for long-lived assets and equity method investments,
	•		accounting for the effects of industry regulation,
	•		accounting for pension and OPEB,
	•		accounting for asset retirement obligations, and
	•		accounting for nuclear decommissioning costs.

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

Capital Resources And Liquidity

Factors affecting our liquidity and capital requirements are:

	•		results of operations,
	•		capital expenditures,
	•		energy commodity and transportation costs,
	•		contractual obligations,
	•		regulatory decisions,
	•		debt maturities,
	•		credit ratings,
	•		working capital needs, and
	•		collateral requirements.

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

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

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

	•		our current level of cash and revolving credit facilities,
	•		our anticipated cash flows from operating and investing activities, and
	•		our ability to access secured and unsecured borrowing capacity in the capital markets, if necessary.

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

Cash Position, Investing, and Financing

Our operating, investing, and financing activities meet consolidated cash needs. At September 30, 2007, we had $1.293 billion consolidated cash, which includes $48 million of restricted cash and $4 million from entities consolidated pursuant to FIN 46(R).

Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For the nine months ended September 30, 2007, Consumers paid $176 million in common stock dividends to CMS Energy.

Operating Activities: For the nine months ended September 30, 2007, net cash used in operating

activities was $116 million, an increase of $563 million versus 2006. The increase in cash used in operations was a result of the absence, in 2007, of the sale of accounts receivable combined with payments made to fund our pension plan and to settle a shareholder class action lawsuit. The absence of the return of funds formerly held as collateral under certain gas hedging arrangements and other timing differences also contributed to the increased use of cash from operations. These increases were offset partially by the absence of the MCV Partnership gas supplier funds on deposit and a decrease in expenditures for gas inventory, as the milder winter in 2006 allowed us to accumulate more gas in our storage facilities.

Investing Activities: For the nine months ended September 30, 2007, net cash provided by investing activities was $1.394 billion, an increase of $1.83 billion versus 2006. This increase was primarily due to proceeds from asset sales and proceeds from nuclear decommissioning trust funds. For additional details on asset sales, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Financing Activities: For the nine months ended September 30, 2007, cash used in financing activities was $386 million, a decrease of $14 million versus 2006. This was primarily due to a decrease in debt payments offset by the payment of common stock dividends. For additional details on long-term debt activity, see Note 4, Financings and Capitalization.

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

Obligations and Commitments

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

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

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

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

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

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may sell up to $325 million of certain accounts receivable. The highly liquid and efficient market for securitized

financial assets provides a lower cost source of funding compared to unsecured debt. For additional details, see Note 4, Financings and Capitalization.

Outlook

CORPORATE OUTLOOK

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

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

In January 2007, we reinstated a quarterly dividend on our common stock after a four-year suspension at $0.05 per share. For the nine months ended September 30, 2007, we paid $34 million in common stock dividends. On October 26, 2007, we declared a dividend of $0.05 per share on our common stock payable November 30, 2007 to shareholders of record on November 9, 2007.

ELECTRIC UTILITY BUSINESS OUTLOOK

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

Over the next five years, we expect electric deliveries to grow less than 1.5 percent per year. This outlook assumes a modestly growing customer base and a stabilizing Michigan economy after 2007. This growth rate includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. This growth rate reflects a long-range expected trend of growth. Growth from year to year may vary from this trend due to customer response to the following:

	•		energy conservation measures,
	•		fluctuations in weather conditions, and
	•		changes in economic conditions, including utilization and expansion or contraction of manufacturing facilities.

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

Electric Reserve Margin: We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2008 through 2010. As of September 30, 2007, we expect total 2007 capacity costs for these primarily seasonal electric capacity and energy contracts to be $17 million.

We are currently planning for a reserve margin of approximately 11 percent for summer 2008, or supply resources equal to 111 percent of projected firm summer peak load. Of the 2008 supply resources target, we expect 85 percent to come from our electric generating plants and long-term power purchase contracts with other contractual arrangements making up the remainder of our supply resource needs for 2008. If the MPSC approves the Zeeland power plant purchase, we expect 95 percent of our 2008 supply resource target will be satisfied with our electric generating plants and long-term power purchase contracts, with other contractual arrangements making up the remainder of our supply resource needs for 2008. Our 15-year power purchase agreement with Entergy for 100 percent of the Palisades facility’s current electric output will offset the reduction in the owned capacity represented by the sale of Palisades in April 2007.

In September 2007, we exercised the regulatory-out provision in the MCV PPA, resulting in a reduction in the amount we pay to the MCV Partnership to equal the amount we are allowed to recover in the rates charged to customers. The MCV Partnership may, under certain circumstances, have the right to terminate the MCV PPA, which could affect our reserve margin status. The MCV PPA represents 13 percent of our 2008 expected supply resources.

Electric Transmission Expenses: METC, which provides electric transmission service to us, increased substantially the transmission rates it charged us in 2006. The revenue collected by METC under those rates in 2006 was subject to refund. The parties filed a settlement agreement with the FERC, which was approved in August 2007. This settlement resulted in a refund of 2006 transmission charges of $18 million and a corresponding reduction of our power supply costs.

Electric transmission expenses are anticipated to increase in 2008 by $42 million due primarily to a 33 percent increase in rates charged to us by our major transmission provider. This increase is included in our 2008 PSCR Plan filed with the MPSC in September 2007.

In September 2007, the FERC approved a proposal from transmission owners and operators to include 100 percent of generator interconnection costs in our transmission rates. Previously, generator interconnection costs were split 50-50 between transmission owners and operators and generators. Consumers, Detroit Edison, the MPSC, and other parties filed a request for rehearing regarding the FERC’s order.

For additional details on power supply costs, see Note 3, Contingencies, “Consumers’ Electric Utility Rate Matters — Power Supply Costs.”

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

Balanced Energy Initiative: In May 2007, we filed a “Balanced Energy Initiative” with the MPSC providing a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements. The plan is responsive to the 21st Century Electric Energy Plan and assumes that Michigan will implement a state-wide energy efficiency program and a renewable energy portfolio standard. The filing requests the MPSC to rule that the Balanced Energy Initiative represents a reasonable and prudent plan for the acquisition of necessary electric utility resources. As acknowledged in the 21st Century Electric Energy Plan, implementation of the Balanced Energy Initiative will require legislative repeal or significant reform of the Customer Choice Act. In addition, we endorse the 21st Century Electric

Energy Plan recommendation to adopt a new, up-front certification policy for major power plant investments.

In September 2007, as part of our Balanced Energy Initiative, we announced plans to build an 800 MW advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan. We expect to use 500 MW of the plant’s output to serve Consumers’ customers and to commit the remaining 300 MW to others. We expect the plant to enter operation in 2015 with our share of the cost estimated at $1.3 billion excluding financing costs and $1.6 billion with financing costs.

There are several obstacles that must be cleared before construction of the proposed new clean coal plant, including:

	•		repeal or significant reform of the Customer Choice Act,
	•		obtaining environmental permits,
	•		successful MPSC regulatory review and approval, and
	•		obtaining property tax abatements.

In September 2007, we filed with the MPSC an updated Balanced Energy Initiative including our plan for construction of the new clean coal plant in order to start the regulatory review process for the new plant. In October 2007, we filed an application with the MDEQ for the environmental air quality permits required for the new plant. The Michigan Attorney General has filed a motion with the MPSC to dismiss the Balanced Energy Initiative case claiming that the MPSC lacks jurisdiction over the matter.

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

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

ELECTRIC UTILITY BUSINESS UNCERTAINTIES

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

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

Clean Air Act: Compliance with the federal Clean Air Act and resulting regulations continues to be a significant focus for us. The Nitrogen Oxide State Implementation Plan requires significant reductions in nitrogen oxide emissions. To comply with the regulations, we expect to incur capital expenditures totaling $880 million. From 1998 to present, we have incurred $784 million in capital expenditures to comply with the federal Clean Air Act and resulting regulations and anticipate that the remaining $96 million of capital expenditures will be made through 2011. These expenditures include installing selective catalytic reduction

control technology on four of our coal-fired electric generating units. The key assumptions in the capital expenditure estimate include:

	•		construction commodity prices, especially construction material and labor,
	•		project completion schedules,
	•		cost escalation factor used to estimate future years’ costs of 2.6 percent, and
	•		an AFUDC capitalization rate of 7.8 percent.

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

Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. We plan to meet the nitrogen oxide requirements of this rule by year-round operation of our selective catalytic reduction control technology units, installation of low nitrogen oxide burners, and purchasing emission allowances. We plan to meet the sulfur dioxide requirements of this rule using sorbent injection, installation of flue gas desulfurization scrubbers and purchasing emission allowances. Our total cost for equipment installation is expected to reach approximately $740 million by 2015. Additional purchases of sulfur dioxide emission allowances in 2012 and 2013 will be needed at an estimated cost of $10 million per year, which we expect to recover from our customers through the PSCR process.

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

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

In April 2006, Michigan’s governor announced a plan that would result in mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ on the details of this rule; however, we have developed preliminary cost estimates and a mercury emissions reduction scenario based on our best knowledge of control technology options and initially proposed requirements. We estimate costs associated with Phase I of the state’s mercury rule will be approximately $190 million by 2010 and an additional $320 million by 2015.

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

		State and Federal		State and Federal
		Phase I		Phase II
Federal Clean Air Mercury Rule		30% reduction by 2010 with interstate trading of allowances		70% reduction by 2018 with interstate trading of allowances
Proposed State Mercury Rule		30% reduction by 2010 without interstate trading of allowances		90% reduction by 2015 without interstate trading of allowances

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to modify the plant. We have received and responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance.” If our interpretation is found to be incorrect, we may be required to install additional pollution controls at some or all of our coal-fired electric generating plants and potentially pay fines. Additionally, the viability of certain plants remaining in operation would be re-examined. We cannot predict the financial impact or outcome of this issue.

Greenhouse Gases : Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, including carbon dioxide. These laws, 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.

On April 2, 2007, the U.S. Supreme Court ruled that the Clean Air Act gives the EPA the authority to regulate emissions of carbon dioxide and other greenhouse gases from automobiles. In its decision, the court ordered the EPA to revisit its finding that it has the discretion not to regulate greenhouse gas emissions from automobiles.

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

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

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

Competition and Regulatory Restructuring: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At September 30, 2007, alternative electric suppliers were providing 311 MW of generation service to ROA customers.

This is 4 percent of our total distribution load and represents an increase of 1 percent of ROA load compared to September 30, 2006.

In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred from 2002 through 2003 through a surcharge applied to ROA customers. Since the MPSC order, we have experienced a downward trend in ROA customers. If this trend continues, it will extend the time it takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends, which affect our ability to recover timely these Stranded Costs.

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

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

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

OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990. The cost that we incur under the MCV PPA exceeded the recovery amount allowed by the MPSC until we exercised the regulatory-out provision in the MCV PPA in September 2007. This action limited our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. We incurred $39 million in underrecoveries in 2007. 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, but cannot assure that we will prevail in the event of a proceeding on this issue.

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

To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a determination regarding whether it wished to reconsider the amount of the MCV PPA payments that we recover from customers. Also, in May 2007, the MCV Partnership filed an application with the MPSC seeking approval to increase our recovery of costs incurred under the MCV PPA. We are unable to predict

the outcome of these requests. For additional details on the MCV PPA, see Note 3, Contingencies, “Other Consumers’ Electric Utility Contingencies — The MCV PPA.”

Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million. The final purchase price, subject to various closing adjustments, resulted in us receiving $363 million as of September 30, 2007. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. Because of the sale of Palisades, we also paid the NMC, the former operator of Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC.

The MPSC order approving the Palisades transaction allowed us to recover the book value of Palisades. This results in us crediting estimated proceeds in excess of book value of $66 million to our customers from June 2007 through December 2008. After closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were $77 million as of September 30, 2007. The MPSC order deferred ruling on the recovery of transaction costs, including the NMC exit fees, and the $30 million payment to Entergy related to the Big Rock ISFSI until the next general rate case.

Entergy assumed responsibility for the future decommissioning of Palisades and for storage and disposal of spent nuclear fuel located at Palisades and the Big Rock ISFSI sites. We transferred $252 million in trust fund assets to Entergy. We are crediting estimated excess decommissioning funds of $189 million to our retail customers from June 2007 through December 2008. Access to additional decommissioning fund balances above the estimates in the MPSC order resulted in excess decommissioning funds of $123 million as of September 30, 2007. We have proposed a plan to credit these balances to our retail customers and this plan is under review by the MPSC in our current electric rate case filing.

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

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

GAS UTILITY BUSINESS OUTLOOK

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

	•		fluctuations in weather conditions,
	•		use by independent power producers,
	•		changes in gas commodity prices,
	•		Michigan economic conditions,
	•		the price of competing energy sources or fuels,
	•		gas consumption per customer, and
	•		improvements in gas appliance efficiency.

GAS UTILITY BUSINESS UNCERTAINTIES

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

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

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

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

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

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

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. The proposed Revenue Decoupling and Conservation Incentive Mechanism was not approved. On September 25, 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 included in our original filing. If approved in total, this would result in an additional rate increase of $9 million to be used to implement the energy efficiency program.

ENTERPRISES OUTLOOK

In 2007, we completed the sale of our international assets. Our primary focus with respect to our non-utility businesses is to optimize cash flow and maximize the value of our remaining assets.

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

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

	•		an option to buy CMS Gas Transmission’s ownership interest in TGN, subject to the rights of other third parties,
	•		the right to certain proceeds that may be awarded and received by CMS Gas Transmission in connection with certain legal proceedings, and
	•		the right to proceeds that Enterprises will receive if it sells its stock interest in CMS Generation San Nicolas Company.

Under these agreements, we have essentially sold our rights to certain awards or proceeds that we may receive in the future. Of the total consideration received in the sale, we allocated $32 million to these agreements and recorded this amount as a deferred credit on our Consolidated Balance Sheets. Due to the settlement of certain legal proceedings in September 2007, a portion of CMS Gas Transmission’s obligations under these agreements has been satisfied. As such, we recognized $17 million of the deferred credit as a gain in September 2007.

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

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

	•		the outcome of ongoing negotiations to restructure the power supply agreements associated with our DIG power plant,
	•		the impact of indemnity and environmental remediation obligations at Bay Harbor,
	•		the outcome of certain legal proceedings,
	•		the impact of representations, warranties, and related indemnities in connection with the sales of our international assets,
	•		the outcome of the planned sale of other assets, and
	•		changes in commodity prices and interest rates on certain derivative contracts that do not qualify for hedge accounting and must be marked to market through earnings.

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

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

Other Outlook

Software Implementation: We are in the process of implementing new business software to replace existing business processes and information technology. The core business processes include finance, purchasing/supply chain, customer billing, human resources and payroll, and utility asset construction and maintenance work management. We intend the new business software, scheduled to be in production in the first half of 2008, to improve customer service, reduce risk, and increase flexibility.

Michigan Public Service Commission: During the third quarter of 2007, the Michigan governor appointed a new MPSC chairperson and a new MPSC Commissioner. We are unable to predict the impact of these appointments.

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

Michigan Tax Legislation: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan Business Tax Act, which imposes a business income tax of 4.95 percent and a modified gross receipts tax of 0.8 percent. The bill provides for a number of tax credits and incentives geared toward those companies investing and employing in Michigan. The Michigan Business Tax, which is effective January 1, 2008, replaces the state’s current Single Business Tax that expires on December 31, 2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional deductions in future years against the business income portion of the tax. These future deductions are phased in over a 15-year period, beginning in 2015. As a result of the enactment of this tax, we recorded, on a consolidated basis, a net deferred tax liability of $113 million and a corresponding net deferred tax asset of $113 million.

In September 2007, Michigan’s governor also signed legislation expanding the state’s sales tax to certain services. The list of covered services includes certain services that we purchase from outside vendors and potentially services that we sell. This list includes, but is not limited to, certain consulting services, landscaping (which encompasses tree trimming), janitorial services, security guards and security systems.

The Michigan Business Tax and the expanded sales tax were enacted to replace the expiring Michigan Single Business Tax. We are currently evaluating the impact of the replacement of the Michigan Single Business Tax with these new taxes. We expect to recover the taxes that we pay from our customers, but we cannot predict the timeliness of such recovery.

Implementation of New Accounting Standards

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

FIN 48, Accounting for Uncertainty in Income Taxes : We adopted the provisions of FIN 48 on January 1, 2007. This interpretation provides a two-step approach for the recognition and measurement of

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

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

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

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

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

New Accounting Standards Not Yet Effective

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

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard will give us the option to select certain financial instruments and other items, which otherwise are not required to be measured at fair value, and measure those items at fair value. If we choose to elect the fair value option for an item, we would recognize unrealized gains and

losses associated with changes in the fair value of the item over time. The statement will also require disclosures for items for which the fair value option has been elected. We are presently evaluating whether we will choose to elect the fair value option for any financial instruments or other items.

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

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

The accompanying notes are an integral part of these statements.

		In Millions, Except Per Share Amounts
		Three Months Ended								Nine Months Ended
September 30		2007				2006				2007				2006
CMS Energy
Net Income (Loss)
Net Income (Loss) Available to Common Stockholders		$	82			$	(103	)		$	(100	)		$	(58	)
Basic Earnings (Loss) Per Average Common Share
Income (Loss) from Continuing Operations		$	0.37			$	(0.52	)		$	(0.06	)		$	(0.41	)
Gain (Loss) from Discontinued Operations			—				0.05				(0.39	)			0.15
Net Income (Loss) Attributable to Common Stock		$	0.37			$	(0.47	)		$	(0.45	)		$	(0.26	)
Diluted Earnings (Loss) Per Average Common Share
Income (Loss) from Continuing Operations		$	0.34			$	(0.52	)		$	(0.06	)		$	(0.41	)
Gain (Loss) from Discontinued Operations			—				0.05				(0.39	)			0.15
Net Income (Loss) Attributable to Common Stock		$	0.34			$	(0.47	)		$	(0.45	)		$	(0.26	)
Dividends Declared Per Common Share		$	0.05			$	—			$	0.15			$	—

The accompanying notes are an integral part of these statements.

CMS Energy Corporation
Consolidated Statements of Cash Flows
(Unaudited)

		Nine Months Ended
September 30		2007				2006
						In Millions
Cash Flows from Operating Activities
Net loss		$	(91	)		$	(50	)
Adjustments to reconcile net loss to net cash provided by operating activities
Depreciation and amortization, net of nuclear decommissioning of $4 and $3			407				418
Deferred income taxes and investment tax credit			(79	)			(223	)
Minority interests (obligations), net			(13	)			(27	)
Asset impairment charges, net of insurance recoveries			204				239
Fuel costs mark-to-market at the MCV Partnership			—				226
Regulatory return on capital expenditures			(24	)			(18	)
Capital lease and other amortization			41				34
Loss on the sale of assets			117				—
Earnings from equity method investees			(36	)			(63	)
Cash distributions from equity method investees			15				63
Pension contribution			(109	)			(13	)
Shareholder class action settlement			(125	)			—
Changes in other assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenues			(148	)			340
Decrease (increase) in accrued power supply and gas revenue			52				(90	)
Increase in inventories			(186	)			(246	)
Decrease in deferred property taxes			111				102
Decrease in accounts payable			(91	)			(116	)
Decrease in accrued taxes			(144	)			(152	)
Increase (decrease) in accrued expenses			(37	)			35
Decrease in the MCV Partnership gas supplier funds on deposit			—				(159	)
Decrease in other current and non-current assets			87				106
Increase (decrease) in other current and non-current liabilities			(67	)			41
Net cash provided by (used in) operating activities			(116	)			447
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)			(523	)			(477	)
Cost to retire property			(18	)			(41	)
Restricted cash and restricted short-term investments			34				125
Investments in nuclear decommissioning trust funds			(1	)			(20	)
Proceeds from nuclear decommissioning trust funds			333				20
Maturity of the MCV Partnership restricted investment securities held-to-maturity			—				119
Purchase of the MCV Partnership restricted investment securities held-to-maturity			—				(118	)
Proceeds from sale of assets			1,696				—
Cash relinquished from sale of assets			(113	)			—
Other investing			(14	)			(44	)
Net cash provided by (used in) investing activities			1,394				(436	)
Cash Flows from Financing Activities
Proceeds from notes, bonds, and other long-term debt			476				72
Issuance of common stock			13				7
Retirement of bonds and other long-term debt			(769	)			(433	)
Redemption of preferred stock			(32	)			—
Payment of common stock dividends			(34	)			—
Payment of preferred stock dividends			(8	)			(8	)
Payment of capital lease and financial lease obligations			(14	)			(23	)
Debt issuance costs, financing fees, and other			(18	)			(15	)
Net cash used in financing activities			(386	)			(400	)
Effect of Exchange Rates on Cash			2				1
Net Increase (Decrease) in Cash and Cash Equivalents			894				(388	)
Cash and Cash Equivalents, Beginning of Period			351				847
Cash and Cash Equivalents, End of Period		$	1,245			$	459

The accompanying notes are an integral part of these statements.

CMS Energy Corporation

Consolidated Balance Sheets

						In Millions
		September 30				December 31
ASSETS		2007				2006
		(Unaudited)
Plant and Property (At cost)
Electric utility		$	7,945			$	8,504
Gas utility			3,327				3,273
Enterprises			391				453
Other			34				33
			11,697				12,263
Less accumulated depreciation, depletion and amortization			4,117				5,194
			7,580				7,069
Construction work-in-progress			381				639
			7,961				7,708
Investments
Enterprises			20				556
Other			5				10
			25				566
Current Assets
Cash and cash equivalents at cost, which approximates market			1,245				249
Restricted cash at cost, which approximates market			48				71
Accounts receivable and accrued revenue, less allowances of $20 in 2007 and $25 in 2006			531				502
Notes receivable			80				48
Accrued power supply and gas revenue			104				156
Accounts receivable and notes receivable — related parties			2				62
Inventories at average cost
Gas in underground storage			1,301				1,129
Materials and supplies			83				87
Generating plant fuel stock			125				126
Regulatory assets — postretirement benefits			19				19
Deferred income taxes			—				155
Deferred property taxes			103				150
Assets held for sale			—				239
Price risk management assets			4				45
Prepayments and other			51				105
			3,696				3,143
Non-current Assets
Regulatory Assets
Securitized costs			479				514
Postretirement benefits			1,032				1,131
Customer Choice Act			158				190
Other			508				497
Nuclear decommissioning trust funds			—				602
Deferred income taxes			123				—
Notes receivable			152				137
Notes receivable — related parties			—				125
Assets held for sale			—				412
Price risk management assets			—				19
Other			170				327
			2,622				3,954
Total Assets		$	14,304			$	15,371