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, 2008

OR

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

For the transition period from                      to                     

Commission	Registrant; State of Incorporation;	IRS Employer
File Number	Address; and Telephone Number	Identification No.
1-9513	CMS ENERGY CORPORATION	38-2726431
	(A Michigan Corporation)
	One Energy Plaza, Jackson, Michigan 49201
	(517) 788-0550
1-5611	CONSUMERS ENERGY COMPANY	38-0442310
	(A Michigan Corporation)
	One Energy Plaza, Jackson, Michigan 49201
	(517) 788-0550

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, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

CMS Energy Corporation:

Large accelerated filer þ Accelerated filer o 
Non-accelerated filer o
(Do not check if a smaller reporting company) Smaller reporting company o

Consumers Energy Company:

Large accelerated filer o Accelerated filer o 
Non-accelerated filer þ
(Do not check if a smaller reporting company) Smaller reporting company o

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 31, 2008:

CMS Energy Corporation:

CMS Energy Common Stock, $.01 par value	226,207,584
Consumers Energy Company, $10 par value, privately held by CMS Energy Corporation		84,108,789

CMS Energy Corporation
Consumers Energy Company
Quarterly reports on Form 10-Q to the
United States Securities and Exchange Commission
for the Quarter Ended September 30, 2008

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

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

TABLE OF CONTENTS

	Page
Glossary		3
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements
CMS Energy Corporation
Consolidated Statements of Income (Loss) (unaudited)	CMS-28
Consolidated Statements of Cash Flows (unaudited)	CMS-31
Consolidated Balance Sheets (unaudited)	CMS-32
Consolidated Statements of Common Stockholders’ Equity (unaudited)	CMS-34
Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies	CMS-37
2. Fair Value Measurements	CMS-40
3. Asset Sales, Discontinued Operations and Impairment Charges	CMS-43
4. Contingencies	CMS-46
5. Financings and Capitalization	CMS-58
6. Earnings Per Share	CMS-60
7. Financial and Derivative Instruments	CMS-62
8. Retirement Benefits	CMS-64
9. Income Taxes	CMS-65
10. Reportable Segments	CMS-66
Consumers Energy Company
Consolidated Statements of Income (unaudited)	CE-22
Consolidated Statements of Cash Flows (unaudited)	CE-23
Consolidated Balance Sheets (unaudited)	CE-24
Consolidated Statements of Common Stockholder’s Equity (unaudited)	CE-26

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TABLE OF CONTENTS
(Continued)

	Page
Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies	CE-29
2. Fair Value Measurements	CE-31
3. Asset Sales	CE-34
4. Contingencies	CE-34
5. Financings and Capitalization	CE-42
6. Financial and Derivative Instruments	CE-43
7. Retirement Benefits	CE-44
8. Reportable Segments	CE-46
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-5
Critical Accounting Policies	CMS-13
Capital Resources and Liquidity	CMS-15
Outlook	CMS-17
Implementation of New Accounting Standards	CMS-25
New Accounting Standards Not Yet Effective	CMS-26
Consumers Energy Company
Forward-looking Statements and Information	CE-1
Executive Overview	CE-3
Results of Operations	CE-5
Critical Accounting Policies	CE-10
Capital Resources and Liquidity	CE-11
Outlook	CE-13
Implementation of New Accounting Standards	CE-19
New Accounting Standards Not Yet Effective	CE-20
Item 3. Quantitative and Qualitative Disclosures about Market Risk	CO-1
Item 4. Controls and Procedures	CO-1
Item 4T. Controls and Procedures	CO-1
PART II — OTHER INFORMATION
Item 1. Legal Proceedings	CO-2
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-10
Item 6. Exhibits	CO-10
Signatures	CO-11
EX-12(a)
EX-12(b)
EX-31(a)
EX-31(b)
EX-31(c)
EX-31(d)
EX-32(a)
EX-32(b)

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GLOSSARY

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

ALJ	Administrative Law Judge
AOC	Administrative Order on Consent
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
ARB	Accounting Research Bulletin
ARO	Asset retirement obligation
Bay Harbor	A residential/commercial real estate area located near Petoskey, Michigan. In 2002, CMS Energy sold its interest in Bay Harbor.
bcf	One billion cubic feet of gas
Big Rock	Big Rock Point nuclear power plant
Big Rock ISFSI	Big Rock Independent Spent Fuel Storage Installation
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CKD	Cement kiln dust
Clean Air Act	Federal Clean Air Act, as amended
CMS Capital	CMS Capital, L.L.C., a wholly owned subsidiary of CMS Energy
CMS Energy	CMS Energy Corporation, the parent of Consumers and Enterprises
CMS Energy Common Stock or common stock	Common stock of CMS Energy, par value $.01 per share
CMS ERM	CMS Energy Resource Management Company, formerly CMS MST, a subsidiary of Enterprises
CMS Field Services	CMS Field Services, Inc., a former wholly owned subsidiary of CMS Gas Transmission
CMS Gas Transmission	CMS Gas Transmission Company, a wholly owned subsidiary of Enterprises
CMS Generation	CMS Generation Co., a former wholly owned subsidiary of Enterprises
CMS Land	CMS Land Company, a wholly owned subsidiary of CMS Energy
CMS MST	CMS Marketing, Services and Trading Company, a wholly owned subsidiary of Enterprises, whose name was changed to CMS ERM effective January 2004
CMS Oil and Gas	CMS Oil and Gas Company, formerly a subsidiary of Enterprises
Consumers	Consumers Energy Company, a subsidiary of CMS Energy
Customer Choice Act	Customer Choice and Electricity Reliability Act, a Michigan statute
DCCP	Defined Company Contribution Plan
DC SERP	Defined Contribution Supplemental Executive Retirement Plan
Detroit Edison	The Detroit Edison Company, a non-affiliated company
DIG	Dearborn Industrial Generation, LLC, a wholly owned subsidiary of CMS Energy
DOE	U.S. Department of Energy

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DOJ	U.S. Department of Justice
Dow	The Dow Chemical Company, a non-affiliated company
DSSP	Deferred Salary Savings Plan
EISP	Executive Incentive Separation Plan
EITF	Emerging Issues Task Force
EITF Issue 06-11	EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
EITF Issue 07-5	EITF Issue No. 07-5, “Determining Whether an Instrument (or Embedded Feature) Is Indexed to an Entity’s Own Stock”
EITF Issue 08-5	EITF Issue No. 08-5, “Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement”
El Chocon	A 1,200 MW hydro power plant located in Argentina, in which CMS Generation formerly held a 17.2 percent ownership interest
EnerBank	EnerBank USA, a wholly owned subsidiary of CMS Energy
Entergy	Entergy Corporation, a non-affiliated company
Enterprises	CMS Enterprises Company, a subsidiary of CMS Energy
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 14	FASB Interpretation No. 14, Reasonable Estimation of Amount of a Loss
FIN 45	FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others
FIN 46(R)	Revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities
FIN 48	FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109
FMB	First Mortgage Bonds
FMLP	First Midland Limited Partnership, a partnership that holds a lessor interest in the MCV Facility
FOV	Finding of Violation
FSP	FASB Staff Position
FSP APB 14-1	FASB Staff Position on APB No. 14, Accounting for Convertible Debt and Debt Issued with Stock Purchase Warrants
FSP EITF 03-6-1	FASB Staff Position on EITF No. 03-6, Participating Securities and the Two-Class method under FASB Statement No. 128
FSP FAS 133-1 and FIN 45-4	FASB Staff Position on FASB No. 133, “Accounting for Derivative Instruments and Hedging Activities” and FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FSP FAS 142-3	FASB Staff Position on FASB No. 142, Determination of the Useful Life of Intangible Assets
FSP FAS 157-3	FASB Staff Position on FASB No. 157, “Fair Value Measurements”
FSP FIN 39-1	FASB Staff Position on FASB Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts”

4

GAAP	U.S. Generally Accepted Accounting Principles
GasAtacama	GasAtacama Holding Limited, a limited liability partnership that manages GasAtacama S.A., which includes an integrated natural gas pipeline and electric generating plant in Argentina and Chile and Atacama Finance Company, in which CMS International Ventures formerly owned a 50 percent interest
GCR	Gas cost recovery
ICSID	International Centre for the Settlement of Investment Disputes
IRS	Internal Revenue Service
ISFSI	Independent spent fuel storage installation
Jamaica	Jamaica Private Power Company, Limited, a 63 MW diesel-fueled power plant in Jamaica, in which CMS Generation formerly owned a 42 percent interest
Jorf Lasfar	A 1,356 MW coal-fueled power plant in Morocco, in which CMS Generation formerly owned a 50 percent interest
kWh	Kilowatt-hour (a unit of energy equal to one thousand watt hours)
Lucid Energy	Lucid Energy LLC, a non-affiliated company
Ludington	Ludington pumped storage plant, jointly owned by Consumers and Detroit Edison
Marathon	Marathon Oil Company, Marathon E.G. Holding, Marathon E.G. Alba, Marathon E.G. LPG, Marathon Production LTD, and Alba Associates, LLC
mcf	One thousand cubic feet of gas
MCV Facility	A natural gas-fueled, combined-cycle cogeneration facility operated by the MCV Partnership
MCV Partnership	Midland Cogeneration Venture Limited Partnership
MCV PPA	The Power Purchase Agreement between Consumers and the MCV Partnership with a 35-year term commencing in March 1990, as amended and restated in an agreement dated as of June 9, 2008 between the MCV Partnership and Consumers
MD&A	Management’s Discussion and Analysis
MDEQ	Michigan Department of Environmental Quality
MDL	Multidistrict Litigation
MEI	Michigan Energy Investments LLC, an affiliate of Lucid Energy
METC	Michigan Electric Transmission Company, LLC, a non-affiliated company owned by ITC Holdings Corporation and a member of MISO
MGP	Manufactured Gas Plant
MISO	Midwest Independent Transmission System Operator, Inc.
MPSC	Michigan Public Service Commission
MSBT	Michigan Single Business Tax
MW	Megawatt (a unit of power equal to one million watts)
MWh	Megawatt hour (a unit of energy equal to one million watt hours)
NAV	Net Asset Values
NMC	Nuclear Management Company LLC, a non-affiliated company
NOV	Notice of Violation
NREPA	Michigan Natural Resources and Environmental Protection Act
NSR	New Source Review
NYMEX	New York Mercantile Exchange
OPEB	Postretirement benefit plans other than pensions

5

Palisades	Palisades nuclear power plant, formerly owned by Consumers
Panhandle	Panhandle Eastern Pipe Line Company, including its subsidiaries Trunkline, Pan Gas Storage, Panhandle Storage, and Panhandle Holdings, a former wholly owned subsidiary of CMS Gas Transmission
PCB	Polychlorinated biphenyl
PDVSA	Petroleos de Venezuela S.A., a non-affiliated company
Peabody Energy	Peabody Energy, a non-affiliated company
Pension Plan	The trusteed, non-contributory, defined benefit pension plan of Panhandle, Consumers and CMS Energy
PowerSmith	A 124 MW natural gas power plant located in Oklahoma, in which CMS Generation formerly held a 6.25% limited partner ownership interest
Prairie State	Prairie State Energy Campus, a planned 1,600 MW power plant and coal mine in southern Illinois
PSCR	Power supply cost recovery
PSD	Prevention of Significant Deterioration
PURPA	Public Utility Regulatory Policies Act of 1978
Quicksilver	Quicksilver Resources, Inc., a non-affiliated company
RAKTL	Ronald A. Katz Technology Licensing L.P., a non-affiliated company
RCP	Resource Conservation Plan
Reserve Margin	The amount of unused available electric capacity at peak demand as a percentage of total electric peak demand
ROA	Retail Open Access, which allows electric generation customers to choose alternative electric suppliers pursuant to the Customer Choice Act.
SEC	U.S. Securities and Exchange Commission
SENECA	Sistema Electrico del Estado Nueva Esparta C.A., a former subsidiary of CMS International Ventures
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SFAS No. 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS No. 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS No. 133	SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended and interpreted”
SFAS No. 141(R)	SFAS No. 141 (revised 2007), “Business Combinations”
SFAS No. 142	SFAS No. 142, “Goodwill and Other Intangible Assets”
SFAS No. 157	SFAS No. 157, “Fair Value Measurements”
SFAS No. 158	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)”
SFAS No. 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an Amendment to FASB Statement No. 115”
SFAS No. 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51”
SFAS No. 161	SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133”

6

Stranded Costs	Costs incurred by utilities in order to serve their customers in a regulated monopoly environment, which may not be recoverable in a competitive environment because of customers leaving their systems and ceasing to pay for their costs. These costs could include owned and purchased generation and regulatory assets.
Superfund	Comprehensive Environmental Response, Compensation and Liability Act
TAQA	Abu Dhabi National Energy Company, a subsidiary of Abu Dhabi Water and Electricity Authority, a non-affiliated company
TGN	A natural gas transportation and pipeline business located in Argentina, in which CMS Gas Transmission formerly owned a 23.54 percent interest
Trunkline	CMS Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle Holdings, LLC
TTT	Gas title transfer tracking fees and services
Wolverine	Wolverine Power Supply Cooperative, Inc., a non-affiliated company
Zeeland	A 935 MW gas-fired power plant located in Zeeland, Michigan

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CMS Energy Corporation

CMS Energy Corporation
MANAGEMENT’S DISCUSSION AND ANALYSIS

This MD&A is a consolidated report of CMS Energy. The terms “we” and “our” as used in this report refer to CMS Energy and its subsidiaries as a consolidated entity, except where it is clear that such term means only CMS Energy. This MD&A has been prepared in accordance with the instructions to Form 10-Q and Item 303 of Regulation S-K. This MD&A should be read in conjunction with the MD&A contained in CMS Energy’s Form 10-K for the year ended December 31, 2007.

FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q and other written and oral statements that we make contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Our intention with the use of words such as “may,” “could,” “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict or control:

• the price of CMS Energy Common Stock, capital and financial market conditions and the effect of such market conditions on our postretirement benefit plans, interest rates, and access to the capital markets including availability of financing (including our accounts receivable sales program and revolving credit facilities) to CMS Energy, Consumers, or any of their affiliates, and the energy industry,

• the impact of the continued downturn in the economy and the sharp downturn and extreme volatility in the financial and credit markets on CMS Energy including its:

• revenues,

• capital expenditure program and related earnings growth,

• ability to collect accounts receivable from our customers,

• access to capital, and

• contributions to the Pension Plan,

• market perception of the energy industry or of CMS Energy, Consumers, or any of their affiliates,

• credit ratings of CMS Energy or Consumers,

• factors affecting 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,

• changes in federal or state laws or regulations or in the interpretation of existing laws and regulations that could have an impact on our business,

• the impact of any future regulations or laws regarding carbon dioxide and other greenhouse gas emissions,

• national, regional, and local economic, competitive, and regulatory policies, conditions and developments,

CMS-1

• adverse regulatory or legal interpretations or decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such interpretations or decisions, including but not limited to those that may affect Bay Harbor,

• potentially adverse regulatory treatment or failure to receive timely regulatory orders concerning a number of significant questions currently 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,

• timely recognition in rates of additional equity investments and additional operation and maintenance expenses at Consumers,

• adequate and timely recovery of additional utility rate-based investments,

• adequate and timely recovery of higher MISO energy and transmission costs,

• timely recovery of costs associated with energy efficiency investments and any state or federally mandated renewables resource standards,

• recovery of Big Rock decommissioning funding shortfalls,

• authorization of a new clean coal plant, and

• implementation of new energy legislation,

• adverse consequences resulting from a past or future assertion of indemnity or warranty claims associated with previously owned assets and businesses, including claims resulting from attempts by the governments of Equatorial Guinea and Morocco to assess taxes on past operations or transactions,

• the ability of Consumers to recover 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,

• the impact of expanded enforcement powers and investigation activities at the FERC,

• federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of our 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,

• the impact of natural gas prices and coal prices on our cash flow and working capital,

• the impact of construction material prices,

• the availability of qualified construction personnel to implement our construction program,

• earnings volatility resulting from the GAAP requirement that we apply mark-to-market accounting to certain energy commodity contracts, including electricity sales agreements, and interest rate swaps,

• potential disruption or interruption of facilities or operations due to accidents, war, or terrorism, and the ability to obtain or maintain insurance coverage for such events,

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• disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance, performance bonds, and tax exempt debt insurance,

• technological developments in energy production, delivery, usage, and gas storage,

• achievement of capital expenditure and operating expense goals,

• changes in financial or regulatory accounting principles or policies, including a possible future requirement to comply with International Financial Reporting Standards,

• changes in tax laws or new IRS interpretations of existing or past tax laws,

• the impact of our new integrated business software system on our operations, including customer billing, finance, purchasing, human resources and payroll processes, and utility asset construction and maintenance work management systems,

• the impact of credit market and economic conditions on EnerBank,

• the outcome, cost, and other effects of legal or administrative proceedings, settlements, investigations or claims, including those resulting from the investigation by the DOJ regarding round-trip trading and price reporting, and the pending appeal of the Quicksilver litigation, and

• 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.

For additional information regarding these and other uncertainties, see the “Outlook” section included in this MD&A, Note 4, Contingencies, and Part II, Item 1A. Risk Factors.

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EXECUTIVE OVERVIEW

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

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

• 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 emphasized improving our consolidated balance sheet and maintaining focus on our core strength: utility operations and service.

Our forecast calls for investing about $6.7 billion in the utility over the period from 2009 through 2013, with a key aspect of our strategy being our Balanced Energy Initiative. Our Balanced Energy Initiative is a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements with energy efficiency, demand management, expanded use of renewable energy, development of new power plants, and pursuit of additional power purchase agreements to complement existing generating sources.

In October 2008, the Michigan governor signed into law a comprehensive energy reform package. We plan to file an updated Balanced Energy Initiative with the MPSC in order to conform it to various aspects of this new legislation. Significant features of the new legislation include:

• a provision to streamline the regulatory process by generally allowing utilities to self-implement rates six months after filing and requiring the MPSC to issue an order 12 months after filing or the rates as-filed become permanent,

• reform of the Customer Choice Act to limit generally alternative energy suppliers to 10 percent of our weather-adjusted sales,

• establishment of a certificate-of-necessity process at the MPSC for proposed power plants, power purchase agreements, and projects costing more than $500 million,

• a requirement that 10 percent of power come from renewable sources by 2015 with specific interim targets, and

• new programs and incentives to encourage greater energy efficiency among customers, along with the requirement of the utility to prepare energy cost savings optimization plans.

In June 2008, the MPSC approved a settlement agreement that provides for an amended and restated MCV PPA and resolves the issues concerning our September 2007 exercise of the regulatory-out provision. The revised MCV PPA also provides more certainty of our access to 1,240 MW of the MCV Facility capacity through March 2025. The amended and restated MCV PPA took effect in October 2008.

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

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

In the future, we will focus our strategy on:

• continuing investment in our utility business,

• growing earnings while controlling operating and fuel costs and parent debt,

• managing cash flow, and

• maintaining 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 Michigan economy that has been hampered by the continued downturn in Michigan’s automotive industry and limited growth in the non-manufacturing sectors of the state’s economy. There also has been a sharp downturn, uncertainty, and extreme volatility in the financial and credit markets resulting from the subprime mortgage crisis, bank failures and consolidation, and other market weaknesses. While we believe that our sources of liquidity will be sufficient to meet our requirements, we continue to monitor closely developments in the financial and credit markets and government response to those developments for potential implications for our business.

RESULTS OF OPERATIONS

CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS

In Millions (except for per share amounts)
Three months ended September 30	2008			2007			Change
Net Income Available to Common Stockholders	$	79		$	82		$	(3	)
Basic Earnings Per Share	$	0.36		$	0.37		$	(0.01	)
Diluted Earnings Per Share	$	0.34		$	0.34		$	—
Electric Utility	$	108		$	67		$	41
Gas Utility		(18	)		(8	)		(10	)
Enterprises		5			58			(53	)
Corporate Interest and Other		(17	)		(35	)		18
Discontinued Operations		1			—			1
Net Income Available to Common Stockholders	$	79		$	82		$	(3	)

For the three months ended September 30, 2008, our net income was $79 million, a $3 million decrease versus 2007. Compared with the third quarter of 2007, combined net income from our electric and gas utility segments increased, reflecting the positive impact of the MPSC rate orders and the elimination of certain costs from the power purchase agreement with the MCV Partnership, partially offset by lower deliveries and increased depreciation and other expenses. Further increasing net income were lower corporate interest expense and financing costs. These increases were more than offset by the absence of an insurance reimbursement recognized at Enterprises in 2007.

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

		In Millions
•	increase in net earnings at our electric utility segment primarily due to favorable MPSC rate orders,	$	63
•	lower corporate interest expense and the absence, in 2008, of premiums paid on the early retirement of CMS Energy debt in 2007,		18
•	the elimination of certain costs at our electric utility from the power purchase agreement with the MCV Partnership,		9
•	decrease in net income from Enterprises and discontinued operations primarily due to the absence, in 2008, of an insurance reimbursement recognized in 2007, related to the non-payment by the Argentine government of our ICSID award,		(52	)
•	other combined net decrease at our electric and gas utility segments due primarily to reduced interest income and higher depreciation and other expenses, and		(31	)
•	decreased deliveries at our electric utility segment.		(10	)
Total change		$	(3	)

In Millions (except for per share amounts)
Nine months ended September 30	2008			2007			Change
Net Income (Loss) Available to Common Stockholders	$	228		$	(100	)	$	328
Basic Earnings (Loss) Per Share	$	1.02		$	(0.45	)	$	1.47
Diluted Earnings (Loss) Per Share	$	0.96		$	(0.45	)	$	1.41
Electric Utility	$	232		$	158		$	74
Gas Utility		46			53			(7	)
Enterprises		13			(194	)		207
Corporate Interest and Other		(63	)		(30	)		(33	)
Discontinued Operations		—			(87	)		87
Net Income (Loss) Available to Common Stockholders	$	228		$	(100	)	$	328

For the nine months ended September 30, 2008, our net income was $228 million, a $328 million increase versus 2007. Compared with the first three quarters of 2007, combined net income from our electric and gas utility segments increased, reflecting the positive impact of the MPSC rate orders and the elimination of certain costs from the power purchase agreement with the MCV Partnership, partially offset by lower deliveries, increased depreciation expense and lower interest income. Further increasing net income was the absence of the net impact of activities associated with assets sold in 2007, lower corporate debt costs, and the rescission of a contract with Quicksilver.

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

		In Millions
•	absence of impairment charges related to international businesses sold in 2007 partially offset by the 2008 impairment charge recorded on our SERP investments,	$	133
•	increase in combined net earnings at our electric and gas utility segments primarily due to favorable MPSC rate orders,		114
•	absence in 2008, of a net loss on the disposal of discontinued operations in 2007,		87
•	lower corporate interest expense and the absence, in 2008, of premiums paid on the early retirement of CMS Energy debt in 2007,		37
•	the elimination of certain costs at our electric utility from the power purchase agreement with the MCV Partnership,		29
•	absence of charges associated with the rescission of a contract with Quicksilver,		24
•	decreased deliveries at our electric utility segment,		(52	)
•	other combined net decrease at our electric and gas utility segments due primarily to reduced interest income and higher depreciation expense, and		(24	)
•	absence of tax benefits and earnings related to international assets sold, which more than offset the benefit from reduced operating and maintenance expense.		(20	)
Total change		$	328

ELECTRIC UTILITY RESULTS OF OPERATIONS

In Millions
September 30	2008		2007		Change
Three months ended	$	108	$	67	$	41
Nine months ended	$	232	$	158	$	74

	Three Months Ended			Nine Months Ended
	September 30, 2008			September 30, 2008
Reasons for the change:	vs. 2007			vs. 2007
Electric deliveries and rate increase	$	80		$	65
Surcharge revenue		—			10
Power supply costs and related revenue		5			12
Non-commodity revenue		(1	)		(13	)
Depreciation and other operating expenses		(11	)		62
Other income		(20	)		(36	)
General taxes		6			14
Interest charges		6			11
Income taxes		(24	)		(51	)
Total change	$	41		$	74

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Electric deliveries and rate increase: For the three months ended September 30, 2008, electric delivery revenues increased by $80 million versus 2007 primarily due to additional revenue of $97 million from the inclusion of the Zeeland power plant in rates and from the June 2008 rate order. The increase was partially offset by decreased electric revenue of $17 million primarily due to lower deliveries reflecting milder weather. Deliveries to end-use customers were 9.9 billion kWh, a decrease of 0.5 billion kWh or 5 percent versus 2007. For additional details on the June 2008 rate order, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters.”

For the nine months ended September 30, 2008, electric delivery revenues increased by $65 million versus 2007 primarily due to additional revenue of $145 million from the inclusion of the Zeeland power plant in rates and from the June 2008 rate order. The increase was partially offset by decreased electric revenue of $80 million primarily due to lower deliveries. Deliveries to end-use customers were 28.4 billion kWh, a decrease of 1.0 billion kWh or 3 percent versus 2007.

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

Power supply costs and related revenue: PSCR revenue increased $5 million for the three months ended September 30, 2008, and $12 million for the nine months ended September 30, 2008. These increases primarily reflect the 2007 reduction to revenue made in response to the MPSC’s position that PSCR discounts given to our Transitional Primary Rate customers could not be recovered under the PSCR mechanism. The decrease also reflects the absence, in 2008, of a decrease in power supply revenue associated with the 2006 PSCR reconciliation case.

Non-commodity revenue: Non-commodity revenue decreased $1 million for the three months ended September 30, 2008, and $13 million for the nine months ended September 30, 2008. The decreases were primarily due to the absence, in 2008, of METC transmission services revenue.

Depreciation and other operating expenses: For the three months ended September 30, 2008, the increase of $11 million in depreciation and other operating expenses was primarily due to higher costs associated with the implementation of our integrated business software system on July 1, 2008, higher uncollectible accounts expense and higher depreciation expense. The increase was partially offset by the absence, in 2008, of certain costs that are no longer incurred under our power purchase agreement with the MCV Partnership.

For the nine months ended September 30, 2008, the decrease of $62 million in depreciation and other operating expenses was primarily due to the absence of operating expenses associated with the sale of Palisades in April 2007, and certain costs that are no longer incurred under our power purchase agreement with the MCV Partnership. Also contributing to the decrease in expenses was the April 2008 MPSC order allowing us to retain a portion of the proceeds from the 2006 sale of certain sulfur dioxide allowances. The decrease was partially offset by higher retirement benefit expense due to the April 2008 MPSC order allowing recovery of certain costs through a surcharge and higher depreciation expense. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Consumers’ Electric Utility Contingencies.”

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Other income: Other income decreased $20 million for the three months ended September 30, 2008, and $36 million for the nine months ended September 30, 2008. The decreases were primarily due to reduced interest income and the MPSC’s June 2008 order, which did not allow us to recover all of our costs associated with the sale of Palisades. Also contributing to the decrease was an impairment charge that recognized an other than temporary decline in the fair value of our SERP investments, reflecting the continuing decline in the stock market.

General taxes: General tax expense decreased $6 million for the three months ended September 30, 2008 and $14 million for the nine months ended September 30, 2008. The decreases were primarily due to the absence, in 2008, of MSBT, which was replaced with the Michigan Business Tax effective January 1, 2008. The Michigan Business Tax is now recorded in income taxes. The decreases were partially offset by higher property tax expense.

Interest charges: Interest charges decreased $6 million for the three months ended September 30, 2008 and $11 million for the nine months ended September 30, 2008. These decreases were primarily due to lower interest associated with amounts to be refunded to customers as a result of the sale of Palisades. The MPSC order approving the Palisades power purchase agreement with Entergy directed us to record interest on the unrefunded balances. Also contributing to the decrease was the absence, in 2008, of interest charges related to an IRS settlement.

Income taxes: For the three months ended September 30, 2008, income taxes increased $24 million versus 2007. The increase reflects $23 million due to higher earnings, $2 million due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008, and a $1 million benefit due to increased quarterly Medicare subsidy.

For the nine months ended September 30, 2008, income taxes increased $51 million versus 2007. The increase reflects $45 million due to higher earnings and $6 million due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008.

GAS UTILITY RESULTS OF OPERATIONS

In Millions
September 30	2008			2007			Change
Three months ended	$	(18	)	$	(8	)	$	(10	)
Nine months ended		46		$	53		$	(7	)

	Three Months Ended			Nine Months Ended
	September 30, 2008			September 30, 2008
Reasons for the change:	vs. 2007			vs. 2007
Gas deliveries and rate increase	$	2		$	20
Gas wholesale and retail services, other gas revenues and other income, net		(12	)		(23	)
Operation and maintenance		(6	)		(15	)
General taxes and depreciation		1			—
Interest charges		1			7
Income taxes		4			4
Total change	$	(10	)	$	(7	)

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Gas deliveries and rate increase: For the three months ended September 30, 2008, gas delivery revenues increased $2 million versus 2007 primarily due to additional revenue of $3 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by a $1 million increase in system losses. Gas deliveries, including miscellaneous transportation to end-use customers, totaled 24 bcf, a decrease of 1 bcf or 4 percent versus 2007.

For the nine months ended September 30, 2008, gas delivery revenues increased $20 million versus 2007 primarily due to additional revenue of $31 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by higher system losses and lower gas deliveries, including miscellaneous transportation to end-use customers, totaling 204 bcf, a decrease of 4 bcf or 2 percent versus 2007, which resulted in a decrease in gas delivery revenue of $11 million.

Gas wholesale and retail services, other gas revenues and other income, net: Gas wholesale and retail services, other gas revenues and other income decreased $12 million for the three months ended September 30, 2008, and $23 million for the nine months ended September 30, 2008. These decreases were primarily due to lower interest income and lower pipeline capacity optimization revenue. Also contributing to the decrease was an impairment charge that recognized an other than temporary decline in the fair value of our SERP investments, reflecting the continuing decline in the stock market.

Operation and maintenance: Operation and maintenance expenses increased $6 million for the three months ended September 30, 2008 and $15 million for the nine months ended September 30, 2008. These increases were primarily due to higher uncollectible accounts expense and higher operating expense across our storage, transmission and distribution systems.

General taxes and depreciation: For the three months ended September 30, 2008, general taxes and depreciation decreased $1 million versus 2007 due to the absence, in 2008, of MSBT, which was replaced by the Michigan Business Tax effective January 1, 2008. The Michigan Business Tax is now recorded in income taxes.

For the nine months ended September 30, 2008, general taxes and depreciation did not change versus 2007, as the absence in 2008 of $8 million of MSBT was offset by increases of $6 million in depreciation expense and $2 million in property tax expenses.

Interest charges: Interest charges decreased $1 million for the three months ended September 30, 2008 and $7 million for the nine months ended September 30, 2008. These decreases were primarily due to lower average debt levels and a lower average interest rate.

Income taxes: For the three months ended September 30, 2008, income taxes decreased $4 million versus 2007. The decrease reflects $5 million due to lower quarterly earnings and $1 million related to the treatment of property, plant and equipment, as required by MPSC orders. These decreases were partially offset by a $1 million increase due to lower annual Medicare subsidy and a $1 million increase related to the forfeiture of restricted stock.

For the nine months ended September 30, 2008, income taxes decreased $4 million versus 2007. The decrease reflects $4 million due to lower earnings and $3 million related to the treatment of property, plant and equipment, as required by MPSC orders. These decreases were partially offset by a $1 million increase due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008, a $1 million increase due to lower annual Medicare subsidy and a $1 million increase related to the forfeiture of restricted stock.

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ENTERPRISES RESULTS OF OPERATIONS

In Millions
September 30	2008		2007			Change
Three months ended	$	5	$	58		$	(53	)
Nine months ended	$	13	$	(194	)	$	207

	Three Months Ended			Nine months ended
	September 30, 2008			September 30, 2008
Reasons for the change:	vs. 2007			vs. 2007
Operating revenues	$	8		$	(7	)
Fuel for electric generation, cost of gas and purchased power		(2	)		67
Earnings from equity method investees		5			(33	)
Gain (loss) on sale of assets		(18	)		(8	)
Operation and maintenance		3			36
General taxes, depreciation, and other income, net		(1	)		(1	)
Asset impairment charges, net of insurance reimbursement in 2007		(76	)		187
Fixed charges		1			4
Minority interests		1			3
Income taxes		26			(41	)
Total change	$	(53	)	$	207

Operating revenues: For the three months ended September 30, 2008, operating revenues increased $8 million versus 2007. The increase was due to higher net mark-to-market gains on power and gas contracts of $6 million and lower financial settlements losses of $4 million. Also contributing to the increase was higher power sales of $4 million. These increases were partially offset by lower gas sales of $4 million and the absence, in 2008, of operating revenue of $2 million from assets sold in 2007.

For the nine months ended September 30, 2008, operating revenues decreased $7 million versus 2007. The decrease was due to the absence, in 2008, of gas sales of $44 million resulting primarily from the termination of a gas sales contract, lower net mark-to-market gains on power and gas contracts of $12 million, and the absence, in 2008, of revenue of $5 million from assets sold in 2007. These decreases were partially offset by the absence, in 2008, of the write-off of $40 million of derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, and the absence, in 2008, of net financial settlements losses of $14 million.

Fuel for electric generation, cost of gas and purchased power: For the three months ended September 30, 2008, fuel for electric generation, cost of gas and purchased power increased $2 million versus 2007. The increase was due to higher net mark-to-market losses on gas and power supply contracts of $9 million, partially offset by decreased power purchase costs of $3 million and reduced cost of gas of $4 million resulting from decreased usage offset by higher average prices.

For the nine months ended September 30, 2008, fuel for electric generation, cost of gas and purchased power decreased $67 million versus 2007. The decrease was due to the absence, in 2008, of gas purchases of $42 million resulting primarily from the termination of a gas supply contract, reduced fuel for electric generation of $11 million, a decrease in purchased power costs of $10 million and mark-to-market gains on gas and power supply contracts of $4 million.

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Earnings from equity method investees: For the three months ended September 30, 2008, earnings from equity method investees were $5 million. The earnings included $3 million from our investment in North Carolina, primarily related to a mark-to-market derivative gain on a power contract, and a $2 million liquidating distribution from an energy fund investment.

For the nine months ended September 30, 2008, earnings from equity method investees decreased $33 million versus 2007. The decrease was due to the absence, in 2008, of $32 million of earnings from our investments in Africa, the Middle East, and India that were sold in May 2007 and our investment in Jamaica that was sold in October 2007. Also contributing to the decrease was the absence, in 2008, of $3 million of earnings associated with our remaining asset in Argentina. These decreases were partially offset by a $2 million liquidating distribution from an energy fund investment in 2008.

Gain (loss) on sale of assets: For the three months ended September 30, 2008, we recognized a gain of less than $1 million on the sale of real estate in Chile. For the three months ended September 30, 2007, the net gain on asset sales was $18 million.

For the nine months ended September 30, 2008, we recognized a gain on asset sales of $8 million related to our interests in TGN granted to MEI, an affiliate of Lucid Energy, in connection with the sale in 2007 of our Argentine and Michigan assets. For the nine months ended September 30, 2007, the net gain on asset sales was $16 million. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Operation and maintenance: For the three months ended September 30, 2008, operation and maintenance expenses decreased $3 million versus 2007. The decrease was due to the absence, in 2008, of $6 million of expenses associated with assets sold during 2007 which had been partially offset by the reimbursement in 2007 of $3 million of arbitration costs at CMS Gas Transmission.

For the nine months ended September 30, 2008, operation and maintenance expenses decreased $36 million versus 2007. The decrease was due to the absence, in 2008, of $33 million of expenses associated with assets sold during 2007 and $3 million of arbitration costs at CMS Gas Transmission.

General taxes, depreciation, and other income, net: For the three months and the nine months ended September 30, 2008, the net of general taxes, depreciation, and other income decreased operating income by $1 million versus 2007. The decrease was primarily due to an impairment charge of $3 million to recognize an other than temporary decline in the fair value of our SERP assets partially offset by the recognition of a foreign currency gain of $2 million on a liability associated with a 2007 asset sale.

Asset impairment charges, net of insurance reimbursement in 2007: For the three months ended September 30, 2007, we recorded an insurance reimbursement of $75 million to recognize a prior award associated with our ownership interest in TGN. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

For the nine months ended September 30, 2007, we recorded asset impairment charges net of insurance reimbursements of $187 million, that included $262 million of charges for the reduction in fair value of our investments in TGN, GasAtacama, Jamaica and PowerSmith, and a $75 million credit to recognize a prior insurance award associated with our ownership interest in TGN. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Fixed charges: Fixed charges decreased $1 million for the three months ended September 30, 2008 and $4 million for the nine months ended September 30, 2008 due to lower interest expense from subsidiary debt.

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

Income taxes: For the three months ended September 30, 2008, income tax expense decreased $26 million versus 2007 due to lower earnings.

For the nine months ended September 30, 2008, income tax expense increased $41 million versus 2007. The increase reflects $86 million of additional tax expense on higher earnings. These increases were offset by the absence of $45 million of tax expense recorded in 2007, primarily on earnings associated with the recognition of previously unremitted foreign earnings of subsidiaries sold.

CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS

In Millions
September 30	2008			2007			Change
Three months ended	$	(17	)	$	(35	)	$	18
Nine months ended	$	(63	)	$	(30	)	$	(33	)

For the three months ended September 30, 2008, corporate interest and other net expenses were $17 million, a decrease of $18 million versus 2007. The decrease in net expenses of $18 million primarily reflects the reduction of certain tax valuation allowances that were no longer required and reduced interest expense due to lower debt levels in 2008. Also contributing to the decrease in expense was the absence, in 2008, of premiums paid on the early retirement of CMS Energy debt in 2007.

For the nine months ended September 30, 2008, corporate interest and other net expenses were $63 million, an increase of $33 million versus 2007. The increase in net expenses of $33 million primarily reflects the absence, in 2008, of the recognition of certain tax benefits related to the sale of our international operations. Partially offsetting the increase was the absence, in 2008, of the reduction in fair value of notes receivable from GasAtacama, and premiums paid on the early retirement of CMS Energy debt in 2007. Also contributing to the decrease was reduced interest expense due to lower debt levels in 2008.

DISCONTINUED OPERATIONS

For the three months ended September 30, 2008, net income from discontinued operations was $1 million, primarily due to a reduction to a legal reserve related to previously sold assets.

For the nine months ended September 30, 2007, net loss from discontinued operations was $87 million, primarily due to the net loss on the disposal of international businesses sold in 2007.

CRITICAL ACCOUNTING POLICIES

The following accounting policies and related information are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A. These policies are an update of the policies disclosed in CMS Energy’s Form 10-K for the year ended December 31, 2007.

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Use of Estimates and Assumptions

Fair Value Measurements: We have a number of assets and liabilities that must be accounted for or disclosed at fair value in accordance with SFAS No. 157. Fair value measurements require the incorporation of all assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. Development of these assumptions requires significant judgment.

The most material of our fair value measurements are for our SERP assets and our derivative instruments. For a detailed discussion of the methods used to calculate these fair value measurements, see Note 2, Fair Value Measurements.

Derivative Instruments

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

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

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

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

Retirement Benefits

In accordance with SFAS No. 158, we record liabilities for pension and OPEB on our consolidated balance sheet at the present value of the future obligations, net of any plan assets. We use SFAS No. 87 to account for pension expense and SFAS No. 106 to account for other postretirement benefit expense. The calculation of the liabilities and associated expenses requires the expertise of actuaries, and requires many assumptions, including:

• life expectancies,

• discount rates,

• expected long-term rate of return on plan assets,

• rate of compensation increases, and

• anticipated health care costs.

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A change in these assumptions could change significantly our recorded liabilities and associated expenses.

The following table provides estimates as of September 30, 2008 of our pension cost, OPEB cost, and cash contributions:

In Millions
Expected Costs	Pension Cost		OPEB Cost		Contributions
2008	$	103	$	27	$	51
2009		93		61		263
2010		88		58		180

Contribution estimates include amounts required and discretionary contributions. Consumers’ pension and OPEB costs are recoverable through our general ratemaking process. Actual future pension cost and contributions will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the Pension Plan. As a result of additional losses experienced since September 30, 2008 in global equity markets, our Pension Plan contributions may be substantially larger in 2009 and assets are likely to have a negative return for 2008.

For additional details on retirement benefits, see Note 8, Retirement Benefits.

CAPITAL RESOURCES AND LIQUIDITY

Factors affecting our liquidity and capital requirements include:

• results of operations,

• capital expenditures,

• energy commodity and transportation costs,

• contractual obligations,

• regulatory decisions,

• debt maturities,

• credit ratings,

• pension plan funding requirements,

• tendering of our convertible securities for conversion,

• working capital needs,

• collateral requirements, and

• access to credit markets.

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

Components of our cash management plan include controlling operating expenses and capital expenditures and evaluating market conditions for financing opportunities, if needed. We have taken the following actions to strengthen our liquidity:

• in September 2008, Consumers issued $350 million FMB,

• in September 2008, Consumers entered into a $150 million revolving credit agreement, and

• in October 2008, CMS Energy drew $420 million, of the remaining $421 million balance, on its $550 million revolving credit facility.

In April 2008, we redeemed two of our tax-exempt debt issues with $96 million of refinancing proceeds and converted $35 million of tax-exempt debt previously backed by municipal bond insurers to variable rate demand bonds, effectively eliminating our variable rate debt backed by municipal bond insurers.

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Despite the current market volatility, we expect to be able to continue to have access to the capital markets, including funds available under our revolving credit facilities and our accounts receivable sales program. Our revolving credit facilities of $350 million are subject to renewal in 2009 and $1.050 billion are subject to renewal in 2012. Our accounts receivable sales program is subject to renewal in February 2009. We believe that our current level of cash and our anticipated cash flows from operating activities, together with access to sources of liquidity, will be sufficient to meet cash requirements. For additional details, see Note 5, Financings and Capitalization.

Cash Position, Investing, and Financing

Our operating, investing, and financing activities meet consolidated cash needs. At September 30, 2008, we had $193 million of consolidated cash, which includes $31 million of restricted cash and $8 million held by entities consolidated under FIN 46(R).

Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. Consumers paid $238 million in common stock dividends and Enterprises paid $950 million in common stock dividends, resulting from 2007 asset sales, to CMS Energy for the nine months ended September 30, 2008. For details on dividend restrictions, see Note 5, Financings and Capitalization.

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

Summary of Consolidated Statements of Cash Flows:

In Millions
Nine months ended September 30	2008			2007
Net cash provided by (used in):
Operating activities	$	183		$	(115	)
Investing activities		(538	)		1,394
Net cash provided by (used in) operating and investing activities		(355	)		1,279
Net cash provided by (used in) financing activities		169			(387	)
Effect of exchange rates on cash		—			2
Net Increase (Decrease) in Cash and Cash Equivalents	$	(186	)	$	894

Operating Activities:

For the nine months ended September 30, 2008, net cash provided by operating activities was $183 million, an increase of $298 million versus 2007. The increase was primarily due to an increase in earnings and the timing of cash receipts from accounts receivable. We accelerate our collections from customer billings through the sale of accounts receivable. The sale of accounts receivable at the end of 2006 reduced our collections from customers during 2007. At the end of 2007, we did not rely on sales of accounts receivable and collected customer billings for the nine months ended September 30, 2008. These increases were partially offset by the impact of higher gas prices on inventory purchases and the timing of postretirement benefit contributions and other settlement payments.

Investing Activities:

For the nine months ended September 30, 2008, net cash used in investing activities was $538 million, an increase of $1.932 billion versus 2007. This increase reflects the absence of asset sale proceeds and proceeds from our nuclear decommissioning trust funds in 2008.

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Financing Activities:

For the nine months ended September 30, 2008, net cash provided by financing activities was $169 million, an increase of $556 million versus 2007. This was primarily due to an increase in net proceeds from the issuance of long-term debt. For additional details on long-term debt, see Note 5, Financings and Capitalization.

Obligations and Commitments

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

Sale of Accounts Receivable: Under its revolving accounts receivable sales program, Consumers may sell up to $250 million of certain accounts receivable.

Capital Expenditures: For reporting purposes, we identify annual capital expenditures for the next three years. We review these estimates and may revise them periodically, due to a number of factors including environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital. In response to recent economic conditions, we reviewed our capital expenditures plan. For 2009, we have reduced our capital expenditures plan by $180 million to $855 million. We will continue to monitor our forecasted capital expenditures for 2009 and beyond.

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

OUTLOOK

Corporate Outlook

In the future, we will focus our strategy on continuing investment in our utility business, growing earnings while controlling operating costs and parent debt, and maintaining principles of safe, efficient operations, customer value, fair and timely regulation, and consistent financial performance.

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

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Electric Utility Business Outlook

Michigan Energy Legislation: In October 2008, the Michigan governor signed into law a comprehensive energy reform package. Significant features of the new legislation include:

• a provision to streamline the regulatory process by generally allowing utilities to self-implement rates six months after filing and requiring the MPSC to issue an order 12 months after filing or the rates as-filed become permanent,

• reform of the Customer Choice Act to limit generally alternative energy suppliers to 10 percent of our weather-adjusted sales,

• establishment of a certificate-of-necessity process at the MPSC for proposed power plants, power purchase agreements, and projects costing more than $500 million,

• a requirement that 10 percent of power come from renewable sources by 2015 with specific interim targets, and

• new programs and incentives to encourage greater energy efficiency among customers, along with the requirement of the utility to prepare energy cost savings optimization plans.

Balanced Energy Initiative: Our Balanced Energy Initiative is a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements with energy efficiency, demand management, expanded use of renewable energy, and development of new power plants and pursuit of additional power purchase agreements to complement existing generating sources. Our Balanced Energy Initiative includes our plan to build an 800 MW advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan.

The new energy legislation in Michigan provides guidelines with respect to the MPSC review and approval of energy resource plans and proposed power plants. We plan to file an updated Balanced Energy Initiative with the MPSC in conjunction with a certificate-of-necessity that conforms to the requirements of the new legislation and the rules that the MPSC will develop for the certificate-of-necessity filings.

Electric Deliveries: We are anticipating a decrease in electric deliveries of approximately 3 percent in 2008 compared with 2007 or 1 percent excluding weather conditions. This decline reflects a decline in industrial economic activity, and the cancellation of one wholesale customer contract. For 2009 compared with 2008, a decline, excluding weather conditions, of 1 percent is expected. Our outlook for 2009 includes continuing growth in deliveries to our largest growing customer that produces semiconductor and solar energy components. Without this customer’s growth our electric deliveries in 2009 are expected to decline 3 percent compared with 2008. Our outlook also reflects reduced deliveries associated with our investment in energy efficiency programs included in the recently enacted legislation, as well as recent projections of Michigan economic conditions.

After 2009, we anticipate economic conditions to stabilize, resulting in modestly growing deliveries of electricity. We expect deliveries to grow on average about 0.5 percent annually over the period from 2009 to 2014. This growth rate also includes expected results of energy efficiency programs and both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but transactions with other wholesale market participants are not included. Actual growth may vary from this trend due to the following:

• energy conservation measures and results of energy efficiency programs,

• fluctuations in weather conditions, and

• changes in economic conditions, including utilization and expansion or contraction of manufacturing facilities, population trends, and housing activity.

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

Electric Reserve Margin: To reduce the risk of high power supply costs during peak demand periods and to achieve our Reserve Margin target, we purchase electric capacity and energy for the physical delivery of electricity primarily in the summer months. We are currently planning for a Reserve Margin of 13.7 percent for summer 2009, or supply resources equal to 113.7 percent of projected firm summer peak load. We have purchased capacity and energy covering partially our Reserve Margin requirements for 2009 through 2010. Of the 2009 supply resources target, we expect 93 percent to come from our electric generating plants and long-term power purchase contracts, with other contractual arrangements making up the remainder. We expect capacity costs for these electric capacity and energy contractual arrangements to be $15 million for 2009.

Electric Transmission Expenses: We expect the transmission charges we incur to increase by $32 million in 2008 compared with 2007 primarily due to a 33 percent increase in METC transmission rates. This increase was included in our 2008 PSCR plan filed with the MPSC in September 2007, which we self-implemented in January 2008.

We expect the transmission charges we incur to increase by $55 million in 2009 compared with 2008 primarily due to a 25 percent increase in METC and Wolverine transmission rates. This increase was included in our 2009 PSCR plan filed with the MPSC in September 2008.

The MPSC issued an order that allowed transmission expenses to be included in the PSCR process. The Attorney General appealed the MPSC order to the Michigan Court of Appeals, which affirmed the MPSC order. The Attorney General filed an application for leave to appeal with the Michigan Supreme Court, which was granted in September 2008. We cannot predict the financial impact or outcome of this matter.

For additional details on the electric transmission expense litigation, see Note 4, Contingencies, “Consumers’ Electric Utility Contingencies — Litigation.”

Electric Utility Business Uncertainties

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

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

Clean Air Act: We continue to focus on complying with the federal Clean Air Act and numerous state and federal regulations. We plan to spend $795 million for equipment installation through 2015 to comply with a number of environmental regulations, including regulations limiting nitrogen oxides and sulfur dioxide emissions. We expect to recover these costs in customer rates.

Clean Air Interstate Rule: In March 2005, the EPA adopted the CAIR, which required additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. The CAIR was

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appealed to the U.S. Court of Appeals for the District of Columbia and, in July 2008, the court vacated the CAIR and the CAIR federal implementation plan in their entirety. If upheld, the decision would remand the CAIR back to the EPA to form a new rule, which will likely take considerable time. Several parties have petitioned the court for hearing by the full court. This keeps the CAIR in effect at least until the court decides whether to grant the rehearing. At the same time, Congress is considering legislative options to reinstate all or part of the CAIR.

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

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. If this plan becomes effective, we estimate the associated costs will be approximately $400 million by 2015.

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as “routine maintenance, repair and replacement” rather than seeking permits from the EPA to modify their plants. We responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance, repair and replacement.” In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. In addition, in October 2008, we received a NOV for three of our coal-fired facilities relating to violations of NSR and PSD regulations, alleging ten projects from 1986 to 1998 were subject to PSD review. We are currently preparing our response to this NOV and the information request. If the EPA does not accept our interpretation, we could be required to install additional pollution control equipment at some or all of our coal-fired electric generating plants and pay fines. Additionally, we would need to assess the viability of continuing operations at certain plants. We cannot predict the financial impact or outcome of this matter.

Greenhouse Gases: The United States Congress has introduced proposals that would require reductions in emissions of greenhouse gases, including carbon dioxide. These laws, or similar state laws or rules, if enacted, could require us to replace equipment, install additional equipment for emission controls, purchase allowances, curtail operations, or take other steps to manage or lower the emission of greenhouse gases. 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.

The EPA has published an Advance Notice of Proposed Rulemaking to present possible options for regulating greenhouse gases under the Clean Air Act, as well as to solicit comments and additional ideas. The comment period closes in November 2008. In addition to the potential for federal actions related to greenhouse gas regulation, the State of Michigan has convened a climate change stakeholder process under the name Michigan Climate Action Council. Michigan is also a signatory participant in the Midwest Governors Greenhouse Gas Reduction Accord process. We cannot predict the extent or the likelihood of any actions that could result from these state and regional processes.

Water: In July 2004, the EPA issued rules that govern existing electric generating plant cooling water intake systems. These rules require a significant reduction in the number of fish harmed by intake structures at large existing power plants. The EPA compliance options in the rule were challenged before the United States Court of Appeals for the Second Circuit. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The United States Court of Appeals for the Second Circuit’s ruling is expected to

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increase significantly the cost of complying with this rule, but we will not know the cost to comply until the EPA’s reconsideration is complete. In April 2008, the U.S. Supreme Court agreed to hear this case, thereby extending the time before this issue is finally resolved.

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

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

Electric ROA: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. However, the energy legislation enacted in Michigan in October 2008 generally limits alternative electric supply to 10 percent of our weather-adjusted retail sales for the preceding calendar year. At September 2008, alternative electric suppliers were providing 339 MW of generation service to ROA customers, which is equivalent to 4 percent of our weather-adjusted retail sales from the preceding calendar year.

In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred in 2002 and 2003 through a surcharge applied to ROA customers. The new energy legislation directs the MPSC to approve rates that will allow us to recover our Stranded Costs within five years.

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

In June 2008, the MPSC issued an order authorizing us to increase revenue by $221 million. This was lower than our revised position primarily due to the MPSC’s authorized return on equity of 10.7 percent and the final determination of our Zeeland plant revenue requirement.

We plan to file a new electric rate case by late November 2008.

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

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

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

• a capacity charge of $10.14 per MWh of available capacity,

• a fixed energy charge based on our annual average base load coal generating plant operating and maintenance cost,

• a variable energy charge for all delivered energy that reflects the MCV Partnership’s cost of production,

• the elimination of the RCP, but continues the $5 million annual contribution by the MCV Partnership to a renewable resources program, and

• an option for us to extend the MCV PPA for five years or purchase the MCV Facility at the conclusion of the MCV PPA’s term in March 2025.

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

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

Gas Utility Business Outlook

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

• fluctuations in weather conditions,

• use by independent power producers,

• availability and development of renewable energy sources,

• changes in gas prices,

• Michigan economic conditions including population trends and housing activity,

• the price of competing energy sources or fuels, and

• energy efficiency and conservation.

Gas Utility Business Uncertainties

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

Gas Environmental Estimates: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 4, Contingencies, “Consumers’ Gas Utility Contingencies — Gas Environmental Matters.”

Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudence in annual plan and reconciliation proceedings. For additional details on GCR, see Note 4, Contingencies, “Consumers’ Gas Utility Rate Matters — Gas Cost Recovery.”

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Gas Depreciation: On August 1, 2008, we filed a gas depreciation case using 2007 data with the MPSC-ordered variations on traditional cost-of-removal methodologies. We cannot predict the outcome of this matter. If a final order in our gas depreciation case is not issued concurrently with a final order in a general gas rate case, the MPSC may incorporate the results of the depreciation case into general gas rates through a surcharge, which may be either positive or negative.

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

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million based on an 11 percent authorized return on equity. The MPSC staff and intervenors filed testimony in September 2008. The MPSC staff recommended an increase of $36 million based on a 10.45 percent authorized return on equity.

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

Enterprises Outlook

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

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

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

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

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

• the impact of indemnity and environmental remediation obligations at Bay Harbor,

• the outcome of certain legal proceedings,

• the impact of representations, warranties, and indemnities we provided in connection with the sales of our international 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.

Other Outlook

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

Advanced Metering Infrastructure: We are developing an advanced metering system that will provide enhanced controls and information about our customer energy usage and notification of service interruptions. The system also will allow customers to make decisions about energy efficiency and conservation, provide other customer benefits, and reduce costs. We expect to develop integration software and pilot new technology over approximately the next two to three years, and incur capital expenditures of approximately $800 million over the next seven years.

Litigation and Regulatory Investigation: We are the subject of an investigation by the DOJ regarding round-trip trading transactions by CMS MST. Also, we are named as a party in various litigation matters including, but not limited to, several lawsuits regarding alleged false natural gas price reporting and price manipulation and the appeal initiated by Quicksilver in the Texas Court of Appeals. Additionally, the SEC is investigating the actions of former CMS Energy subsidiaries in relation to Equatorial Guinea. For additional details regarding these and other matters, see Note 4, Contingencies and Part II, Item 1. Legal Proceedings.

Emergency Economic Stabilization Act of 2008 — Mark-to-Market Accounting: In October 2008, President Bush signed into law a $700 billion economic recovery plan. The plan includes a provision authorizing the SEC to suspend the application of SFAS No. 157 for any issuer with respect to any class or category of transaction as deemed necessary. In addition, the SEC is required to conduct a study on mark-to-market accounting (fair value accounting), including its possible impacts on recent bank failures, along with a consideration of alternative accounting treatments. The SEC must submit a report to Congress within 90 days. We apply this accounting primarily to our commodity derivative instruments and our SERP investments. We will continue to monitor developments in this area.

EnerBank: EnerBank, a wholly owned subsidiary representing one percent of CMS Energy’s net assets, is a state-chartered, FDIC-insured industrial bank providing unsecured home improvement loans. The value of EnerBank’s loan portfolio was $180 million at September 30, 2008, with a corresponding liability recorded on our Consolidated Balance Sheets. Twelve-month rolling average default rates on loans held by EnerBank have risen from 1.0 percent at December 31, 2007 to 1.3 percent at September 30, 2008. Due to recent economic events, EnerBank expects the level of loan defaults to continue to increase throughout 2009 and into 2010, returning to historically lower levels thereafter.

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IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

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

SEC / FASB Guidance on Fair Value Measurements: In September 2008, in response to concerns about fair value accounting and its possible role in the recent declines in the financial markets, the SEC Office of the Chief Accountant and the FASB staff jointly released additional guidance on fair value measurements. The guidance, which is effective for us immediately, did not change or conflict with the fair value principles in SFAS No. 157, but rather provided further clarification on how to value a financial asset in an illiquid market. This guidance had no impact on our fair value measurements.

FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active: In October 2008, the FASB issued this standard, effective for us as of the quarter ended September 30, 2008. The standard clarifies the application of SFAS No. 157 in measuring financial assets in illiquid markets and is consistent with the guidance issued by the SEC and the FASB as discussed in the preceding paragraph, but an example is provided to further illustrate the concepts. The standard is to be applied prospectively. The guidance in this standard did not impact our fair value measurements.

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS No. 158. Phase one of this standard, implemented in December 2006, required us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase two, implemented in January 2008, required us to change our plan measurement date from November 30 to December 31, effective for the year ending December 31, 2008. For additional details, see Note 8, Retirement Benefits.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: This standard, which was effective for us January 1, 2008, gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We have not elected the fair value option for any financial instruments or other items.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39: This standard, which was effective for us January 1, 2008, permits us to offset the fair value of derivative instruments held under master netting arrangements with cash collateral received or paid for those derivatives. Adopting this standard resulted in an immaterial reduction to both our total assets and total liabilities. There was no impact on earnings from adopting this standard. We applied the standard retrospectively for all periods presented in our consolidated financial statements. For additional details, see Note 7, Financial and Derivative Instruments, “CMS ERM Contracts.”

EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards: This standard was effective for us January 1, 2008. The standard requires companies to recognize, as an increase to additional paid-in capital, the income tax benefit realized from dividends or dividend equivalents that are charged to retained earnings and paid to employees for non-vested equity-classified employee share-based payment awards. This standard did not have a material effect on our consolidated financial statements.

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NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

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

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Under this standard, ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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

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

FSP FAS 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161: In September 2008, the FASB issued this standard, effective for us December 31, 2008. This standard will amend SFAS No. 133 and FIN 45 to enhance the disclosure requirements for issuers of credit derivatives and financial guarantees. As we have not issued any credit derivatives, this standard will apply only to our disclosures about guarantees we have issued. It will have no effect on our consolidated financial statements.

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

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

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

EITF Issue 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement: In September 2008, the FASB ratified EITF Issue 08-5, effective for us January 1, 2009. This guidance concludes that the fair value measurement of a liability should not consider the effect of a third-party credit enhancement or guarantee supporting the liability. The fair value of the liability should thus reflect the credit standing of the issuer and should not be adjusted to reflect the credit standing of a third-party guarantor. The standard is to be applied prospectively. This standard will not have a material impact on our consolidated financial statements.

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CMS Energy Corporation
Consolidated Statements of Income (Loss)
(Unaudited)

										In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Operating Revenue	$	1,428		$	1,282		$	4,977		$	4,790
Earnings from Equity Method Investees		5			—			3			36
Operating Expenses
Fuel for electric generation		173			158			470			408
Purchased and interchange power		406			390			1,026			1,079
Cost of gas sold		191			171			1,526			1,509
Other operating expenses		218			226			615			714
Maintenance		51			45			140			155
Depreciation and amortization		135			121			436			402
General taxes		47			53			155			176
Asset impairment charges, net of insurance recoveries		—			(76	)		—			204
Gain on asset sales, net		—			(18	)		(8	)		(16	)
		1,221			1,070			4,360			4,631
Operating Income		212			212			620			195
Other Income (Deductions)
Interest and dividends		5			33			23			78
Regulatory return on capital expenditures		9			9			25			24
Foreign currency gain, net		1			—			1			1
Other income		3			4			9			15
Other expense		(15	)		(12	)		(21	)		(29	)
		3			34			37			89
Fixed Charges
Interest on long-term debt		86			96			257			295
Interest on long-term debt — related parties		3			3			10			10
Other interest		8			14			26			36
Capitalized interest		(1	)		(1	)		(4	)		(5	)
		96			112			289			336
Income (Loss) Before Income Taxes		119			134			368			(52	)
Income Tax Expense (Benefit)		37			46			126			(58	)
Income Before Minority Interests, Net		82			88			242			6
Minority Interests, Net		2			4			6			10
Income (Loss) From Continuing Operations		80			84			236			(4	)
Income (Loss) From Discontinued Operations, Net of Tax (Tax Benefit) of $1, $-, $- and $(1)		1			—			—			(87	)
Net Income (Loss)		81			84			236			(91	)
Preferred Dividends		2			2			8			8
Redemption Premium on Preferred Stock		—			—			—			1
Net Income (Loss) Available to Common Stockholders	$	79		$	82		$	228		$	(100	)

The accompanying notes are an integral part of these statements.

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In Millions, Except Per Share Amounts
	Three Months Ended				Nine Months Ended
September 30	2008		2007		2008		2007
	(Unaudited)
CMS Energy
Net Income (Loss)
Net Income (Loss) Available to Common Stockholders	$	79	$	82	$	228	$	(100	)
Basic Earnings (Loss) Per Average Common Share
Income (Loss) from Continuing Operations	$	0.35	$	0.37	$	1.02	$	(0.06	)
Income (Loss) from Discontinued Operations		0.01		—		—		(0.39	)
Net Income (Loss) Available to Common Stock	$	0.36	$	0.37	$	1.02	$	(0.45	)
Diluted Earnings (Loss) Per Average Common Share
Income (Loss) from Continuing Operations	$	0.33	$	0.34	$	0.96	$	(0.06	)
Income (Loss) from Discontinued Operations		0.01		—		—		(0.39	)
Net Income (Loss) Available to Common Stock	$	0.34	$	0.34	$	0.96	$	(0.45	)
Dividends Declared Per Common Share	$	0.09	$	0.05	$	0.27	$	0.15

The accompanying notes are an integral part of these statements.

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CMS Energy Corporation
Consolidated Statements of Cash Flows
(Unaudited)

				In Millions
Nine Months Ended September 30	2008			2007
Cash Flows from Operating Activities
Net income (loss)	$	236		$	(91	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation and amortization, net of nuclear decomissioning of $- and $4		436			407
Deferred income taxes and investment tax credit		117			(79	)
Minority interests (obligations), net		6			(12	)
Asset impairment charges, net of insurance recoveries		—			204
Postretirement benefits costs		110			102
Regulatory return on capital expenditures		(25	)		(24	)
Capital lease and other amortization		28			41
Loss (gain) on the sale of assets		(8	)		117
Earnings from equity method investees		(3	)		(36	)
Cash distributions from equity method investees		2			15
Postretirement benefits contributions		(38	)		(147	)
Shareholder class action settlement		—			(125	)
Electric sales contract termination payment		(275	)		—
Changes in other assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenues		178			(148	)
Decrease in accrued power supply and gas revenue		39			52
Increase in inventories		(393	)		(186	)
Decrease in deferred property taxes		118			111
Decrease in accounts payable		(21	)		(91	)
Decrease in accrued taxes		(189	)		(144	)
Decrease in accrued expenses		(42	)		(37	)
Decrease in other current and non-current assets		47			53
Decrease in other current and non-current liabilities		(140	)		(97	)
Net cash provided by (used in) operating activities		183			(115	)
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)		(511	)		(523	)
Cost to retire property		(22	)		(18	)
Restricted cash		4			34
Investments in nuclear decommissioning trust funds		—			(1	)
Proceeds from nuclear decommissioning trust funds		—			333
Proceeds from sale of assets		1			1,696
Cash relinquished from sale of assets		—			(113	)
Other investing		(10	)		(14	)
Net cash provided by (used in) investing activities		(538	)		1,394
Cash Flows from Financing Activities
Proceeds from notes, bonds, and other long-term debt		930			476
Issuance of common stock		6			13
Retirement of bonds and other long-term debt		(668	)		(769	)
Redemption of preferred stock		—			(32	)
Payment of common stock dividends		(61	)		(34	)
Payment of preferred stock dividends		(10	)		(9	)
Payment of capital lease and financial lease obligations		(18	)		(14	)
Debt issuance costs, financing fees, and other		(10	)		(18	)
Net cash provided by (used in) financing activities		169			(387	)
Effect of Exchange Rates on Cash		—			2
Net Increase (Decrease) in Cash and Cash Equivalents		(186	)		894
Cash and Cash Equivalents, Beginning of Period		348			351
Cash and Cash Equivalents, End of Period	$	162		$	1,245

The accompanying notes are an integral part of these statements.

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CMS Energy Corporation
Consolidated Balance Sheets

ASSETS	In Millions
	September 30		December 31
	2008		2007
	(Unaudited)
Plant and Property (at cost)
Electric utility	$	8,885	$	8,555
Gas utility		3,598		3,467
Enterprises		392		391
Other		34		34
		12,909		12,447
Less accumulated depreciation, depletion and amortization		4,360		4,166
		8,549		8,281
Construction work-in-progress		446		447
		8,995		8,728
Investments
Enterprises		6		6
Other		5		5
		11		11
Current Assets
Cash and cash equivalents at cost, which approximates market		162		348
Restricted cash at cost, which approximates market		31		34
Notes receivable		99		68
Accounts receivable and accrued revenue, less allowances of $20 in 2008 and $21 in 2007		638		837
Accrued power supply revenue		4		45
Accounts receivable — related parties		1		2
Inventories at average cost
Gas in underground storage		1,476		1,123
Materials and supplies		110		86
Generating plant fuel stock		140		125
Deferred property taxes		111		158
Regulatory assets — postretirement benefits		19		19
Prepayments and other		39		35
		2,830		2,880
Non-current Assets
Regulatory Assets
Securitized costs		429		466
Postretirement benefits		849		921
Customer Choice Act		104		149
Other		462		504
Deferred income taxes		48		99
Notes receivable, less allowances of $30 in 2008 and $31 in 2007		180		170
Other		169		264
		2,241		2,573
Total Assets	$	14,077	$	14,192

The accompanying notes are an integral part of these statements.

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STOCKHOLDERS’ INVESTMENT AND LIABILITIES	In Millions
	September 30			December 31
	2008			2007
	(Unaudited)
Capitalization
Common stockholders’ equity
Common stock, authorized 350.0 shares; outstanding 226.1 shares in 2008 and 225.1 shares in 2007	$	2		$	2
Other paid-in capital		4,491			4,480
Accumulated other comprehensive loss		(17	)		(144	)
Accumulated deficit		(2,047	)		(2,208	)
		2,429			2,130
Preferred stock of subsidiary		44			44
Preferred stock		249			250
Long-term debt		5,718			5,385
Long-term debt — related parties		178			178
Non-current portion of capital lease obligations		212			225
		8,830			8,212
Minority Interests		53			53
Current Liabilities
Current portion of long-term debt, capital and finance lease obligations		649			722
Notes payable		—			1
Accounts payable		417			430
Accrued rate refunds		11			19
Accounts payable — related parties		—			1
Accrued interest		78			103
Accrued taxes		119			308
Deferred income taxes		147			41
Regulatory liabilities		159			164
Electric sales contract termination liability		2			279
Argentine currency impairment reserve		—			197
Other		293			208
		1,875			2,473
Non-current Liabilities
Regulatory Liabilities
Regulatory liabilities for cost of removal		1,184			1,127
Income taxes, net		561			533
Other regulatory liabilities		147			313
Postretirement benefits		876			858
Asset retirement obligation		204			198
Deferred investment tax credit		56			58
Other		291			367
		3,319			3,454
Commitments and Contingencies (Notes 4, 5 and 7)
Total Stockholders’ Investment and Liabilities	$	14,077		$	14,192

The accompanying notes are an integral part of these statements.

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CMS Energy Corporation
Consolidated Statements of Common Stockholders’ Equity
(Unaudited)

	In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Common Stock
At beginning and end of period	$	2		$	2		$	2		$	2
Other Paid-in Capital
At beginning of period		4,488			4,477			4,480			4,468
Common stock issued		4			4			12			26
Common stock repurchased		(1	)		(5	)		(1	)		(5	)
Common stock reissued		—			—			—			6
Redemption of preferred stock		—			—			—			(19	)
At end of period		4,491			4,476			4,491			4,476
Accumulated Other Comprehensive Loss
Retirement Benefits Liability
At beginning of period		(16	)		(23	)		(15	)		(23	)
Retirement benefits liability adjustments (a)		—			1			(1	)		1
At end of period		(16	)		(22	)		(16	)		(22	)
Investments
At beginning of period		(5	)		16			—			14
Unrealized gain (loss) on investments (a)		(3	)		—			(8	)		2
Reclassification adjustments included in net income (loss) (a)		8			—			8			—
At end of period		—			16			—			16
Derivative Instruments
At beginning of period		(1	)		(1	)		(1	)		(12	)
Unrealized loss on derivative instruments (a)		—			—			—			(3	)
Reclassification adjustments included in net income (loss) (a)		—			—			—			14
At end of period		(1	)		(1	)		(1	)		(1	)
Foreign Currency Translation
At beginning of period		—			(129	)		(128	)		(297	)
Sale of interests in TGN (a)		—			—			128			—
Sale of Argentine assets (a)		—			—			—			128
Sale of Brazilian assets (a)		—			—			—			36
Other foreign currency translations (a)		—			—			—			4
At end of period		—			(129	)		—			(129	)
Total Accumulated Other Comprehensive Loss		(17	)		(136	)		(17	)		(136	)
Accumulated Deficit
At beginning of period		(2,106	)		(2,140	)		(2,208	)		(1,918	)
Effects of changing the retirement plans measurement date pursuant to SFAS No. 158
Service cost, interest cost, and expected return on plan assets for December 1 through December 31, 2007, net of tax		—			—			(4	)		—
Additional loss from December 1 through December 31, 2007, net of tax		—			—			(2	)		—
Adjustment to initially apply FIN 48, net of tax		—			—			—			(18	)
Net income (loss) (a)		81			84			236			(91	)
Preferred stock dividends declared		(2	)		(2	)		(8	)		(8	)
Common stock dividends declared		(20	)		(12	)		(61	)		(34	)
Redemption of preferred stock		—			—			—			(1	)
At end of period		(2,047	)		(2,070	)		(2,047	)		(2,070	)
Total Common Stockholders’ Equity	$	2,429		$	2,272		$	2,429		$	2,272

The accompanying notes are an integral part of these statements.

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	In Millions
	Three Months Ended					Nine Months Ended
September 30	2008			2007		2008			2007
	(Unaudited)
(a) Disclosure of Comprehensive Income:
Net income (loss)	$	81		$	84	$	236		$	(91	)
Retirement benefits liability adjustments, net of tax of $-, $1, $2, and $1, respectively		—			1		(1	)		1
Unrealized gain (loss) on investments, net of tax (tax benefit) of $(3), $1, $(6), and $1, respectively		(3	)		—		(8	)		2
Reclassification adjustments included in net income (loss), net of tax of $5, $-, $5, and $-, respectively		8			—		8			—
Derivative Instruments
Unrealized loss on derivative instruments, net of tax (tax benefit) of $-, $(1), $-, and $2, respectively		—			—		—			(3	)
Reclassification adjustments included in net income (loss) , net of tax of $-, $7, $-, and $7, respectively		—			—		—			14
Sale of interests in TGN, net of tax of $69		—			—		128			—
Sale of Argentine assets, net of tax of $68		—			—		—			128
Sale of Brazilian assets, net of tax of $20		—			—		—			36
Other foreign currency translations		—			—		—			4
Total Comprehensive Income	$	86		$	85	$	363		$	91

The accompanying notes are an integral part of these statements.

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CMS Energy Corporation
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

These interim Consolidated Financial Statements have been prepared by CMS Energy in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. As a result, CMS Energy has condensed or omitted certain information and Note disclosures normally included in consolidated financial statements prepared in accordance with accounting principles generally accepted in the United States. CMS Energy has reclassified certain prior year amounts to conform to the presentation in the current year. Therefore, the consolidated financial statements for the three and nine months ended September 30, 2007 have been updated for amounts previously reported. In management’s opinion, the unaudited information contained in this report reflects all adjustments of a normal recurring nature necessary to ensure the fair presentation of financial position, results of operations and cash flows for the periods presented. The Notes to Consolidated Financial Statements and the related Consolidated Financial Statements should be read in conjunction with the Consolidated Financial Statements and related Notes contained in CMS Energy’s Form 10-K for the year ended December 31, 2007. Due to the seasonal nature of CMS Energy’s operations, the results presented for this interim period are not necessarily indicative of results to be achieved for the fiscal year.

1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES

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

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

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

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

Revenue Recognition Policy: We recognize revenues from deliveries of electricity and natural gas, and from the transportation, processing, and storage of natural gas when services are provided. We record unbilled revenues for the estimated amount of energy delivered to customers but not yet billed. Our unbilled receivables were $259 million at September 30, 2008 and $490 million at December 31, 2007. We record sales tax on a net basis and exclude it from revenues. We recognize revenues on sales of marketed electricity, natural gas, and other energy products at delivery.

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Cash and Cash Equivalents: Cash and cash equivalents include short-term, highly-liquid investments with original maturities of three months or less. At September 30, 2008, these investments consisted of money market funds invested in U.S. Treasury notes and repurchase agreements collateralized by U.S. Treasury notes. The fair value of these investments approximates their amortized cost.

Other Income and Other Expense: The following tables show the components of Other income and Other expense:

	In Millions
	Three Months Ended				Nine Months Ended
September 30	2008		2007		2008		2007
Other income
Electric restructuring return	$	—	$	—	$	—	$	1
Return on stranded and security costs		1		1		4		4
Gain on investment		—		3		—		7
All other		2		—		5		3
Total other income	$	3	$	4	$	9	$	15

	In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Other expense
Derivative loss on debt tender offer	$	—		$	—		$	—		$	(3	)
Loss on reacquired and extinguished debt		—			(11	)		—			(22	)
Unrealized investment loss		(13	)		—			(13	)		—
Civic and political expenditures		(1	)		(1	)		(5	)		(2	)
All other		(1	)		—			(3	)		(2	)
Total other expense	$	(15	)	$	(12	)	$	(21	)	$	(29	)

Reclassifications: We have reclassified certain prior-period amounts on our Consolidated Financial Statements to conform to the presentation for the current period. These reclassifications did not affect consolidated net income (loss) or cash flows for the periods presented.

New Accounting Standards Not Yet Effective: SFAS No. 141(R), Business Combinations: In December 2007, the FASB issued SFAS No. 141(R), which replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes how an acquiring entity should measure and recognize assets acquired, liabilities assumed, and noncontrolling interests acquired through a business combination. The standard also establishes how goodwill or gains from bargain purchases should be measured and recognized and what information the acquirer should disclose to enable users of the financial statements to evaluate the nature and financial effects of a business combination. Costs of an acquisition are to be recognized separately from the business combination. We will apply SFAS No. 141(R) prospectively to any business combination for which the date of acquisition is on or after January 1, 2009.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Under this standard, ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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

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

FSP FAS 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161: In September 2008, the FASB issued this standard, effective for us December 31, 2008. This standard will amend SFAS No. 133 and FIN 45 to enhance the disclosure requirements for issuers of credit derivatives and financial guarantees. As we have not issued any credit derivatives, this standard will apply only to our disclosures about guarantees we have issued. It will have no effect on our consolidated financial statements.

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

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

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

EITF Issue 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement: In September 2008, the FASB ratified EITF Issue 08-5, effective for us January 1, 2009. This guidance concludes that the fair value measurement of a liability should not consider the effect of a third-party credit enhancement or guarantee supporting the liability. The fair value of the liability should

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thus reflect the credit standing of the issuer and should not be adjusted to reflect the credit standing of a third-party guarantor. The standard is to be applied prospectively. This standard will not have a material impact on our consolidated financial statements.

2: FAIR VALUE MEASUREMENTS

SFAS No. 157, which became effective January 1, 2008, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. It does not require any new fair value measurements, but applies to those fair value measurements recorded or disclosed under other accounting standards. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants, and requires that fair value measurements incorporate all assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. The standard also eliminates the prohibition against recognizing “day one” gains and losses on derivative instruments. We did not hold any derivatives with “day one” gains or losses during the nine months ended September 30, 2008. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we held during the nine months ended September 30, 2008.

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

• Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities. These markets must be accessible to us at the measurement date.

• Level 2 inputs are observable, market-based inputs, other than Level 1 prices. Level 2 inputs may include quoted prices for similar assets or liabilities in active markets, quoted prices in inactive markets, interest rates and yield curves observable at commonly quoted intervals, credit risks, default rates, and inputs derived from or corroborated by observable market data.

• Level 3 inputs are unobservable inputs that reflect our own assumptions about how market participants would value our assets and liabilities.

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

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

• AROs,

• most of the nonfinancial assets and liabilities acquired in a business combination, and

• impairment analyses performed for nonfinancial assets.

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

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SEC and FASB Guidance on Fair Value Measurements: On September 30, 2008, in response to concerns about fair value accounting and its possible role in the recent declines in the financial markets, the SEC Office of the Chief Accountant and the FASB staff jointly released additional guidance on fair value measurements. The guidance, which is effective for us immediately, did not change or conflict with the fair value principles in SFAS No. 157, but rather provided further clarification on how to value a financial asset in an illiquid market. In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active. The standard is consistent with the joint guidance issued by the SEC and FASB and is effective for us as of the quarter ended September 30, 2008. The standard is to be applied prospectively. The guidance in this standard and the joint guidance provided by the FASB and the SEC did not impact our fair value measurements.

Assets/Liabilities Measured at Fair Value on a Recurring Basis

The following table summarizes, by level within the fair value hierarchy, our assets and liabilities accounted for at fair value on a recurring basis at September 30, 2008.

	In Millions
	Total			Level 1			Level 2			Level 3
Assets:
Nonqualified Deferred Compensation Plan Assets	$	5		$	5		$	—		$	—
SERP
Equity Securities		50			50			—			—
Debt Securities		29			—			29			—
CMS ERM derivative contracts:
Non-trading electric/gas contracts (a)		10			1			8			1
Total (c)	$	94		$	56		$	37		$	1
Liabilities:
Nonqualified Deferred Compensation Plan Liabilities	$	(5	)	$	(5	)	$	—		$	—
CMS ERM derivative contracts:
Non-trading electric/gas contracts (b)		(27	)		(1	)		(7	)		(19	)
Total (c)	$	(32	)	$	(6	)	$	(7	)	$	(19	)

(a)	This amount is gross and excludes the $4 million impact of offsetting derivative assets and liabilities under master netting arrangements. We report the fair values of our derivative assets net of these impacts within Other assets on our Consolidated Balance Sheets.
(b)	This amount is gross and excludes the $4 million impact of offsetting derivative assets and liabilities under a master netting arrangement. We report the fair values of our derivative liabilities net of these impacts within Other liabilities on our Consolidated Balance Sheets.
(c)	At September 30, 2008, assets classified as Level 3 represent one percent of total assets measured at fair value and liabilities classified as Level 3 represent 59 percent of total liabilities measured at fair value.

Nonqualified Deferred Compensation Plan Assets: Our nonqualified deferred compensation plan assets are invested in various mutual funds. We value these assets using a market approach, which uses the daily quoted NAV provided by the fund managers that are the basis for transactions to buy or sell shares in each fund. On our Consolidated Balance Sheets, these assets are included in Other non-current assets.

SERP Assets: Our SERP assets are valued using a market approach, which incorporates prices and other relevant information from market transactions. Our SERP equity securities consist of an investment in a

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Standard & Poor’s 500 Index mutual fund. The fund’s securities are listed on an active exchange or dealer market. The fair value of the SERP equity securities is based on the NAV of the mutual fund that is derived from the daily closing prices of the equity securities held by the fund. The NAV is the basis for transactions to buy or sell shares in the fund. Our SERP debt securities, which are investment grade municipal bonds, are valued using a market approach, which is based on a matrix pricing model that incorporates market-based information. The fair value of our SERP debt securities is derived from various observable inputs, including benchmark yields, reported securities trades, broker/dealer quotes, bond ratings, and general information on market movement for investment grade municipal securities normally considered by market participants when pricing a debt security. SERP assets are included in Other non-current assets on our Consolidated Balance Sheets. For additional details about our SERP securities, see Note 7, Financial and Derivative Instruments.

Derivative Instruments: Our derivative instruments are valued using either a market approach that incorporates information from market transactions, or an income approach that discounts future expected cash flows to a present value amount. We use various inputs to value our derivatives depending on the type of contract and the availability of market data. We have exchange-traded derivative contracts that are valued based on Level 1 quoted prices in actively traded markets. We also have derivatives that are valued using Level 2 inputs, including commodity market prices, interest rates, credit ratings, default rates, and market-based seasonality factors. For derivative instruments that extend beyond time periods in which quoted prices are available, we use modeling methods to project future prices. Such fair value measurements are classified in Level 3 unless modeling was required only for an insignificant portion of the total derivative value.

CMS ERM’s non-trading contracts include an electricity sales agreement that extends beyond the term for which quoted electricity prices are available and which is classified as Level 3. To value this agreement, we use a proprietary forward power pricing curve that is based on forward gas prices and an implied heat rate. We also increased the fair value of the liability for this agreement by an amount that reflects the uncertainty of our model.

For all fair values other than Level 1 prices, we incorporate adjustments for the risk of nonperformance. For our derivative assets, we apply a credit adjustment against the asset based on the published default rate for the counterparty’s assigned credit rating. These credit ratings are assigned to each counterparty based on an internal credit-scoring model that considers various inputs, including the counterparty’s financial statements, credit reports, trade press, and other information that would be available to market participants. We compare the results of our credit-scoring model to credit ratings published by independent rating agencies. To the extent that our internal ratings are comparable to those obtained from the independent agencies, we classify the resulting credit adjustment within Level 2. If our internal model results in a rating that is outside of the range of ratings given by the independent agencies, the credit adjustment would be classified as a Level 3 input, and if significant to the overall valuation, would cause the entire fair value to be classified as Level 3. We also adjust our derivative liabilities downward to reflect our own risk of nonperformance, based on the published credit ratings for our company. For details about our derivative contracts, see Note 7, Financial and Derivative Instruments.

Nonqualified Deferred Compensation Plan Liabilities: The non-qualified deferred compensation plan liabilities are valued based on the fair values of the plan assets, as they reflect what is owed to the plan participants in accordance with their investment elections. These liabilities, except for our primary DSSP plan liability, are included in Other non-current liabilities on our Consolidated Balance Sheets. Our primary DSSP plan liability is included in non-current Postretirement benefits on our Consolidated Balance Sheets.

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Asset/Liabilities Measured at Fair Value on a Recurring Basis using Level 3 inputs

The following table is a reconciliation of changes in the fair values of our Level 3 assets and liabilities accounted for at fair value on a recurring basis.

	In Millions
	CMS ERM
	Non-trading
	contracts
Balance at June 30, 2008	$	(24	)
Total gains (losses) (realized and unrealized)
Included in earnings (a)		5
Included in AOCL		—
Purchases, sales, issuances, and settlements (net)		1
Balance at September 30, 2008	$	(18	)
Unrealized gains (losses) included in earnings for the quarter ended September 30, 2008 relating to assets and liabilities still held at September 30, 2008 (a)	$	6

	CMS ERM
	Non-trading
	contracts
Balance at December 31, 2007	$	(19	)
Total gains (losses) (realized and unrealized)
Included in earnings (a)		(1	)
Included in AOCL		—
Purchases, sales, issuances, and settlements (net)		2
Balance at September 30, 2008		(18	)
Unrealized gains (losses) included in earnings for the nine months ended September 30, 2008 relating to assets and liabilities still held at September 30, 2008 (a)	$	—

(a) Realized and unrealized gains (losses) for Level 3 recurring fair values are recorded in earnings as a component of Operating Revenue or Operating Expenses in our Consolidated Statements of Income (Loss). For the nine months ended September 30, 2008, unrealized gains (losses) included in earnings relating to Level 3 fair values still held at September 30, 2008 were immaterial.

3: ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES

ASSET SALES

The impacts of our asset sales are included in Gain on asset sales, net and Income (Loss) from Discontinued Operations in our Consolidated Statements of Income (Loss). Asset sales were immaterial for the nine months ended September 30, 2008.

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

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As of May 2008, the Republic of Argentina had not paid the ICSID award as due, causing its option to purchase our interests in TGN to expire. In June 2008, we executed an agreement with MEI and a third- party to assign the ICSID award and to sell our interests in TGN directly to the third-party. In accordance with the agreements executed in March 2007, the proceeds from the assignment of the ICSID award and the sale of TGN were passed on to MEI. In light of these events, during the second quarter of 2008 we recognized an $8 million deferred gain on the assignment of the ICSID award in Gain on asset sales, net in our Consolidated Statements of Income (Loss). We also recognized a $197 million cumulative net foreign currency translation loss related to TGN, which had been deferred as a Foreign Currency Translation component of stockholders’ equity. This charge was fully offset by the elimination of a $197 million Argentine currency impairment reserve on our Consolidated Balance Sheets, created when we impaired our investment in TGN in March 2007. For additional details, see “Impairment Charges” within this Note.

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

The following table summarizes our asset sales for the nine months ended September 30, 2007:

In Millions
							Disposal of
				Continuing			Discontinued
				Operations			Operations
		Cash		Pretax			Pretax
Month Sold	Business	Proceeds		Gain (Loss)			Gain (Loss)
March	El Chocon (a)	$	50	$	34		$	—
March	Argentine/Michigan businesses (b)		130		(5	)		(278	)
April	Palisades (c)		334		—			—
April	SENECA (d)		106		—			46
May	Middle East, Africa and India businesses (e)		792		(16	)		96
June	CMS Energy Brasil S.A. (f)		201		—			3
August	GasAtacama (g)		80		—			—
Various	Other		3		3			—
	Total	$	1,696	$	16		$	(133	)

(a)	We sold our interest in El Chocon to Endesa, S.A.
(b)	We sold a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy. Due to the settlement of certain legal proceedings, we recognized a $17 million gain in the third quarter of 2007.
(c)	We sold Palisades to Entergy for $380 million and received $364 million after various closing adjustments. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. Because of the sale of Palisades, we paid the NMC, the former operator of Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC. 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 accounted for the disposal of Palisades as a financing for accounting purposes and thus we recognized no gain on the Consolidated Statements of Income (Loss). We accounted for the remaining non-real estate assets and liabilities associated with the transaction as a sale.
(d)	We sold our ownership interest in SENECA and certain associated generating equipment to PDVSA.

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(e)	We sold our ownership interest in businesses in the Middle East, Africa, and India to TAQA.
(f)	We sold CMS Energy Brasil S.A. to CPFL Energia S.A., a Brazilian utility.
(g)	We sold our investment in GasAtacama to Endesa S.A.

DISCONTINUED OPERATIONS

Discontinued operations are a component of our Enterprises business segment. We included the following amounts in the Income (Loss) From Discontinued Operations line in our Consolidated Statements of Income (Loss):

In Millions
Three months ended September 30	2008		2007
Revenues	$	—	$	—
Discontinued operations:
Pretax income from discontinued operations	$	2	$	—
Income tax expense		1		—
Income From Discontinued Operations	$	1	$	—

In Millions
Nine months ended September 30	2008		2007
Revenues	$	—	$	235
Discontinued operations:
Pretax loss from discontinued operations	$	—	$	(88	)(a)
Income tax benefit		—		(1	)
Loss From Discontinued Operations	$	—	$	(87	)

(a) Includes a loss on disposal of our Argentine and northern Michigan non-utility assets of $278 million ($171 million after tax and after minority interest), a gain on disposal of SENECA of $46 million ($33 million after tax and after minority interest), a gain on disposal of our ownership interests in businesses in the Middle East, Africa, and India of $96 million ($62 million after tax), and a gain on disposal of CMS Energy Brasil S.A. of $3 million ($2 million after tax).

For the nine months ended September 30, 2007, discontinued operations include a provision for closing costs and a portion of CMS Energy’s parent company interest expense. We allocated interest expense of $7 million equal to the net book value of the asset sold divided by CMS Energy’s total capitalization of each discontinued operation multiplied by CMS Energy’s interest expense.

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IMPAIRMENT CHARGES

We did not have asset impairment charges for the nine months ended September 30, 2008. The following table summarizes asset impairments at our Enterprises business segment for the nine months ended September 30, 2007:

In Millions
Nine months ended September 30	2007
Asset impairments:
TGN (a)	$	140
GasAtacama (b)		35
Jamaica (c)		22
PowerSmith (d)		5
Prairie State (e)		2
Total asset impairments	$	204

(a)	We recorded a $215 million impairment charge to recognize the reduction in fair value of our investment in TGN, a natural gas business in Argentina. The impairment included a cumulative net foreign currency translation loss of $197 million. In September 2007, we recognized a $75 million deferred credit in Asset impairment charges, net of insurance recoveries, in our Consolidated Statements of Income (Loss).
(b)	We recorded an impairment charge to reflect the fair value of our investment in GasAtacama as determined in sale negotiations.
(c)	We recorded an impairment charge to reflect the fair value of our investment in an electric generating plant in Jamaica by discounting a set of probability-weighted streams of future operating cash flows.
(d)	We recorded an impairment charge to reflect the fair value of our investment in PowerSmith as determined in sale negotiations.
(e)	We recorded an impairment charge to reflect our withdrawal from the co-development of Prairie State with Peabody Energy because the project did not meet our investment criteria.

4: CONTINGENCIES

DOJ Investigation: From May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These transactions, referred to as round-trip trades, had no impact on previously reported consolidated net income, EPS or cash flows, but had the effect of increasing operating revenues and operating expenses by equal amounts. We are cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. We responded to the DOJ’s last request in May 2004. We are unable to predict the outcome of this matter and what effect, if any, this investigation will have on our business.

SEC Investigation and Settlement: In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and we neither admitted to nor denied the order’s findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. As of June 30, 2008, all three former employees have settled with the SEC.

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Gas Index Price Reporting Investigation: We notified appropriate regulatory and governmental agencies that some employees at CMS MST and CMS Field Services appeared to have provided inaccurate information regarding natural gas trades to various energy industry publications, which compile and report index prices. We cooperated with an investigation by the DOJ regarding this matter. Although we have not received any formal notification that the DOJ has completed its investigation, the DOJ’s last request for information occurred in November 2003, and we completed our response to this request in May 2004. We are unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation will have on our business.

Gas Index Price Reporting Litigation: We, along with CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a result of allegedly inaccurate natural gas price reporting. Allegations include manipulation of NYMEX natural gas futures and options prices, price-fixing conspiracies, and artificial inflation of natural gas retail prices in California, Colorado, Kansas, Missouri, Tennessee, and Wisconsin. In June 2007, CMS MST settled a master class action suit in California state court for $7 million. In September 2007, the CMS Energy defendants also settled four class action suits originally filed in California federal court. The other cases in several jurisdictions remain pending. We cannot predict the financial impact or outcome of these matters.

Katz Technology Litigation: In June 2007, RAKTL filed a lawsuit in the United States District Court for the Eastern District of Michigan against CMS Energy and Consumers alleging patent infringement. RAKTL claimed that automated customer service, bill payment services and gas leak reporting offered to our customers and accessed through toll free numbers infringe on patents held by RAKTL. CMS Energy, along with Consumers, signed a settlement and license agreement with RAKTL in June 2008 to settle the litigation. The settlement and licensing costs with RAKTL are immaterial. On June 10, 2008, the court entered an order dismissing the case with prejudice.

Bay Harbor: As part of the development of Bay Harbor by certain subsidiaries of CMS Energy, pursuant to an agreement with the MDEQ, third parties constructed a golf course and park over several abandoned CKD piles, left over from the former cement plant operations on the Bay Harbor site. The third parties also undertook a series of remedial actions, including removing abandoned buildings and equipment; consolidating, shaping and covering CKD piles with soil and vegetation; removing CKD from streams and beaches; and constructing a leachate collection system at an identified seep. Leachate is formed when water passes through CKD. In 2002, CMS Energy sold its interest in Bay Harbor, but retained its obligations under environmental indemnifications entered into at the start of the project.

In 2005, the EPA along with CMS Land and CMS Capital executed an AOC and approved a Removal Action Work Plan to address problems at Bay Harbor. Collection systems required under the plan have been installed and shoreline monitoring is ongoing. In February 2008, CMS Land and CMS Capital submitted a proposed augmentation plan to the EPA to address areas where pH measurements are not satisfactory. CMS Land, CMS Capital and the EPA have agreed upon the augmentation measures and a schedule for their installation. The augmentation meaures are being implemented and are anticipated to be completed in 2009.

In February 2008, the MDEQ and the EPA granted permits for CMS Land or its affiliate to construct and operate a deep injection well near Alba, Michigan in eastern Antrim County. Certain environmental groups, a local township, and a local county filed an appeal of the EPA’s decision and following denial by the MDEQ of a right to a hearing, filed lawsuits in the Ingham Circuit Court appealing the permits. These same groups filed a lawsuit in Antrim County seeking an injunction against development of the well. The EPA has denied the appeal; however, the cases in the Circuit Courts remain pending.

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CMS Land and CMS Capital, the MDEQ, the EPA, and other parties are having ongoing discussions concerning the long-term remedy for the Bay Harbor sites. These discussions are addressing, among other things, issues relating to:

• the disposal of leachate,

• the capping and excavation of CKD,

• the location and design of collection lines and upstream diversion of water,

• potential flow of leachate below the collection system,

• applicable criteria for various substances such as mercury, and

• other matters that are likely to affect the scope of remedial work that CMS Land and CMS Capital may be obligated to undertake.

CMS Energy has recorded cumulative charges, including accretion expense, related to this matter of $141 million. At September 30, 2008, we have a recorded liability of $67 million for our remaining obligations. We calculated this liability based on discounted projected costs, using a discount rate of 4.45 percent and an inflation rate of one percent on annual operating and maintenance costs. Our discount rate is based on the interest rate for 30-year U.S. Treasury securities. The undiscounted amount of the remaining obligation is $81 million. We expect to pay $21 million in 2008, $15 million in 2009, $9 million in 2010 and in 2011, and the remaining expenditures as part of long-term liquid disposal and operating and maintenance costs. Our estimate of remedial action costs and the timing of expenditures could be impacted by any significant change in circumstances or assumptions, such as:

• an increase in the number of problem areas,

• different remediation techniques,

• nature and extent of contamination,

• continued inability to reach agreement with the MDEQ or the EPA over required remedial actions,

• delays in the receipt of requested permits,

• delays following the receipt of any requested permits due to legal appeals of third parties,

• increase in water disposal costs,

• additional or new legal or regulatory requirements, or

• new or different landowner claims.

Depending on the size of any indemnification obligation or liability under environmental laws, an adverse outcome of this matter could have a potentially significant adverse effect on CMS Energy’s financial condition and liquidity and could negatively impact CMS Energy’s financial results. We cannot predict the financial impact or outcome of this matter.

Quicksilver Resources, Inc.: On November 1, 2001, Quicksilver sued CMS MST in Texas state court in Fort Worth, Texas for breach of contract in connection with a base contract for the sale and purchase of natural gas. The contract outlines Quicksilver’s agreement to sell, and CMS MST’s agreement to buy, natural gas. Quicksilver believes that it is entitled to more payments for natural gas than it has received. CMS MST disagrees with Quicksilver’s analysis and believes that it has paid all amounts owed for delivery of gas according to the contract. Quicksilver sought damages of up to approximately $126 million, plus prejudgment interest and attorney fees.

The jury verdict awarded Quicksilver zero compensatory damages but $10 million in punitive damages. The jury found that CMS MST breached the contract and committed fraud but found no actual damage related to such a claim.

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On May 15, 2007, the trial court vacated the jury award of punitive damages but held that the contract should be rescinded prospectively. The judicial rescission of the contract caused CMS Energy to record a charge in the second quarter of 2007 of $24 million, net of tax. To preserve its appellate rights, CMS MST filed a motion to modify, correct or reform the judgment and a motion for a judgment contrary to the jury verdict with the trial court. The trial court dismissed these motions. CMS MST has filed a notice of appeal with the Texas Court of Appeals. Quicksilver has filed a notice of cross appeal. Both Quicksilver and CMS MST have filed their opening briefs and briefs of cross appeal. Oral arguments were made on October 29, 2008. Quicksilver claims that the contract should be rescinded from its inception, rather than merely from the date of the judgment. Although we believe Quicksilver’s position to be without merit, if the court were to grant the relief requested by Quicksilver, it could result in a loss in excess of $150 million and have a material adverse effect on us. We cannot predict the financial impact or outcome of this matter.

Consumers’ Electric Utility Contingencies

Electric Environmental Matters: Our operations are subject to environmental laws and regulations. Generally, we have been able to recover in customer rates the costs to operate our facilities in compliance with these laws and regulations.

Cleanup and Solid Waste: Under the NREPA, we will ultimately incur investigation and response activity costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies.

We are a potentially responsible party at a number of contaminated sites administered under the Superfund. Superfund liability is joint and several. However, many other creditworthy parties with substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for most of our known Superfund sites will be between $2 million and $11 million. At September 30, 2008, we have recorded a liability for the minimum amount of our estimated probable Superfund liability in accordance with FIN 14.

The timing of payments related to our investigation and response activities at our Superfund and NREPA sites is uncertain. Any significant change in assumptions, such as different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of response activity costs and the timing of our payments.

Ludington PCB: In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at Ludington. We removed and replaced part of the PCB material with non-PCB material. Since proposing a plan to deal with the remaining materials, we have had several communications with the EPA. The EPA has proposed a rule that would allow us to leave the material in place, subject to certain restrictions. We are not able to predict when the EPA will issue a final ruling. We cannot predict the financial impact or outcome of this matter.

Electric Utility Plant Air Permit Issues: In April 2007, we received a NOV/FOV from the EPA alleging that 14 of our utility boilers exceeded visible emission limits in their associated air permits. The utility boilers are located at the Karn/Weadock Generating Complex, Campbell Plant, Cobb Electric Generating Station and Whiting Plant, which are all in Michigan. We have responded formally to the NOV/FOV denying the allegations and are awaiting the EPA’s response to our submission. We cannot predict the financial impact or outcome of this matter.

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as “routine maintenance, repair and replacement” rather than seeking permits from the EPA to modify their plants. We responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance, repair and replacement.” In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. In addition, in October 2008, we received a

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NOV for three of our coal-fired facilities relating to violations of NSR and PSD regulations, alleging ten projects from 1986 to 1998 were subject to PSD review. We are currently preparing our response to this NOV and the information request. If the EPA does not accept our interpretation, we could be required to install additional pollution control equipment at some or all of our coal-fired electric generating plants and pay fines. Additionally, we would need to assess the viability of continuing operations at certain plants. We cannot predict the financial impact or outcome of this matter.

Litigation: Qualifying Facilities: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs) filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made under power purchase agreements. The judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The plaintiffs appealed the MPSC order to the Michigan Court of Appeals, which, in April 2008, affirmed the MPSC order. The plaintiffs filed an application for leave to appeal with the Michigan Supreme Court. In September 2008, the application for leave to appeal was denied. The plaintiffs also agreed to dismiss two related cases, thus closing this litigation.

Transmission Charges: Transmission charges we have paid to MISO have been subject to regulatory review and recovery through the annual PSCR process. The Attorney General has argued that the statute governing the PSCR process does not permit recovery of transmission charges in that manner and those expenses should be considered in general rate cases. Several decisions of the Michigan Court of Appeals have ruled against the Attorney General’s arguments, but in September 2008, the Michigan Supreme Court granted the Attorney General’s applications for leave to appeal two of those decisions. If the Michigan Supreme Court accepts the Attorney General’s position, we and other electric utilities would be required to obtain recovery of transmission charges through an alternative ratemaking mechanism. We expect a decision by the Michigan Supreme Court on these appeals by mid-2009. We cannot predict the financial impact or outcome of this matter.

Consumers’ Electric Utility Rate Matters

Electric ROA: The Customer Choice Act allows electric utilities to recover their net Stranded Costs. In November 2004, the MPSC approved recovery of our Stranded Costs incurred in 2002 and 2003 plus interest through the period of collection. At September 30, 2008, we had a regulatory asset for Stranded Costs of $70 million. We collect these Stranded Costs through a surcharge on ROA customers. The new energy legislation directs the MPSC to approve rates that will allow us to recover our Stranded Costs within five years.

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Power Supply Costs: The PSCR process is designed to allow us to recover reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudence in annual plan proceedings and in annual plan reconciliation proceedings. The following table summarizes our PSCR reconciliation filing currently pending with the MPSC:

Power Supply Cost Recovery Reconciliation

PSCR		Net Under-	PSCR Cost of
Year	Date Filed	recovery	Power Sold	Description of Net Underrecovery
2007	March 2008	$42 million (a)	$1.628 billion	Underrecovery relates primarily to the removal of $44 million of Palisades sale proceeds credits from the PSCR. The MPSC directed that we refund these credits through a separate surcharge instead of as a reduction of power supply costs.

(a) This amount includes 2006 underrecoveries as allowed by the MPSC order in our 2007 PSCR plan case.

2006 PSCR Reconciliation: Our 2006 PSCR reconciliation resulted in a $56 million underrecovery. The April 2008 MPSC order disallowed $6 million related to certain replacement power costs and the recovery of discount credits provided to certain customers. As a result, we reduced our Accrued power supply revenue for the period ended March 31, 2008 for this amount. The MPSC order also addressed the allocation of our proceeds from the sale of sulfur dioxide allowances of $62 million. The MPSC order directed us to credit $44 million of the proceeds to PSCR customers and allowed us to retain $18 million of the proceeds. We previously reserved all proceeds as a regulatory liability. As a result of the MPSC order, we recognized our retained portion in earnings for the period ended March 31, 2008.

2007 PSCR Plan: In April 2008, the MPSC issued an order allowing us to continue to use our 2007 PSCR monthly factor as approved in its temporary order, with minor adjustments. The order also allowed us to include prior year underrecoveries and overrecoveries in future PSCR plans as prescribed in the temporary order. Furthermore, the MPSC order directed us to allocate the proceeds from the sale of sulfur dioxide allowances to PSCR customers in the manner approved in the 2006 PSCR reconciliation case.

2008 PSCR Plan: In September 2007, we submitted our 2008 PSCR plan filing to the MPSC. The plan includes recovery of 2007 PSCR underrecoveries, which were $42 million. We self-implemented a 2008 PSCR charge in January 2008. In June 2008, the ALJ issued a Proposal for Decision that is consistent with our position, with minor exceptions.

2009 PSCR Plan: In September 2008, we submitted our 2009 PSCR plan filing to the MPSC. We expect to self-implement the proposed 2008 PSCR charge in January 2009, absent action by the MPSC by the end of 2008.

While we expect to recover fully all of our PSCR costs, we cannot predict the financial impact or the outcome of these proceedings. When we are unable to collect these costs as they are incurred, there is a negative impact on our cash flows.

Electric Rate Case: During 2007, we filed applications with the MPSC, as revised, seeking an annual increase in revenue of $265 million, which incorporated a requested 11.25 percent authorized return on equity. The filings sought recovery of the costs associated with increased plant investment, including the purchase of the Zeeland power plant, increased equity investment, higher operation and maintenance expenses, recovery of transaction costs from the sale of Palisades, and the approval of an energy efficiency program. In June 2008, the MPSC issued an order authorizing us to increase revenue by $221 million. This was

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lower than our revised position primarily due to the MPSC’s authorized return on equity of 10.7 percent and the final determination of our Zeeland plant revenue requirement. The MPSC order further instructed that we absorb $2 million of the Palisades sale transaction costs and that we exclude the energy efficiency surcharge from base rates until pending legislation regarding energy efficiency programs is completed. The legislation was enacted in October 2008 and it established separate procedures for implementation of energy efficiency programs outside of base rates.

The following table summarizes the components of the requested increase in revenue and the MPSC order:

In Millions
	Consumers			MPSC
Components of the increase in revenue	Position			Order			Difference
Revenue Sufficiency	$	(21	)	$	(46	)	$	(25	)
Zeeland Plant Requirement		86			74			(12	)
Base Rates Total		65			28			(37	)
Eliminate Palisades Recovery Credit in PSCR (a)		167			167			—
Palisades Sale Transaction Cost Surcharge		28			26			(2	)
Energy Efficiency Surcharge		5			—			(5	)
Total	$	265		$	221		$	(44	)

(a) Palisades power purchase agreement costs in the PSCR were offset through a base rate recovery credit until the MPSC order discontinued and removed the Palisades costs from base rates.

When we are unable to include increased costs and investments in rates in a timely manner, there is a negative impact on our cash flows.

Palisades Regulatory Proceedings: The MPSC order approving the Palisades sale transaction requires that we credit $255 million of excess sales proceeds and decommissioning amounts to our retail customers by December 2008. There are additional excess sales proceeds and decommissioning fund balances of $135 million above the amount in the MPSC order. The MPSC order in our electric rate case instructed us to offset the excess sales proceeds and decommissioning fund balances with $26 million of transaction costs from the Palisades sale and credit the remaining balance to customers. The distribution of these funds is still pending with the MPSC.

Other Consumers’ Electric Utility Contingencies

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-year power purchase agreement that began in 1990. Prior to September 2007, the cost that we incurred under the MCV PPA exceeded the recovery amount allowed by the MPSC. Pursuant to a regulatory-out provision in the contract, effective September 2007, we provided notice that we intended to limit our capacity and fixed energy payments to the MCV Partnership to the amount that we collect from our customers. As a result, the MCV Partnership filed an application with the MPSC requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed energy charges that we were allowed to recover from our customers.

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In June 2008, the MPSC approved an amended and restated MCV PPA entered into as part of a settlement agreement among us and other parties to an MPSC proceeding initiated by the MCV Partnership. The amended and restated MCV PPA, which took effect in October 2008, effectively eliminates the 88.7 percent availability cap and the resultant mismatch between the payments to the MCV Partnership and the amount that we collect from our customers. The amended and restated MCV PPA provides for:

• a capacity charge of $10.14 per MWh of available capacity,

• a fixed energy charge based on our annual average base load coal generating plant operating and maintenance cost,

• a variable energy charge for all delivered energy that reflects the MCV Partnership’s cost of production,

• the elimination of the RCP, but continues the $5 million annual contribution by the MCV Partnership to a renewable resources program, and

• an option for us to extend the MCV PPA for five years or purchase the MCV Facility at the conclusion of the MCV PPA’s term in March 2025.

As a part of the amended and restated MCV PPA, the MCV Partnership agreed not to contest our exercise of the regulatory-out provision in the original MCV PPA.

Nuclear Matters: DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other utilities participated, has not been successful in producing more specific relief for the DOE’s failure to accept the spent nuclear fuel.

A number of court decisions support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. We filed our complaint in December 2002. If our litigation against the DOE is successful, we plan to use any recoveries as reimbursement for the incurred costs of spent nuclear fuel storage during our ownership of Palisades and Big Rock. We cannot predict the financial impact or outcome of this matter. The sale of Palisades and the Big Rock ISFSI did not transfer the right to any recoveries from the DOE related to costs of spent nuclear fuel storage incurred during our ownership of Palisades and Big Rock.

Big Rock Decommissioning: The MPSC and the FERC regulate the recovery of costs to decommission Big Rock. In December 2000, funding of a Big Rock trust fund ended because the MPSC-authorized decommissioning surcharge collection period expired. The level of funds provided by the trust fell short of the amount needed to complete decommissioning. As a result, we provided $44 million of corporate contributions for decommissioning costs. This amount is in addition to the $30 million payment to Entergy to assume ownership and responsibility for the Big Rock ISFSI and additional corporate contributions for nuclear fuel storage costs of $55 million, due to the DOE’s failure to accept spent nuclear fuel on schedule. We have a $129 million regulatory asset recorded on our Consolidated Balance Sheets for these costs.

In July 2008, we filed an application with the MPSC seeking the deferral of ratemaking treatment regarding the recovery of our nuclear fuel storage costs and the payment to Entergy, until the litigation regarding these costs is resolved in the federal courts. In the application, we also are seeking to recover the $44 million Big Rock decommissioning shortfall from customers. We cannot predict the outcome of this proceeding.

Nuclear Fuel Disposal Cost: We deferred payment for disposal of spent nuclear fuel used before April 7, 1983. Our DOE liability is $162 million at September 30, 2008. This amount includes interest, and is payable upon the first delivery of spent nuclear fuel to the DOE. We recovered the amount of this liability, excluding a portion of interest, through electric rates. In conjunction with the sale of Palisades and the Big Rock ISFSI, we retained this obligation and provided a $155 million letter of credit to Entergy as security for this obligation.

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Consumers’ Gas Utility Contingencies

Gas Environmental Matters: We expect to incur investigation and remediation costs at a number of sites under the NREPA, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In December 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represented a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through proceeds from insurance settlements and MPSC-approved rates.

From January 1, 2006 to September 30, 2008, we have spent a total of $14 million for MGP response activities. At September 30, 2008, we have a liability of $15 million and a regulatory asset of $46 million, which includes $31 million of deferred MGP expenditures. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. We expect annual response activity costs to range between $4 million and $5 million over the next four years. Periodically, we review these response activity cost estimates. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of response activity costs and the timing of our payments.

Gas Title Transfer Tracking Fees and Services: In November 2007, we reached an agreement in principle with Duke Energy Corporation, Dynegy Incorporated, Reliant Energy Resources Incorporated and the FERC Staff to settle the TTT proceeding. The terms of the agreement include the payment of $2 million in total refunds to all TTT customers and a reduced rate for future TTT transactions. The settlement agreement was filed on February 1, 2008. The FERC conditionally approved the settlement on July 28, 2008.

FERC Investigation: In February 2008, we received a data request relating to an investigation the FERC is conducting into possible violations of the FERC’s posting and competitive bidding regulations related to releases of firm capacity on natural gas pipelines. We responded to the FERC’s first data request in the first quarter of 2008. In July 2008, we responded to a second set of data requests from the FERC. The FERC has also taken depositions from two Consumers employees and made an additional data request. We cannot predict the financial impact or the outcome of this matter.

Consumers’ Gas Utility Rate Matters

Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudence in annual plan and reconciliation proceedings.

The following table summarizes our GCR reconciliation filings currently pending with the MPSC:

Gas Cost Recovery Reconciliation

		Net Over-	GCR Cost of Gas
GCR Year	Date Filed	recovery	Sold	Description of Net Overrecovery
2007-2008	June 2008	$17 million	$1.7 billion	The total amount reflects an overrecovery of $15 million plus $2 million in accrued interest owed to customers.

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GCR Reconciliation for 2006-2007: In July 2008, the MPSC issued an order approving our GCR Reconciliation for the GCR plan period of April 1, 2006 to March 31, 2007. The total amount reflects an overrecovery of $1 million plus $4 million in accrued interest owed to customers.

GCR plan for year 2007-2008: In July 2007, the MPSC issued an order for our 2007-2008 GCR plan year. The order approved a settlement agreement that allowed a base GCR ceiling factor of $8.47 per mcf for April 2007 through March 2008, subject to a quarterly ceiling price adjustment mechanism. We were able to maintain our GCR billing factor below the authorized level.

GCR plan for year 2008-2009: In December 2007, we filed an application with the MPSC seeking approval of a GCR plan for our 2008-2009 GCR Plan year. Our request proposed the use of a base GCR ceiling factor of $8.17 per mcf, plus a quarterly GCR ceiling price adjustment contingent upon future events.

Due to an increase in NYMEX gas prices, the base GCR ceiling factor increased to $9.52 per mcf for the three-month period of April through June 2008 and to $9.92 for the three-month period of July through September 2008, pursuant to the quarterly ceiling price adjustment mechanism. Beginning in October 2008, the base GCR ceiling factor was adjusted to $8.17 due to a decrease in NYMEX gas prices.

The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor for November 2008 is $8.17 per mcf. When we are unable to collect GCR costs as they are incurred, there is a negative impact on our cash flows.

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

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million based on an 11 percent authorized return on equity. The MPSC staff and intervenors filed testimony in September 2008. The MPSC staff recommended an increase of $36 million based on a 10.45 percent authorized return on equity.

Other Contingencies

T.E.S. Filer City Air Permit Issue: In January 2007, we received a NOV from the EPA alleging that T.E.S. Filer City, a generating facility in which we have a 50 percent partnership interest, exceeded certain air permit limits. Negotiations between the EPA and T.E.S. Filer City resulted in a fine of an immaterial amount in the first quarter of 2008.

Equatorial Guinea Tax Claim: In 2004, we received a request for indemnification from the purchaser of CMS Oil and Gas. The indemnification claim relates to the sale of our oil, gas and methanol projects in Equatorial Guinea and the claim of the government of Equatorial Guinea that we owe $142 million in taxes in connection with that sale. CMS Energy concluded that the government’s tax claim is without merit and the purchaser of CMS Oil and Gas submitted a response to the government rejecting the claim. The government of Equatorial Guinea has indicated that it still intends to pursue its claim. We cannot predict the financial impact or outcome of this matter.

Moroccan Tax Claim: In May 2007, we sold our 50 percent interest in Jorf Lasfar. As part of the sale agreement, we agreed to indemnify the purchaser for 50 percent of any tax assessments on Jorf Lasfar attributable to tax years prior to the sale. In December 2007, the Moroccan tax authority concluded its audit of Jorf Lasfar for tax years 2003 through 2005. The audit asserted deficiencies in certain corporate and withholding taxes. In July 2008, an agreement was reached with the Moroccan tax authority under

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which we will make a payment of $19 million in January 2009. This payment will be charged against a tax indemnification liability established when we recorded the sale of Jorf Lasfar, and accordingly will not affect earnings.

Marathon Indemnity Claim regarding F.T. Barr Claim: On December 3, 2001, F. T. Barr, an individual with an overriding royalty interest in production from the Alba field, filed a lawsuit in Harris County District Court in Texas against CMS Energy, CMS Oil and Gas and other defendants alleging that his overriding royalty payments related to Alba field production were improperly calculated. CMS Oil and Gas believed that Barr was being paid properly on gas sales and that he was, and would not be, entitled to the additional overriding royalty payment sought. All parties signed a confidential settlement agreement on April 26, 2004. The settlement resolved claims between Barr and the defendants, and the involved CMS Energy entities reserved all defenses to any indemnity claim relating to the settlement. Issues exist between Marathon and certain current or former CMS Energy entities as to the existence and scope of any indemnity obligations to Marathon in connection with the settlement. Between April 2005 and April 2008, there were no further communications between Marathon and CMS Energy entities regarding this matter. In April 2008, Marathon indicated its intent to pursue the indemnity claim. Present and former CMS Energy entities and Marathon entered into an agreement tolling the statute of limitations on any claim by Marathon under the indemnity. CMS Energy entities dispute Marathon’s claim, and will vigorously oppose it if raised in any legal proceeding. CMS Energy entities also will assert that Marathon has not suffered any damages that would be material to CMS Energy. CMS Energy cannot predict the outcome of this matter. If Marathon’s claim were sustained, it would have a material effect on CMS Energy’s future earnings and cash flow.

Guarantees and Indemnifications: FIN 45 requires a guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee. To measure the fair value of a guarantee liability, we recognize a liability for any premium received or receivable in exchange for the guarantee. For a guarantee issued as part of a larger transaction, such as in association with an asset sale or executory contract, we recognize a liability for any premium that would have been received had the guarantee been issued as a single item.

The following table describes our guarantees at September 30, 2008:

In Millions
	Issue	Expiration	Maximum			FIN 45 Carrying
Guarantee Description	Date	Date	Obligation			Amount
Indemnifications from asset sales and other agreements	Various	Indefinite	$	1,447	(a)	$	85	(b)
Surety bonds and other indemnifications	Various	Indefinite		35			1
Guarantees and put options	Various	Various through September 2027		89	(c)		1

(a)

The majority of this amount arises from provisions in stock and asset sales agreements under which we indemnify the purchaser for losses resulting from claims related to tax disputes, claims related to power purchase agreements and the failure of title to the assets or stock sold by us to the purchaser. Except for items described elsewhere in this Note, we believe the likelihood of loss to be remote for the indemnifications we have not recorded as liabilities.

(b)

As of September 30, 2008, we have recorded an $85 million liability in connection with indemnities related to the sale of certain subsidiaries.

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(c) The maximum obligation includes $85 million related to the MCV Partnership’s nonperformance under a steam and electric power agreement with Dow. We sold our interests in the MCV Partnership and the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments, to pay $85 million, subject to certain reimbursement rights, if Dow terminates an agreement under which the MCV Partnership provides it steam and electric power. This agreement expires in March 2016, subject to certain terms and conditions. The purchaser secured its reimbursement obligation with an irrevocable letter of credit of up to $85 million.

The following table provides additional information regarding our guarantees:

Guarantee Description	How Guarantee Arose	Events That Would Require Performance
Indemnifications from asset sales and other agreements	Stock and asset sales agreements	Findings of misrepresentation, breach of warranties, tax claims and other specific events or circumstances
Surety bonds and other indemnifications	Normal operating activity, permits and licenses	Nonperformance
Guarantees and put options	Normal operating activity	Nonperformance or non-payment by a subsidiary under a related contract
	Agreement to provide power and steam to Dow	MCV Partnership’s nonperformance or non-payment under a related contract
	Bay Harbor remediation efforts	Owners exercising put options requiring us to purchase property

At September 30, 2008, certain contracts contained provisions allowing us to recover, from third parties, amounts paid under the guarantees. Additionally, if we are required to purchase a property under a put option agreement, we may sell the property to recover the amount paid under the option.

We also enter into various agreements containing tax and other indemnification provisions for which we are unable to estimate the maximum potential obligation. We consider the likelihood that we would be required to perform or incur significant losses related to these indemnities to be remote.

Other: In addition to the matters disclosed within this Note, Consumers and certain other subsidiaries of CMS Energy are parties to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters.

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5: FINANCINGS AND CAPITALIZATION

Long-term debt is summarized as follows:

				In Millions
	September 30, 2008			December 31, 2007
CMS Energy Corporation
Senior notes	$	1,703		$	1,713
Revolving credit facility		105			—
Total — CMS Energy Corporation		1,808			1,713
Consumers Energy Company
First mortgage bonds		3,518			3,170
Senior notes and other		503			659
Securitization bonds		286			309
Total — Consumers Energy Company		4,307			4,138
Other Subsidiaries		237			236
Total principal amounts outstanding		6,352			6,087
Current amounts		(624	)		(692	)
Net unamortized discount		(10	)		(10	)
Total Long-term debt	$	5,718		$	5,385

Financings: The following is a summary of significant long-term debt transactions during the nine months ended September 30, 2008:

	Principal					Issue/Retirement
	(in millions)		Interest Rate (%)			Date	Maturity Date
Debt Issuances:
Consumers
First mortgage bonds	$	250		5.650	%	March 2008	September 2018
Tax-exempt bonds (a)		28		4.250	%	March 2008	June 2010
Tax-exempt bonds (b)		68	Variable			March 2008	April 2018
First mortgage bonds		350		6.125	%	September 2008	March 2019
Total	$	696
Debt Retirements:
Consumers
Senior notes	$	159		6.375	%	February 2008	February 2008
First mortgage bonds		250		4.250	%	April 2008	April 2008
Tax-exempt bonds (a)		28	Variable			April 2008	June 2010
Tax-exempt bonds (b)		68	Variable			April 2008	April 2018
Total	$	505

(a)

In March 2008, Consumers utilized the Michigan Strategic Fund for the issuance of $28 million of tax-exempt Michigan Strategic Fund Limited Obligation Refunding Revenue Bonds, bearing interest at a 4.25 percent annual rate. The bonds are secured by FMBs. The proceeds were used for the April 2008 redemption of $28 million of insured tax-exempt bonds.

(b)

In March 2008, Consumers utilized the Michigan Strategic Fund for the issuance of $68 million of tax-exempt Michigan Strategic Fund Variable Rate Limited Obligation Refunding Revenue Bonds. The initial interest rate was 2.25 percent and it resets weekly. The bonds, which are backed by a letter of credit, are subject to optional tender by the holders that would result in remarketing. The proceeds were used for the April 2008 redemption of $68 million of insured tax-exempt bonds.

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In April 2008, Consumers caused the conversion of $35 million of tax-exempt Michigan Strategic Fund Variable Rate Limited Obligation Revenue Bonds from insured bonds to demand bonds, backed by a letter of credit.

The Michigan Strategic Fund is housed within the Michigan Department of Treasury to provide public and private development finance opportunities for agriculture, forestry, business, industry and communities within the State of Michigan.

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at September 30, 2008:

								In Millions
Company	Expiration Date	Amount of Facility		Amount Borrowed		Outstanding Letters of Credit		Amount Available
CMS Energy (a)	April 2, 2012	$	550	$	105	$	24	$	421
Consumers	March 30, 2012		500		—		127		373
Consumers (b)	November 30, 2009		200		—		185		15
Consumers	September 9, 2009		150		—		—		150

(a)	Average borrowings during the quarter totaled $112 million, with a weighted average annual interest rate of 3.25 percent, at LIBOR plus 0.75 percent. During October 2008, we borrowed an additional $420 million under this credit facility.
(b)	Secured revolving letter of credit facility. Effective November 30, 2008, this commitment will be reduced to $192 million.

Dividend Restrictions: Under provisions of our senior notes indenture, at September 30, 2008, payment of common stock dividends was limited to $529 million.

Under the provisions of its articles of incorporation, at September 30, 2008, Consumers had $293 million of unrestricted retained earnings available to pay common stock dividends. Provisions of the Federal Power Act and the Natural Gas Act appear to restrict dividends to the amount of Consumers’ retained earnings. Several decisions from the FERC suggest that under a variety of circumstances common dividends from Consumers would not be limited to amounts in Consumers’ retained earnings. Decisions in those circumstances would, however, be based on specific facts and circumstances and would result only after a formal regulatory filing process.

For the nine months ended September 30, 2008, CMS Energy received $238 million of common stock dividends from Consumers.

Contingently Convertible Securities: At September 30, 2008, the significant terms of our contingently convertible securities were as follows:

			Outstanding		Adjusted Conversion		Adjusted Trigger
Security	Maturity		(In Millions)		Price		Price
4.50% preferred stock		—	$	249	$	9.66	$	11.60
3.375% senior notes		2023	$	140	$	10.42	$	12.51
2.875% senior notes		2024	$	288	$	14.41	$	17.29

In September 2008, the $11.60 per share conversion trigger price contingency was met for our $249 million 4.50 percent contingently convertible preferred stock, and the $12.51 per share conversion trigger price contingency was met for our $140 million 3.375 percent contingently convertible senior

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notes. As a result, these securities are convertible at the option of the security holders for the three months ending December 31, 2008, with the par value or principal payable in cash.

In June 2008, $1 million of 4.50 percent preferred stock was tendered for conversion. The conversion at $14.10 per share resulted in the issuance of 32,567 shares of common stock and payment of $1 million. In July 2008, $10 million of 3.375 percent senior notes was tendered for conversion. The conversion at $13.41 per share resulted in the issuance of 213,742 shares of common stock and payment of $10 million.

6: EARNINGS PER SHARE

The following table presents our basic and diluted EPS computations based on Earnings (Loss) from Continuing Operations:

	In Millions, Except Per Share Amounts
Three Months Ended September 30	2008			2007
Earnings Available to Common Stockholders
Earnings from Continuing Operations	$	80		$	84
Less Preferred Dividends and Redemption Premium		(2	)		(2	)
Earnings from Continuing Operations Available to Common Stockholders — Basic and Diluted	$	78		$	82
Average Common Shares Outstanding
Weighted Average Shares — Basic		224.1			223.0
Add dilutive impact of Contingently Convertible Securities		9.6			17.0
Add dilutive Stock Options, Warrants, and Restricted Stock Awards		0.6			1.3
Weighted Average Shares — Diluted		234.3			241.3
Earnings Per Average Common Share Available to Common Stockholders
Basic	$	0.35		$	0.37
Diluted	$	0.33		$	0.34

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	In Millions, Except Per Share Amounts
Nine Months Ended September 30	2008			2007
Earnings (Loss) Available to Common Stockholders
Earnings (Loss) from Continuing Operations	$	236		$	(4	)
Less Preferred Dividends and Redemption Premium		(8	)		(9	)
Earnings (Loss) from Continuing Operations Available to Common Stockholders — Basic and Diluted	$	228		$	(13	)
Average Common Shares Outstanding
Weighted Average Shares — Basic		223.7			222.4
Add dilutive impact of Contingently Convertible Securities		12.0			—
Add dilutive Stock Options, Warrants, and Restricted Stock Awards		0.6			—
Weighted Average Shares — Diluted		236.3			222.4
Earnings (Loss) Per Average Common Share Available to Common Stockholders
Basic	$	1.02		$	(0.06	)
Diluted	$	0.96		$	(0.06	)

Contingently Convertible Securities: Our contingently convertible securities dilute EPS to the extent that the conversion value, which is based on the average market price of our common stock, exceeds the principal or par value. Had there been positive income from continuing operations for the nine months ended September 30, 2007, our contingently convertible securities would have contributed an additional 19.0 million shares to the calculation of diluted EPS. For additional details on our contingently convertible securities, see Note 5, Financings and Capitalization.

Stock Options, Warrants and Restricted Stock: For the periods ended September 30, 2008, options and warrants to purchase 0.7 million shares of common stock exceeded the average market price of our stock and were excluded from the computation of diluted EPS. For the nine months ended September 30, 2007, 1.1 million shares of unvested restricted stock awards, and options and warrants to purchase 0.3 million shares of common stock were anti-dilutive. Additional options and warrants to purchase 0.7 million shares of common stock had exercise prices that exceeded the average market price of our stock for the periods ended September 30, 2007. These stock options could dilute EPS in the future.

Convertible Debentures: For the three and nine months ended September 30, 2008 and 2007, there was no impact on diluted EPS from our 7.75 percent convertible subordinated debentures. Using the if-converted method, the debentures would have:

• increased the numerator of diluted EPS, by $2 million for the three months ended September 30, 2008 and 2007 and by $7 million for the nine months ended September 30, 2008 and 2007, from an assumed reduction of interest expense, net of tax, and

• increased the denominator of diluted EPS by 4.2 million shares.

We can revoke the conversion rights if certain conditions are met.

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7: FINANCIAL AND DERIVATIVE INSTRUMENTS

Financial Instruments: The summary of our available-for-sale SERP investment securities is as follows:

																In Millions
	September 30, 2008									December 31, 2007
	Cost		Unrealized Gains		Unrealized Losses			Fair Value		Cost		Unrealized Gains		Unrealized Losses		Fair Value
Equity securities	$	50		—		—		$	50	$	62		—		—	$	62
Debt securities		30		—		(1	)		29		13		—		—		13

Equity securities consist of an investment in a Standard & Poor’s 500 Index mutual fund. Debt securities consist of investment grade municipal bonds.

During 2008, our SERP investment in equity securities experienced a decline in fair value to $50 million. In the third quarter of 2008, we determined that this decline in fair value was other than temporary. Accordingly, we reclassified net unrealized losses of $13 million ($8 million, net of tax) from AOCL into Other expense in the Consolidated Statements of Income (Loss) and established a new cost basis of $50 million for these investments, which was equal to fair value at September 30, 2008.

Derivative Instruments: In order to limit our exposure to certain market risks, primarily changes in interest rates, foreign currency exchange rates, and commodity prices, we may enter into various risk management contracts, such as swaps, options, futures, and forward contracts. We enter into these contracts using established policies and procedures, under the direction of an executive oversight committee consisting of senior management representatives and a risk committee consisting of business unit managers.

The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative accounting under SFAS No. 133. If a contract is a derivative and does not qualify for the normal purchases and sales exception under SFAS No. 133, we record it on our consolidated balance sheet at its fair value. Each quarter, we adjust the resulting asset or liability to reflect any change in the fair value of the contract, a practice known as marking the contract to market. Since we have not designated any of our derivatives as accounting hedges under SFAS No. 133, we report all mark-to-market gains and losses in earnings. For a discussion of how we determine the fair value of our derivatives, see Note 2, Fair Value Measurements.

Most of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:

• they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MWh of electricity or bcf of natural gas),

• they qualify for the normal purchases and sales exception, or

• there is not an active market for the commodity.

Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. If an active market for coal develops in the future, some of these contracts may qualify as derivatives. For Consumers, which is subject to regulatory accounting, the resulting mark-to-market gains and losses would be offset by changes in regulatory assets and liabilities and would not affect net income. For other CMS Energy subsidiaries, we do not believe the resulting mark-to-market impact on earnings would be material.

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The following table summarizes our derivative instruments:

														In Millions
	September 30, 2008								December 31, 2007
Derivative Instruments	Cost		Fair Value			Unrealized Loss			Cost		Fair Value			Unrealized Loss
Held by consolidated subsidiaries:
CMS ERM	$	—	$	(17	)	$	(17	)	$	—	$	(23	)	$	(23	)

CMS ERM Contracts: In order to support CMS Energy’s ongoing non-utility operations, CMS ERM enters into contracts to purchase and sell electricity and natural gas in the future. These forward contracts are generally long-term in nature and result in physical delivery of the commodity at a contracted price. To manage commodity price risks associated with these forward purchase and sale contracts, CMS ERM also uses various financial instruments, such as swaps, options, and futures.

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

We record the fair value of these contracts in either Other current and non-current assets or Other current and non-current liabilities on our Consolidated Balance Sheets. For contracts that economically hedge sales of power or gas to third parties, CMS ERM records mark-to-market gains and losses in earnings as a component of Operating Revenue. For contracts that economically hedge purchases of power or gas, CMS ERM records mark-to-market gains and losses in earnings as a component of Operating Expenses.

On January 1, 2008, we implemented FSP FIN 39-1, which permits entities to offset the fair value of derivatives held under master netting arrangements with cash collateral received or paid for those derivatives. We have made an accounting policy choice to offset the fair value of our derivatives held under master netting arrangements. Therefore, as a result of adopting this standard, we also offset related cash collateral amounts, which resulted in a reduction to both CMS ERM’s derivative-related assets and liabilities of less than $1 million as of September 30, 2008 and $4 million as of December 31, 2007.

Credit Risk: CMS ERM enters into derivatives primarily with companies in the energy industry. This industry concentration may have a positive or negative impact on our exposure to credit risk depending on how these counterparties are affected by similar changes in economic or other conditions. At September 30, 2008, we had a $5 million exposure to credit risk; that is, in the event each counterparty within this industry concentration failed to meet its contractual obligations, we could incur up to $5 million in losses. All of this exposure was held with investment grade companies. Given our credit policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance.

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8: RETIREMENT BENEFITS

We provide retirement benefits to our employees under a number of plans, including:

• a non-contributory, qualified defined benefit Pension Plan (closed to new non-union participants as of July 1, 2003 and closed to new union participants as of September 1, 2005),

• a qualified cash balance Pension Plan for certain employees hired between July 1, 2003 and August 31, 2005,

• a non-contributory, qualified DCCP for employees hired on or after September 1, 2005,

• benefits to certain management employees under a non-contributory, nonqualified defined benefit SERP (closed to new participants as of March 31, 2006),

• benefits to certain management employees under a non-contributory, nonqualified DC SERP hired on or after April 1, 2006,

• health care and life insurance benefits under OPEB,

• benefits to a selected group of management under a non-contributory, nonqualified EISP, and

• a contributory, qualified defined contribution 401(k) plan.

Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan’s assets are not distinguishable by company.

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. This standard required us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 also required us to recognize changes in the funded status of our plans in the year in which the changes occur. In addition, the standard requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. In the first quarter of 2008, we recorded the measurement date change, which resulted in a $6 million net-of-tax decrease to retained earnings, a $4 million reduction to the SFAS No. 158 regulatory assets, a $7 million increase in Postretirement benefit liabilities, and a $5 million increase in Deferred tax assets on our Consolidated Balance Sheets.

In April 2008, the MPSC issued an order in our PSCR case that allowed us to collect a one-time surcharge under a pension and OPEB equalization mechanism. For the three months ended June 30, 2008, we collected $10 million of pension and $2 million of OPEB surcharge revenue in electric rates. We recorded a reduction of $12 million of equalization regulatory assets on our Consolidated Balance Sheets and an increase of $12 million of expense on our Consolidated Statements of Income (Loss). Thus, our collection of the equalization mechanism surcharge had no impact on net income for the three months ended June 30, 2008.

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Costs: The following tables recap the costs and other changes in plan assets and benefit obligations incurred in our retirement benefits plans:

In Millions
	Pension
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Service cost	$	11		$	12		$	32		$	37
Interest expense		23			22			71			65
Expected return on plan assets		(20	)		(19	)		(61	)		(59	)
Amortization of:
Net loss		10			12			31			35
Prior service cost		1			1			4			5
Net periodic cost		25			28			77			83
Regulatory adjustment		—			(6	)		4			(14	)
Net periodic cost after regulatory adjustment	$	25		$	22		$	81		$	69

In Millions
	OPEB
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Service cost	$	6		$	7		$	17		$	19
Interest expense		18			17			54			52
Expected return on plan assets		(17	)		(16	)		(50	)		(47	)
Amortization of:
Net loss		3			6			7			17
Prior service credit		(3	)		(3	)		(8	)		(8	)
Net periodic cost		7			11			20			33
Regulatory adjustment		—			(2	)		3			(5	)
Net periodic cost after regulatory adjustment	$	7		$	9		$	23		$	28

9: INCOME TAXES

Our effective income tax rate for the nine months ended September 30, 2008 was 35 percent versus 94 percent for the nine months ended September 30, 2007. The difference in the effective income tax rate is due primarily to the absence of tax adjustments recorded in conjunction with the 2007 sales of our foreign investments. For the nine months ended September 30, 2007, the 35 percent tax benefit on our pre-tax book loss was increased by 132 percentage points due to expected profits from our international sales, allowing the release of a previously recorded valuation allowance. Offsetting this increase was a 73 percentage point reduction, primarily for the recognition of U.S. tax on the undistributed earnings of foreign subsidiaries that were no longer deemed permanently reinvested.

The amount of income taxes we pay is subject to ongoing examination by federal, state and foreign tax authorities, which can result in proposed assessments. Our estimate of the potential outcome of any uncertain tax issue is highly judgmental. It is reasonably possible that the outcome of these examinations may result in a change in our valuation allowance for unrecognized tax benefits related to certain tax credit carryforwards. The total valuation allowance for these credit carryforwards was $2 million at September 30, 2008. During the quarter we released $7 million of valuation allowance related to loss carryforwards that we now believe will be fully utilized prior to their expiration.

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10: REPORTABLE SEGMENTS

Our reportable segments consist of business units defined by the products and services they offer. We evaluate performance based on the net income of each segment. We operate principally in three reportable segments: electric utility, gas utility, and enterprises.

“Other” includes corporate interest and other expenses and benefits. The following tables show our financial information by reportable segment:

	In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Operating Revenue
Electric utility	$	1,074		$	963		$	2,775		$	2,663
Gas utility		233			209			1,886			1,811
Enterprises		115			105			300			303
Other		6			5			16			13
Total Operating Revenue	$	1,428		$	1,282		$	4,977		$	4,790
Net Income (Loss) Available to Common Stockholders
Electric utility	$	108		$	67		$	232		$	158
Gas utility		(18	)		(8	)		46			53
Enterprises		5			58			13			(194	)
Discontinued operations		1			—			—			(87	)
Other		(17	)		(35	)		(63	)		(30	)
Total Net Income (Loss) Available to Common Stockholders	$	79		$	82		$	228		$	(100	)

In Millions
	September 30, 2008		December 31, 2007
Assets
Electric utility (a)	$	8,343	$	8,492
Gas utility (a)		4,541		4,102
Enterprises		801		982
Other		392		616
Total Assets	$	14,077	$	14,192

(a) Amounts include a portion of Consumers’ other common assets attributable to both the electric and gas utility businesses.

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Consumers Energy Company

Consumers Energy Company
Management’s Discussion and Analysis

This MD&A is a consolidated report of Consumers. The terms “we” and “our” as used in this report refer to Consumers and its subsidiaries as a consolidated entity, except where it is clear that such term means only Consumers. 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 Consumers’ Form 10-K for the year ended December 31, 2007.

FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-Q and other written and oral statements that we make contain forward-looking statements as defined by the Private Securities Litigation Reform Act of 1995. Our intention with the use of words such as “may,” “could,” “anticipates,” “believes,” “estimates,” “expects,” “intends,” “plans,” and other similar words is to identify forward-looking statements that involve risk and uncertainty. We designed this discussion of potential risks and uncertainties to highlight important factors that may impact our business and financial outlook. We have no obligation to update or revise forward-looking statements regardless of whether new information, future events, or any other factors affect the information contained in the statements. These forward-looking statements are subject to various factors that could cause our actual results to differ materially from the results anticipated in these statements. Such factors include our inability to predict or control:

• the price of CMS Energy Common Stock, capital and financial market conditions and the effect of such market conditions on our postretirement benefit plans, interest rates, and access to the capital markets including availability of financing (including our accounts receivable sales program and revolving credit facilities) to Consumers, CMS Energy, or any of their affiliates, and the energy industry,

• the impact of the continued downturn in the economy and the sharp downturn and extreme volatility in the financial and credit markets on Consumers including its:

• revenues,

• capital expenditure program and related earnings growth,

• ability to collect accounts receivable from our customers,

• access to capital, and

• contributions to the Pension Plan,

• market perception of the energy industry or of Consumers, CMS Energy, or any of their affiliates,

• credit ratings of Consumers or CMS Energy,

• factors affecting 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,

• changes in federal or state laws or regulations or in the interpretation of existing laws and regulations that could have an impact on our business,

• the impact of any future regulations or laws regarding carbon dioxide and other greenhouse gas emissions,

• national, regional, and local economic, competitive, and regulatory policies, conditions and developments,

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• adverse regulatory or legal interpretations or decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with such interpretations or decisions,

• potentially adverse regulatory treatment or failure to receive timely regulatory orders concerning a number of significant questions currently 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,

• timely recognition in rates of additional equity investments and additional operation and maintenance expenses at Consumers,

• adequate and timely recovery of additional electric and gas rate-based investments,

• adequate and timely recovery of higher MISO energy and transmission costs,

• timely recovery of costs associated with energy efficiency investments and any state or federally mandated renewables resource standards,

• recovery of Big Rock decommissioning funding shortfalls,

• authorization of a new clean coal plant, and

• implementation of new energy legislation,

• adverse consequences resulting from a past or future assertion of indemnity or warranty claims associated with previously owned assets and businesses,

• our ability to recover 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,

• the impact of expanded enforcement powers and investigation activities at the FERC,

• federal regulation of electric sales and transmission of electricity, including periodic re-examination by federal regulators of our 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,

• the impact of natural gas prices and coal prices on our cash flow and working capital,

• the impact of construction material prices,

• the availability of qualified construction personnel to implement our construction program,

• potential disruption or interruption of facilities or operations due to accidents, war, or terrorism, and the ability to obtain or maintain insurance coverage for such events,

• disruptions in the normal commercial insurance and surety bond markets that may increase costs or reduce traditional insurance coverage, particularly terrorism and sabotage insurance, performance bonds, and tax exempt debt insurance,

• technological developments in energy production, delivery, usage, and gas storage,

• achievement of capital expenditure and operating expense goals,

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• changes in financial or regulatory accounting principles or policies, including a possible future requirement to comply with International Financial Reporting Standards,

• changes in tax laws or new IRS interpretations of existing or past tax laws,

• the impact of our new integrated business software system on our operations, including customer billing, finance, purchasing, human resources and payroll processes, and utility asset construction and maintenance work management systems,

• the outcome, cost, and other effects of legal or administrative proceedings, settlements, investigations or claims, and

• other business or investment considerations that may be disclosed from time to time in Consumers’ or CMS Energy’s SEC filings, or in other publicly issued written documents.

For additional information regarding these and other uncertainties, see the “Outlook” section included in this MD&A, Note 4, Contingencies, and Part II, Item 1A. Risk Factors.

EXECUTIVE OVERVIEW

Consumers, a subsidiary of CMS Energy, a holding company, is a combination electric and gas utility company serving in Michigan’s Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers.

We manage our business by the nature of service provided and operate principally in two business segments: electric utility and gas utility. Our electric utility operations include the generation, purchase, distribution, and sale of electricity. Our gas utility operations include the purchase, transportation, storage, distribution, and sale of natural gas.

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

• weather, especially during the normal heating and cooling seasons,

• economic conditions,

• regulation and regulatory issues,

• energy commodity prices,

• interest rates, and

• our debt credit rating.

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

Our forecast calls for investing about $6.7 billion in the utility over the period from 2009 through 2013, with a key aspect of our strategy being our Balanced Energy Initiative. Our Balanced Energy Initiative is a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements with energy efficiency, demand management, expanded use of renewable energy, and development of new power plants and pursuit of additional power purchase agreements to complement existing generating sources.

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In October 2008, the Michigan governor signed into law a comprehensive energy reform package. We plan to file an updated Balanced Energy Initiative with the MPSC in order to conform it to various aspects of this new legislation. Significant features of the new legislation include:

• a provision to streamline the regulatory process by generally allowing utilities to self-implement rates six months after filing and requiring the MPSC to issue an order 12 months after filing or the rates as-filed become permanent,

• reform of the Customer Choice Act to limit generally alternative energy suppliers to 10 percent of our weather-adjusted sales,

• establishment of a certificate-of-necessity process at the MPSC for proposed power plants, power purchase agreements, and projects costing more than $500 million,

• a requirement that 10 percent of power come from renewable sources by 2015 with specific interim targets, and

• new programs and incentives to encourage greater energy efficiency among customers, along with the requirement of the utility to prepare energy cost savings optimization plans.

In June 2008, the MPSC approved a settlement agreement that provides for an amended and restated MCV PPA and resolves the issues concerning our September 2007 exercise of the regulatory-out provision. The revised MCV PPA also provides more certainty of our access to 1,240 MW of the MCV Facility capacity through March 2025. The amended and restated MCV PPA took effect in October 2008.

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

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

In the future, we will continue to focus our strategy on:

• investing in our utility system to enable us to meet our customer commitments, comply with increasing environmental performance standards, improve system performance, and maintain adequate supply and capacity,

• growing earnings while controlling operating and fuel costs,

• managing cash flow, and

• maintaining 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 Michigan economy that has been hampered by the continued downturn in Michigan’s automotive industry and limited growth in the non-manufacturing sectors of the state’s economy. There also has been a sharp downturn, uncertainty, and extreme volatility in the financial and credit markets resulting from the subprime mortgage crisis, bank failures and consolidation, and other market weaknesses. While we believe that our sources of liquidity will be sufficient to meet our requirements, we continue to monitor closely developments in the financial and credit markets and government response to those developments for potential implications for our business.

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RESULTS OF OPERATIONS

NET INCOME AVAILABLE TO COMMON STOCKHOLDER

	In Millions
Three months ended September 30	2008			2007			Change
Electric	$	108		$	67		$	41
Gas		(18	)		(8	)		(10	)
Other		—			1			(1	)
Net Income Available to Common Stockholder	$	90		$	60		$	30

For the three months ended September 30, 2008, net income available to our common stockholder was $90 million, compared to $60 million for the three months ended September 30, 2007. The increase reflects higher net income from our electric utility segment primarily due to rate increases authorized in December 2007 and June 2008 and reduced costs associated with our power purchase agreement with the MCV Partnership. Partially offsetting these increases to income was a decrease in electric deliveries and lower net income from our gas utility segment.

Specific changes to net income available to our common stockholder for 2008 versus 2007 are:

		In Millions
•	increase in electric delivery revenue primarily due to the MPSC’s December 2007 and June 2008 electric rate orders,	$	63
•	decrease in electric operating expense due to the absence, in 2008, of certain costs which are no longer incurred under our power purchase agreement with the MCV Partnership,		9
•	other net increases,		2
•	decrease in other income primarily due to reduced interest income,		(14	)
•	decrease in electric deliveries,		(10	)
•	increase in operating expenses, and		(11	)
•	increase in depreciation expense.		(9	)
Total Change		$	30

	In Millions
Nine months ended September 30	2008		2007		Change
Electric	$	232	$	158	$	74
Gas		46		53		(7	)
Other		1		5		(4	)
Net Income Available to Common Stockholder	$	279	$	216	$	63

For the nine months ended September 30, 2008, net income available to our common stockholder was $279 million, compared to $216 million for the nine months ended September 30, 2007. The increase reflects higher net income from our electric utility segment primarily due to rate increases authorized in December 2007 and June 2008 and reduced costs associated with our power purchase agreement with the MCV Partnership. Partially offsetting these increases was a decrease in electric deliveries and lower net income from our gas utility segment.

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Specific changes to net income available to our common stockholder for 2008 versus 2007 are:

		In Millions
•	increase in electric delivery revenue primarily due to the MPSC’s December 2007 and June 2008 electric rate orders,	$	94
•	decrease in electric operating expense due to the absence, in 2008, of certain costs which are no longer incurred under our power purchase agreement with the MCV Partnership,		29
•	lower nuclear operating and maintenance costs,		24
•	increase in gas delivery revenue primarily due to the MPSC’s August 2007 gas rate order,		20
•	decrease in electric deliveries,		(52	)
•	decrease in other income,		(29	)
•	increase in depreciation expense, and		(20	)
•	other net decreases.		(3	)
Total Change		$	63

ELECTRIC UTILITY RESULTS OF OPERATIONS

	In Millions
September 30	2008		2007		Change
Three months ended	$	108	$	67	$	41
Nine months ended	$	232	$	158	$	74

	Three Months Ended			Nine Months Ended
	September 30, 2008			September 30, 2008
Reasons for the change:	vs. 2007			vs. 2007
Electric deliveries and rate increase	$	80		$	65
Surcharge revenue		—			10
Power supply costs and related revenue		5			12
Non-commodity revenue		(1	)		(13	)
Depreciation and other operating expenses		(11	)		62
Other income		(20	)		(36	)
General taxes		6			14
Interest charges		6			11
Income taxes		(24	)		(51	)
Total change	$	41		$	74

Electric deliveries and rate increase: For the three months ended September 30, 2008, electric delivery revenues increased by $80 million versus 2007 primarily due to additional revenue of $97 million from the inclusion of the Zeeland power plant in rates and from the June 2008 rate order. The increase was partially offset by decreased electric revenue of $17 million primarily due to lower deliveries reflecting milder weather. Deliveries to end-use customers were 9.9 billion kWh, a decrease of 0.5 billion kWh or 5 percent versus 2007. For additional details on the June 2008 rate order, see Note 4, Contingencies, “Electric Rate Matters.”

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For the nine months ended September 30, 2008, electric delivery revenues increased by $65 million versus 2007 primarily due to additional revenue of $145 million from the inclusion of the Zeeland power plant in rates and from the June 2008 rate order. The increase was partially offset by decreased electric revenue of $80 million primarily due to lower deliveries. Deliveries to end-use customers were 28.4 billion kWh, a decrease of 1.0 billion kWh or 3 percent versus 2007.

Surcharge revenue: For the nine months ended September 30, 2008, surcharge revenue increased by $10 million versus 2007. The increase was primarily due to the April 2008 MPSC order allowing recovery of certain retirement benefits through a surcharge. Consistent with the recovery of these costs, we recognized a similar amount of benefit expense. For additional details, see “Depreciation and other operating expenses” within this section and Note 7, Retirement Benefits.

Power supply costs and related revenue: PSCR revenue increased $5 million for the three months ended September 30, 2008, and $12 million for the nine months ended September 30, 2008. These increases primarily reflect the 2007 reduction to revenue made in response to the MPSC’s position that PSCR discounts given to our Transitional Primary Rate customers could not be recovered under the PSCR mechanism. The decrease also reflects the absence, in 2008, of a decrease in power supply revenue associated with the 2006 PSCR reconciliation case.

Non-commodity revenue: Non-commodity revenue decreased $1 million for the three months ended September 30, 2008, and $13 million for the nine months ended September 30, 2008. The decreases were primarily due to the absence, in 2008, of METC transmission services revenue.

Depreciation and other operating expenses: For the three months ended September 30, 2008, the increase of $11 million in depreciation and other operating expenses was primarily due to higher costs associated with the implementation of our integrated business software system on July 1, 2008, higher uncollectible accounts expense and higher depreciation expense. The increase was partially offset by the absence, in 2008, of certain costs that are no longer incurred under our power purchase agreement with the MCV Partnership.

For the nine months ended September 30, 2008, the decrease of $62 million in depreciation and other operating expenses was primarily due to the absence of operating expenses associated with the sale of Palisades in April 2007, and certain costs that are no longer incurred under our power purchase agreement with the MCV Partnership. Also contributing to the decrease in expenses was the April 2008 MPSC order allowing us to retain a portion of the proceeds from the 2006 sale of certain sulfur dioxide allowances. The decrease was partially offset by higher retirement benefit expense due to the April 2008 MPSC order allowing recovery of certain costs through a surcharge and higher depreciation expense. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Electric Contingencies.”

Other income: Other income decreased $20 million for the three months ended September 30, 2008, and $36 million for the nine months ended September 30, 2008. The decreases were primarily due to reduced interest income and the MPSC’s June 2008 order, which did not allow us to recover all of our costs associated with the sale of Palisades. Also contributing to the decrease was an impairment charge that recognized an other than temporary decline in the fair value of our SERP investments, reflecting the continuing decline in the stock market.

General taxes: General tax expense decreased $6 million for the three months ended September 30, 2008 and $14 million for the nine months ended September 30, 2008. The decreases were primarily due to the absence, in 2008, of MSBT, which was replaced with the Michigan Business Tax effective January 1, 2008. The Michigan Business Tax is now recorded in income taxes. The decreases were partially offset by higher property tax expense.

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Interest charges: Interest charges decreased $6 million for the three months ended September 30, 2008 and $11 million for the nine months ended September 30, 2008. These decreases were primarily due to lower interest associated with amounts to be refunded to customers as a result of the sale of Palisades. The MPSC order approving the Palisades power purchase agreement with Entergy directed us to record interest on the unrefunded balances. Also contributing to the decrease was the absence, in 2008, of interest charges related to an IRS settlement.

Income taxes: For the three months ended September 30, 2008, income taxes increased $24 million versus 2007. The increase reflects $23 million due to higher earnings, $2 million due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008, and a $1 million benefit due to increased quarterly Medicare subsidy.

For the nine months ended September 30, 2008, income taxes increased $51 million versus 2007. The increase reflects $45 million due to higher earnings and $6 million due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008.

GAS UTILITY RESULTS OF OPERATIONS

	In Millions
September 30	2008			2007			Change
Three months ended	$	(18	)	$	(8	)	$	(10	)
Nine months ended		46		$	53		$	(7	)

	Three Months Ended			Nine Months Ended
	September 30, 2008			September 30, 2008
Reasons for the change:	vs. 2007			vs. 2007
Gas deliveries and rate increase	$	2		$	20
Gas wholesale and retail services, other gas revenues and other income, net		(12	)		(23	)
Operation and maintenance		(6	)		(15	)
General taxes and depreciation		1			—
Interest charges		1			7
Income taxes		4			4
Total change	$	(10	)	$	(7	)

Gas deliveries and rate increase: For the three months ended September 30, 2008, gas delivery revenues increased $2 million versus 2007 primarily due to additional revenue of $3 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by a $1 million increase in system losses. Gas deliveries, including miscellaneous transportation to end-use customers, totaled 24 bcf, a decrease of 1 bcf or 4 percent versus 2007.

For the nine months ended September 30, 2008, gas delivery revenues increased $20 million versus 2007 primarily due to additional revenue of $31 million from the MPSC’s August 2007 gas rate order. The increase was partially offset by higher system losses and lower gas deliveries, including miscellaneous transportation to end-use customers, totaling 204 bcf, a decrease of 4 bcf or 2 percent versus 2007, which resulted in a decrease in gas delivery revenue of $11 million.

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Gas wholesale and retail services, other gas revenues and other income, net: Gas wholesale and retail services, other gas revenues and other income decreased $12 million for the three months ended September 30, 2008, and $23 million for the nine months ended September 30, 2008. These decreases were primarily due to lower interest income and lower pipeline capacity optimization revenue. Also contributing to the decrease was an impairment charge that recognized an other than temporary decline in the fair value of our SERP investments, reflecting the continuing decline in the stock market.

Operation and maintenance: Operation and maintenance expenses increased $6 million for the three months ended September 30, 2008 and $15 million for the nine months ended September 30, 2008. These increases were primarily due to higher uncollectible accounts expense and higher operating expense across our storage, transmission and distribution systems.

General taxes and depreciation: For the three months ended September 30, 2008, general taxes and depreciation decreased $1 million versus 2007 due to the absence, in 2008, of MSBT, which was replaced by the Michigan Business Tax effective January 1, 2008. The Michigan Business Tax is now recorded in income taxes.

For the nine months ended September 30, 2008, general taxes and depreciation did not change versus 2007, as the absence in 2008 of $8 million of MSBT was offset by increases of $6 million in depreciation expense and $2 million in property tax expenses.

Interest charges: Interest charges decreased $1 million for the three months ended September 30, 2008 and $7 million for the nine months ended September 30, 2008. These decreases were primarily due to lower average debt levels and a lower average interest rate.

Income taxes: For the three months ended September 30, 2008, income taxes decreased $4 million versus 2007. The decrease reflects $5 million due to lower quarterly earnings and $1 million related to the treatment of property, plant and equipment, as required by MPSC orders. These decreases were partially offset by a $1 million increase due to lower annual Medicare subsidy and a $1 million increase related to the forfeiture of restricted stock.

For the nine months ended September 30, 2008, income taxes decreased $4 million versus 2007. The decrease reflects $4 million due to lower earnings and $3 million related to the treatment of property, plant and equipment, as required by MPSC orders. These decreases were partially offset by a $1 million increase due to the inclusion of the Michigan Business Tax, which replaced the MSBT effective January 1, 2008, a $1 million increase due to lower annual Medicare subsidy and a $1 million increase related to the forfeiture of restricted stock.

OTHER RESULTS OF OPERATIONS

September 30	2008		2007		Change
Three months ended	$	—	$	1	$	(1	)
Nine months ended	$	1	$	5	$	(4	)

For the nine months ended September 30, 2008, net income from other non-utility operations decreased $4 million versus 2007. The decrease is primarily due to the absence, in 2008, of gains recorded on CMS Energy common stock contributed to certain charitable foundations and organizations.

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CRITICAL ACCOUNTING POLICIES

The following accounting policies and related information are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A. These policies are an update of the policies disclosed in Consumers’ Form 10-K for the year ended December 31, 2007.

Use of Estimates and Assumptions

Fair Value Measurements: We have a number of assets and liabilities that must be accounted for or disclosed at fair value in accordance with SFAS No. 157. Fair value measurements require the incorporation of all assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. Development of these assumptions requires significant judgment.

The most material of our fair value measurements are for our SERP assets. For a detailed discussion of the methods used to calculate these fair value measurements, see Note 2, Fair Value Measurements.

Retirement Benefits

In accordance with SFAS No. 158, we record liabilities for pension and OPEB on our consolidated balance sheet at the present value of the future obligations, net of any plan assets. We use SFAS No. 87 to account for pension expense and SFAS No. 106 to account for other postretirement benefit expense. The calculation of the liabilities and associated expenses requires the expertise of actuaries, and requires many assumptions, including:

• life expectancies,

• discount rates,

• expected long-term rate of return on plan assets,

• rate of compensation increases, and

• anticipated health care costs.

A change in these assumptions could change significantly our recorded liabilities and associated expenses.

The following table provides estimates as of September 30, 2008 of our pension cost, OPEB cost, and cash contributions:

	In Millions
Expected Costs	Pension Cost		OPEB Cost		Contributions
2008	$	100	$	29	$	50
2009		90		64		255
2010		85		61		175

Contribution estimates include amounts required and discretionary contributions. The pension and OPEB costs are recoverable through our general ratemaking process. Actual future pension cost and contributions will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the Pension Plan. As a result of additional losses experienced since September 30, 2008 in global equity markets, our Pension Plan contributions may be substantially larger in 2009 and assets are likely to have a negative return for 2008.

For additional details on retirement benefits, see Note 7, Retirement Benefits.

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CAPITAL RESOURCES AND LIQUIDITY

Factors affecting our liquidity and capital requirements include:

• results of operations,

• capital expenditures,

• energy commodity and transportation costs,

• contractual obligations,

• regulatory decisions,

• debt maturities,

• credit ratings,

• pension plan funding requirements,

• working capital needs,

• collateral requirements, and

• access to credit markets.

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

Components of our cash management plan include controlling operating expenses and capital expenditures and evaluating market conditions for financing opportunities, if needed. We have taken the following actions to strengthen our liquidity:

• in September 2008, we issued $350 million FMB, and

• in September 2008, we entered into a $150 million revolving credit agreement.

In April 2008, we redeemed two of our tax-exempt debt issues with $96 million of refinancing proceeds and converted $35 million of tax-exempt debt previously backed by municipal bond insurers to variable rate demand bonds, effectively eliminating our variable rate debt backed by municipal bond insurers.

Despite the current market volatility, we expect to be able to continue to have access to the capital markets, including funds available under our revolving credit facilities and our accounts receivable sales program. Our revolving credit facilities of $350 million are subject to renewal in 2009 and $500 million are subject to renewal in 2012. Our accounts receivable sales program is subject to renewal in February 2009. We believe that our current level of cash and our anticipated cash flows from operating activities, together with access to sources of liquidity, will be sufficient to meet cash requirements. For additional details, see Note 5, Financings and Capitalization.

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Cash Position, Investing, and Financing

Our operating, investing, and financing activities meet consolidated cash needs. At September 30, 2008, we had $113 million of consolidated cash, which includes $24 million of restricted cash.

Summary of Consolidated Statements of Cash Flows:

	In Millions
Nine months ended September 30	2008			2007
Net cash provided by (used in):
Operating activities	$	524		$	189
Investing activities		(531	)		151
Net cash provided by (used in) operating and investing activities		(7	)		340
Net cash provided by (used in) financing activities		(99	)		392
Net Increase (Decrease) in Cash and Cash Equivalents	$	(106	)	$	732

Operating Activities: For the nine months ended September 30, 2008, net cash provided by operating activities was $524 million, an increase of $335 million versus 2007. The increase was primarily due to an increase in earnings, lower postretirement benefits contributions and timing of cash receipts from accounts receivable. We accelerate our collections from customer billings through the sale of accounts receivable. The sale of accounts receivable at the end of 2006 reduced our collections from customers during 2007. At the end of 2007, we did not rely on sales of accounts receivable and collected customer billings for the nine months ended September 30, 2008. These increases were partially offset by the impact of higher gas prices on inventory purchases.

Investing Activities: For the nine months ended September 30, 2008, net cash used in investing activities was $531 million, an increase of $682 million versus 2007. This increase was mainly due to the absence of proceeds from the sale of Palisades and proceeds from our nuclear decommissioning trust funds.

Financing Activities: For the nine months ended September 30, 2008, net cash used in financing activities was $99 million, an increase of $491 million versus 2007. This was primarily due to the absence of contributions from the parent, partially offset by an increase in net proceeds from long-term debt. For additional details on long-term debt activity, see Note 5, Financings and Capitalization.

Obligations and Commitments

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

Sale of Accounts Receivable: Under our revolving accounts receivable sales program, we may sell up to $250 million of certain accounts receivable.

Capital Expenditures: For reporting purposes, we identify annual capital expenditures for the next three years. We review these estimates and may revise them periodically, due to a number of factors including environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital. In response to recent economic conditions, we reviewed our capital expenditures plan. For 2009, we have reduced our capital expenditures plan by $125 million to $855 million. We will continue to monitor our forecasted capital expenditures for 2009 and beyond.

Dividend Restrictions: For details on dividend restrictions, see Note 5, Financings and Capitalization.

Off-Balance sheet Arrangements

We enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. For additional details on these arrangements, see Note 4, Contingencies, “Other Contingencies — Guarantees and Indemnifications.”

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OUTLOOK

CORPORATE OUTLOOK

Our business strategy will focus on continuing to invest in our utility system to enable us to meet our customer commitments, to comply with increasingly demanding environmental performance standards, to improve system performance, and to maintain adequate supply and capacity.

ELECTRIC BUSINESS OUTLOOK

Michigan Energy Legislation: In October 2008, the Michigan governor signed into law a comprehensive energy reform package. Significant features of the new legislation include:

• a provision to streamline the regulatory process by generally allowing utilities to self-implement rates six months after filing and requiring the MPSC to issue an order 12 months after filing or the rates as-filed become permanent,

• reform of the Customer Choice Act to limit generally alternative energy suppliers to 10 percent of our weather-adjusted sales,

• establishment of a certificate-of-necessity process at the MPSC for proposed power plants, power purchase agreements, and projects costing more than $500 million,

• a requirement that 10 percent of power come from renewable sources by 2015 with specific interim targets, and

• new programs and incentives to encourage greater energy efficiency among customers, along with the requirement of the utility to prepare energy cost savings optimization plans.

Balanced Energy Initiative: Our Balanced Energy Initiative is a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements with energy efficiency, demand management, expanded use of renewable energy, and development of new power plants and pursuit of additional power purchase agreements to complement existing generating sources. Our Balanced Energy Initiative includes our plan to build an 800 MW advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan.

The new energy legislation in Michigan provides guidelines with respect to the MPSC review and approval of energy resource plans and proposed power plants. We plan to file an updated Balanced Energy Initiative with the MPSC in conjunction with a certificate-of-necessity that conforms to the requirements of the new legislation and the rules that the MPSC will develop for the certificate-of-necessity filings.

Electric Deliveries: We are anticipating a decrease in electric deliveries of approximately 3 percent in 2008 compared with 2007 or 1 percent excluding weather conditions. This decline reflects a decline in industrial economic activity, and the cancellation of one wholesale customer contract. For 2009 compared with 2008, a decline, excluding weather conditions, of 1 percent is expected. Our outlook for 2009 includes continuing growth in deliveries to our largest growing customer that produces semiconductor and solar energy components. Without this customer’s growth our electric deliveries in 2009 are expected to decline 3 percent compared with 2008. Our outlook also reflects reduced deliveries associated with our investment in energy efficiency programs included in the recently enacted legislation, as well as recent projections of Michigan economic conditions.

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After 2009, we anticipate economic conditions to stabilize, resulting in modestly growing deliveries of electricity. We expect deliveries to grow on average about 0.5 percent annually over the period from 2009 to 2014. This growth rate also includes expected results of energy efficiency programs and both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but transactions with other wholesale market participants are not included. Actual growth may vary from this trend due to the following:

• energy conservation measures and results of energy efficiency programs,

• fluctuations in weather conditions, and

• changes in economic conditions, including utilization and expansion or contraction of manufacturing facilities, population trends, and housing activity.

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

Electric Reserve Margin: To reduce the risk of high power supply costs during peak demand periods and to achieve our Reserve Margin target, we purchase electric capacity and energy for the physical delivery of electricity primarily in the summer months. We are currently planning for a Reserve Margin of 13.7 percent for summer 2009, or supply resources equal to 113.7 percent of projected firm summer peak load. We have purchased capacity and energy covering partially our Reserve Margin requirements for 2009 through 2010. Of the 2009 supply resources target, we expect 93 percent to come from our electric generating plants and long-term power purchase contracts, with other contractual arrangements making up the remainder. We expect capacity costs for these electric capacity and energy contractual arrangements to be $15 million for 2009.

Electric Transmission Expenses: We expect the transmission charges we incur to increase by $32 million in 2008 compared with 2007 primarily due to a 33 percent increase in METC transmission rates. This increase was included in our 2008 PSCR plan filed with the MPSC in September 2007, which we self-implemented in January 2008.

We expect the transmission charges we incur to increase by $55 million in 2009 compared with 2008 primarily due to a 25 percent increase in METC and Wolverine transmission rates. This increase was included in our 2009 PSCR plan filed with the MPSC in September 2008.

The MPSC issued an order that allowed transmission expenses to be included in the PSCR process. The Attorney General appealed the MPSC order to the Michigan Court of Appeals, which affirmed the MPSC order. The Attorney General filed an application for leave to appeal with the Michigan Supreme Court, which was granted in September 2008. We cannot predict the financial impact or outcome of this matter.

For additional details on the electric transmission expense litigation, see Note 4, Contingencies, “Electric Contingencies — Litigation.”

ELECTRIC BUSINESS UNCERTAINTIES

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

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

Clean Air Act: We continue to focus on complying with the federal Clean Air Act and numerous state and federal regulations. We plan to spend $795 million for equipment installation through 2015 to comply with a number of environmental regulations, including regulations limiting nitrogen oxides and sulfur dioxide emissions. We expect to recover these costs in customer rates.

Clean Air Interstate Rule: In March 2005, the EPA adopted the CAIR, which required additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. The CAIR was appealed to the U.S. Court of Appeals for the District of Columbia and, in July 2008, the court vacated the CAIR and the CAIR federal implementation plan in their entirety. If upheld, the decision would remand the CAIR back to the EPA to form a new rule, which will likely take considerable time. Several parties have petitioned the court for hearing by the full court. This keeps the CAIR in effect at least until the court decides whether to grant the rehearing. At the same time, Congress is considering legislative options to reinstate all or part of the CAIR.

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

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. If this plan becomes effective, we estimate the associated costs will be approximately $400 million by 2015.

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as “routine maintenance, repair and replacement” rather than seeking permits from the EPA to modify their plants. We responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance, repair and replacement.” In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. In addition, in October 2008, we received a NOV for three of our coal-fired facilities relating to violations of NSR and PSD regulations, alleging ten projects from 1986 to 1998 were subject to PSD review. We are currently preparing our response to this NOV and the information request. If the EPA does not accept our interpretation, we could be required to install additional pollution control equipment at some or all of our coal-fired electric generating plants and pay fines. Additionally, we would need to assess the viability of continuing operations at certain plants. We cannot predict the financial impact or outcome of this matter.

Greenhouse Gases: The United States Congress has introduced proposals that would require reductions in emissions of greenhouse gases, including carbon dioxide. These laws, or similar state laws or rules, if enacted, could require us to replace equipment, install additional equipment for emission controls, purchase allowances, curtail operations, or take other steps to manage or lower the emission of greenhouse gases. 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.

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The EPA has published an Advance Notice of Proposed Rulemaking to present possible options for regulating greenhouse gases under the Clean Air Act, as well as to solicit comments and additional ideas. The comment period closes in November 2008. In addition to the potential for federal actions related to greenhouse gas regulation, the State of Michigan has convened a climate change stakeholder process under the name Michigan Climate Action Council. Michigan is also a signatory participant in the Midwest Governors Greenhouse Gas Reduction Accord process. We cannot predict the extent or the likelihood of any actions that could result from these state and regional processes.

Water: In July 2004, the EPA issued rules that govern existing electric generating plant cooling water intake systems. These rules require a significant reduction in the number of fish harmed by intake structures at large existing power plants. The EPA compliance options in the rule were challenged before the United States Court of Appeals for the Second Circuit. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The United States Court of Appeals for the Second Circuit’s ruling is expected to increase significantly the cost of complying with this rule, but we will not know the cost to comply until the EPA’s reconsideration is complete. In April 2008, the U.S. Supreme Court agreed to hear this case, thereby extending the time before this issue is finally resolved.

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

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

Electric ROA: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. However, the energy legislation enacted in Michigan in October 2008 generally limits alternative electric supply to 10 percent of our weather-adjusted retail sales for the preceding calendar year. At September 2008, alternative electric suppliers were providing 339 MW of generation service to ROA customers, which is equivalent to 4 percent of our weather-adjusted retail sales from the preceding calendar year.

In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred in 2002 and 2003 through a surcharge applied to ROA customers. The new energy legislation directs the MPSC to approve rates that will allow us to recover our Stranded Costs within five years.

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

In June 2008, the MPSC issued an order authorizing us to increase revenue by $221 million. This was lower than our revised position primarily due to the MPSC’s authorized return on equity of 10.7 percent and the final determination of our Zeeland plant revenue requirement.

We plan to file a new electric rate case by late November 2008.

Palisades Regulatory Proceedings: We sold Palisades to Entergy in April 2007. The MPSC order approving the transaction requires that we credit $255 million of excess sale proceeds and decommissioning amounts to our retail customers by December 2008. There are additional excess sales proceeds and decommissioning fund balances of $135 million above the amount in the MPSC order. The MPSC order in our electric rate case instructed us to offset the excess sales proceeds and

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decommissioning fund balances with $26 million of transaction costs from the Palisades sale and credit the remaining balance to customers. The distribution of these funds is still pending with the MPSC.

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

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

• a capacity charge of $10.14 per MWh of available capacity,

• a fixed energy charge based on our annual average base load coal generating plant operating and maintenance cost,

• a variable energy charge for all delivered energy that reflects the MCV Partnership’s cost of production,

• the elimination of the RCP, but continues the $5 million annual contribution by the MCV Partnership to a renewable resources program, and

• an option for us to extend the MCV PPA for five years or purchase the MCV Facility at the conclusion of the MCV PPA’s term in March 2025.

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

For additional details on the MCV PPA, see Note 4, Contingencies, “Other Electric Contingencies - The MCV PPA.”

GAS BUSINESS OUTLOOK

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

• fluctuations in weather conditions,

• use by independent power producers,

• availability and development of renewable energy sources,

• changes in gas prices,

• Michigan economic conditions including population trends and housing activity,

• the price of competing energy sources or fuels, and

• energy efficiency and conservation.

GAS BUSINESS UNCERTAINTIES

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

Gas Environmental Estimates: We expect to incur investigation and remedial action costs at a number of sites, including 23 former manufactured gas plant sites. For additional details, see Note 4, Contingencies, “Gas Contingencies — Gas Environmental Matters.”

Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural gas

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costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudence in annual plan and reconciliation proceedings. For additional details on GCR, see Note 4, Contingencies, “Gas Rate Matters — Gas Cost Recovery.”

Gas Depreciation: On August 1, 2008, we filed a gas depreciation case using 2007 data with the MPSC-ordered variations on traditional cost-of-removal methodologies. We cannot predict the outcome of this matter. If a final order in our gas depreciation case is not issued concurrently with a final order in a general gas rate case, the MPSC may incorporate the results of the depreciation case into general gas rates through a surcharge, which may be either positive or negative.

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

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million based on an 11 percent authorized return on equity. The MPSC staff and intervenors filed testimony in September 2008. The MPSC staff recommended an increase of $36 million based on a 10.45 percent authorized return on equity.

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

OTHER OUTLOOK

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

Advanced Metering Infrastructure: We are developing an advanced metering system that will provide enhanced controls and information about our customer energy usage and notification of service interruptions. The system also will allow customers to make decisions about energy efficiency and conservation, provide other customer benefits, and reduce costs. We expect to develop integration software and pilot new technology over approximately the next two to three years, and incur capital expenditures of approximately $800 million over the next seven years.

Litigation and Regulatory Investigation: We are a party to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. For additional details regarding these lawsuits and proceedings, see Note 4, Contingencies and Part II, Item 1. Legal Proceedings.

Emergency Economic Stabilization Act of 2008 — Mark-to-Market Accounting: In October 2008, President Bush signed into law a $700 billion economic recovery plan. The plan includes a provision authorizing the SEC to suspend the application of SFAS No. 157 for any issuer with respect to any class

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or category of transaction as deemed necessary. In addition, the SEC is required to conduct a study on mark-to-market accounting (fair value accounting), including its possible impacts on recent bank failures, along with a consideration of alternative accounting treatments. The SEC must submit a report to Congress within 90 days. We apply this accounting primarily to our commodity derivative instruments and our SERP investments. We will continue to monitor developments in this area.

IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

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

SEC / FASB Guidance on Fair Value Measurements: In September 2008, in response to concerns about fair value accounting and its possible role in the recent declines in the financial markets, the SEC Office of the Chief Accountant and the FASB staff jointly released additional guidance on fair value measurements. The guidance, which is effective for us immediately, did not change or conflict with the fair value principles in SFAS No. 157, but rather provided further clarification on how to value a financial asset in an illiquid market. This guidance had no impact on our fair value measurements.

FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active: In October 2008, the FASB issued this standard, effective for us as of the quarter ended September 30, 2008. The standard clarifies the application of SFAS No. 157 in measuring financial assets in illiquid markets and is consistent with the guidance issued by the SEC and the FASB as discussed in the preceding paragraph, but an example is provided to further illustrate the concepts. The standard is to be applied prospectively. The guidance in this standard did not impact our fair value measurements.

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS No. 158. Phase one of this standard, implemented in December 2006, required us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase two, implemented in January 2008, required us to change our plan measurement date from November 30 to December 31, effective for the year ending December 31, 2008. For additional details, see Note 7, Retirement Benefits.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: This standard, which was effective for us January 1, 2008, gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We have not elected the fair value option for any financial instruments or other items.

EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards: This standard was effective for us January 1, 2008. The standard requires companies to recognize, as an increase to additional paid-in capital, the income tax benefit realized from dividends or dividend equivalents that are charged to retained earnings and paid to employees for non-vested equity-classified employee share-based payment awards. This standard did not have a material effect on our consolidated financial statements.

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NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

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

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Under this standard, ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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

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

FSP FAS 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161: In September 2008, the FASB issued this standard, effective for us December 31, 2008. This standard will amend SFAS No. 133 and FIN 45 to enhance the disclosure requirements for issuers of credit derivatives and financial guarantees. As we have not issued any credit derivatives, this standard will apply only to our disclosures about guarantees we have issued. It will have no effect on our consolidated financial statements.

EITF Issue 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement: In September 2008, the FASB ratified EITF Issue 08-5, effective for us January 1, 2009. This guidance concludes that the fair value measurement of a liability should not consider the effect of a third-party credit enhancement or guarantee supporting the liability. The fair value of the liability should thus reflect the credit standing of the issuer and should not be adjusted to reflect the credit standing of a third-party guarantor. The standard is to be applied prospectively. This standard will not have a material impact on our consolidated financial statements.

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Consumers Energy Company
Consolidated Statements of Income
(Unaudited)

							In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Operating Revenue	$	1,307		$	1,172		$	4,661		$	4,474
Operating Expenses
Fuel for electric generation		128			122			373			298
Purchased and interchange power		405			383			1,015			1,055
Purchased power — related parties		20			20			57			59
Cost of gas sold		135			113			1,368			1,309
Other operating expenses		201			201			565			619
Maintenance		44			41			124			143
Depreciation and amortization		131			117			425			390
General taxes		44			51			146			166
Gain on asset sales, net		—			—			—			(2	)
		1,108			1,048			4,073			4,037
Operating Income		199			124			588			437
Other Income (Deductions)
Interest		4			24			20			55
Regulatory return on capital expenditures		9			9			25			24
Other income		4			5			9			19
Other expense		(11	)		(1	)		(17	)		(4	)
		6			37			37			94
Interest Charges
Interest on long-term debt		56			59			169			177
Interest on long-term debt — related parties		—			—			—			2
Other interest		6			10			17			25
Capitalized interest		(1	)		(1	)		(4	)		(5	)
		61			68			182			199
Income Before Income Taxes		144			93			443			332
Income Tax Expense		53			33			162			115
Net Income		91			60			281			217
Preferred Stock Dividends		1			—			2			1
Net Income Available to Common Stockholder	$	90		$	60		$	279		$	216

The accompanying notes are an integral part of these statements.

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Consumers Energy Company
Consolidated Statements of Cash Flows
(Unaudited)

				In Millions
Nine Months Ended September 30	2008			2007
Cash Flows from Operating Activities
Net income	$	281		$	217
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (includes nuclear decommissioning of $- and $4)		425			390
Deferred income taxes and investment tax credit		87			(6	)
Regulatory return on capital expenditures		(25	)		(24	)
Gain on sale of assets		—			(2	)
Postretirement benefits costs		107			96
Capital lease and other amortization		23			32
Postretirement benefits contributions		(37	)		(140	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, notes receivable and accrued revenue		178			(142	)
Decrease in accrued power supply and gas revenue		39			52
Increase in inventories		(411	)		(184	)
Decrease in deferred property taxes		118			111
Decrease in accounts payable		(14	)		(67	)
Decrease in accrued taxes		(127	)		(75	)
Decrease in accrued expenses		(36	)		(21	)
Decrease in other current and non-current assets		50			41
Decrease in other current and non-current liabilities		(134	)		(89	)
Net cash provided by operating activities		524			189
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)		(510	)		(518	)
Cost to retire property		(22	)		(18	)
Restricted cash		1			16
Investments in nuclear decommissioning trust funds		—			(1	)
Proceeds from nuclear decommissioning trust funds		—			333
Proceeds from sale of assets		—			337
Other investing		—			2
Net cash provided by (used in) investing activities		(531	)		151
Cash Flows from Financing Activities
Proceeds from issuance of long term debt		600			—
Retirement of long-term debt		(434	)		(24	)
Payment of common stock dividends		(238	)		(176	)
Payment of capital and finance lease obligations		(18	)		(14	)
Stockholder’s contribution		—			650
Payment of preferred stock dividends		(2	)		(1	)
Decrease in notes payable		—			(42	)
Debt issuance and financing costs		(7	)		(1	)
Net cash provided by (used in) financing activities		(99	)		392
Net Increase (Decrease) in Cash and Cash Equivalents		(106	)		732
Cash and Cash Equivalents, Beginning of Period		195			37
Cash and Cash Equivalents, End of Period	$	89		$	769

The accompanying notes are an integral part of these statements.

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Consumers Energy Company
Consolidated Balance Sheets

ASSETS

			In Millions
	September 30		December 31
	2008		2007
	(Unaudited)
Plant and Property (at cost)
Electric	$	8,885	$	8,555
Gas		3,598		3,467
Other		15		15
		12,498		12,037
Less accumulated depreciation, depletion, and amortization		4,177		3,993
		8,321		8,044
Construction work-in-progress		446		447
		8,767		8,491
Investments
Stock of affiliates		23		32
Current Assets
Cash and cash equivalents at cost, which approximates market		89		195
Restricted cash at cost, which approximates market		24		25
Notes receivable		97		67
Accounts receivable and accrued revenue, less allowances of $16 in 2008 and $16 in 2007		616		810
Accrued power supply revenue		4		45
Accounts receivable — related parties		2		4
Inventories at average cost
Gas in underground storage		1,476		1,123
Materials and supplies		102		79
Generating plant fuel stock		133		100
Deferred property taxes		111		158
Regulatory assets — postretirement benefits		19		19
Prepayments and other		30		28
		2,703		2,653
Non-current Assets
Regulatory assets
Securitized costs		429		466
Postretirement benefits		849		921
Customer Choice Act		104		149
Other		462		504
Other		111		185
		1,955		2,225
Total Assets	$	13,448	$	13,401

The accompanying notes are an integral part of these statements.

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STOCKHOLDER’S INVESTMENT AND LIABILITIES

			In Millions
	September 30		December 31
	2008		2007
	(Unaudited)
Capitalization
Common stockholder’s equity
Common stock, authorized 125.0 shares; outstanding 84.1 shares for all periods	$	841	$	841
Paid-in capital		2,482		2,482
Retained earnings		359		324
		3,682		3,647
Preferred stock		44		44
Long-term debt		3,918		3,692
Non-current portion of capital and finance lease obligations		212		225
		7,856		7,608
Current Liabilities
Current portion of long-term debt, capital and finance lease obligations		408		470
Accounts payable		396		403
Accrued rate refunds		11		19
Accounts payable — related parties		14		13
Accrued interest		45		65
Accrued taxes		226		353
Deferred income taxes		173		151
Regulatory liabilities		159		164
Other		180		150
		1,612		1,788
Non-current Liabilities
Deferred income taxes		746		713
Regulatory liabilities
Regulatory liabilities for cost of removal		1,184		1,127
Income taxes, net		561		533
Other regulatory liabilities		147		313
Postretirement benefits		831		813
Asset retirement obligations		203		198
Deferred investment tax credit		56		58
Other		252		250
		3,980		4,005
Commitments and Contingencies (Notes 4, 5, and 6)
Total Stockholder’s Investment and Liabilities	$	13,448	$	13,401

The accompanying notes are an integral part of these statements.

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Consumers Energy Company
Consolidated Statements of Common Stockholder’s Equity
(Unaudited)

							In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Common Stock
At beginning and end of period (a)	$	841		$	841		$	841		$	841
Other Paid-in Capital
At beginning of period		2,482			2,482			2,482			1,832
Stockholder’s contribution		—			—			—			650
At end of period		2,482			2,482			2,482			2,482
Accumulated Other Comprehensive Income
Retirement benefits liability
At beginning of period		(9	)		(8	)		(15	)		(8	)
Retirement benefits liability adjustment (b)		—			—			6			—
At end of period		(9	)		(8	)		(9	)		(8	)
Investments
At beginning of period		8			22			15			23
Unrealized loss on investments (b)		(5	)		—			(12	)		(1	)
Reclassification adjustments included in net income (b)		6			—			6			—
At end of period		9			22			9			22
Total Accumulated Other Comprehensive Income		—			14			—			14
Retained Earnings
At beginning of period		339			286			324			270
Effects of changing the retirement plans measurement date pursuant to SFAS No. 158
Service cost, interest cost, and expected return on plan assets for December 1 through December 31, 2007, net of tax		—			—			(4	)		—
Additional loss from December 1 through December 31, 2007, net of tax		—			—			(2	)		—
Adjustment to initially apply FIN 48, net of tax		—			—			—			(5	)
Net income		91			60			281			217
Cash dividends declared — Common Stock		(70	)		(41	)		(238	)		(176	)
Cash dividends declared — Preferred Stock		(1	)		—			(2	)		(1	)
At end of period		359			305			359			305
Total Common Stockholder’s Equity	$	3,682		$	3,642		$	3,682		$	3,642

The accompanying notes are an integral part of these statements.

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									In Millions
	Three Months Ended					Nine Months Ended
September 30	2008			2007		2008			2007
				(Unaudited)
(a) Number of shares of common stock outstanding was 84,108,789 for all periods presented.
(b) Disclosure of Comprehensive Income:
Net income	$	91		$	60	$	281		$	217
Retirement benefits liability
Retirement benefits liability adjustment, net of tax of $-, $-, $2 and $-, respectively		—			—		6			—
Investments
Unrealized loss on investments, net of tax benefit of $(3), $-, $(6) and $(1), respectively		(5	)		—		(12	)		(1	)
Reclassification adjustments included in net income, net of tax $3, $-, $3 and $-, respectively		6			—		6			—
Total Comprehensive Income	$	92		$	60	$	281		$	216

The accompanying notes are an integral part of these statements.

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Consumers Energy Company
Notes to Consolidated Financial Statements
(Unaudited)

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

1: Corporate Structure and Accounting Policies

Corporate Structure: Consumers, a subsidiary of CMS Energy, a holding company, is a combination electric and gas utility company serving Michigan’s Lower Peninsula. Our customer base includes a mix of residential, commercial, and diversified industrial customers. We manage our business by the nature of service provided and operate principally in two business segments: electric utility and gas utility.

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

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

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

Revenue Recognition Policy: We recognize revenues from deliveries of electricity and natural gas, and from the storage of natural gas when services are provided. We record unbilled revenues for the estimated amount of energy delivered to customers but not yet billed. Our unbilled receivables were $259 million at September 30, 2008 and $490 million at December 31, 2007. We record sales tax on a net basis and exclude it from revenues.

Cash and Cash Equivalents: Cash and cash equivalents include short-term, highly-liquid investments with original maturities of three months or less. At September 30, 2008, these investments consisted of

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money market funds invested in U.S. Treasury notes and repurchase agreements collateralized by U.S. Treasury notes. The fair value of these investments approximates their amortized cost.

Other Income and Other Expense: The following tables show the components of Other income and Other expense:

In Millions
	Three Months Ended				Nine Months Ended
September 30	2008		2007		2008		2007
Other income
Electric restructuring return	$	—	$	—	$	—	$	1
Return on stranded and security costs		1		1		4		4
Gain on stock		—		—		—		4
Gain on investment		—		3		—		7
All other		3		1		5		3
Total other income	$	4	$	5	$	9	$	19

In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Other expense
Unrealized investment loss	$	(9	)	$	—		$	(9	)	$	—
Civic and political expenditures		(1	)		(1	)		(5	)		(2	)
All other		(1	)		—			(3	)		(2	)
Total other expense	$	(11	)	$	(1	)	$	(17	)	$	(4	)

New Accounting Standards Not Yet Effective: SFAS No. 141(R), Business Combinations: In December 2007, the FASB issued SFAS No. 141(R), which replaces SFAS No. 141, Business Combinations. SFAS No. 141(R) establishes how an acquiring entity should measure and recognize assets acquired, liabilities assumed, and noncontrolling interests acquired through a business combination. The standard also establishes how goodwill or gains from bargain purchases should be measured and recognized and what information the acquirer should disclose to enable users of the financial statements to evaluate the nature and financial effects of a business combination. Costs of an acquisition are to be recognized separately from the business combination. We will apply SFAS No. 141(R) prospectively to any business combination for which the date of acquisition is on or after January 1, 2009.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — an amendment to ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Under this standard, ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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

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

FSP FAS 133-1 and FIN 45-4, Disclosures about Credit Derivatives and Certain Guarantees: An Amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161: In September 2008, the FASB issued this standard, effective for us December 31, 2008. This standard will amend SFAS No. 133 and FIN 45 to enhance the disclosure requirements for issuers of credit derivatives and financial guarantees. As we have not issued any credit derivatives, this standard will apply only to our disclosures about guarantees we have issued. It will have no effect on our consolidated financial statements.

EITF Issue 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement: In September 2008, the FASB ratified EITF Issue 08-5, effective for us January 1, 2009. This guidance concludes that the fair value measurement of a liability should not consider the effect of a third-party credit enhancement or guarantee supporting the liability. The fair value of the liability should thus reflect the credit standing of the issuer and should not be adjusted to reflect the credit standing of a third-party guarantor. The standard is to be applied prospectively. This standard will not have a material impact on our consolidated financial statements.

2: Fair Value Measurements

SFAS No. 157, which became effective January 1, 2008, defines fair value, establishes a framework for measuring fair value, and expands disclosures about fair value measurements. It does not require any new fair value measurements, but applies to those fair value measurements recorded or disclosed under other accounting standards. The standard defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants, and requires that fair value measurements incorporate all assumptions that market participants would use in pricing an asset or liability, including assumptions about risk. The standard also eliminates the prohibition against recognizing “day one” gains and losses on derivative instruments. We did not hold any derivatives with “day one” gains or losses during the nine months ended September 30, 2008. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we held during the nine months ended September 30, 2008.

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

• Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities. These markets must be accessible to us at the measurement date.

• Level 2 inputs are observable, market-based inputs, other than Level 1 prices. Level 2 inputs may include quoted prices for similar assets or liabilities in active markets, quoted prices in inactive markets, interest rates and yield curves observable at commonly quoted intervals, credit risks, default rates, and inputs derived from or corroborated by observable market data.

• Level 3 inputs are unobservable inputs that reflect our own assumptions about how market participants would value our assets and liabilities.

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

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

• AROs,

• most of the nonfinancial assets and liabilities acquired in a business combination, and

• impairment analyses performed for nonfinancial assets.

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

SEC and FASB Guidance on Fair Value Measurements: On September 30, 2008, in response to concerns about fair value accounting and its possible role in the recent declines in the financial markets, the SEC Office of the Chief Accountant and the FASB staff jointly released additional guidance on fair value measurements. The guidance, which is effective for us immediately, did not change or conflict with the fair value principles in SFAS No. 157, but rather provided further clarification on how to value a financial asset in an illiquid market. In October 2008, the FASB issued FSP FAS 157-3, Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active. The standard is consistent with the joint guidance issued by the SEC and FASB and is effective for us as of the quarter ended September 30, 2008. The standard is to be applied prospectively. The guidance in this standard and the joint guidance provided by the FASB and the SEC did not impact our fair value measurements.

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Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following table summarizes, by level within the fair value hierarchy, our assets and liabilities accounted for at fair value on a recurring basis at September 30, 2008.

In Millions
	Total			Level 1			Level 2
Assets:
CMS Energy Common Stock	$	23		$	23		$	—
Nonqualified Deferred Compensation Plan Assets		3			3			—
SERP
Equity Securities		32			32			—
Debt Securities		19			—			19
Total	$	77		$	58		$	19
Liabilities:
Nonqualified Deferred Compensation Plan Liabilities	$	(3	)	$	(3	)	$	—

Nonqualified Deferred Compensation Plan Assets: Our Nonqualified deferred compensation plan assets are invested in various mutual funds. We value these assets using a market approach, which uses the daily quoted NAV provided by the fund managers that are the basis for transactions to buy or sell shares in each fund. On our Consolidated Balance Sheets, these assets are included in Other non-current assets.

SERP Assets: Our SERP assets are valued using a market approach, which incorporates prices and other relevant information from market transactions. Our SERP equity securities comprise an investment in Standard & Poor’s 500 Index mutual fund. The fund’s securities are listed on an active exchange or dealer market. The fair value of the SERP equity securities is based on the NAV of the mutual fund that is derived from the daily closing prices of the equity securities held by the fund. The NAV is the basis for transactions to buy or sell shares in the fund. Our SERP debt securities, which are investment grade municipal bonds, are valued using a market approach, which is based on a matrix pricing model that incorporates market-based information. The fair value of our SERP debt securities is derived from various observable inputs, including benchmark yields, reported securities trades, broker/dealer quotes, bond ratings, and general information on market movement for investment grade municipal securities normally considered by market participants when pricing a debt security. SERP assets are included in Other non-current assets on our Consolidated Balance Sheets. For additional details about our SERP securities, see Note 6, Financial and Derivative Instruments.

Nonqualified Deferred Compensation Plan Liabilities: The non-qualified deferred compensation plan liabilities are valued based on the fair values of the plan assets, as they reflect what is owed to the plan participants in accordance with their investment elections. These liabilities, except for our primary DSSP plan liability, are included in Other non-current liabilities on our Consolidated Balance Sheets. Our primary DSSP plan liability is included in non-current Postretirement benefits on our Consolidated Balance Sheets.

At September 30, 2008, we did not have any assets or liabilities classified as Level 3.

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3: Asset Sales

ASSET SALES

The impacts of our asset sales are included in Gain on asset sales, net in our Consolidated Statements of Income. Asset sales were immaterial for the nine months ended September 30, 2008.

Gross cash proceeds from the sale of assets totaled $337 million through September 30, 2007. For the nine months ended September 30, 2007, we sold the following assets:

In Millions
		Pretax		After-tax
Month Sold	Business/Project	Gain		Gain
April	Palisades (a)	$	—	$	—
Various	Other		2		1
	Total gain on asset sales	$	2	$	1

(a) We sold Palisades to Entergy for $380 million and received $364 million after various closing adjustments. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. Because of the sale of Palisades, we paid the NMC, the former operator of Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC. 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 accounted for the disposal of Palisades as a financing for accounting purposes and thus we recognized no gain in the Consolidated Statements of Income. We accounted for the remaining non-real estate assets and liabilities associated with the transaction as a sale.

4: Contingencies

Katz Technology Litigation: In June 2007, RAKTL filed a lawsuit in the United States District Court for the Eastern District of Michigan against CMS Energy and Consumers alleging patent infringement. RAKTL claimed that automated customer service, bill payment services and gas leak reporting offered to our customers and accessed through toll free numbers infringe on patents held by RAKTL. Consumers, along with CMS Energy, signed a settlement and license agreement with RAKTL in June 2008 to settle the litigation. The settlement and licensing costs with RAKTL are immaterial. On June 10, 2008, the court entered an order dismissing the case with prejudice.

ELECTRIC CONTINGENCIES

Electric Environmental Matters: Our operations are subject to environmental laws and regulations. Generally, we have been able to recover in customer rates the costs to operate our facilities in compliance with these laws and regulations.

Cleanup and Solid Waste: Under the NREPA, we will ultimately incur investigation and response activity costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies.

We are a potentially responsible party at a number of contaminated sites administered under the Superfund. Superfund liability is joint and several. However, many other creditworthy parties with

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substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for most of our known Superfund sites will be between $2 million and $11 million. At September 30, 2008, we have recorded a liability for the minimum amount of our estimated probable Superfund liability in accordance with FIN 14.

The timing of payments related to our investigation and response activities at our Superfund and NREPA sites is uncertain. Any significant change in assumptions, such as different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of response activity costs and the timing of our payments.

Ludington PCB: In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at Ludington. We removed and replaced part of the PCB material with non-PCB material. Since proposing a plan to deal with the remaining materials, we have had several communications with the EPA. The EPA has proposed a rule that would allow us to leave the material in place, subject to certain restrictions. We are not able to predict when the EPA will issue a final ruling. We cannot predict the financial impact or outcome of this matter.

Electric Utility Plant Air Permit Issues: In April 2007, we received a NOV/FOV from the EPA alleging that 14 of our utility boilers exceeded visible emission limits in their associated air permits. The utility boilers are located at the Karn/Weadock Generating Complex, Campbell Plant, Cobb Electric Generating Station and Whiting Plant, which are all in Michigan. We have responded formally to the NOV/FOV denying the allegations and are awaiting the EPA’s response to our submission. We cannot predict the financial impact or outcome of this matter.

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as “routine maintenance, repair and replacement” rather than seeking permits from the EPA to modify their plants. We responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance, repair and replacement.” In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. In addition, in October 2008, we received a NOV for three of our coal-fired facilities relating to violations of NSR and PSD regulations, alleging ten projects from 1986 to 1998 were subject to PSD review. We are currently preparing our response to this NOV and the information request. If the EPA does not accept our interpretation, we could be required to install additional pollution control equipment at some or all of our coal-fired electric generating plants and pay fines. Additionally, we would need to assess the viability of continuing operations at certain plants. We cannot predict the financial impact or outcome of this matter.

Litigation: Qualifying Facilities: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs) filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made under power purchase agreements. The judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The plaintiffs appealed the MPSC order to the Michigan Court of Appeals, which, in April 2008, affirmed the MPSC order. The plaintiffs filed an application for leave to appeal with the Michigan Supreme Court. In September 2008, the application for leave to appeal was denied. The plaintiffs also agreed to dismiss two related cases, thus closing this litigation.

Transmission Charges: Transmission charges we have paid to MISO have been subject to regulatory review and recovery through the annual PSCR process. The Attorney General has argued that the statute governing the PSCR process does not permit recovery of transmission charges in that manner and those expenses should be considered in general rate cases. Several decisions of the Michigan Court

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of Appeals have ruled against the Attorney General’s arguments, but in September 2008, the Michigan Supreme Court granted the Attorney General’s applications for leave to appeal two of those decisions. If the Michigan Supreme Court accepts the Attorney General’s position, we and other electric utilities would be required to obtain recovery of transmission charges through an alternative ratemaking mechanism. We expect a decision by the Michigan Supreme Court on these appeals by mid-2009. We cannot predict the financial impact or outcome of this matter.

ELECTRIC RATE MATTERS

Electric ROA: The Customer Choice Act allows electric utilities to recover their net Stranded Costs. In November 2004, the MPSC approved recovery of our Stranded Costs incurred in 2002 and 2003 plus interest through the period of collection. At September 30, 2008, we had a regulatory asset for Stranded Costs of $70 million. We collect these Stranded Costs through a surcharge on ROA customers. The new energy legislation directs the MPSC to approve rates that will allow us to recover our Stranded Costs within five years.

Power Supply Costs: The PSCR process is designed to allow us to recover reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudence in annual plan proceedings and in annual plan reconciliation proceedings. The following table summarizes our PSCR reconciliation filing currently pending with the MPSC:

Power Supply Cost Recovery Reconciliation

PSCR		Net Under-	PSCR Cost of
Year	Date Filed	recovery	Power Sold	Description of Net Underrecovery
2007	March 2008	$42 million (a)	$1.628 billion	Underrecovery relates primarily to the removal of $44 million of Palisades sale proceeds credits from the PSCR. The MPSC directed that we refund these credits through a separate surcharge instead of as a reduction of power supply costs.

(a) This amount includes 2006 underrecoveries as allowed by the MPSC order in our 2007 PSCR plan case.

2006 PSCR Reconciliation: Our 2006 PSCR reconciliation resulted in a $56 million underrecovery. The April 2008 MPSC order disallowed $6 million related to certain replacement power costs and the recovery of discount credits provided to certain customers. As a result, we reduced our Accrued power supply revenue for the period ended March 31, 2008 for this amount. The MPSC order also addressed the allocation of our proceeds from the sale of sulfur dioxide allowances of $62 million. The MPSC order directed us to credit $44 million of the proceeds to PSCR customers and allowed us to retain $18 million of the proceeds. We previously reserved all proceeds as a regulatory liability. As a result of the MPSC order, we recognized our retained portion in earnings for the period ended March 31, 2008.

2007 PSCR Plan: In April 2008, the MPSC issued an order allowing us to continue to use our 2007 PSCR monthly factor as approved in its temporary order, with minor adjustments. The order also allowed us to include prior year underrecoveries and overrecoveries in future PSCR plans as prescribed in the temporary order. Furthermore, the MPSC order directed us to allocate the proceeds from the sale of sulfur dioxide allowances to PSCR customers in the manner approved in the 2006 PSCR reconciliation case.

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2008 PSCR Plan: In September 2007, we submitted our 2008 PSCR plan filing to the MPSC. The plan includes recovery of 2007 PSCR underrecoveries, which were $42 million. We self-implemented a 2008 PSCR charge in January 2008. In June 2008, the ALJ issued a Proposal for Decision that is consistent with our position, with minor exceptions.

2009 PSCR Plan: In September 2008, we submitted our 2009 PSCR plan filing to the MPSC. We expect to self-implement the proposed 2008 PSCR charge in January 2009, absent action by the MPSC by the end of 2008.

While we expect to recover fully all of our PSCR costs, we cannot predict the financial impact or the outcome of these proceedings. When we are unable to collect these costs as they are incurred, there is a negative impact on our cash flows.

Electric Rate Case: During 2007, we filed applications with the MPSC, as revised, seeking an annual increase in revenue of $265 million, which incorporated a requested 11.25 percent authorized return on equity. The filings sought recovery of the costs associated with increased plant investment, including the purchase of the Zeeland power plant, increased equity investment, higher operation and maintenance expenses, recovery of transaction costs from the sale of Palisades, and the approval of an energy efficiency program. In June 2008, the MPSC issued an order authorizing us to increase revenue by $221 million. This was lower than our revised position primarily due to the MPSC’s authorized return on equity of 10.7 percent and the final determination of our Zeeland plant revenue requirement. The MPSC order further instructed that we absorb $2 million of the Palisades sale transaction costs and that we exclude the energy efficiency surcharge from base rates until pending legislation regarding energy efficiency programs is completed. The legislation was enacted in October 2008 and it established separate procedures for implementation of energy efficiency programs outside of base rates.

The following table summarizes the components of the requested increase in revenue and the MPSC order:

In Millions
	Consumers			MPSC
Components of the increase in revenue	Position			Order			Difference
Revenue Sufficiency	$	(21	)	$	(46	)	$	(25	)
Zeeland Plant Requirement		86			74			(12	)
Base Rates Total		65			28			(37	)
Eliminate Palisades Recovery Credit in PSCR (a)		167			167			—
Palisades Sale Transaction Cost Surcharge		28			26			(2	)
Energy Efficiency Surcharge		5			—			(5	)
Total	$	265		$	221		$	(44	)

(a)  Palisades power purchase agreement costs in the PSCR were offset through a base rate recovery credit until the MPSC order discontinued and removed the Palisades costs from base rates.

When we are unable to include increased costs and investments in rates in a timely manner, there is a negative impact on our cash flows.

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Palisades Regulatory Proceedings: The MPSC order approving the Palisades sale transaction requires that we credit $255 million of excess sales proceeds and decommissioning amounts to our retail customers by December 2008. There are additional excess sales proceeds and decommissioning fund balances of $135 million above the amount in the MPSC order. The MPSC order in our electric rate case instructed us to offset the excess sales proceeds and decommissioning fund balances with $26 million of transaction costs from the Palisades sale and credit the remaining balance to customers. The distribution of these funds is still pending with the MPSC.

OTHER ELECTRIC CONTINGENCIES

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-year power purchase agreement that began in 1990. Prior to September 2007, the cost that we incurred under the MCV PPA exceeded the recovery amount allowed by the MPSC. Pursuant to a regulatory-out provision in the contract, effective September 2007, we provided notice that we intended to limit our capacity and fixed energy payments to the MCV Partnership to the amount that we collect from our customers. As a result, the MCV Partnership filed an application with the MPSC requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed energy charges that we were allowed to recover from our customers.

In June 2008, the MPSC approved an amended and restated MCV PPA entered into as part of a settlement agreement among us and other parties to an MPSC proceeding initiated by the MCV Partnership. The amended and restated MCV PPA, which took effect in October 2008, effectively eliminates the 88.7 percent availability cap and the resultant mismatch between the payments to the MCV Partnership and the amount that we collect from our customers. The amended and restated MCV PPA provides for:

• a capacity charge of $10.14 per MWh of available capacity,

• a fixed energy charge based on our annual average base load coal generating plant operating and maintenance cost,

• a variable energy charge for all delivered energy that reflects the MCV Partnership’s cost of production,

• the elimination of the RCP, but continues the $5 million annual contribution by the MCV Partnership to a renewable resources program, and

• an option for us to extend the MCV PPA for five years or purchase the MCV Facility at the conclusion of the MCV PPA’s term in March 2025.

As a part of the amended and restated MCV PPA, the MCV Partnership agreed not to contest our exercise of the regulatory-out provision in the original MCV PPA.

Nuclear Matters: DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE was to begin accepting deliveries of spent nuclear fuel for disposal by January 1998. Subsequent U.S. Court of Appeals litigation, in which we and other utilities participated, has not been successful in producing more specific relief for the DOE’s failure to accept the spent nuclear fuel.

A number of court decisions support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. We filed our complaint in December 2002. If our litigation against the DOE is successful, we plan to use any recoveries as reimbursement for the incurred costs of spent nuclear fuel storage during our ownership of Palisades and Big Rock. We cannot predict the financial impact or outcome of this matter. The sale of Palisades and the Big Rock ISFSI did not transfer the right to any recoveries from the DOE related to costs of spent nuclear fuel storage incurred during our ownership of Palisades and Big Rock.

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Big Rock Decommissioning: The MPSC and the FERC regulate the recovery of costs to decommission Big Rock. In December 2000, funding of a Big Rock trust fund ended because the MPSC-authorized decommissioning surcharge collection period expired. The level of funds provided by the trust fell short of the amount needed to complete decommissioning. As a result, we provided $44 million of corporate contributions for decommissioning costs. This amount is in addition to the $30 million payment to Entergy to assume ownership and responsibility for the Big Rock ISFSI and additional corporate contributions for nuclear fuel storage costs of $55 million, due to the DOE’s failure to accept spent nuclear fuel on schedule. We have a $129 million regulatory asset recorded on our Consolidated Balance Sheets for these costs.

In July 2008, we filed an application with the MPSC seeking the deferral of ratemaking treatment regarding the recovery of our nuclear fuel storage costs and the payment to Entergy, until the litigation regarding these costs is resolved in the federal courts. In the application, we also are seeking to recover the $44 million Big Rock decommissioning shortfall from customers. We cannot predict the outcome of this proceeding.

Nuclear Fuel Disposal Cost: We deferred payment for disposal of spent nuclear fuel used before April 7, 1983. Our DOE liability is $162 million at September 30, 2008. This amount includes interest, and is payable upon the first delivery of spent nuclear fuel to the DOE. We recovered the amount of this liability, excluding a portion of interest, through electric rates. In conjunction with the sale of Palisades and the Big Rock ISFSI, we retained this obligation and provided a $155 million letter of credit to Entergy as security for this obligation.

GAS CONTINGENCIES

Gas Environmental Matters: We expect to incur investigation and remediation costs at a number of sites under the NREPA, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In December 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represented a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through proceeds from insurance settlements and MPSC-approved rates.

From January 1, 2006 to September 30, 2008, we have spent a total of $14 million for MGP response activities. At September 30, 2008, we have a liability of $15 million and a regulatory asset of $46 million, which includes $31 million of deferred MGP expenditures. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. We expect annual response activity costs to range between $4 million and $5 million over the next four years. Periodically, we review these response activity cost estimates. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of response activity costs and the timing of our payments.

Gas Title Transfer Tracking Fees and Services: In November 2007, we reached an agreement in principle with Duke Energy Corporation, Dynegy Incorporated, Reliant Energy Resources Incorporated and the FERC Staff to settle the TTT proceeding. The terms of the agreement include the payment of $2 million in total refunds to all TTT customers and a reduced rate for future TTT transactions. The settlement agreement was filed on February 1, 2008. The FERC conditionally approved the settlement

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on July 28, 2008.

FERC Investigation: In February 2008, we received a data request relating to an investigation the FERC is conducting into possible violations of the FERC’s posting and competitive bidding regulations related to releases of firm capacity on natural gas pipelines. We responded to the FERC’s first data request in the first quarter of 2008. In July 2008, we responded to a second set of data requests from the FERC. The FERC has also taken depositions from two Consumers employees and made an additional data request. We cannot predict the financial impact or the outcome of this matter.

GAS RATE MATTERS

Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudence in annual plan and reconciliation proceedings.

The following table summarizes our GCR reconciliation filings currently pending with the MPSC:

Gas Cost Recovery Reconciliation

		Net Over-	GCR Cost of Gas
GCR Year	Date Filed	recovery	Sold	Description of Net Overrecovery
2007-2008	June 2008	$17 million	$1.7 billion	The total amount reflects an overrecovery of $15 million plus $2 million in accrued interest owed to customers.

GCR Reconciliation for 2006-2007: In July 2008, the MPSC issued an order approving our GCR Reconciliation for the GCR plan period of April 1, 2006 to March 31, 2007. The total amount reflects an overrecovery of $1 million plus $4 million in accrued interest owed to customers.

GCR plan for year 2007-2008: In July 2007, the MPSC issued an order for our 2007-2008 GCR plan year. The order approved a settlement agreement that allowed a base GCR ceiling factor of $8.47 per mcf for April 2007 through March 2008, subject to a quarterly ceiling price adjustment mechanism. We were able to maintain our GCR billing factor below the authorized level.

GCR plan for year 2008-2009: In December 2007, we filed an application with the MPSC seeking approval of a GCR plan for our 2008-2009 GCR Plan year. Our request proposed the use of a base GCR ceiling factor of $8.17 per mcf, plus a quarterly GCR ceiling price adjustment contingent upon future events.

Due to an increase in NYMEX gas prices, the base GCR ceiling factor increased to $9.52 per mcf for the three-month period of April through June 2008 and to $9.92 for the three-month period of July through September 2008, pursuant to the quarterly ceiling price adjustment mechanism. Beginning in October 2008, the base GCR ceiling factor was adjusted to $8.17 due to a decrease in NYMEX gas prices.

The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor for November 2008 is $8.17 per mcf. When we are unable to collect GCR costs as they are incurred, there is a negative impact on our cash flows.

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

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million based on an 11 percent authorized return on equity. The MPSC staff and intervenors filed testimony in September 2008. The MPSC staff recommended an increase of $36 million based on a 10.45 percent authorized return on equity.

OTHER CONTINGENCIES

Guarantees and Indemnifications: FIN 45 requires a guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee. To measure the fair value of a guarantee liability, we recognize a liability for any premium received or receivable in exchange for the guarantee. For a guarantee issued as part of a larger transaction, such as in association with an asset sale or executory contract, we recognize a liability for any premium that would have been received had the guarantee been issued as a single item.

The following table describes our guarantees at September 30, 2008:

In Millions
		Expiration	Maximum
Guarantee Description	Issue Date	Date	Obligation
Surety bonds and other indemnifications	Various	Various	$	—	(a)
Guarantee	January 1987	March 2016		85	(b)

(a)

In the normal course of business, we issue surety bonds and indemnities to third parties to facilitate commercial transactions. We would be required to pay a counterparty if it incurs losses due to a breach of contract terms or nonperformance under the contract. At September 30, 2008, the guarantee liability recorded for surety bonds and indemnities was immaterial. The maximum obligation for surety bonds and indemnities was less than $1 million.

(b)

The maximum obligation includes $85 million related to the MCV Partnership’s non-performance under a steam and electric power agreement with Dow. We sold our interests in the MCV Partnership and the FMLP. The sales agreement calls for the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments, to pay $85 million, subject to certain reimbursement rights, if Dow terminates an agreement under which the MCV Partnership provides it steam and electric power. This agreement expires in March 2016, subject to certain terms and conditions. The purchaser secured its reimbursement obligation with an irrevocable letter of credit of up to $85 million.

We also enter into various agreements containing tax and other indemnification provisions for which we are unable to estimate the maximum potential obligation. We consider the likelihood that we would be required to perform or incur significant losses related to these indemnities to be remote.

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Other: In addition to the matters disclosed within this Note, we are party to certain lawsuits and administrative proceedings before various courts and governmental agencies arising from the ordinary course of business. These lawsuits and proceedings may involve personal injury, property damage, contractual matters, environmental issues, federal and state taxes, rates, licensing, and other matters.

5: Financings and Capitalization

Long-term debt is summarized as follows:

In Millions
	September 30, 2008			December 31, 2007
First mortgage bonds	$	3,518		$	3,170
Senior notes and other		503			659
Securitization bonds		286			309
Principal amounts outstanding		4,307			4,138
Current amounts		(383	)		(440	)
Net unamortized discount		(6	)		(6	)
Total Long-term debt	$	3,918		$	3,692

Financings: The following is a summary of significant long-term debt transactions during the nine months ended September 30, 2008:

	Principal		Interest			Issue/Retirement
	(in millions)		Rate (%)			Date	Maturity Date
Debt Issuances:
First mortgage bonds	$	250		5.650	%	March 2008	September 2018
Tax-exempt bonds (a)		28		4.250	%	March 2008	June 2010
Tax-exempt bonds (b)		68	Variable			March 2008	April 2018
First mortgage bonds		350		6.125	%	September 2008	March 2019
Total	$	696
Debt Retirements:
Senior notes	$	159		6.375	%	February 2008	February 2008
First mortgage bonds		250		4.250	%	April 2008	April 2008
Tax-exempt bonds (a)		28	Variable			April 2008	June 2010
Tax-exempt bonds (b)		68	Variable			April 2008	April 2018
Total	$	505

(a)

In March 2008, we utilized the Michigan Strategic Fund for the issuance of $28 million of tax-exempt Michigan Strategic Fund Limited Obligation Refunding Revenue Bonds, bearing interest at a 4.25 percent annual rate. The bonds are secured by FMBs. The proceeds were used for the April 2008 redemption of $28 million of insured tax-exempt bonds.

(b)

In March 2008, we utilized the Michigan Strategic Fund for the issuance of $68 million of tax-exempt Michigan Strategic Fund Variable Rate Limited Obligation Refunding Revenue Bonds. The initial interest rate was 2.25 percent and it resets weekly. The bonds, which are backed by a letter of credit, are subject to optional tender by the holders that would result in remarketing. The proceeds were used for the April 2008 redemption of $68 million of insured tax-exempt bonds.

In April 2008, we caused the conversion of $35 million of tax-exempt Michigan Strategic Fund Variable Rate Limited Obligation Revenue Bonds from insured bonds to demand bonds, backed by a letter of credit.

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The Michigan Strategic Fund is housed within the Michigan Department of Treasury to provide public and private development finance opportunities for agriculture, forestry, business, industry and communities within the State of Michigan.

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at September 30, 2008:

In Millions
					Outstanding Letters
Expiration Date	Amount of Facility		Amount Borrowed		of Credit		Amount Available
March 30, 2012	$	500	$	—	$	127	$	373
November 30, 2009 (a)		200		—		185		15
September 9, 2009		150		—		—		150

(a) Secured revolving letter of credit facility. Effective November 30, 2008, this commitment will be reduced to $192 million.

Dividend Restrictions: Under the provisions of our articles of incorporation, at September 30, 2008, we had $293 million of unrestricted retained earnings available to pay common stock dividends. For the nine months ended September 30, 2008, we paid $238 million of common stock dividends to CMS Energy.

6: Financial and Derivative Instruments

Financial Instruments: The summary of our available-for-sale investment securities is as follows:

In Millions
	September 30, 2008									December 31, 2007
	Cost		Unrealized Gains		Unrealized Losses			Fair Value		Cost		Unrealized Gains		Unrealized Losses		Fair Value
Common stock of CMS Energy	$	8	$	15	$	—		$	23	$	8	$	24	$	—	$	32
SERP:
Equity securities		32		—		—			32		35		—		—		35
Debt securities		20		—		(1	)		19		7		—		—		7

Equity securities consist of an investment in a Standard & Poor’s 500 Index mutual fund. Debt securities consist of investment grade municipal bonds.

During 2008, our SERP investment in equity securities experienced a decline in fair value to $32 million. In the third quarter of 2008, we determined that this decline in fair value was other than temporary. Accordingly, we reclassified net unrealized losses of $9 million ($6 million, net of tax) from AOCI into Other expense in the Consolidated Statements of Income and established a new cost basis of $32 million for these investments, which was equal to fair value at September 30, 2008.

Derivative Instruments: In order to limit our exposure to certain market risks, primarily changes in interest rates, foreign currency exchange rates, and commodity prices, we may enter into various risk management contracts, such as swaps, options, and forward contracts. We enter into these contracts

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using established policies and procedures, under the direction of an executive oversight committee consisting of senior management representatives and a risk committee consisting of business unit managers.

The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative accounting under SFAS No. 133. If a contract is a derivative and does not qualify for the normal purchases and sales exception under SFAS No. 133, we record it on our consolidated balance sheet at its fair value. Each quarter, we adjust the resulting asset or liability to reflect any change in the fair value of the contract, a practice known as marking the contract to market. Since we have not designated any of our derivatives as accounting hedges under SFAS No. 133, we report all mark-to-market gains and losses in earnings.

Most of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:

• they do not have a notional amount (that is, a number of units specified in a derivative instrument, such as MWh of electricity or bcf of natural gas),

• they qualify for the normal purchases and sales exception, or

• there is not an active market for the commodity.

Our coal purchase contracts are not derivatives because there is not an active market for the coal we purchase. If an active market for coal develops in the future, some of these contracts may qualify as derivatives. Under regulatory accounting, the resulting mark-to-market gains and losses would be offset by changes in regulatory assets and liabilities and would not affect net income.

At September 30, 2008, the fair value of our derivative contracts was immaterial.

7: Retirement Benefits

We provide retirement benefits to our employees under a number of plans, including:

• a non-contributory, qualified defined benefit Pension Plan (closed to new non-union participants as of July 1, 2003 and closed to new union participants as of September 1, 2005),

• a qualified cash balance Pension Plan for certain employees hired between July 1, 2003 and August 31, 2005,

• a non-contributory, qualified DCCP for employees hired on or after September 1, 2005,

• benefits to certain management employees under a non-contributory, nonqualified defined benefit SERP (closed to new participants as of March 31, 2006),

• benefits to certain management employees under a non-contributory, nonqualified DC SERP hired on or after April 1, 2006,

• health care and life insurance benefits under OPEB,

• benefits to a selected group of management under a non-contributory, nonqualified EISP, and

• a contributory, qualified defined contribution 401(k) plan.

Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of our affiliate, and Panhandle, a former subsidiary. The Pension Plan’s assets are not distinguishable by company.

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

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SFAS No. 158. This standard required us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 also required us to recognize changes in the funded status of our plans in the year in which the changes occur. In addition, the standard requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. In the first quarter of 2008, we recorded the measurement date change, which resulted in a $6 million net-of-tax decrease to retained earnings, a $4 million reduction to the SFAS No. 158 regulatory assets, a $7 million increase in Postretirement benefit liabilities, and a $5 million increase in Deferred tax assets on our Consolidated Balance Sheets.

In April 2008, the MPSC issued an order in our PSCR case that allowed us to collect a one-time surcharge under a pension and OPEB equalization mechanism. For the three months ended June 30, 2008, we collected $10 million of pension and $2 million of OPEB surcharge revenue in electric rates. We recorded a reduction of $12 million of equalization regulatory assets on our Consolidated Balance Sheets and an increase of $12 million of expense on our Consolidated Statements of Income. Thus, our collection of the equalization mechanism surcharge had no impact on net income for the three months ended June 30, 2008.

Costs: The following tables recap the costs and other changes in plan assets and benefit obligations incurred in our retirement benefits plans:

In Millions
	Pension
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Service cost	$	10		$	12		$	30		$	35
Interest expense		23			20			69			61
Expected return on plan assets		(20	)		(18	)		(59	)		(56	)
Amortization of:
Net loss		10			11			30			33
Prior service cost		2			1			5			5
Net periodic cost		25			26			75			78
Regulatory adjustment		—			(6	)		4			(14	)
Net periodic cost after regulatory adjustment		$25		$	20		$	79		$	64

In Millions
	OPEB
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008			2007
Service cost	$	6		$	7		$	17		$	20
Interest expense		18			17			54			52
Expected return on plan assets		(16	)		(16	)		(49	)		(47	)
Amortization of:
Net loss		3			6			8			17
Prior service credit		(3	)		(3	)		(8	)		(8	)
Net periodic cost		8			11			22			34
Regulatory adjustment		—			(2	)		3			(5	)
Net periodic cost after regulatory adjustment	$	8		$	9		$	25		$	29

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8: Reportable Segments

Our reportable segments consist of business units defined by the products and services they offer. We evaluate performance based on the net income of each segment. Our two reportable segments are electric utility and gas utility.

The following tables show our financial information by reportable segment:

	In Millions
	Three Months Ended						Nine Months Ended
September 30	2008			2007			2008		2007
Operating Revenue
Electric	$	1,074		$	963		$	2,775	$	2,663
Gas		233			209			1,886		1,811
Total Operating Revenue	$	1,307		$	1,172		$	4,661	$	4,474
Net Income Available to Common Stockholder
Electric	$	108		$	67		$	232	$	158
Gas		(18	)		(8	)		46		53
Other		—			1			1		5
Total Net Income Available to Common Stockholder	$	90		$	60		$	279	$	216

In Millions
	September 30, 2008		December 31, 2007
Assets
Electric (a)	$	8,343	$	8,492
Gas (a)		4,541		4,102
Other		564		807
Total Assets	$	13,448	$	13,401

(a) Amounts include a portion of our other common assets attributable to both the electric and gas utility businesses.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

CMS ENERGY

Quantitative and Qualitative Disclosures about Market Risk is contained in PART I, Item 2. — CMS Energy’s MD&A, which is incorporated by reference herein.

CONSUMERS

Quantitative and Qualitative Disclosures about Market Risk is contained in PART I, Item 2. - Consumers’ MD&A, which is incorporated by reference herein.

Item 4. Controls and Procedures

CMS ENERGY

Disclosure Controls and Procedures: CMS Energy’s management, with the participation of its CEO and CFO, has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, CMS Energy’s CEO and CFO have concluded that, as of the end of such period, its disclosure controls and procedures are effective.

Internal Control over Financial Reporting: In July 2008, CMS Energy implemented an integrated business software system. The new system is a process improvement initiative designed to improve business effectiveness and the overall system of internal control over financial reporting through further automation and integration of processes. This initiative was considerable in scale and complexity, and has resulted in significant changes in CMS Energy’s internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

Item 4T. Controls and Procedures

CONSUMERS

Disclosure Controls and Procedures: Consumers’ management, with the participation of its CEO and CFO, has evaluated the effectiveness of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this report. Based on such evaluation, Consumers’ CEO and CFO have concluded that, as of the end of such period, its disclosure controls and procedures are effective.

Internal Control over Financial Reporting: In July 2008, Consumers implemented an integrated business software system. The new system is a process improvement initiative designed to improve business effectiveness and the overall system of internal control over financial reporting through further automation and integration of processes. This initiative was considerable in scale and complexity, and has resulted in significant changes in Consumers’ internal control over financial reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

The discussion below is limited to an update of developments that have occurred in various judicial and administrative proceedings, many of which are more fully described in CMS Energy’s and Consumers’ Forms 10-K for the year ended December 31, 2007 and Forms 10-Q for the quarters ended March 31, 2008 and June 30, 2008. Reference is also made to the NOTES TO CONSOLIDATED FINANCIAL STATEMENTS, in particular, Note 4, Contingencies, for CMS Energy and Note 4, Contingencies, for Consumers, included herein for additional information regarding various pending administrative and judicial proceedings involving rate, operating, regulatory and environmental matters.

CMS ENERGY

GAS INDEX PRICE REPORTING LITIGATION

Texas-Ohio Energy, Inc. filed a putative class action lawsuit in the United States District Court for the Eastern District of California in November 2003 against a number of energy companies engaged in the sale of natural gas in the United States (including CMS Energy). The complaint alleged defendants entered into a price-fixing scheme by engaging in activities to manipulate the price of natural gas in California. The complaint alleged violations of the federal Sherman Act, the California Cartwright Act, and the California Business and Professions Code relating to unlawful, unfair and deceptive business practices. The complaint sought both actual and exemplary damages for alleged overcharges, attorneys’ fees and injunctive relief regulating defendants’ future conduct relating to pricing and price reporting. In April 2004, a Nevada MDL panel ordered the transfer of the Texas-Ohio case to a pending MDL matter in the Nevada federal district court that at the time involved seven complaints originally filed in various state courts in California that made similar allegations. The court granted the defendants’ motion to dismiss on the basis of the “filed rate doctrine“and entered a judgment in favor of the defendants on April 11, 2005. Texas-Ohio appealed the dismissal to the Ninth Circuit Court of Appeals.

While that appeal was pending, CMS Energy agreed to settle the Texas-Ohio case and three other cases originally filed in California federal courts (Fairhaven, Abelman Art Glass and Utility savings), for a total payment of $700,000. On September 10, 2007, the court entered an order granting final approval of the settlement and dismissing the CMS Energy defendants from these cases. On September 26, 2007, the Ninth Circuit Court of Appeals reversed and remanded the case to the federal district court. While CMS Energy is no longer a party to the Texas-Ohio case, the Ninth Circuit Court of Appeals’ ruling may affect the positions of CMS Energy entities in other pending cases, as it did in the Leggett case discussed below.

Commencing in or about February 2004, 15 state law complaints containing allegations similar to those made in the Texas-Ohio case, but generally limited to the California Cartwright Act and unjust enrichment, were filed in various California state courts against many of the same defendants named in the federal price manipulation cases discussed in the preceding paragraphs. In addition to CMS Energy, CMS MST is named in all 15 state law complaints. Cantera Gas Company and Cantera Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in all but one complaint.

In February 2005, these 15 separate actions, as well as nine other similar actions that were filed in California state court but do not name CMS Energy or any of its former or current subsidiaries, were ordered coordinated with pending coordinated proceedings in the San Diego Superior Court. The 24 state court complaints involving price reporting were coordinated as Natural Gas Antitrust Cases V. Plaintiffs in Natural Gas Antitrust Cases V were ordered to file a consolidated complaint, but a consolidated complaint was filed only for the two putative class action lawsuits. Pursuant to a ruling dated August 23, 2006, CMS Energy, Cantera Gas Company and Cantera Natural Gas, LLC were dismissed as defendants in the master class action and the 13 non-class actions, due to lack of personal jurisdiction. In September 2006, CMS MST reached an agreement in principle to settle the master class action for $7

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million. In March 2007, CMS Energy paid $7 million into a trust fund account following preliminary approval of the settlement by the judge. On June 12, 2007, the court entered a judgment, final order and decree granting final approval to the class action settlement with CMS MST. Certain of the individual cases filed in the California State Court remain pending against CMS MST.

Samuel D. Leggett, et al. v. Duke Energy Corporation, et al., a class action complaint brought on behalf of retail and business purchasers of natural gas in Tennessee, was filed in the Chancery Court of Fayette County, Tennessee in January 2005. The complaint contains claims for violations of the Tennessee Trade Practices Act based upon allegations of false reporting of price information by defendants to publications that compile and publish indices of natural gas prices for various natural gas hubs. The complaint seeks statutory full consideration damages and attorneys’ fees and injunctive relief regulating defendants’ future conduct. The defendants include CMS Energy, CMS MST and CMS Field Services. On February 2, 2007, the state court granted defendants’ motion to dismiss the complaint. Plaintiffs filed a notice of appeal on April 4, 2007. Oral arguments were heard on November 8, 2007. On October 29, 2008, the appellate court reversed the trial court and remanded the case for further proceedings, finding that the trial court had mis-applied the filed rate doctrine.

J.P. Morgan Trust Company, in its capacity as Trustee of the FLI Liquidating Trust, filed an action in Kansas state court in August 2005 against a number of energy companies, including CMS Energy, CMS MST and CMS Field Services. The complaint alleges various claims under the Kansas Restraint of Trade Act relating to reporting false natural gas trade information to publications that report trade information. Plaintiff is seeking statutory full consideration damages for its purchases of natural gas between January 1, 2000 and December 31, 2001. The case was removed to the United States District Court for the District of Kansas on September 8, 2005 and transferred to the MDL proceeding on October 13, 2005. CMS Energy filed a motion to dismiss for lack of personal jurisdiction, which was initially granted on December 18, 2006. The court later reversed its ruling on reconsideration and allowed plaintiffs personal jurisdiction discovery. On September 7, 2007, CMS MST and CMS Field Services filed an answer to the complaint. CMS Energy has renewed its motion to dismiss for lack of personal jurisdiction, and is awaiting the court’s decision. On September 26, 2008, Defendants filed a motion for judgment on the pleadings on the ground that the claims are barred by implied antitrust immunity arising from the Commodity Exchange Act.

On November 20, 2005, CMS MST was served with a summons and complaint which named CMS Energy, CMS MST and CMS Field Services as defendants in a putative class action filed in Kansas state court, Learjet, Inc., et al. v. Oneok, Inc., et al. Similar to the other actions that have been filed, the complaint alleges that during the putative class period, January 1, 2000 through October 31, 2002, defendants engaged in a scheme to violate the Kansas Restraint of Trade Act by knowingly reporting false or inaccurate information to the publications, thereby affecting the market price of natural gas. Plaintiffs, who allege they purchased natural gas from defendants and others for their facilities, are seeking statutory full consideration damages consisting of the full consideration paid by plaintiffs for natural gas. On December 7, 2005, the case was removed to the United States District Court for the District of Kansas and later transferred to the MDL proceeding. On September 7, 2007, the CMS MST and CMS Field Services filed an answer to the complaint. CMS Energy has a pending motion to dismiss for lack of personal jurisdiction and is awaiting the court’s decision. On September 26, 2008, Defendants filed a motion for judgment on the pleadings on the ground that the claims are barred by implied antitrust immunity arising from the Commodity Exchange Act. Plaintiffs filed their motion for class certification on October 17, 2008. On October 27, 2008, Defendants filed a second motion for judgment on the pleadings on statute of limitations grounds.

Breckenridge Brewery of Colorado, LLC and BBD Acquisition Co. v. Oneok, Inc., et al., a class action complaint brought on behalf of retail direct purchasers of natural gas in Colorado, was filed in Colorado state court in May 2006. Defendants, including CMS Energy, CMS Field Services, and CMS MST, are alleged to have violated the Colorado Antitrust Act of 1992 in connection with their natural gas price reporting activities. Plaintiffs are seeking full refund damages. The case was removed to the United States

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District Court for the District of Colorado on June 12, 2006, and later transferred to the MDL proceeding. CMS Energy filed a motion to dismiss for lack of personal jurisdiction, which was initially granted. The court later reversed its ruling on reconsideration and allowed plaintiffs personal jurisdiction discovery. CMS Energy has re-filed its personal jurisdiction motion and is awaiting the court’s decision. The remaining CMS Energy defendants filed a summary judgment motion which the court granted in March 2008 on the basis that the named plaintiffs made no natural gas purchases from any named defendant. Plaintiffs requested reconsideration and the court ordered further briefing which was done. We are awaiting the court’s decision on reconsideration. On September 26, 2008, Defendants filed a motion for judgment on the pleadings on the ground that the claims are barred by implied antitrust immunity arising from the Commodity Exchange Act. Plaintiffs filed their motion for class certification on October 17, 2008.

On October 30, 2006, CMS Energy and CMS MST were each served with a summons and complaint which named CMS Energy, CMS MST and CMS Field Services as defendants in an action filed in Missouri state court, titled Missouri Public Service Commission v. Oneok, Inc. The Missouri Public Service Commission purportedly is acting as an assignee of six local distribution companies, and it alleges that from at least January 2000 through at least October 2002, defendants knowingly reported false natural gas prices to publications that compile and publish indices of natural gas prices, and engaged in wash sales. The complaint contains claims for violation of the Missouri Anti-Trust Law, fraud and unjust enrichment. Defendants removed the case to Missouri federal court and then transferred it to the Nevada MDL proceeding. On October 30, 2007, the court granted the plaintiff’s motion to remand the case to state court in Missouri. CMS Energy filed a motion to dismiss for lack of personal jurisdiction. Defendants, including CMS MST and CMS Field Services, filed a motion to dismiss for lack of standing.

A class action complaint, Heartland Regional Medical Center, et al. v. Oneok Inc. et al., was filed in Missouri state court in March 2007 alleging violations of Missouri anti-trust laws. Defendants, including CMS Energy, CMS Field Services, and CMS MST, are alleged to have violated the Missouri Anti-Trust Law in connection with their natural gas price reporting activities. The action was removed to Missouri federal court, and later transferred to the MDL proceeding. Plaintiffs filed a motion to remand the case back to state court but later withdrew that motion and filed an amended complaint. CMS Energy filed a motion to dismiss for lack of personal jurisdiction. CMS MST and CMS Field Services filed answers to the amended complaint. On September 26, 2008, Defendants filed a motion for judgment on the pleadings on the ground that the claims are barred by implied antitrust immunity arising from the Commodity Exchange Act. Plaintiffs filed their motion for class certification on October 17, 2008.

A class action complaint, Arandell Corp., et al. v. XCEL Energy Inc., et al., was filed on or about December 15, 2006 in Wisconsin state court on behalf of Wisconsin commercial entities that purchased natural gas between January 1, 2000 and October 31, 2002. Defendants, including CMS Energy, CMS ERM and Cantera Gas Company, LLC, are alleged to have violated Wisconsin’s antitrust statute by conspiring to manipulate natural gas prices. Plaintiffs are seeking full consideration damages, plus exemplary damages in an amount equal to three times the actual damages, and attorneys’ fees. The action was removed to Wisconsin federal district court and later transferred to the MDL proceeding. All of the CMS Energy defendants filed a motion to dismiss for lack of personal jurisdiction, which has been fully briefed. The court has not yet ruled on the motion. On September 26, 2008, Defendants filed a motion for judgment on the pleadings on the ground that the claims are barred by implied antitrust immunity arising from the Commodity Exchange Act. Plaintiffs filed their motion for class certification on October 17, 2008.

CMS Energy and the other CMS Energy defendants will defend themselves vigorously against these matters but cannot predict their outcome.

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ROUND-TRIP TRADING INVESTIGATIONS

From May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These transactions, referred to as round-trip trades, had no impact on previously reported consolidated net income, EPS or cash flows, but had the effect of increasing operating revenues and operating expenses by equal amounts.

CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business.

In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order’s findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. As of June 30, 2008, all three former employees have settled with the SEC.

QUICKSILVER RESOURCES, INC.

On November 1, 2001, Quicksilver sued CMS MST in Texas state court in Fort Worth, Texas for breach of contract in connection with a base contract for the sale and purchase of natural gas. The contract outlines Quicksilver’s agreement to sell, and CMS MST’s agreement to buy, natural gas. Quicksilver believes that it is entitled to more payments for natural gas than it has received. CMS MST disagrees with Quicksilver’s analysis and believes that it has paid all amounts owed for delivery of gas according to the contract. Quicksilver sought damages of up to approximately $126 million, plus prejudgment interest and attorney fees.

The jury verdict awarded Quicksilver zero compensatory damages but $10 million in punitive damages. The jury found that CMS MST breached the contract and committed fraud but found no actual damage related to such a claim.

On May 15, 2007, the trial court vacated the jury award of punitive damages but held that the contract should be rescinded prospectively. The judicial rescission of the contract caused CMS Energy to record a charge in the second quarter of 2007 of $24 million, net of tax. To preserve its appellate rights, CMS MST filed a motion to modify, correct or reform the judgment and a motion for a judgment contrary to the jury verdict with the trial court. The trial court dismissed these motions. CMS MST has filed a notice of appeal with the Texas Court of Appeals. Quicksilver has filed a notice of cross appeal. Both Quicksilver and CMS MST have filed their opening briefs and briefs of cross appeal. Oral arguments were made on October 29, 2008. Quicksilver claims that the contract should be rescinded from its inception, rather than merely from the date of the judgment. Although we believe Quicksilver’s position to be without merit, if the Court were to grant the relief requested by Quicksilver, it could result in a loss in excess of $150 million and have a material adverse effect on us. We cannot predict the financial impact or outcome of this matter.

MARATHON INDEMNITY CLAIM REGARDING F.T. BARR CLAIM

On December 3, 2001, F. T. Barr, an individual with an overriding royalty interest in production from the Alba field, filed a lawsuit in Harris County District Court in Texas against CMS Energy, CMS Oil and Gas Company and other defendants alleging that his overriding royalty payments related to Alba field production were improperly calculated. CMS Oil and Gas believes that Barr was being properly paid on gas sales and that he was, and would not be, entitled to the additional overriding royalty payment sought.

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All parties signed a confidential settlement agreement on April 26, 2004. The settlement resolved claims between Barr and the defendants, and the involved CMS Energy entities reserved all defenses to any indemnity claim relating to the settlement. Issues exist between Marathon and certain current or former CMS Energy entities as to the existence and scope of any indemnity obligations to Marathon in connection with the settlement. Between April 2005 and April 2008, there were no further communications between Marathon and CMS Energy entities regarding this matter. In April 2008, Marathon indicated its intent to pursue the indemnity claim. Present and former CMS Energy entities and Marathon entered into an agreement tolling the statute of limitations on any claim by Marathon under the indemnity. CMS Energy entities dispute Marathon’s claim, and will vigorously oppose it if raised in any legal proceeding. CMS Energy entities also will assert that Marathon has not suffered any damages that would be material to CMS Energy. CMS Energy cannot predict the outcome of this matter. If Marathon’s claim were sustained, it would have a material effect on CMS Energy’s future earnings and cash flow.

ENVIRONMENTAL MATTERS

CMS Energy and Consumers, as well as their subsidiaries and affiliates, are subject to various federal, state and local laws and regulations relating to the environment. Several of these companies have been named parties to various actions involving environmental issues. Based on their present knowledge and subject to future legal and factual developments, they believe it is unlikely that these actions, individually or in total, will have a material adverse effect on their financial condition or future results of operations. For additional information, see both CMS Energy’s and Consumers’ Forms 10-K for the year ended December 31, 2007 — ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Item 1A. Risk Factors

Other than discussed below, there have been no material changes to the Risk Factors as previously disclosed in CMS Energy’s Form 10-K and Consumers’ Form 10-K for the year ended December 31, 2007.

Risk Related to CMS Energy

CMS Energy retains contingent liabilities in connection with its asset sales

The agreements CMS Energy enters into for the sale of assets customarily include provisions whereby it is required to retain specified preexisting liabilities such as for taxes, pensions, or environmental conditions, indemnify the buyers against specified risks, including the inaccuracy of representations and warranties it makes, and make payments to the buyers depending on the outcome of post-closing adjustments, litigation, audits or other reviews. Examples of these situations include claims related to attempts by the governments of Equatorial Guinea and Morocco to assess taxes on past operations or transactions, and F. T. Barr. Many of these contingent liabilities can remain open for extended periods of time after the sales are closed. Depending on the extent to which the buyers may ultimately seek to enforce their rights under these contractual provisions, and the resolution of any disputes CMS Energy may have concerning them, these liabilities could have a material adverse effect on its financial condition, liquidity and future results of operations.

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Risk Related to CMS Energy and Consumers

CMS Energy and Consumers could incur significant capital expenditures to comply with environmental regulations and face difficulty in recovering these costs on a current basis.

We plan to spend $795 million for equipment installation by 2015 to comply with a number of environmental regulations, including regulations limiting nitrogen oxides and sulfur dioxide emissions.

In March 2005, the EPA adopted the CAIR, which required additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. The CAIR was appealed to the U.S. Court of Appeals for the District of Columbia, and in July 2008, the court vacated the CAIR and the CAIR federal implementation plan in their entirety. If upheld, the decision would remand the CAIR back to the EPA to form a new rule, which will likely take considerable time. Several parties have petitioned the court for hearing by the full court. This keeps the CAIR in effect at least until the court decides whether to grant the rehearing. At the same time, Congress is considering legislative options to reinstate all or part of the CAIR.

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

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. If this plan becomes effective, we estimate the associated costs will be approximately $400 million by 2015.

The EPA has alleged that some utilities have incorrectly classified major plant modifications as “routine maintenance, repair and replacement” rather than seeking permits from the EPA to modify their plants. We responded to information requests from the EPA on this subject in 2000, 2002, and 2006. We believe that we have properly interpreted the requirements of “routine maintenance, repair and replacement.” In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. In addition, in October 2008, we received a NOV for three of our coal-fired facilities relating to violations of NSR and PSD regulations, alleging ten projects from 1986 to 1998 were subject to PSD review. We are currently preparing our response to this NOV and the information request. If the EPA does not accept our interpretation, we could be required to install additional pollution control equipment at some or all of our coal-fired electric generating plants and pay fines. Additionally, we would need to assess the viability of continuing operations at certain plants. We cannot predict the financial impact or outcome of this matter.

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, or similar state laws or rules, if enacted, could require us to replace equipment, install additional equipment for emission controls, purchase allowances, curtail operations, or take other steps to manage or lower the emission of greenhouse gases.

In July 2004, the EPA issued rules that govern existing electric generating plant cooling water intake systems. These rules require a significant reduction in the number of fish harmed by intake structures at large existing power plants. The EPA compliance options in the rule were challenged before the United States Court of Appeals for the Second Circuit. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The United States Court of Appeals for the Second Circuit’s ruling is expected to increase significantly the cost of complying with this rule, but we will not know the cost to comply until

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the EPA’s reconsideration is complete. In April 2008, the U.S. Supreme Court agreed to hear this case, thereby extending the time before this issue is finally resolved.

CMS Energy and Consumers expect to collect fully from their customers, through the ratemaking process, these and other required environmental expenditures. Recovery of these environmental expenditures could significantly impact customer rates. However, if these expenditures are not recovered from customers in Consumers’ rates, CMS Energy and/or Consumers may be required to seek significant additional financing to fund these expenditures, which could strain their cash resources. We can give no assurances that CMS Energy and/or Consumers will have access to bank financing or capital markets to fund these environmental expenditures.

Regulatory changes and other developments have resulted and could continue to result in increased competition in the domestic energy business. Generally, increased competition threatens market share in certain segments of CMS Energy’s business and can reduce its and Consumers’ profitability.

Prior to October 2008, the Customer Choice Act allowed all electric customers in Michigan the choice of buying electric generation service from Consumers or an alternative electric supplier. On October 6, 2008, the Customer Choice Act was amended to limit generally the amount of customer load that could purchase generation service from alternative electric suppliers to 10 percent of Consumers’ weather-adjusted sales from the preceding calendar year. At September 30, 2008, alternative electric suppliers were providing 339 MW of generation service to ROA customers. This amount is equivalent to 4 percent of Consumers’ weather-adjusted sales from the preceding calendar year. While Consumers cannot predict the amount of electric supply load that may be lost to competitor suppliers in the future, that amount is now limited.

CMS Energy and Consumers may be adversely affected by regulatory investigations regarding “round-trip” trading by CMS MST.

As a result of round-trip trading transactions (simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price) at CMS MST, CMS Energy is under investigation by the DOJ. CMS Energy received subpoenas in 2002 and 2003 from U.S. Attorneys’ Offices regarding an investigation of those trades. CMS Energy responded to those subpoenas in 2003 and 2004.

In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy relating to round-trip trading. The order did not assess a fine and CMS Energy neither admitted nor denied the order’s findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. As of June 30, 2008, all three former employees have settled with the SEC.

CMS Energy and Consumers cannot predict the outcome of the DOJ investigation. It is possible that the outcome of the investigation could affect adversely CMS Energy’s and Consumers’ financial condition, liquidity or results of operations.

Consumers’ exercise of its regulatory-out rights under the MCV PPA.

The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers under a 35-year power purchase agreement that began in 1990. Prior to September 2007, the cost that Consumers incurred under the MCV PPA exceeded the recovery amount allowed by the MPSC. Pursuant to a regulatory-out provision in the contract, effective September 2007, Consumers provided notice that it intended to limit its capacity and fixed energy payments to the MCV Partnership to the amount that it collects from its customers. The MCV Partnership previously disputed the exercise of regulatory-out rights by Consumers. The MCV Partnership also filed an application with the MPSC requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed energy charges that Consumers was allowed to recover from its customers.

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In June 2008, the MPSC approved an amended and restated MCV PPA entered into as part of a settlement agreement among us and other parties to an MPSC proceeding initiated by the MCV Partnership. The amended and restated MCV PPA, which took effect in October 2008, effectively eliminates the 88.7 percent availability cap and the resultant mismatch between the payments to the MCV Partnership and the amount that Consumers collects from its customers. The amended and restated MCV PPA provides for:

• a capacity charge of $10.14 per MWh of available capacity,

• a fixed energy charge based on Consumers’ annual average base load coal generating plant operating and maintenance cost,

• a variable energy charge for all delivered energy that reflects the MCV Partnership’s cost of production,

• the elimination of the RCP, but continues the $5 million annual contribution by the MCV Partnership to a renewable resources program, and

• an option for us to extend the MCV PPA for five years or purchase the MCV Facility at the conclusion of the MCV PPA’s term in March 2025.

As a part of the amended and restated MCV PPA, the MCV Partnership agrees not to contest Consumers’ exercise of the regulatory-out provision in the original MCV PPA, thus resolving the prior dispute over Consumers’ exercise of regulatory-out rights.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

(c) Issuer Repurchases of Equity Securities

     The table below shows our repurchases of equity securities for the three months ended September 30, 2008:

					Total Number of		Maximum Number of
					Shares		Shares that May Yet
	Total Number				Purchased as Part of		Be Purchased Under
	of Shares		Average Price		Publicly Announced		Publicly Announced
Period	Purchased*		Paid per Share		Plans or Programs		Plans or Programs
July 1, 2008 to July 31, 2008		—	$	—		—		—
August 1, 2008 to August 31, 2008		32,802	$	13.34		—		—
September 1, 2008 to September 30, 2008		1,252	$	13.16		—		—
Total		34,054		—		—		—

* We repurchase certain restricted shares upon vesting under the Performance Incentive Stock Plan from participants in the Performance Incentive Stock Plan, equal to our minimum statutory income tax withholding obligation. Shares repurchased have a value based on the market price on the vesting date.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Submission of Matters to a Vote of Security Holders

None.

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Item 5. Other Information

A shareholder who wishes to submit a proposal for consideration at the CMS Energy 2009 Annual Meeting pursuant to the applicable rules of the SEC must send the proposal to reach CMS Energy’s Corporate Secretary on or before December 12, 2008. In any event, if CMS Energy has not received written notice of any matter to be proposed at that meeting by February 25, 2009, the holders of proxies may use their discretionary voting authority on such matter. The proposals should be addressed to: Corporate Secretary, CMS Energy Corporation, One Energy Plaza, Jackson, MI 49201.

Item 6. Exhibits

(12)(a)  Statement regarding computation of CMS Energy’s Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends

(12)(b)  Statement regarding computation of Consumers’ Ratios of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends

(31)(a)  CMS Energy Corporation’s certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(31)(b)  CMS Energy Corporation’s certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(31)(c)  Consumers Energy Company’s certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(31)(d)  Consumers Energy Company’s certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

(32)(a)  CMS Energy Corporation’s certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

(32)(b)  Consumers Energy Company’s certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. The signature for each undersigned company shall be deemed to relate only to matters having reference to such company or its subsidiary.

	CMS ENERGY CORPORATION (Registrant)
Dated: November 5, 2008	By:	/s/ Thomas J. Webb
		Thomas J. Webb
		Executive Vice President and Chief Financial Officer

	CONSUMERS ENERGY COMPANY (Registrant)
Dated: November 5, 2008	By:	/s/ Thomas J. Webb
		Thomas J. Webb
		Executive Vice President and Chief Financial Officer

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