UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 10-K

[X]

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 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 (A Michigan Corporation) One Energy Plaza, Jackson, Michigan 49201 (517) 788-0550	38-2726431
1-5611	Consumers Energy Company (A Michigan Corporation) One Energy Plaza, Jackson, Michigan 49201 (517) 788-0550	38-0442310

Securities registered pursuant to Section 12(b) of the Act:

		Name of Each Exchange
Registrant	Title of Class	on Which Registered
CMS Energy Corporation	Common Stock, $.01 par value	New York Stock Exchange
Consumers Energy Company	Preferred Stocks, $100 par value: $4.16 Series, $4.50 Series	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the Registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

CMS Energy Corporation: Yes [X] No o Consumers Energy Company: Yes [X] No o

Indicate by check mark if the Registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

CMS Energy Corporation: Yes o No [X] Consumers Energy Company: Yes o No [X]

Indicate by check mark whether the Registrant (1) has 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 Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

CMS Energy Corporation: Yes [X] No o Consumers Energy Company: Yes [X] No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of Registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o

CMS Energy Corporation:

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):

Large accelerated filer x Accelerated filer o Non-accelerated filer o Smaller reporting company o

(Do not check if a smaller reporting company)

Consumers Energy Company:

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):

Large accelerated filer o Accelerated filer o Non-accelerated filer x Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the Registrant is a shell company (as defined in Rule 12b-2 of the Act).

CMS Energy Corporation: Yes o No [X] Consumers Energy Company: Yes o No [X]

The aggregate market value of CMS Energy voting and non-voting common equity held by non-affiliates was $3.344 billion for the 224,418,751 CMS Energy Common Stock shares outstanding on June 30, 2008 based on the closing sale price of $14.90 for CMS Energy Common Stock, as reported by the New York Stock Exchange on such date.

There were 226,623,039 shares of CMS Energy Common Stock outstanding on February 23, 2009. On February 23, 2009, CMS Energy held all voting and non-voting common equity of Consumers.

Documents incorporated by reference: CMS Energy’s proxy statement and Consumers’ information statement relating to the 2009 annual meeting of shareholders to be held May 22, 2009, are incorporated by reference in Part III.

CMS Energy Corporation

And

Consumers Energy Company

Annual Reports on Form 10-K to the Securities and Exchange Commission for the Year Ended

December 31, 2008

This combined Form 10-K is separately filed by CMS Energy Corporation and Consumers Energy Company. Information in this combined Form 10-K 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 CMS Energy Corporation, CMS Enterprises Company or any of CMS Energy Corporation’s other subsidiaries’ (other than Consumers Energy Company and its own subsidiaries (in relevant circumstances)) financial resources or results of operations 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.

TABLE OF CONTENTS

		Page
Glossary		4
PART I:
Item 1.	Business	11
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	33
Item 3.	Legal Proceedings	33
Item 4.	Submission of Matters to a Vote of Security Holders	37
PART II:
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	38
Item 6.	Selected Financial Data	38
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	39
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	39
Item 8.	Financial Statements and Supplementary Data	40
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	CO-1
Item 9A.	Controls and Procedures	CO-1
Item 9A(T).	Controls and Procedures	CO-2
Item 9B.	Other Information	CO-2
PART III:
Item 10.	Directors, Executive Officers and Corporate Governance	CO-3
Item 11.	Executive Compensation	CO-3
Item 12.	Security Ownership of Certain Beneficial Owners and Management Related Stockholder Matters	CO-4
Item 13.	Certain Relationships and Related Transactions, and Director Independence	CO-4
Item 14.	Principal Accountant Fees and Services	CO-4
PART IV:
Item 15.	Exhibits, Financial Statement Schedules	CO-4
EX-3.(B)
EX-3.(D)
EX-4.(F)
EX-10.(B)
EX-10.(L)
EX-10.(M)
EX-10.(N)
EX-10.(P)
EX-10.(R)
EX-10.(S)
EX-10.(T)
EX-10.(TT)
EX-10.(WW)
EX-10.(XX)
EX-12.(A)
EX-12.(B)
EX-21
EX-23(A)
EX-23.(B)
EX-23(C)
EX-23(D)
EX-23.(E)
EX-23(F)
EX-24(A)
EX-24(B)
EX-31.(A)
EX-31.(B)
EX-31.(C)
EX-31.(D)
EX-32.(A)
EX-32.(B)

2

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3

GLOSSARY

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

ABATE	Association of Businesses Advocating Tariff Equity
ABO	Accumulated Benefit Obligation. The liabilities of a pension plan based on service and pay to date. This differs from the Projected Benefit Obligation that is typically disclosed in that it does not reflect expected future salary increases.
AEI	Ashmore Energy International, a non-affiliated company
AFUDC	Allowance for funds used during construction
AMT	Alternative minimum tax
AOC	Administrative Order on Consent
AOCI	Accumulated Other Comprehensive Income
AOCL	Accumulated Other Comprehensive Loss
APB	Accounting Principles Board
APB Opinion No. 18	APB Opinion No. 18, “The Equity Method of Accounting for Investments in Common Stock”
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.
Beeland	Beeland Group LLC, a wholly owned indirect subsidiary of CMS Energy
bcf	Billion cubic feet of gas
Big Rock	Big Rock Point nuclear power plant
Big Rock ISFSI	Big Rock Independent Spent Fuel Storage Installation
Board of Directors	Board of Directors of CMS Energy
Btu	British thermal unit; one Btu equals the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CEO	Chief Executive Officer
CFO	Chief Financial Officer
City gate arrangement	The arrangement made for the point at which a local distribution company physically receives gas from a supplier or pipeline
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 Electric and Gas	CMS Electric & Gas Company, L.L.C., a wholly owned subsidiary of Enterprises
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 wholly owned 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 International Ventures	CMS International Ventures LLC, a subsidiary of Enterprises

4

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 wholly owned subsidiary of Enterprises
CMS Viron	CMS Viron Corporation, a wholly owned subsidiary of CMS ERM
Consumers	Consumers Energy Company, a wholly owned subsidiary of CMS Energy
CPEE	Companhia Paulista de Energia Eletrica, in which CMS International Ventures formerly owned a 94 percent interest
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
Dekatherms/day	A measure of the heat content value of gas per day; one dekatherm/day is equivalent to 1,000,000 British thermal units (Btu) per day
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
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 Capital
Entergy	Entergy Corporation, a non-affiliated company
Enterprises	CMS Enterprises Company, a wholly owned 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
FDIC	Federal Deposit Insurance Corporation
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”

5

FIN 47	FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”
FIN 48	FASB Interpretation No. 48, “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”
First Mortgage Bond Indenture	The indenture dated as of September 1, 1945 between Consumers and The Bank of New York Mellon, as Trustee, and as amended and supplemented
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 132(R)-1	FASB Staff Position on SFAS No. 132(R), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”
FSP FAS 133-1 and FIN 45-4	FASB Staff Position on SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” and FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”
FSP FAS 142-3	FASB Staff Position on SFAS No. 142, “Determination of the Useful Life of Intangible Assets”
FSP FAS 157-3	FASB Staff Position on SFAS No. 157, “Fair Value Measurements”
FSP FIN 39-1	FASB Staff Position on SFAS Interpretation No. 39, “Offsetting of Amounts Related to Certain Contracts”
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
Genesee	Genesee Power Station Limited Partnership
GCR	Gas cost recovery
GWh	Gigawatt hour (a unit of energy equal to one million kilowatt hours)
Grayling	Grayling Generating Station Limited Partnership
HYDRA-CO	HYDRA-CO Enterprises, Inc. a wholly owned subsidiary of Enterprises
ICSID	International Centre for the Settlement of Investment Disputes
IPP	Independent power producer
IRS	Internal Revenue Service
ISFSI	Independent spent fuel storage installation
ITC	Income tax credit
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-based power plant in Morocco, in which CMS Generation formerly owned a 50 percent interest
kilovolts	Thousand volts (unit used to measure the difference in electrical pressure along a current)
kWh	Kilowatt-hour (a unit of energy equal to one thousand watt hours)

6

LS Power Group	LS Power Group, a non-affiliated company
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, each a non-affiliated company
mcf	One thousand cubic feet of gas
MCV Facility	A natural gas-fueled, combined-cycle cogeneration facility operated by the MCV Partnership
MCV GP II	Successor of CMS Midland, Inc., formerly a subsidiary of Consumers that had a 49 percent ownership interest in 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
Midwest Energy Market	An energy market developed by the MISO to provide day-ahead and real-time market information and centralized dispatch for market participants
MISO	Midwest Independent Transmission System Operator, Inc.
MPSC	Michigan Public Service Commission
MRV	Market-Related Value of Plan assets
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
Neyveli	ST-CMS Electric Company Private Ltd., a joint venture power project company located in India, in which CMS International Ventures formerly indirectly owned a 50 percent interest
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
Palisades	Palisades nuclear power plant, formerly owned by Consumers
Panhandle	Panhandle Eastern Pipe Line Company, including its wholly owned 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 Corporation, a non-affiliated company

7

Pension Plan	The trusteed, non-contributory, defined benefit pension plan of Panhandle, Consumers and CMS Energy
Pension Protection Act	The Pension Protection Act of 2006, signed into law on August 17, 2006
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
PUHCA	Public Utility Holding Company Act
PURPA	Public Utility Regulatory Policies Act of 1978
Quicksilver	Quicksilver Resources, Inc., 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
RMRR	Routine maintenance, repair and replacement
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
Securitization	A financing method authorized by statute and approved by the MPSC which allows a utility to sell its right to receive a portion of the rate payments received from its customers for the repayment of securitization bonds issued by a special purpose entity affiliated with such utility
SENECA	Sistema Electrico del Estado Nueva Esparta C.A., a former wholly owned subsidiary of CMS International Ventures
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SFAS No. 13	SFAS No. 13, “Accounting for Leases”
SFAS No. 71	SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation”
SFAS No. 87	SFAS No. 87, “Employers’ Accounting for Pensions”
SFAS No. 98	SFAS No. 98, “Accounting for Leases”
SFAS No. 106	SFAS No. 106, “Employers’ Accounting for Postretirement Benefits Other Than Pensions”
SFAS No. 109	SFAS No. 109, “Accounting for Income Taxes”
SFAS No. 123(R)	SFAS No. 123 (revised 2004), “Share-Based Payments”
SFAS No. 132(R)	SFAS No. 132 (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”
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. 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
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)”

8

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”
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
Supplemental Environmental Programs	Environmentally beneficial projects which a party agrees to undertake as part of the settlement of an enforcement action, but which the party is not otherwise legally required to perform
Takoradi	A 200 MW open-cycle combustion turbine crude oil power plant located in Ghana, in which CMS Generation formerly owned a 90 percent interest
TAQA	Abu Dhabi National Energy Company, a subsidiary of Abu Dhabi Water and Electricity Authority, a non-affiliated company
T.E.S. Filer City	T.E.S. Filer City Station Limited Partnership
TGN	A natural gas transportation and pipeline business located in Argentina, in which CMS Gas Transmission formerly owned a 23.54 percent interest
TNEB	Tamil Nadu Electricity Board, a non-affiliated company
TRAC	Terminal Rental Adjustment Clause, a provision of a leasing agreement which permits or requires the rental price to be adjusted upward or downward by reference to the amount realized by the lessor under the agreement upon sale or other disposition of formerly leased property
Trunkline	CMS Trunkline Gas Company, LLC, formerly a wholly owned subsidiary of CMS Panhandle Holdings, LLC
Trust Preferred Securities	Securities representing an undivided beneficial interest in the assets of statutory business trusts, the interests of which have a preference with respect to certain trust distributions over the interests of either CMS Energy or Consumers, as applicable, as owner of the common beneficial interests of the trusts
TSR	Total shareholder return
Union	Utility Workers Union of America, AFL-CIO
VEBA	VEBA employees’ beneficiary association trusts accounts established to set aside specifically employer contributed assets to pay for future expenses of the OPEB plan
VIE	Variable interest entity
Wolverine	Wolverine Power Supply Cooperative, Inc., a non-affiliated company
Zeeland	A 935 MW gas-based power plant located in Zeeland, Michigan

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10

PART I

ITEM 1. BUSINESS

GENERAL

CMS Energy

CMS Energy was formed in Michigan in 1987 and is an energy company operating primarily in Michigan. It is the parent holding company of several subsidiaries, including Consumers and Enterprises. Consumers is a combination electric and gas utility company that provides electricity and/or natural gas to almost 6.5 million of Michigan’s 10 million residents and serves customers in all 68 counties of Michigan’s Lower Peninsula. Enterprises, through its subsidiaries and equity investments, is engaged primarily in domestic independent power production.

CMS Energy’s consolidated operating revenue was $6.821 billion in 2008, $6.464 billion in 2007, and $6.126 billion in 2006. CMS Energy manages its businesses by the nature of services each provides and operates principally in three business segments: electric utility, gas utility, and enterprises. See BUSINESS SEGMENTS in this Item 1 for further discussion of each segment.

Consumers

Consumers was formed in Michigan in 1968 and is the successor to a corporation organized in Maine in 1910 that conducted business in Michigan from 1915 to 1968. Consumers serves individuals and companies operating in the alternative energy, automotive, metal, chemical and food products industries as well as a diversified group of other industries. In 2008, Consumers served 1.8 million electric customers and 1.7 million gas customers.

Consumers’ consolidated operations account for a majority of CMS Energy’s total assets, income, and operating revenue. Consumers’ consolidated operating revenue was $6.421 billion in 2008, $6.064 billion in 2007, and $5.721 billion in 2006.

Consumers’ rates and certain other aspects of its business are subject to the jurisdiction of the MPSC and the FERC, as described in CMS ENERGY AND CONSUMERS REGULATION in this Item 1.

Consumers’ Properties — General:  Consumers owns its principal properties in fee, except that most electric lines and gas mains are located below public roads or on land owned by others and are accessed by Consumers pursuant to easements and other rights. Almost all of Consumers’ properties are subject to the lien of its First Mortgage Bond Indenture. For additional information on Consumers’ properties, see BUSINESS SEGMENTS — Consumers Electric Utility — Electric Utility Properties, and — Consumers Gas Utility — Gas Utility Properties as described later in this Item 1.

BUSINESS SEGMENTS

CMS Energy Financial Information

For further information with respect to operating revenue, net operating income, and identifiable assets and liabilities attributable to all of CMS Energy’s business segments and operations, see ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — SELECTED FINANCIAL INFORMATION, CONSOLIDATED FINANCIAL STATEMENTS and NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Consumers Financial Information

For further information with respect to operating revenue, net operating income, and identifiable assets and liabilities attributable to Consumers’ electric and gas utility operations, see ITEM 8. CONSUMERS’ FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — SELECTED FINANCIAL INFORMATION, CONSOLIDATED FINANCIAL STATEMENTS and NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

11

Consumers Electric Utility

  Electric Utility Operations

Consumers’ electric utility operating revenue was $3.594 billion in 2008, $3.443 billion in 2007, and $3.302 billion in 2006. Consumers’ electric utility operations include the generation, purchase, distribution and sale of electricity. At year-end 2008, Consumers was authorized to provide electric utility service in 61 of the 68 counties of Michigan’s Lower Peninsula. Principal cities served include Battle Creek, Flint, Grand Rapids, Jackson, Kalamazoo, Midland, Muskegon and Saginaw. Consumers’ electric utility customer base comprises a mix of residential, commercial and diversified industrial customers, the largest segment of which is the automotive industry (which represents four percent of Consumers’ 2008 revenues). Consumers’ electric utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of these customers is not reasonably likely to have a material adverse effect on its financial condition.

Consumers’ electric utility operations are seasonal. The consumption of electric energy typically increases in the summer months, primarily due to the use of air conditioners and other cooling equipment. In 2008, Consumers’ electric deliveries were 39 billion kWh, which included ROA deliveries of 1.5 billion kWh. In 2007, Consumers’ electric deliveries were 39 billion kWh, which included ROA deliveries of 1.4 billion kWh.

Consumers’ 2008 summer peak demand was 7,488 MW excluding ROA loads and 7,705 MW including ROA loads. For the 2007-08 winter period, Consumers’ peak demand was 5,739 MW excluding ROA loads and 5,925 MW including ROA loads. Alternative electric suppliers were providing generation services to ROA customers of 332 MW at December 31, 2008 and 315 MW at December 31, 2007. Consumers had a 13.7 percent Reserve Margin target for summer 2008, which was achieved. Consumers owns or controls, through long-term contract, capacity necessary to supply 96.4 percent of projected firm peak load for summer 2009 and has purchased the remainder from others.

12

  Electric Utility Properties

Generation:  At December 31, 2008, Consumers’ electric generating system consisted of the following:

		2008			2008 Net
		Summer Net			Generation
	Number of Units and Year	Demonstrated			(Millions
Name and Location (Michigan)	Entering Service	Capability (MW)			of kWh)
Coal Generation
J H Campbell 1 & 2 — West Olive	2 Units, 1962-1967		615			3,913
J H Campbell 3 — West Olive	1 Unit, 1980		770	(a)		5,722
D E Karn — Essexville	2 Units, 1959-1961		515			2,073
B C Cobb — Muskegon	2 Units, 1956-1957		312			1,999
J R Whiting — Erie	3 Units, 1952-1953		328			2,211
J C Weadock — Essexville	2 Units, 1955-1958		310			1,783
Total coal generation			2,850			17,701
Oil/Gas Generation
B C Cobb — Muskegon	3 Units, 1999-2000(b)		183			—
D E Karn — Essexville	2 Units, 1975-1977		1,276			75
Zeeland — Zeeland	1 Unit, 2002		538			552
Total oil/gas generation			1,997			627
Hydroelectric
Conventional Hydro Generation	13 Plants, 1906-1949		73			454
Ludington	6 Units, 1973		955	(c)		(382	)(d)
Total hydroelectric			1,028			72
Gas/Oil Combustion Turbine
Various Plants	7 Plants, 1966-1971		331			8
Zeeland — Zeeland	2 Units, 2001		330			210
Total gas/oil combustion turbine			661			218
Total owned generation			6,536			18,618
Purchased and Interchange Power(e)			3,050	(f)		20,296	(g)
Total			9,586			38,914

(a)  Represents Consumers’ share of the capacity of the J H Campbell 3 unit, net of the 6.69 percent ownership interest of the Michigan Public Power Agency and Wolverine.

(b)	Cobb 1-3 are retired coal-based units that were converted to gas-based. Units were placed back into service in the years indicated.
(c)	Represents Consumers’ 51 percent share of the capacity of Ludington. Detroit Edison owns 49 percent.
(d)	Represents Consumers’ share of net pumped storage generation. This facility electrically pumps water during off-peak hours for storage to generate electricity later during peak-demand hours.
(e)	Includes purchases from the Midwest Energy Market, long-term purchase contracts, options, spot market and other seasonal purchases.
(f)	Includes 1,240 MW of purchased contract capacity from the MCV Facility and 778 MW of purchased contract capacity from the Palisades plant.
(g)	Includes 6,837 million kWh of purchased energy from the Palisades plant and 3,789 million kWh of purchased energy from the MCV Facility.

Distribution: Consumers’ distribution system includes:

•  398 miles of high-voltage distribution radial lines operating at 120 kilovolts or above;

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•  4,238 miles of high-voltage distribution overhead lines operating at 23 kilovolts and 46 kilovolts;

•  17 subsurface miles of high-voltage distribution underground lines operating at 23 kilovolts and 46 kilovolts;

•  55,734 miles of electric distribution overhead lines;

•  9,872 miles of underground distribution lines; and

•  substations having an aggregate transformer capacity of 23,400,170 kilovoltamperes.

Consumers is interconnected to METC. METC owns an interstate high-voltage electric transmission system in Michigan and is interconnected with neighboring utilities as well as other transmission systems.

Fuel Supply: As shown in the following table, Consumers generated electricity primarily from coal and from its former ownership in nuclear power.

	Millions of kWh
Power Generated	2008			2007			2006			2005			2004
Coal		17,701			17,903			17,744			19,711			18,810
Nuclear		—			1,781			5,904			6,636			5,346
Oil		41			112			48			225			193
Gas		804			129			161			356			38
Hydro		454			416			485			387			445
Net pumped storage		(382	)		(478	)		(426	)		(516	)		(538	)
Total net generation		18,618			19,863			23,916			26,799			24,294

The cost of all fuels consumed, shown in the following table, fluctuates with the mix of fuel used.

	Cost per Million Btu
Fuel Consumed	2008		2007		2006		2005		2004
Coal	$	2.01	$	2.04	$	2.09	$	1.78	$	1.43
Oil		11.54		8.21		8.68		5.98		4.68
Gas		10.94		10.29		8.92		9.76		10.07
Nuclear		—		0.42		0.24		0.34		0.33
All Fuels(a)		2.47		2.07		1.72		1.64		1.26

(a) Weighted average fuel costs.

Consumers has four generating sites that burn coal. In 2008, these plants produced a combined total of 17,701 million kWh of electricity, which represents 95 percent of the energy produced by Consumers’ plants. These plants burned 9.5 million tons of coal in 2008. On December 31, 2008, Consumers had on hand a 40-day supply of coal.

Consumers has entered into coal supply contracts with various suppliers and associated rail transportation contracts for its coal-based generating plants. Under the terms of these agreements, Consumers is obligated to take physical delivery of the coal and make payment based upon the contract terms. Consumers’ coal supply contracts expire through 2011 and total an estimated $478 million. Its coal transportation contracts expire through 2009 and total an estimated $163 million. Long-term coal supply contracts have accounted for approximately 60 to 90 percent of Consumers’ annual coal requirements over the last 10 years.

At December 31, 2008, Consumers had future unrecognized commitments to purchase capacity and energy under long-term power purchase agreements with various generating plants. These contracts require monthly capacity payments based on the plants’ availability or deliverability. These payments for 2009 through 2030 total an estimated $13.770 billion and average $626 million per year. This amount may vary depending upon plant availability and fuel costs. Consumers is obligated to pay capacity charges based upon the amount of capacity available at a given time, whether or not power is delivered to Consumers.

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Consumers Gas Utility

  Gas Utility Operations

Consumers’ gas utility operating revenue was $2.827 billion in 2008, $2.621 billion in 2007, and $2.374 billion in 2006. Consumers’ gas utility operations purchase, transport, store, distribute and sell natural gas. Consumers is authorized to provide gas utility service in 46 of the 68 counties in Michigan’s Lower Peninsula. Principal cities served include Flint, Jackson, Kalamazoo, Lansing, Pontiac, Saginaw, Macomb, Royal Oak, Howell, and Livonia, where more than 1.5 million of Consumers’ gas customers are located. Consumers’ gas utility operations are not dependent upon a single customer, or even a few customers, and the loss of any one or even a few of these customers is not reasonably likely to have a material adverse effect on its financial condition.

Consumers’ gas utility operations are seasonal. Consumers injects natural gas into storage during the summer months for use during the winter months when the demand for natural gas is higher. Peak demand occurs in the winter due to colder temperatures and the resulting use of heating fuels. In 2008, deliveries of natural gas sold through Consumers’ pipeline and distribution network totaled 344 bcf.

Gas Utility Properties: Consumers’ gas distribution and transmission system located throughout Michigan’s Lower Peninsula consists of:

•  26,451 miles of distribution mains;

•  1,656 miles of transmission lines;

•  7 compressor stations with a total of 159,250 installed horsepower; and

•  15 gas storage fields with an aggregate storage capacity of 307 bcf and a working storage capacity of 142 bcf.

Gas Supply: In 2008, Consumers purchased 67 percent of the gas it delivered from United States producers and 23 percent from Canadian producers. Authorized suppliers in the gas customer choice program supplied the remaining 10 percent of gas that Consumers delivered.

Consumers’ firm gas transportation agreements are with ANR Pipeline Company, Great Lakes Gas Transmission, L.P., Trunkline Gas Co., Panhandle Eastern Pipe Line Company, and Vector Pipeline. Consumers uses these agreements to deliver gas to Michigan for ultimate deliveries to market. Consumers’ firm transportation and city gate arrangements are capable of delivering over 90 percent of Consumers’ total gas supply requirements. As of December 31, 2008, Consumers’ portfolio of firm transportation from pipelines to Michigan is as follows:

	Volume
	(dekatherms/day)		Expiration
ANR Pipeline Company		50,000	March	2017
Great Lakes Gas Transmission, L.P		100,000	March	2011
Great Lakes Gas Transmission, L.P		50,000	March	2017
Trunkline Gas Company		240,000	October	2012
Panhandle Eastern Pipe Line Company (starting 4/01/09)		50,000	October	2009
Panhandle Eastern Pipe Line Company (starting 4/01/10)		50,000	October	2010
Panhandle Eastern Pipe Line Company (starting 4/01/11)		50,000	October	2011
Panhandle Eastern Pipe Line Company (starting 4/01/12)		50,000	October	2012
Panhandle Eastern Pipe Line Company (starting 4/01/13)		50,000	October	2013
Panhandle Eastern Pipe Line Company		50,000	October	2013
Vector Pipeline		50,000	March	2012

Consumers purchases the balance of its required gas supply under incremental firm transportation contracts, firm city gate contracts and, as needed, interruptible transportation contracts. The amount of interruptible transportation service and its use vary primarily with the price for this service and the availability and price of the spot supplies being purchased and transported. Consumers’ use of interruptible transportation is generally in off-peak summer months and after Consumers has fully utilized the services under the firm transportation agreements.

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Enterprises

Enterprises, through various subsidiaries and certain equity investments, is engaged primarily in domestic independent power production and the marketing of independent power production. In 2007, Enterprises made a significant change in business strategy by exiting the international marketplace and refocusing its business strategy to concentrate on its independent power business in the United States.

Enterprises’ operating revenue included in Continuing Operations in our consolidated financial statements was $379 million in 2008, $383 million in 2007, and $438 million in 2006. Operating revenue included in Discontinued Operations in our consolidated financial statements was $235 million in 2007 and $684 million in 2006.

Independent Power Production

CMS Generation was formed in 1986. It invested in and operated non-utility power generation plants in the United States and abroad. In 2007, Enterprises sold CMS Generation and all of its international assets and power production facilities and transferred its domestic independent power plant operations to its subsidiary, HYDRA-CO. For more information on the asset sales, see ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — NOTE 3. ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES — ASSET SALES.

The independent power production’s operating revenue included in Continuing Operations in our consolidated financial statements was $36 million in 2008, $41 million in 2007, and $103 million in 2006. Operating revenue included in Discontinued Operations in our consolidated financial statements was $124 million in 2007 and $437 million in 2006.

Independent Power Production Properties: At December 31, 2008, CMS Energy had ownership interests in independent power plants totaling 1,199 gross MW or 1,078 net MW (net MW reflects that portion of the gross capacity in relation to CMS Energy’s ownership interest).

The following table details CMS Energy’s interest in independent power plants at December 31, 2008:

						Percentage of
						Gross Capacity
						Under Long-Term
	Primary	Ownership Interest		Gross Capacity		Contract
Location	Fuel Type	(%)		(MW)		(%)
California	Biomass		37.8		36		100
Connecticut	Scrap tire		100		31		0
Michigan	Coal		50		70		100
Michigan	Natural gas		100		710		92
Michigan	Natural gas		100		224		0
Michigan	Biomass		50		40		100
Michigan	Biomass		50		38		100
North Carolina	Biomass		50		50		0
Total					1,199

For information on capital expenditures, see ITEM 7. CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS — CAPITAL RESOURCES AND LIQUIDITY.

Energy Resource Management

CMS ERM was formed in 1996. It purchases and sells energy commodities in support of CMS Energy’s generating facilities. In 2004, CMS ERM discontinued its natural gas retail program as customer contracts expired and changed its name from CMS Marketing, Services and Trading Company to CMS Energy Resource Management Company.

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In 2008, CMS ERM marketed approximately 22 bcf of natural gas and 1,778 GWh of electricity. Its operating revenue was $343 million in 2008, $342 million in 2007, and $334 million in 2006.

Natural Gas Transmission

CMS Gas Transmission was formed in 1988 and owned, developed and managed domestic and international natural gas facilities. In March 2007, CMS Gas Transmission sold a portfolio of its businesses in Argentina and its northern Michigan non-utility natural gas assets to Lucid Energy. In August 2007, CMS Gas Transmission sold its investment in GasAtacama to Endesa S.A. In June 2008, CMS Gas Transmission completed the sale of TGN in Argentina. For more information on these asset sales see ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — NOTE 3. ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES — ASSET SALES.

CMS Gas Transmission’s operating revenue included in Continuing Operations in our consolidated financial statements was less than $1 million in 2008 and 2007, and $1 million in 2006. Operating revenue included in Discontinued Operations in our consolidated financial statements was $3 million in 2007 and $17 million in 2006.

International Energy Distribution

In April 2007, CMS Energy sold its ownership interest in SENECA. In June 2007, CMS Energy sold CPEE. For more information on these asset sales, see ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — NOTE 3. ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES — ASSET SALES.

The international energy distribution’s operating revenue, all of which was reflected in Discontinued Operations in our consolidated financial statements was $108 million in 2007 and $230 million in 2006.

CMS ENERGY AND CONSUMERS REGULATION

CMS Energy, Consumers and their subsidiaries are subject to regulation by various federal, state, local and foreign governmental agencies, including those described in the following sections.

Michigan Public Service Commission

Consumers is subject to the jurisdiction of the MPSC, which regulates public utilities in Michigan with respect to retail utility rates, accounting, utility services, certain facilities and other matters.

The Michigan Attorney General, ABATE, and the MPSC staff typically participate in MPSC proceedings concerning Consumers. The Michigan Attorney General or ABATE often appeal significant MPSC orders.

Rate Proceedings: In 2008, the MPSC issued an order that established the electric authorized rate of return on common equity at 10.7 percent. During 2008, we filed an electric rate case with the MPSC requesting an 11 percent authorized rate of return, which is still pending. In February 2008, we filed a gas rate case with the MPSC requesting an 11 percent authorized rate of return. In December 2008, the MPSC approved a settlement agreement that established the gas authorized rate of return on common equity at 10.55 percent.

The PSCR and GCR processes allow for recovery of reasonable and prudent power supply and gas costs. The MPSC reviews these costs for reasonableness and prudency in annual plan proceedings and in plan reconciliation proceedings. For additional information, see ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 4 OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) — CONSUMERS’ ELECTRIC UTILITY RATE MATTERS and CONSUMERS’ GAS UTILITY RATE MATTERS and ITEM 8. CONSUMERS’ FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 4 OF CONSUMERS’ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) — ELECTRIC RATE MATTERS and GAS RATE MATTERS.

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MPSC Regulation and Michigan 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, subject to refund, 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 no more than 10 percent of our weather-adjusted sales,

•  establishment of a certificate-of-necessity process at the MPSC for existing or proposed power plants, or power purchase agreements if the construction, investment, or purchase costs more than $500 million,

•  a requirement that 10 percent of electric sales volume come from renewable energy sources by 2015 with interim targets, and

•  new programs and incentives to encourage greater energy efficiency among customers, along with the requirement that the utility prepare energy cost savings optimization plans and achieve sales reduction targets beginning in 2009 through 2015.

Consumers transports some of the natural gas it sells to customers through facilities owned by competitors including gas producers, marketers and others. Pursuant to a self-implemented gas customer choice program, all of Consumers’ gas customers are eligible to select an alternative gas commodity supplier.

Federal Energy Regulatory Commission

The FERC has exercised limited jurisdiction over several independent power plants and exempt wholesale generators in which Enterprises has ownership interests, as well as over CMS ERM, CMS Gas Transmission, and DIG. Among other things, the FERC has jurisdiction over acquisitions, operation and disposal of certain assets and facilities, services provided and rates charged, conduct among affiliates, and limited jurisdiction over holding company matters with respect to CMS Energy. The FERC, in connection with the North American Electric Reliability Corporation and regional reliability organizations, also regulates generation owners and operators, load serving entities, purchase and sale entities and others with regard to reliability of the bulk power system. Some of Consumers’ gas business is also subject to regulation by the FERC, including a blanket transportation tariff pursuant to which Consumers may transport gas in interstate commerce.

The FERC also regulates certain aspects of Consumers’ electric operations including compliance with the FERC accounting rules, wholesale rates, operation of licensed hydro-electric generating plants, transfers of certain facilities, and corporate mergers and issuance of securities.

Other Regulation

The Secretary of Energy regulates imports and exports of natural gas and has delegated various aspects of this jurisdiction to the FERC and the DOE’s Office of Fossil Fuels.

Consumers’ pipelines are subject to the Natural Gas Pipeline Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which regulate the safety of gas pipelines.

CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE

CMS Energy, Consumers and their subsidiaries are subject to various federal, state and local regulations for environmental quality, including air and water quality, waste management, zoning and other matters.

Consumers continues to install modern emission controls at its electric generating plants and convert electric generating units to burn cleaner fuels. Consumers expects that the cost of future environmental compliance, especially compliance with the federal Clean Air Act, will be significant because of the EPA regulations and

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proposed regulations regarding nitrogen oxides, particulate-related emissions, and mercury. Consumers plans to spend $817 million for equipment installation through 2017 to comply with a number of these environmental regulations, including regulations limiting nitrogen oxides and sulfur dioxide emissions. The MDEQ is currently reviewing public comments on Michigan’s proposed mercury rule. If the proposed rule is enacted, Consumers expects to spend approximately $782 million by 2015 to comply with the rule. For additional information concerning estimated capital expenditures related to environmental compliance, including capital expenditures to reduce nitrogen oxides-related emissions, see ITEM 7. CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC UTILITY BUSINESS UNCERTAINTIES — ELECTRIC ENVIRONMENTAL ESTIMATES.

Construction, operation, and closure of a modern solid waste disposal area for ash can be expensive because of strict federal and state requirements. In order to achieve significant reductions in ash field closure costs, Consumers has worked with others to use bottom ash and fly ash as part of a temporary and final cover for ash disposal areas instead of native materials, in cases where the use of bottom ash and fly ash is compatible with environmental standards. To reduce disposal volumes, Consumers sells coal ash for use as a Portland cement replacement in concrete products, as a filler for asphalt, as feedstock for the manufacture of Portland cement and for other environmentally compatible uses.

The EPA has been considering the development of new federal standards for ash disposal areas for several years. Michigan’s solid waste rules that regulate coal ash landfills were developed in 1993 and have been updated since that time. All Consumers’ ash facilities have groundwater monitoring programs and are subject to quarterly MDEQ inspections. With the installation of a new dry ash handling system at its Karn and Weadock plants in the fourth quarter of 2008, the vast majority of Consumers’ fly ash is collected dry. Consumers is working through industry groups to ensure the development of cost-effective rules that are consistent with protection of the environment.

Like most electric utilities, Consumers has PCB in some of its electrical equipment. During routine maintenance activities, Consumers identified PCB as a component in certain paint, grout and sealant materials at Ludington. Consumers removed and replaced part of the PCB material with non-PCB material. Since proposing a plan to deal with the remaining materials, Consumers has had several communications with the EPA. We are not able to predict when the EPA will issue a final ruling. Consumers is awaiting a response from the EPA.

Certain environmental regulations affecting CMS Energy and Consumers include, but are not limited to, the NREPA and Superfund. Despite some differences between the statutes, both NREPA and Superfund can require the sharing of remediation and other response costs among current site owners and operators, owners and operators at the time of disposal, transporters, and those who arranged for disposal of hazardous substances at the site. For additional information on Consumers’ NREPA and Superfund sites and information on notices of violation from the EPA related to alleged violations of NSR regulations at three of Consumers’ coal-based facilities and alleged emission limits violations related to fourteen of Consumers’ utility boilers, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 4 (CONTINGENCIES) OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS AND NOTE 4 OF CONSUMERS’ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

CMS Energy has recorded a significant liability for its obligations associated with Bay Harbor. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 4 (CONTINGENCIES) OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS and ITEM 1A. RISK FACTORS.

CMS Energy’s and Consumers’ current insurance program does not extend to cover the risks of certain environmental cleanup costs or environmental damages, such as claims for air pollution, damage to sites owned by CMS Energy or Consumers, and for some past PCB contamination, and for some long-term storage or disposal of pollutants.

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CMS ENERGY AND CONSUMERS COMPETITION

Electric Competition

Consumers’ electric utility business experiences actual and potential competition from many sources, both in the wholesale and retail markets, as well as in electric generation, electric delivery, and retail services.

The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. However, legislation enacted in Michigan in October 2008 revised the Customer Choice Act and generally limits alternative electric supply to 10 percent of our weather-adjusted retail sales for the preceding calendar year. At December 2008, alternative electric suppliers were providing 332 MW of generation service to ROA customers, which is equivalent to 4 percent of our weather-adjusted retail sales from the preceding calendar year.

Consumers also has competition or potential competition from:

•  industrial customers relocating all or a portion of their production capacity outside Consumers’ service territory for economic reasons;

•  municipalities owning or operating competing electric delivery systems;

•  customer self-generation; and

•  adjacent utilities that extend lines to customers in contiguous service territories.

Consumers addresses this competition by monitoring activity in adjacent areas and enforcing compliance with the MPSC and the FERC rules, providing non-energy services, and providing tariff-based incentives that support economic development.

Consumers offers non-energy revenue-producing services to electric customers, municipalities and other utilities in an effort to offset costs. These services include engineering and consulting, construction of customer-owned distribution facilities, sales of equipment (such as transformers), power quality analysis, energy management services, meter reading, and joint construction for phone and cable. In these activities, Consumers faces competition from many sources, including energy management services companies, other utilities, contractors, and retail merchandisers.

CMS ERM, a non-utility electric subsidiary, continues to focus on optimizing CMS Energy’s independent power production portfolio. CMS Energy’s independent power production business, a non-utility electric subsidiary, faces competition from generators, marketers and brokers, as well as other utilities marketing power in the wholesale market.

Gas Competition

Competition exists in various aspects of Consumers’ gas utility business, and is likely to increase. Competition comes from other gas suppliers taking advantage of direct access to Consumers’ customers and from alternative fuels and energy sources, such as propane, oil, and electricity.

INSURANCE

CMS Energy and its subsidiaries, including Consumers, maintain insurance coverage similar to comparable companies in the same lines of business. The insurance policies are subject to terms, conditions, limitations and exclusions that might not fully compensate CMS Energy for all losses. A portion of each loss is generally assumed by CMS Energy in the form of deductibles and self-insured retentions that, in some cases, are substantial. As CMS Energy renews its policies it is possible that some of the current insurance coverage may not be renewed or obtainable on commercially reasonable terms due to restrictive insurance markets.

For a discussion of environmental insurance coverage, see ITEM 1. BUSINESS — CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE.

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EMPLOYEES

CMS Energy

At December 31, 2008, CMS Energy and its wholly owned subsidiaries, including Consumers, had 7,970 full-time equivalent employees. Included in the total are 3,475 employees who are covered by union contracts.

Consumers

At December 31, 2008, Consumers and its subsidiaries had 7,697 full-time equivalent employees. Included in the total are full-time operating, maintenance and construction employees and full-time and part-time call center employees who are represented by the Union.

CMS ENERGY EXECUTIVE OFFICERS (as of February 1, 2009)

Name	Age	Position	Period
David W. Joos	55	President and CEO of CMS Energy	2004-Present
		CEO of Consumers	2004-Present
		Chairman of the Board, President, CEO of Enterprises	5/2008-Present
		Director of CMS Energy	2001-Present
		Director of Consumers	2001-Present
		Director of Enterprises	2000-Present
		Chairman of the Board, CEO of Enterprises	2003-5/2008
		President, Chief Operating Officer of CMS Energy	2001-2004
		President, Chief Operating Officer of Consumers	2001-2004
Thomas J. Webb	56	Executive Vice President, CFO of CMS Energy	2002-Present
		Executive Vice President, CFO of Consumers	2002-Present
		Executive Vice President, CFO of Enterprises	2002-Present
		Director of Enterprises	2002-Present
James E. Brunner*	56	Senior Vice President and General Counsel of CMS Energy	11/2006-Present
		Senior Vice President and General Counsel of Consumers	11/2006-Present
		Senior Vice President and General Counsel of Enterprises	11/2007-Present
		Director of Enterprises	2006-Present
		Senior Vice President of Enterprises	2006-11/2007
		Senior Vice President, General Counsel and Chief Compliance Officer of CMS Energy	5/2006-11/2006
		Senior Vice President, General Counsel and Chief Compliance Officer of Consumers	5/2006-11/2006
		Senior Vice President, General Counsel and Interim Chief Compliance Officer of Consumers	2/2006-5/2006
		Senior Vice President and General Counsel of CMS Energy	2/2006-5/2006
		Senior Vice President and General Counsel of Consumers	2/2006-5/2006
		Vice President and General Counsel of Consumers	7/2004-2/2006
		Vice President of Consumers	7/2004

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Name	Age	Position	Period
John M. Butler **	44	Senior Vice President of CMS Energy	2006-Present
		Senior Vice President of Consumers	2006-Present
		Senior Vice President of Enterprises	2006-Present
David G. Mengebier	51	Senior Vice President and Chief Compliance Officer of CMS Energy	11/2006-Present
		Senior Vice President and Chief Compliance Officer of Consumers	11/2006-Present
		Senior Vice President of Enterprises	2003-Present
		Senior Vice President of CMS Energy	2001-11/2006
		Senior Vice President of Consumers	2001-11/2006
John G. Russell	51	President and Chief Operating Officer of Consumers	2004-Present
		Executive Vice President and President — Electric & Gas of Consumers	7/2004-10/2004
		Executive Vice President, President and CEO — Electric of Consumers	2001-2004
Glenn P. Barba	43	Vice President, Controller and Chief Accounting Officer of CMS Energy	2003-Present
		Vice President, Controller and Chief Accounting Officer of Consumers	2003-Present
		Vice President, Chief Accounting Officer and Controller of Enterprises	11/2007-Present
		Vice President and Chief Accounting Officer of Enterprises	2003-11/2007

*	From 1993 until July 2004, Mr. Brunner was Assistant General Counsel of Consumers.
**	From 2002 until 2004, Mr. Butler was Global Compensation and Benefits Resource Center Director at Dow and from 2004 until June 2006, Mr. Butler was Human Resources Director, Manufacturing and Engineering at Dow.

There are no family relationships among executive officers and directors of CMS Energy.

The present term of office of each of the executive officers extends to the first meeting of the Board of Directors after the next annual election of Directors of CMS Energy (scheduled to be held on May 22, 2009).

CONSUMERS EXECUTIVE OFFICERS (as of February 1, 2009)

Name	Age	Position	Period
David W. Joos	55	President and CEO of CMS Energy	2004-Present
		CEO of Consumers	2004-Present
		Chairman of the Board, President, CEO of Enterprises	5/2008-Present
		Director of CMS Energy	2001-Present
		Director of Consumers	2001-Present
		Director of Enterprises	2000-Present
		Chairman of the Board, CEO of Enterprises	2003-5/2008
		President, Chief Operating Officer of CMS Energy	2001-2004
		President, Chief Operating Officer of Consumers	2001-2004
Thomas J. Webb	56	Executive Vice President, CFO of CMS Energy	2002-Present
		Executive Vice President, CFO of Consumers	2002-Present
		Executive Vice President, CFO of Enterprises	2002-Present
		Director of Enterprises	2002-Present

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Name	Age	Position	Period
James E. Brunner*	56	Senior Vice President and General Counsel of CMS Energy	11/2006-Present
		Senior Vice President and General Counsel of Consumers	11/2006-Present
		Senior Vice President and General Counsel of Enterprises	11/2007-Present
		Director of Enterprises	2006-Present
		Senior Vice President of Enterprises	2006-11/2007
		Senior Vice President, General Counsel and Chief Compliance Officer of CMS Energy	5/2006-11/2006
		Senior Vice President, General Counsel and Chief Compliance Officer of Consumers	5/2006-11/2006
		Senior Vice President, General Counsel and Interim Chief Compliance Officer of Consumers	2/2006-5/2006
		Senior Vice President and General Counsel of CMS Energy	2/2006-5/2006
		Senior Vice President and General Counsel of Consumers	2/2006-5/2006
		Vice President and General Counsel of Consumers	7/2004-2/2006
		Vice President of Consumers	7/2004
John M. Butler **	44	Senior Vice President of CMS Energy	2006-Present
		Senior Vice President of Consumers	2006-Present
		Senior Vice President of Enterprises	2006-Present
David G. Mengebier	51	Senior Vice President and Chief Compliance Officer of CMS Energy	11/2006-Present
		Senior Vice President and Chief Compliance Officer of Consumers	11/2006-Present
		Senior Vice President of Enterprises	2003-Present
		Senior Vice President of CMS Energy	2001-11/2006
		Senior Vice President of Consumers	2001-11/2006
John G. Russell	51	President and Chief Operating Officer of Consumers	2004-Present
		Executive Vice President and President — Electric & Gas of Consumers	7/2004-10/2004
		Executive Vice President, President and CEO — Electric of Consumers	2001-2004
William E. Garrity	60	Senior Vice President of Consumers	2005-Present
		Vice President of Consumers	1999-2005
Frank Johnson	60	Senior Vice President of Consumers	2001-Present
Glenn P. Barba	43	Vice President, Controller and Chief Accounting Officer of CMS Energy	2003-Present
		Vice President, Controller and Chief Accounting Officer of Consumers	2003-Present
		Vice President, Chief Accounting Officer and Controller of Enterprises	11/2007-Present
		Vice President and Chief Accounting Officer of Enterprises	2003-11/2007

*	From 1993 until July 2004, Mr. Brunner was Assistant General Counsel of Consumers.
**	From 2002 until 2004, Mr. Butler was Global Compensation and Benefits Resource Center Director at Dow and from 2004 until June 2006, Mr. Butler was Human Resources Director, Manufacturing and Engineering at Dow.

There are no family relationships among executive officers and directors of Consumers.

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The present term of office of each of the executive officers extends to the first meeting of the Board of Directors after the next annual election of Directors of Consumers (scheduled to be held on May 22, 2009).

AVAILABLE INFORMATION

CMS Energy’s internet address is www.cmsenergy.com. Information contained in CMS Energy’s website is not incorporated herein. You can access free of charge on our website all of our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed pursuant to Section 13(a) or 15(d) of the Exchange Act. These reports are available soon after they are electronically filed with the SEC. Also on our website are our:

•  Corporate Governance Principles;

•  Codes of Conduct (Code of Business Conduct and Statement of Ethics);

•  Board committee charters (including the Audit Committee, the Compensation and Human Resources Committee, the Finance Committee and the Governance and Public Responsibility Committee); and

•  Articles of Incorporation (and amendments) and Bylaws.

We will provide this information in print to any shareholder who requests it.

You may also read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC, 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC. The address is http://www.sec.gov.

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ITEM 1A. RISK FACTORS

Actual results in future periods for CMS Energy and Consumers could differ materially from historical results and the forward-looking statements contained in this report. Factors that might cause or contribute to these differences include, but are not limited to, those discussed in the following sections. The companies’ business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond the companies’ control. Additional risks and uncertainties not presently known or that the companies’ management currently believes to be immaterial may also adversely affect the companies. The risk factors described in the following sections, as well as the other information included in this annual report and in the other documents filed with the SEC, should be considered carefully before making an investment in securities of CMS Energy and Consumers. Risk factors of Consumers are also risk factors of CMS Energy.

CMS Energy depends on dividends from its subsidiaries to meet its debt service obligations.

Due to its holding company structure, CMS Energy depends on dividends from its subsidiaries to meet its debt service obligations. Restrictions contained in Consumers’ preferred stock provisions and other legal restrictions, such as certain terms in its articles of incorporation and FERC requirements, limit Consumers’ ability to pay dividends or acquire its own stock from CMS Energy. At December 31, 2008, Consumers had $331 million of unrestricted retained earnings available to pay common stock dividends. If sufficient dividends are not paid to CMS Energy by its subsidiaries, CMS Energy may not be able to generate the funds necessary to fulfill its cash obligations, thereby adversely affecting its liquidity and financial condition.

CMS Energy has substantial indebtedness that could limit its financial flexibility and hence its ability to meet its debt service obligations.

As of December 31, 2008, CMS Energy had $1.881 billion aggregate principal amount of indebtedness, including $178 million of subordinated indebtedness relating to its convertible preferred securities. Subsidiary debt of $4.549 billion is not included in the preceding total. As of December 31, 2008, there were $105 million of borrowings and $24 million of letters of credit outstanding under CMS Energy’s revolving credit agreement. CMS Energy and its subsidiaries may incur additional indebtedness in the future.

The level of CMS Energy’s present and future indebtedness could have several important effects on its future operations, including, among others:

•  a significant portion of its cash flow from operations will be dedicated to the payment of principal and interest on its indebtedness and will not be available for other purposes;

•  covenants contained in its existing debt arrangements require it to meet certain financial tests, which may affect its flexibility in planning for, and reacting to, changes in its business;

•  its ability to obtain additional financing for working capital, capital expenditures, acquisitions and general corporate and other purposes may be limited;

•  it may be at a competitive disadvantage to its competitors that are less leveraged;

•  its vulnerability to adverse economic and industry conditions may increase; and

•  its future credit ratings.

CMS Energy’s ability to meet its debt service obligations and to reduce its total indebtedness will depend on its future performance, which will be subject to general economic conditions, industry cycles, regulatory decisions and financial, business and other factors affecting its operations, many of which are beyond its control. CMS Energy cannot make assurances that its business will continue to generate sufficient cash flow from operations to service its indebtedness. If it is unable to generate sufficient cash flows from operations, it may be required to sell additional assets or obtain additional financing. CMS Energy cannot assure that additional financing will be available on commercially acceptable terms or at all.

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CMS Energy cannot predict the outcome of claims regarding its participation in the development of 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 voluntarily executed an AOC under Superfund and approved a Removal Action Work Plan to address issues 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 measures 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, Beeland, 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. The EPA has denied the appeal. One appeal relating to the state permit remains pending in the state court. Groups opposed to the injection well filed a lawsuit in Antrim County seeking an injunction against development of the well. In January 2009, the trial judge issued a preliminary injunction. Beeland is considering an appeal of the court’s order.

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 a cumulative charge of $141 million, which includes accretion expense, for its obligations. Depending on the size of any indemnification obligation or liability under environmental laws, an adverse outcome of this matter could have a material adverse effect on CMS Energy’s liquidity and financial condition and could negatively impact CMS Energy’s financial results. CMS Energy cannot predict the financial impact or outcome of this matter.

CMS Energy may be adversely affected by regulatory investigations and civil lawsuits regarding pricing information that CMS MST and CMS Field Services provided to market publications.

CMS Energy 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. CMS Energy is cooperating with an ongoing investigation by the DOJ regarding this matter. CMS Energy is unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation will have on CMS Energy.

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CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company were named as defendants in various lawsuits arising as a result of alleged false natural gas price reporting. Allegations included 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. CMS Energy cannot predict the outcome of the lawsuits. It is possible that the outcome in one or more of the lawsuits could affect adversely CMS Energy’s liquidity, financial condition and results of operations.

CMS Energy and Consumers retain contingent liabilities in connection with their asset sales.

The agreements that CMS Energy and Consumers enter into for the sale of assets customarily include provisions whereby they are 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 they make; and

•  make payments to the buyers depending on the outcome of post-closing adjustments, litigation, audits or other reviews.

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 concerning them, there could be a material adverse effect on CMS Energy’s or Consumers’ liquidity, financial condition and results of operations.

CMS Energy and Consumers have financing needs and may be unable to obtain bank financing or access the capital markets. If the national and worldwide financial crisis intensifies, potential disruption in the capital and credit markets may adversely affect CMS Energy’s and Consumers’ businesses, including the availability and cost of short-term funds for liquidity requirements and their ability to meet long-term commitments; each could adversely affect their liquidity, financial condition and results of operations.

CMS Energy and Consumers may be subject to liquidity demands pursuant to commercial commitments, under guarantees, indemnities and letters of credit. Consumers’ capital requirements are expected to be substantial over the next several years as it implements generation and environmental projects.

CMS Energy and Consumers rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from CMS Energy’s and Consumers’ respective operations. CMS Energy and Consumers also use letters of credit issued under each of their revolving credit facilities to support certain operations and investments. Disruptions in the capital and credit markets, as have been experienced during 2008, and continuing in 2009, could adversely affect CMS Energy’s and Consumers’ ability to draw on their respective bank revolving credit facilities. CMS Energy’s and Consumers’ access to funds under those credit facilities is dependent on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to CMS Energy and Consumers if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from CMS Energy and Consumers and other borrowers within a short period of time.

Longer term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could adversely affect CMS Energy’s and Consumers’ access to liquidity needed for their respective businesses. Any disruption could require CMS Energy and Consumers to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for their business needs can be arranged. These measures could include deferring capital expenditures, changing CMS Energy’s and Consumers’ commodity purchasing strategy to avoid collateral-posting requirements, and reducing or eliminating future share repurchases, dividend payments or other discretionary uses of cash.

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CMS Energy continues to explore financing opportunities to supplement its financial plan. These potential opportunities include refinancing and/or issuing new capital markets debt, preferred stock and/or common equity, and bank financing. CMS Energy cannot guarantee the capital markets’ acceptance of its securities or predict the impact of factors beyond its control, such as actions of rating agencies. If CMS Energy is unable to obtain bank financing or access the capital markets to incur or refinance indebtedness, there could be a material adverse effect on its liquidity, financial condition and results of operations. Similarly, Consumers currently plans to seek funds through the capital markets, commercial lenders and leasing arrangements. Entering into new financings is subject in part to capital market receptivity to utility industry securities in general and to Consumers’ securities issuances in particular. Consumers cannot guarantee the capital markets’ acceptance of its securities or predict the impact of factors beyond its control, such as actions of rating agencies. If Consumers is unable to obtain bank financing or access the capital markets to incur or refinance indebtedness, there could be a material adverse effect on its liquidity, financial condition and results of operations.

Certain of CMS Energy’s securities and those of its affiliates, including Consumers, are rated by various credit rating agencies. Any reduction or withdrawal of one or more of its credit ratings could have a material adverse impact on CMS Energy’s or Consumers’ ability to access capital on acceptable terms and maintain commodity lines of credit and could make its cost of borrowing higher. If it is unable to maintain commodity lines of credit, CMS Energy or Consumers may have to post collateral or make prepayments to certain of its suppliers pursuant to existing contracts with them. Further, any adverse developments to Consumers, which provides dividends to CMS Energy, that result in a lowering of Consumers’ credit ratings could have an adverse effect on CMS Energy’s credit ratings. CMS Energy and Consumers cannot guarantee that any of their current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency.

Electric industry regulation could adversely affect CMS Energy’s and Consumers’ business, including their ability to recover costs from their customers.

Federal and state regulation of electric utilities has changed dramatically in the last two decades and could continue to change over the next several years. These changes could have a material adverse effect on CMS Energy’s and Consumers’ liquidity, financial condition and results of operations.

CMS Energy and Consumers are subject to, or affected by, extensive federal and state utility regulation. In CMS Energy’s and Consumers’ business planning and management of operations, they must address the effects of existing and proposed regulation on their businesses and changes in the regulatory framework, including initiatives by federal and state legislatures, regional transmission organizations, utility regulators and taxing authorities. Adoption of new regulations by federal or state agencies, or changes to current regulations and interpretations of these regulations may adversely affect CMS Energy’s and Consumers’ liquidity, financial condition, and results of operations.

There are multiple proceedings pending before the FERC involving transmission rates, regional transmission organizations and electric bulk power markets and transmission. The FERC reviewed the standards under which electric utilities are allowed to participate in wholesale power markets without price restrictions. In June 2007, the FERC issued a final rule on these standards that did not impact negatively Consumers’ ability to retain its market-based rate authority. The U.S. Court of Appeals for the Ninth Circuit has been petitioned to review portions of this final rule. CMS Energy and Consumers cannot predict the impact of these electric industry restructuring proceedings on their liquidity, financial condition or results of operations.

CMS Energy and Consumers could incur significant costs to comply with environmental standards and face difficulty in recovering these costs on a current basis.

CMS Energy, Consumers and their subsidiaries are subject to costly and increasingly stringent environmental regulations. They expect that the cost of future environmental compliance, especially compliance with clean air and water laws, will be significant. Federal rules governing coal-based electric generating plant emission controls for nitrogen oxides, sulfur dioxide and mercury are being reviewed by the courts.

The U.S. Supreme Court, in Massachusetts v. EPA, has remanded a claim to the EPA to consider whether greenhouse gases should be regulated as a pollutant under the Clean Air Act. The EPA is reviewing the matter. There

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are also pending regulatory and judicial actions which seek to have either existing or new coal-based power plants be subject to greenhouse gas regulation under the Clean Air Act. In addition, legislative proposals have been before the U.S. Congress pertaining to the potential regulation or control of carbon dioxide emissions and other greenhouse gases. These or similar proposals are considered likely to be enacted in some form and could have a significant impact upon the operation and cost of existing and planned future coal-based power plants.

In 2008, Consumers obtained 52 percent of its energy from purchased and interchange power and 48 percent of its energy from Consumers-owned generation. Of the amount of energy obtained from Consumers-owned generation, 95 percent came from coal-based power plants. The electric energy from its coal, gas and oil-based power plants would be subject to carbon dioxide emissions regulations. In 2008, it is estimated that carbon dioxide emissions from Consumers-owned coal-based power plants, excluding the portion of jointly-owned Campbell Unit 3, exceeded approximately 19 million tons of carbon dioxide. Enterprises also has interests in coal-based power plants and other types of power plants that produce carbon emissions. These plants would also be subject to carbon dioxide emissions regulations. These proposals, if enacted, could require the purchase of allowances for, or taxation of, carbon emissions, could require the curtailment of use of coal-based power plants, or could require the use of other alternatives to fossil-fuel based generating capacity and/or otherwise could significantly affect Consumers’ and Enterprises operations and plans for, and costs associated with their fossil-fuel generating plants and purchased power.

There are ongoing state-level and Midwest regional greenhouse gas regulatory initiatives. The State of Michigan has convened the Michigan Climate Action Council, a climate change stakeholder process. Michigan is also a signatory participant in the Midwest Governors Greenhouse Gas Reduction Accord process. The governor of Michigan recently proposed a 45 percent reduction in the use of fossil fuel for electric generation by 2020. The governor’s office has subsequently advised us that the 45 percent is only a suggested target, and is intended to apply only to coal-based generation. She also issued an executive directive requiring the MDEQ to determine whether an electric generation need exists that would be served by a proposed coal-based power plant; and if such need exists, to consider reasonable and prudent alternatives to coal before issuing an air permit for the proposed coal-based power plant. The Michigan attorney general issued an opinion that invalidated the governor’s directive on the basis that the governor’s directive exceeded the governor’s authority. If the attorney general’s action is challenged and the directive is ultimately upheld, it will have a significant impact upon the operation and cost of existing and planned future coal-based power plants.

Other laws, proposals, rules and judicial interpretations of presently existing laws that govern areas such as electric generating plant cooling water intake systems and electric generating plant modifications could have a significant impact upon their generating plants. The EPA is currently contesting the applicability of NSR standards to certain of Consumers’ coal-based plant projects, which if the EPA’s position is sustained, could lead to costly environmental upgrades, monetary sanctions, or both. If these measures or similar state measures are enacted or become effective, CMS Energy and Consumers could be required to replace equipment, install additional equipment, restructure or shut down operations at various facilities.

CMS Energy and Consumers expect to collect fully from their customers, through the ratemaking process, expenditures incurred to comply with environmental regulations. 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. This action 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.

Market performance and other changes may decrease the value of benefit plan assets, which then could require significant funding.

The performance of the capital markets affects the values of assets that are held in trust to satisfy future obligations under CMS Energy’s and Consumers’ pension and postretirement benefit plans. CMS Energy and Consumers have significant obligations in this area and hold significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below CMS Energy’s and Consumers’ forecasted return rates. A decline in the market value of the assets or a change in the level of interest rates used to

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measure the required minimum funding levels may increase the funding requirements of these obligations. Also, changes in demographics, including increased number of retirements or changes in life expectancy assumptions, may increase the funding requirements of the obligations related to the pension and postretirement benefit plans. If CMS Energy and Consumers are unable to successfully manage their pension and postretirement plan assets, it could affect negatively their liquidity, financial condition and results of operations.

Periodic reviews of the values of CMS Energy’s and Consumers’ assets could result in accounting charges.

CMS Energy and Consumers are required by GAAP to review periodically the carrying value of their assets, including those that may be sold. Market conditions, the operational characteristics of their assets and other factors could result in recording additional impairment charges for their assets, which could have an adverse effect on their stockholders’ equity and their access to additional financing. In addition, CMS Energy and Consumers may be required to record impairment charges at the time they sell assets, depending on the sale prices they are able to secure and other factors.

CMS Energy’s and Consumers’ revenues and results of operations are subject to risks that are beyond their control, including but not limited to future terrorist attacks or related acts of war.

The cost of repairing damage to CMS Energy’s and Consumers’ facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events, in excess of insurance recoveries and reserves established for these repairs, may affect adversely their liquidity, financial condition and results of operations. The occurrence or risk of occurrence of future terrorist activity and the high cost or potential unavailability of insurance to cover this terrorist activity may affect their liquidity, financial condition and results of operations in unpredictable ways. These actions could also result in disruptions of power and fuel markets. Instability in the financial markets as a result of terrorism, war or natural disasters, credit crises, recessions or other factors may adversely affect CMS Energy’s and Consumers’ liquidity, financial condition and results of operations.

Energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities to Consumers and CMS Energy or increased volatility of its earnings.

Consumers is exposed to changes in market prices for natural gas, coal, electricity and emission credits. Prices for natural gas, coal, electricity and emission credits may fluctuate substantially over relatively short periods of time and expose Consumers to commodity price risk. A substantial portion of Consumers’ operating expenses for its plants consists of the costs of obtaining these commodities. Consumers manages these risks using established policies and procedures, and it may use various contracts to manage these risks, including swaps, options, futures and forward contracts. No assurance can be made that these strategies will be successful in managing Consumers’ pricing risk or that they will not result in net liabilities to Consumers as a result of future volatility in these markets.

Natural gas prices in particular have historically been volatile. Consumers routinely enters into contracts to mitigate exposure to the risks of demand, market effects of weather and changes in commodity prices associated with its gas distribution business. These contracts are executed in conjunction with the GCR mechanism, which is designed to allow Consumers to recover prudently incurred costs associated with those positions. However, Consumers does not always hedge the entire exposure of its operations from commodity price volatility. Furthermore, the ability to hedge exposure to commodity price volatility depends on liquid commodity markets. As a result, to the extent the commodity markets are illiquid, Consumers may not be able to execute its risk management strategies, which could result in greater unhedged positions than preferred at a given time. To the extent that unhedged positions exist, fluctuating commodity prices can improve or worsen CMS Energy’s and Consumers’ liquidity, financial condition and results of operations.

In addition, Consumers included in its 2009-10 GCR filing a proposal to extend the GCR forward purchase period by two years beyond the typical three-year period, through the 2013-14 GCR period. These potential additional gas purchases could have a significant impact on Consumers’ credit requirements and could result in significant margin calls if prices were to fall below the forward purchase prices of gas purchased.

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Changes in taxation as well as inherent difficulty in quantifying potential tax effects of business decisions could negatively impact CMS Energy’s and Consumers’ results of operations.

CMS Energy and Consumers are required to make judgments regarding the potential tax effects of various financial transactions and results of operations in order to estimate their obligations to taxing authorities. The tax obligations include income, real estate, sales and use taxes, employment-related taxes and ongoing issues related to these tax matters. The judgments include reserves for potential adverse outcomes regarding tax positions that have been taken that may be subject to challenge by the IRS and/or other taxing authorities. Unfavorable settlements of any of the issues related to these reserves at CMS Energy or Consumers could adversely affect their liquidity, financial condition and results of operations.

Consumers is exposed to risks related to general economic conditions in its service territories.

Consumers’ electric and gas utility businesses are impacted by the economic conditions of the customers it serves. In its service territories in Michigan, the economy has been hampered by the continued downturn and financial uncertainty in the automotive industry. Michigan’s economy has also been impacted negatively by the uncertainty in the financial and credit markets resulting from the subprime mortgage crisis. In the event economic conditions in Michigan or the region continue to decline, Consumers may experience reduced demand for electricity or natural gas that could result in decreased earnings and cash flow. In addition, economic conditions in its service territory affect its collections of accounts receivable, liquidity and financial condition.

CMS Energy’s and Consumers’ energy sales and operations are impacted by seasonal factors and varying weather conditions from year to year.

CMS Energy’s and Consumers’ businesses are generally seasonal. Demand for electricity is greater in the summer and winter months associated with cooling and heating, and demand for natural gas peaks in the winter heating season. Accordingly, their overall results in the future may fluctuate substantially on a seasonal basis. Mild temperatures during the summer cooling season and winter heating season will adversely affect CMS Energy’s and Consumers’ liquidity, financial condition and results of operations.

Unplanned power plant outages may be costly for Consumers.

Unforeseen maintenance may be required to produce electricity. As a result of unforeseen maintenance, Consumers may be required to incur unplanned expenses and to make spot market purchases of electricity that exceed its costs of generation. Its liquidity, financial condition and results of operations may be adversely affected if it is unable to recover those increased costs.

Failure to succeed in implementing new processes and information systems could interrupt our operations.

CMS Energy and Consumers depend on numerous information systems for operations and financial information and billings. They completed recently a multi-year company-wide initiative to improve existing processes and implement new core information systems. Failure to implement successfully new processes and new core information systems could interrupt their operations.

Consumers may not be able to obtain an adequate supply of coal, which could limit its ability to operate its facilities.

Consumers is dependent on coal for much of its electric generating capacity. While Consumers has coal supply and transportation contracts in place, there can be no assurance that the counterparties to these agreements will fulfill their obligations to supply coal to Consumers. The suppliers under the agreements may experience financial or operational problems that inhibit their ability to fulfill their obligations to Consumers. In addition, suppliers under these agreements may not be required to supply coal to Consumers under certain circumstances, such as in the event of a natural disaster. If it is unable to obtain its coal requirements under existing or future coal supply and transportation contracts, Consumers may be required to purchase coal at higher prices, or it may be forced to make additional MWh purchases through other potentially higher cost generating resources in the Midwest Energy Market. Higher coal costs increase its working capital requirements.

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CMS Energy and Consumers are subject to rate regulation.

CMS Energy and Consumers are subject to rate regulation. Electric and gas rates for their utilities are set by the MPSC and cannot be increased without regulatory authorization. The FERC authorizes certain subsidiaries of CMS Energy to sell electricity at market-based rates. CMS Energy and Consumers may be impacted negatively by new regulations or interpretations by the MPSC, the FERC or other regulatory bodies. Failure of CMS Energy and Consumers to obtain adequate rates or regulatory approvals in a timely manner may adversely affect CMS Energy’s and Consumers’ liquidity, financial condition, and results of operations. New legislation, regulations or interpretations could change how the business of CMS Energy and Consumers operates, impact the ability of CMS Energy and Consumers to recover costs through rate increases or require CMS Energy and Consumers to incur additional expenses.

CMS Energy and Consumers are exposed to credit risk of those with whom they do business.

CMS Energy and Consumers are exposed to credit risk of counterparties with whom they do business. Adverse economic conditions affecting, or the financial difficulties of, counterparties with whom they do business could impair the ability of these counterparties to pay for CMS Energy’s and Consumers’ services or fulfill their contractual obligations, including performance and/or payment of damages. CMS Energy and Consumers depend on these counterparties to remit payments and perform services on a timely basis. Any delay or default in payment and/or performance of contractual obligations could adversely affect CMS Energy’s and Consumers’ liquidity, financial condition and results of operations. The capital and credit markets have been experiencing levels of volatility and disruption unprecedented in recent years. Market disruption and volatility could have a negative impact on CMS Energy’s and Consumers’ lenders, suppliers and other counterparties or Consumers’ customers, causing them to fail to meet their obligations. Adverse economic conditions could also have a negative impact on the loan portfolio of CMS Energy’s banking subsidiary, EnerBank.

CMS Energy could be required to pay cash to certain security holders in connection with the optional conversion of their convertible securities.

CMS Energy has issued three series of cash-convertible securities, of which an aggregate principal amount (or par value in the case of preferred stock) of approximately $677 million was outstanding as of December 31, 2008. If the trading price of CMS Energy’s common stock exceeds specified amounts at the end of a particular fiscal quarter, then holders of one or more series of these convertible securities will have the option to convert their securities in the following fiscal quarter, with the principal amount (or par value) payable in cash by CMS Energy. Accordingly, if these trading price minimums are satisfied and security holders exercise their conversion rights, CMS Energy may be required to outlay a significant amount of cash to those security holders, which could adversely affect CMS Energy’s liquidity and financial condition.

Consumers has a significant capital investment program planned for the next five years.

Consumers’ planned investments include a new coal-based power generation plant, an advanced metering infrastructure program, renewable power generation, gas compression, and other electric and gas infrastructure to upgrade delivery systems. The success of these investments depends on or could be affected by a variety of factors including, but not limited to, effective cost and schedule management during implementation, changes in commodity and other prices, operational performance, changes in environmental, legislative and regulatory requirements and regulatory cost recovery. Consumers cannot predict the impact that any of these factors may have on the success of its capital investment program. It is possible that adverse events reflected in these factors could adversely affect Consumers’ liquidity, financial condition and results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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ITEM 2. PROPERTIES

Descriptions of CMS Energy’s and Consumers’ properties are found in the following sections of Item 1, all of which are incorporated by reference in this Item 2:

•  BUSINESS — GENERAL — Consumers — Consumers’ Properties — General;

•  BUSINESS — BUSINESS SEGMENTS — Consumers Electric Utility — Electric Utility Properties;

•  BUSINESS — BUSINESS SEGMENTS — Consumers Gas Utility — Gas Utility Properties; and

•  BUSINESS — BUSINESS SEGMENTS — Independent Power Production — Independent Power Production Properties.

ITEM 3. LEGAL PROCEEDINGS

CMS Energy, Consumers and some of their subsidiaries and affiliates are parties to certain routine lawsuits and administrative proceedings incidental to their businesses involving, for example, claims for personal injury and property damage, contractual matters, various taxes, and rates and licensing. For additional information regarding various pending administrative and judicial proceedings involving regulatory, operating and environmental matters, see ITEM 1. BUSINESS — CMS ENERGY AND CONSUMERS REGULATION, both CMS Energy’s and Consumers’ ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS and both CMS Energy’s and Consumers’ ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

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 in a following paragraph.

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

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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 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. The CMS defendants have filed an applications for leave to appeal to the Tennessee Supreme Court which stays further proceedings in the trial court until the Supreme Court rules on the application.

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. Plaintiffs have filed a motion for class certification to which defendants’ response is due on March 16, 2009.

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, 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. Defendants’ response to the class certification motion is due on March 16, 2009.

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

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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 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. On January 8, 2009, the judge denied plaintiffs’ motion for reconsideration, thereby dismissing CMS MST and CMS Field Services. 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 February 23, 2009, the court granted CMS Energy’s motion to dismiss for lack of jurisdiction. The January 8, 2009 ruling also renders moot the defendants’ motion for judgment on the pleadings filed in September 2008 and the plaintiffs’ motion for class certification. An appeal of the dismissal is expected.

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 antitrust 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, and in November 2008, plaintiffs voluntarily dismissed CMS Energy as a party to this case. Defendants, including CMS MST and CMS Field Services, filed a motion to dismiss for lack of standing. On January 13, 2009, the state court judge in Kansas City, Missouri entered an order finding that the plaintiff Missouri Public Service Commission lacks standing to sue and the case was dismissed as to all defendants. All other pending motions were overruled as moot. An appeal of the dismissal is expected.

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 antitrust laws. Defendants, including CMS Energy, CMS Field Services, and CMS MST, are alleged to have violated the Missouri AntiTrust 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. Defendants’ response to the class certification motion is due on March 16, 2009.

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 Anti-Trust 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. Defendants’ response to the class certification motion is due on March 16, 2009.

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CMS Energy and the other CMS Energy defendants will defend themselves vigorously against these matters but cannot predict their outcome.

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 no 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 CMS Energy believes Quicksilver’s position to be without merit, if the court were to grant the relief requested by Quicksilver, it could result in a loss of up to $10 million.

STATE STREET BANK/TEXAS SOUTHERN UNIVERSITY LITIGATION

In 1998, CMS Viron installed a number of energy savings measures at Texas Southern University. CMS Viron sold the master lease for the project to Academic Capital which transferred its interest to State Street Bank. Although the university accepted the improvements, it refused to pay on the technicality that the Texas Board of Higher Education had not approved the expenditure. In 2002, State Street Bank sued CMS Viron in the District Court of Harris County, Texas because state law made it difficult to sue the university. Presently, the plaintiffs are seeking approximately $6 million from CMS Viron. CMS Viron believes it has a valid defense to the claim, but cannot predict the outcome of this litigation.

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 believes that Barr was properly paid on gas sales and that he was not 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 suffered minimal, if any, damages. 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.

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FERC INVESTIGATION

On February 11, 2008, the FERC issued a data request to Consumers in conjunction with an investigation being conducted into possible violations of the FERC’s posting and competitive bidding regulations regarding releases of firm capacity on interstate natural gas pipelines. The request asked Consumers to provide documents relating to capacity releases by Consumers, among other things. The FERC is presently investigating certain parties with regard to a practice known as “flipping,” which involves the release, at below the maximum tariff rate, of capacity on a short term basis to a party followed by a release of the same capacity to an affiliate of the original recipient of the released capacity in the subsequent month. In other cases, the FERC has taken the position that this practice violates the FERC’s regulations that require posting and competitive bidding of some capacity releases. Consumers has provided responses to the questions posed in the February 11, 2008 data request. In June 2008, Consumers received a second set of data requests from the FERC. Consumers has provided responses to the questions posed in the June 2008 request as well as to several telephonic follow-up data requests. Consumers is fully cooperating with the FERC staff.

ENVIRONMENTAL MATTERS

The EPA has alleged that some utilities have incorrectly classified major plant modifications as RMRR rather than seeking permits from the EPA to modify their plants. Consumers responded to information requests from the EPA on this subject in 2000, 2002 and 2006. Consumers believes that it has properly interpreted the requirements of RMRR. In October 2008, Consumers received another information request from the EPA under Section 114 of the Clean Air Act. Consumers responded to this information request in December 2008.

In addition to the EPA’s information request, in October 2008, Consumers received a NOV for three of its coal-based facilities relating to violations of NSR regulations, alleging ten projects from 1986 to 1998 were subject to NSR review. Consumers met with the EPA in January 2009 and has additional meetings scheduled. If the EPA does not accept Consumers’ interpretation of RMRR, Consumers could be required to install additional pollution control equipment at some or all of its coal-based electric generating plants, surrender emission allowances, engage in supplemental environmental programs or pay fines. Additionally, Consumers would need to assess the viability of continuing operations at certain plants. Consumers cannot predict the financial impact or outcome of this matter.

CMS Energy and Consumers, as well as their subsidiaries and affiliates, are subject to various other federal, state and local laws and regulations relating to the environment. Several of these companies have been named parties to other administrative or judicial proceedings involving environmental issues. Based on their present knowledge and subject to future legal and factual developments, they believe it is unlikely that any of these other actions 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’ ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS and both CMS Energy’s and Consumers’ ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

CMS Energy

During the fourth quarter of 2008, CMS Energy did not submit any matters to a vote of security holders.

Consumers

During the fourth quarter of 2008, Consumers did not submit any matters to a vote of security holders.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER
MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

CMS Energy

CMS Energy’s Common Stock is traded on the New York Stock Exchange. Market prices for CMS Energy’s Common Stock and related security holder matters are contained in ITEM 7. CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS and ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 18 OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)) which is incorporated by reference herein. At February 23, 2009, the number of registered holders of CMS Energy Common Stock totaled 46,080, based upon the number of record holders. On January 26, 2007, the Board of Directors reinstated a quarterly dividend on CMS Energy Common Stock of $0.05 per share. On January 25, 2008, the Board of Directors increased the quarterly dividend on CMS Energy Common Stock to $0.09 per share. On January 23, 2009, the Board of Directors increased the quarterly dividend on CMS Energy Common Stock to $0.125 per share. Information regarding securities authorized for issuance under equity compensation plans is included in our definitive proxy statement, which is incorporated by reference herein.

For additional information regarding dividends and dividend restrictions, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Consumers

Consumers’ common stock is privately held by its parent, CMS Energy, and does not trade in the public market. Consumers paid cash dividends on its common stock of $113 million in February 2008, $55 million in May 2008, $70 million in August 2008, and $59 million in November 2008. Consumers paid cash dividends on its common stock of $94 million in February 2007, $41 million in May 2007, $41 million in August 2007, and $75 million in November 2007.

For additional information regarding dividends and dividend restrictions, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

Issuer Repurchases of Equity Securities

For the three months ended December 31, 2008, there were no repurchases of equity securities by CMS Energy. Periodically, CMS Energy repurchases certain restricted shares upon vesting under the Performance Incentive Stock Plan from participants in this plan, equal to CMS Energy’s minimum statutory income tax withholding obligation. Shares repurchased have a value based on the market price on the vesting date.

ITEM 6. SELECTED FINANCIAL DATA

CMS Energy

Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — CMS ENERGY’S SELECTED FINANCIAL INFORMATION, which is incorporated by reference herein.

Consumers

Selected financial information is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — CONSUMERS’ SELECTED FINANCIAL INFORMATION, which is incorporated by reference herein.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

CMS Energy

Management’s discussion and analysis of financial condition and results of operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS, which is incorporated by reference herein.

Consumers

Management’s discussion and analysis of financial condition and results of operations is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — CONSUMERS’ MANAGEMENT’S DISCUSSION AND ANALYSIS, which is incorporated by reference herein.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

CMS Energy

Quantitative and Qualitative Disclosures About Market Risk is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS — CRITICAL ACCOUNTING POLICIES — FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION, which is incorporated by reference herein.

Consumers

Quantitative and Qualitative Disclosures About Market Risk is contained in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — CONSUMERS’ MANAGEMENT’S DISCUSSION AND ANALYSIS — CRITICAL ACCOUNTING POLICIES — ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION, which is incorporated by reference herein.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

	Page
Index to Financial Statements:
CMS Energy Corporation
Selected Financial Information	CMS - 2
Management’s Discussion and Analysis	CMS - 3
Forward-Looking Statements and Information	CMS - 3
Executive Overview	CMS - 5
Results of Operations	CMS - 6
Critical Accounting Policies	CMS - 13
Capital Resources and Liquidity	CMS - 18
Outlook	CMS - 23
Implementation of New Accounting Standards	CMS - 30
New Accounting Standards Not Yet Effective	CMS - 31
Consolidated Financial Statements
Consolidated Statements of Income (Loss)	CMS - 34
Consolidated Statements of Cash Flows	CMS - 36
Consolidated Balance Sheets	CMS - 38
Consolidated Statements of Common Stockholders’ Equity	CMS - 40
Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies	CMS - 42
2. Fair Value Measurements	CMS - 49
3. Asset Sales, Discontinued Operations and Impairment Charges	CMS - 53
4. Contingencies	CMS - 56
5. Financings and Capitalization	CMS - 67
6. Earnings Per Share	CMS - 72
7. Financial and Derivative Instruments	CMS - 73
8. Retirement Benefits	CMS - 76
9. Asset Retirement Obligations	CMS - 82
10. Income Taxes	CMS - 84
11. Stock Based Compensation	CMS - 87
12. Leases	CMS - 89
13. Property, Plant, and Equipment	CMS - 91
14. Equity Method Investments	CMS - 92
15. Jointly Owned Regulated Utility Facilities	CMS - 94
16. Reportable Segments	CMS - 94
17. Consolidation of Variable Interest Entities	CMS - 97
18. Quarterly Financial and Common Stock Information (Unaudited)	CMS - 98
Reports of Independent Registered Public Accounting Firms	CMS - 99

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	Page
Consumers Energy Company
Selected Financial Information	CE - 2
Management’s Discussion and Analysis
Forward-Looking Statements and Information	CE - 3
Executive Overview	CE - 5
Results of Operations	CE - 7
Critical Accounting Policies	CE - 12
Capital Resources and Liquidity	CE - 16
Outlook	CE - 22
Implementation of New Accounting Standards	CE - 27
New Accounting Standards Not Yet Effective	CE - 28
Consolidated Financial Statements
Consolidated Statements of Income	CE - 31
Consolidated Statements of Cash Flows	CE - 32
Consolidated Balance Sheets	CE - 34
Consolidated Statements of Common Stockholder’s Equity	CE - 36
Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies	CE - 39
2. Fair Value Measurements	CE - 45
3. Asset Sales and Impairment Charges	CE - 48
4. Contingencies	CE - 49
5. Financings and Capitalization	CE - 56
6. Financial and Derivative Instruments	CE - 59
7. Retirement Benefits	CE - 61
8. Asset Retirement Obligations	CE - 67
9. Income Taxes	CE - 69
10. Stock Based Compensation	CE - 71
11. Leases	CE - 74
12. Property, Plant, and Equipment	CE - 75
13. Jointly Owned Regulated Utility Facilities	CE - 77
14. Reportable Segments	CE - 77
15. Quarterly Financial and Common Stock Information (Unaudited)	CE - 79
Reports of Independent Registered Public Accounting Firms	CE - 80

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42

2008 Consolidated Financial Statements

CMS-1

CMS Energy Corporation

SELECTED FINANCIAL INFORMATION

				2008		2007			2006			2005			2004
Operating revenue (in millions)	($		)		6,821		6,464			6,126			5,879			5,154
Earnings from equity method investees (in millions)	($		)		5		40			89			125			115
Income (loss) from continuing operations (in millions)	($		)		300		(126	)		(133	)		(141	)		112
Cumulative effect of change in accounting (in millions)	($		)		—		—			—			—			(2	)
Income (loss) from discontinued operations (in millions)	($		)		—		(89	)		54			57			11
Net income (loss) (in millions)	($		)		300		(215	)		(79	)		(84	)		121
Net income (loss) available to common stockholders (in millions)	($		)		289		(227	)		(90	)		(94	)		110
Average common shares outstanding (in thousands)					223,931		222,644			219,857			211,819			168,553
Net income (loss) from continuing operations per average common share
CMS Energy — Basic	($		)		1.29		(0.62	)		(0.66	)		(0.71	)		0.59
— Diluted	($		)		1.23		(0.62	)		(0.66	)		(0.71	)		0.58
Cumulative effect of change in accounting per average common share
CMS Energy — Basic	($		)		—		—			—			—			(0.01	)
— Diluted	($		)		—		—			—			—			(0.01	)
Net income (loss) per average common share
CMS Energy — Basic	($		)		1.29		(1.02	)		(0.41	)		(0.44	)		0.65
— Diluted	($		)		1.23		(1.02	)		(0.41	)		(0.44	)		0.64
Cash provided by operations (in millions)	($		)		559		25			690			598			353
Capital expenditures, excluding acquisitions and capital lease additions (in millions)	($		)		792		1,263			670			593			525
Total assets (in millions)(a)	($		)		14,901		14,192			15,325			15,976			15,833
Long-term debt, excluding current portion (in millions)(a)	($		)		5,859		5,385			6,200			6,778			6,414
Long-term debt-related parties, excluding current portion (in millions)	($		)		178		178			178			178			504
Non-current portion of capital leases and finance lease obligations (in millions)	($		)		206		225			42			308			315
Total preferred stock (in millions)	($		)		287		294			305			305			305
Cash dividends declared per common share	($		)		0.36		0.20			—			—			—
Market price of common stock at year-end	($		)		10.11		17.38			16.70			14.51			10.45
Book value per common share at year-end	($		)		10.88		9.46			10.03			10.53			10.62
Number of employees at year-end (full-time equivalents)					7,970		7,898			8,640			8,713			8,660
Electric Utility Statistics
Sales (billions of kWh)					37		39			38			39			38
Customers (in thousands)					1,814		1,799			1,797			1,789			1,772
Average sales rate per kWh		(c	)		9.48		8.65			8.46			6.73			6.88
Gas Utility Statistics
Sales and transportation deliveries (bcf)					338		340			309			350			385
Customers (in thousands)(b)					1,713		1,710			1,714			1,708			1,691
Average sales rate per mcf	($		)		11.25		10.66			10.44			9.61			8.04

(a)

Until their sale in November 2006, we were the primary beneficiary of the MCV Partnership and the FMLP. As a result, we consolidated their assets, liabilities and activities into our consolidated financial statements through the date of sale and for the years ended December 31, 2005 and 2004. These partnerships had third-party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004.

(b)

Excludes off-system transportation customers.

CMS-2

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.

FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-K 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. These factors include our inability to predict or control:

•  the price of CMS Energy Common Stock, capital and financial market conditions and the effect of these 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,

•  cost of capital and availability of capital, and

•  Pension Plan and postretirement benefit plans assets and required contributions,

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

•  the 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 applicable laws, rules, regulations, principles or practices or in their interpretation, including with respect to taxes, environmental and accounting matters, that could have an impact on our business,

•  the impact of any future regulations or laws regarding:

•  carbon dioxide, mercury and other greenhouse gas emissions,

•  limitations on the use of coal-based electric power plants, and

•  renewable portfolio standards and energy efficiency mandates,

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

•  adverse regulatory or legal interpretations or decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with these interpretations or decisions, including but not limited to those that may affect Bay Harbor and Consumers’ RMRR classification under NSR regulations,

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•  potentially adverse regulatory treatment or failure to receive timely regulatory orders concerning a number of significant questions currently or potentially before the MPSC, including:

•  adequate and timely recovery of :

•  Clean Air Act capital and operating costs and other environmental and safety-related expenditures,

•  power supply and natural gas supply costs,

•  operation and maintenance expenses at Consumers,

•  additional utility rate-based investments,

•  increased MISO energy and transmission costs,

•  costs associated with energy efficiency investments and state or federally mandated renewable resource standards,

•  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 foreign or domestic governments 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, and their impact on our cash flow and working capital,

•  the impact of construction material prices and 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 these 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, and stability of insurance providers,

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

•  achievement of capital expenditure and operating expense goals,

•  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,

•  changes in financial or regulatory accounting principles or policies,

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•  a possible future requirement to comply with International Financial Reporting Standards, which differ from GAAP in various ways, including the present lack of special accounting treatment for regulated activities similar to that provided under SFAS No. 71,

•  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 the gas price reporting litigation and the pending appeal of the Quicksilver litigation,

•  population growth or decline in the geographic areas where we do business,

•  changes in the economic and financial viability of our suppliers, customers, and other counterparties and the continued ability of these third parties to perform their obligations to us,

•  the effectiveness of our risk management policies and procedures,

•  our ability to achieve generation planning goals and the occurrence and duration of planned or unplanned generation outages,

•  adverse outcomes regarding tax positions due to the difficulty in quantifying tax effects of business decisions and reserves, and

•  other business or investment matters 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 details regarding these and other uncertainties, see the “Outlook” section included in this MD&A, Note 4, Contingencies, and Part I, Item 1A. Risk Factors.

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 in primarily 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 ratings.

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 in excess of $6 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

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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. In February 2009, we filed our renewable energy plan and energy optimization plan with the MPSC in order to conform to various aspects of this legislation.

As we work to implement plans to serve our customers in the future, the cost of energy and related cash flow issues continue to challenge us. Natural gas prices and eastern coal prices have been volatile. 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. There is additional uncertainty associated with state and federal legislative and regulatory proposals related to regulation of carbon dioxide emissions, particularly associated with coal-based generation. We are closely monitoring these developments for the effect on our future plans.

We are 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 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 adversely impacted by the continued downturn and uncertainty in Michigan’s automotive industry. There also has been a sharp economic 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

Years Ended December 31	2008		2007			2006
	In Millions (Except for Per Share Amounts)
Net Earnings (Loss) Available to Common Stockholders	$	289	$	(227	)	$	(90	)
Basic Earnings (Loss) Per Share	$	1.29	$	(1.02	)	$	(0.41	)
Diluted Earnings (Loss) Per Share	$	1.23	$	(1.02	)	$	(0.41	)

Years Ended December 31	2008			2007			Change			2007			2006			Change
	In Millions
Electric Utility	$	271		$	196		$	75		$	196		$	199		$	(3	)
Gas Utility		89			87			2			87			37			50
Enterprises		14			(412	)		426			(412	)		(227	)		(185	)
Corporate Interest and Other		(85	)		(9	)		(76	)		(9	)		(153	)		144
Discontinued Operations		—			(89	)		89			(89	)		54			(143	)
Net Earnings (Loss) Available to Common Stockholders	$	289		$	(227	)	$	516		$	(227	)	$	(90	)	$	(137	)

In 2008, net income was $289 million compared with a net loss of $227 million for 2007. Combined net income from our electric and gas utility segments increased, compared with 2007, reflecting the positive impact of the MPSC rate orders and the elimination of certain costs from the power purchase agreement with the MCV

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Partnership, partially offset by lower electric deliveries and increased depreciation expense. Further increasing net income was the absence of activities associated with assets sold in 2007, the absence of costs associated with the termination of contracts in 2007, and a reduction in corporate interest expense.

Specific changes to net earnings (loss) available to common stockholders for 2008 versus 2007 are:

	In Millions
• absence of costs incurred by CMS ERM due to the termination of certain electricity sales agreements and the rescission of a contract with Quicksilver,	$	217
• absence of impairment charges related to international businesses sold in 2007,		133
• increase in net earnings at our electric and gas utility segments primarily due to favorable MPSC rate orders,		129
• absence of a net loss on the disposal of discontinued operations in 2007,		89
• other net increase at Enterprises and corporate and other primarily due to reduced interest and operating and maintenance expense, and the absence of early debt retirement premiums paid in 2007,		37
• elimination of certain costs at our electric utility from the power purchase agreement with the MCV Partnership,		29
• absence of an increase in the provision for environmental remediation costs at Bay Harbor,		29
• absence of a 2007 net tax benefit, associated with the sale of assets, recorded at Enterprises and corporate and other,		(53	)
• decreased deliveries at our electric utility segment,		(51	)
• decrease due to a charge that recognized an other than temporary decline in the fair value of our SERP investments in 2008 which replaced a gain on the sale of SERP assets in 2007, and		(30	)
• other combined net decrease at our electric and gas utility segments due primarily to higher depreciation expense offset by a reduction in nuclear operating and maintenance costs.		(13	)
Total change	$	516

For 2007, our net loss was $227 million compared with a net loss of $90 million for 2006. The increase in net loss was due primarily to the termination of contracts at CMS ERM. Further increasing the net loss were charges related to the exit from our international businesses, the absence of earnings from these businesses, and an increase in the provision for Bay Harbor environmental remediation costs. The increase in losses was partially offset by the absence of the shareholder settlement liability recorded in 2006, the absence of activities related to our former interest in the MCV Partnership, and increased earnings at our utility primarily due to the positive effects of rate orders and increased sales.

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Specific changes to net loss available to common stockholders for 2007 versus 2006 are:

		In Millions
•	costs incurred by CMS ERM due to the rescission of a contract with Quicksilver and the termination of certain electricity sales agreements,	$	(217	)
•	impact from discontinued operations as losses recorded on the disposal of international businesses in 2007 replaced earnings recorded for these businesses in 2006,		(143	)
•	reduction in earnings from equity method investees primarily due to the absence of earnings from international businesses sold in 2007,		(32	)
•	increase in the provision for environmental remediation costs at Bay Harbor,		(29	)
•	additional taxes at our corporate and Enterprises segments as the absence of tax benefits associated with the resolution of an IRS income tax audit in 2006 more than offset the net tax benefits associated with the sale of international businesses recorded in 2007,		(16	)
•	absence of a 2006 net charge resulting from our agreement to settle shareholder class action lawsuits,		80
•	absence of activities related to our former interest in the MCV Partnership including asset impairments and mark-to-market impacts,		60
•	earnings from non-MCV-related mark-to-market impacts primarily at CMS ERM, as mark-to-market gains in 2007 replaced losses in 2006,		49
•	increase in combined net earnings at our gas utility and electric utility, primarily due to the positive effects of the MPSC gas rate orders and increased weather-related deliveries,		47
•	decrease in non-MCV-related asset impairment charges, net of insurance reimbursement, and		38
•	additional increase at Enterprises and corporate primarily due to gains on the sale of international businesses in 2007, a reduction in interest expense, and increased interest income.		26
Total change		$	(137	)

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Electric Utility Results of Operations

Years Ended December 31	2008		2007		Change			2007		2006		Change
	In Millions
Net income	$	271	$	196	$	75		$	196	$	199	$	(3	)
Reasons for the change:
Electric deliveries and rate increase					$	89						$	(118	)
Surcharge revenue						15							6
Power supply costs and related revenue						18							(17	)
Non-commodity revenue						(14	)						(12	)
Depreciation and other operating expenses						40							150
Other income						(46	)						26
General taxes						15							(15	)
Interest charges						11							(18	)
Income taxes						(53	)						(5	)
Total change					$	75						$	(3	)

Electric deliveries and rate increase: For 2008, electric delivery revenues increased $89 million versus 2007 primarily due to additional revenue of $168 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 $79 million primarily due to lower deliveries. Deliveries to end-use customers were 37.5 billion kWh, a decrease of 1.3 billion kWh or 3 percent versus 2007. Approximately 45 percent of the decrease in electric deliveries was due to weather.

For 2007, electric delivery revenues decreased $118 million versus 2006. The decrease was primarily due to $136 million of revenue related to Palisades that was designated toward the recovery of PSCR costs consistent with the MPSC order related to the sale in April 2007. Partially offsetting the decrease were increased electric delivery revenues of $14 million, as deliveries to end-use customers were 38.8 billion kWh, an increase of 0.3 billion kWh or 0.8 percent versus 2006. The increase in electric deliveries was primarily due to favorable weather. Also contributing to the increase was $2 million of additional revenue from the inclusion of the Zeeland power plant in rates and $2 million related to the return of additional former ROA customers.

Surcharge revenue: For 2008, surcharge revenue increased $15 million versus 2007. The increase was primarily due to the April 2008 MPSC order allowing recovery of pension and OPEB 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.

For 2007, surcharge revenue increased $6 million versus 2006. The increase was primarily due to a surcharge that we began collecting in the first quarter of 2006 that the MPSC authorized under Section 10d(4) of the Customer Choice Act.

Power supply costs and related revenue: For 2008, PSCR revenue increased by $18 million versus 2007. The increase primarily reflects the absence of a 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.

For 2007, PSCR revenue decreased by $17 million versus 2006. This decrease primarily reflects amounts excluded from recovery in the 2006 PSCR reconciliation case. The decrease also reflects the absence, in 2007, of an increase in power supply revenue associated with the 2005 PSCR reconciliation case.

Non-commodity revenue: For 2008, non-commodity revenue decreased $14 million versus 2007 primarily due to the absence, in 2008, of METC transmission services revenue. The METC transmission service agreement expired in April 2007.

For 2007, non-commodity revenue decreased $12 million versus 2006 primarily due to lower METC transmission services revenue.

Depreciation and other operating expenses: For 2008, depreciation and other operating expenses decreased $40 million versus 2007. The decrease was primarily due to the absence of operating expenses of Palisades, which

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was sold 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 pension and OPEB expense due to the April 2008 MPSC order allowing recovery of certain costs through a surcharge, increased depreciation and amortization expense due to more plant in service and increased amortization of certain regulatory assets. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Consumers’ Electric Utility Contingencies.”

For 2007, depreciation and other operating expenses decreased $150 million versus 2006. The decrease was primarily due to lower operating expenses of Palisades, which was sold in April 2007. Also contributing to the decrease was the absence, in 2007, of costs incurred in 2006 related to a refueling outage at Palisades, and lower overhead line maintenance and storm restoration costs. These decreases were offset partially by increased depreciation and amortization expense due to more plant in service and increased amortization of certain regulatory assets.

Other income: For 2008, other income decreased $46 million versus 2007. The decrease was primarily due to reduced interest income, reflecting lower levels of short-term cash investments, 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 a charge that recognized an other-than-temporary decline in the fair value of our SERP investments.

For 2007, other income increased $26 million versus 2006 primarily due to higher interest income on short-term cash investments. The increase in short-term cash investments was primarily due to proceeds from the Palisades sale and equity infusions into Consumers.

General taxes: For 2008, general tax expense decreased $15 million versus 2007 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 an income tax. The decrease was partially offset by higher property tax expense.

For 2007, general tax expense increased $15 million versus 2006 primarily due to higher property tax expense, reflecting higher millage rates and lower property tax refunds versus 2006.

Interest charges: For 2008, interest charges decreased $11 million versus 2007 primarily due to lower interest associated with amounts to be refunded to our 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.

For 2007, interest charges increased $18 million versus 2006. The increase was primarily due to interest on amounts to be refunded to customers as a result of the sale of Palisades as ordered by the MPSC and interest charges related to the IRS settlement.

Income taxes: For 2008, income taxes increased $53 million versus 2007. The increase primarily reflects $47 million due to higher earnings and $6 million due to the inclusion of the Michigan Business Tax.

For 2007, income taxes increased $5 million versus 2006 primarily due to the absence, in 2007, of a $4 million income tax benefit from the restoration and utilization of income tax credits resulting from the resolution of an IRS income tax audit.

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Gas Utility Results of Operations

Years Ended December 31	2008		2007		Change			2007		2006		Change
	In Millions
Net income	$	89	$	87	$	2		$	87	$	37	$	50
Reasons for the change:
Gas deliveries and rate increase					$	44						$	91
Gas wholesale and retail services, other gas revenues, and other income						(28	)						14
Other operating expenses						(24	)						(19	)
General taxes and depreciation						(1	)						(11	)
Interest charges						9							4
Income taxes						2							(29	)
Total change					$	2						$	50

Gas deliveries and rate increase: For 2008, gas delivery revenues increased $44 million versus 2007 primarily due to additional revenue of $33 million from the MPSC’s August 2007 and December 2008 gas rate orders. Also contributing to the increase was higher gas delivery revenue of $11 million. Gas deliveries, including miscellaneous transportation to end-use customers, were 304 bcf, an increase of 4 bcf or 1.3 percent. The increase in gas deliveries was due to colder weather in 2008.

For 2007, gas delivery revenues increased $91 million versus 2006 primarily due to additional revenue of $81 million from the MPSC’s November 2006 and August 2007 gas rate orders. Gas delivery revenues also increased $10 million as gas deliveries, including miscellaneous transportation to end-use customers, were 300 bcf, an increase of 18 bcf or 6.4 percent. The increase in gas deliveries was primarily due to colder weather, partially offset by higher system losses.

Gas wholesale and retail services, other gas revenues, and other income: For 2008, gas wholesale and retail services, other gas revenues, and other income decreased $28 million versus 2007. The decrease was primarily due to lower interest income reflecting lower short-term investments, and lower pipeline capacity optimization revenue. Also contributing to the decrease was a charge that recognized an other-than-temporary decline in the fair value of our SERP investments.

For 2007, gas wholesale and retail services, other gas revenues, and other income increased $14 million versus 2006. The increase was primarily due to higher interest income on short-term cash investments. The increase in short-term cash investments was primarily due to proceeds from the Palisades sale and equity infusions into Consumers.

Other operating expenses: For 2008, other operating expenses increased $24 million versus 2007 primarily due to higher uncollectible accounts expense and higher operating expense across our storage, transmission and distribution systems.

For 2007, other operating expenses increased $19 million versus 2006 primarily due to higher uncollectible accounts expense and payments, beginning in November 2006, to a fund that provides energy assistance to low-income customers.

General taxes and depreciation: For 2008, general taxes and depreciation increased $1 million versus 2007. The increase was primarily due to higher depreciation and increased property taxes. The increase was partially offset by decreased general taxes 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 an income tax.

For 2007, general taxes and depreciation increased $11 million versus 2006. The increase in general taxes reflects higher property tax expense due to higher millage rates and lower property tax refunds versus 2006. The increase in depreciation expense is primarily due to higher plant in service.

Interest charges: For 2008, interest charges decreased $9 million versus 2007 primarily due to lower average debt levels and a lower average interest rate.

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For 2007, interest charges decreased $4 million versus 2006 primarily due to lower average debt levels and a lower average interest rate versus 2006.

Income taxes: For 2008, income taxes decreased $2 million versus 2007. The decrease reflects $4 million related to the tax treatment of items related to property, plant and equipment, as required by the MPSC orders. This decrease was partially offset by a $1 million increase due to the inclusion of the Michigan Business Tax and $1 million related to the forfeiture of restricted stock.

For 2007, income taxes increased $29 million versus 2006 primarily due to higher earnings by the gas utility.

Enterprises Results of Operations

Years Ended December 31	2008		2007			Change			2007			2006			Change
	In Millions
Net income (loss)	$	14	$	(412	)	$	426		$	(412	)	$	(227	)	$	(185	)
Reasons for the change:
CMS ERM						$	242								$	(144	)
Activities associated with the sale of international assets							164									(58	)
Environmental remediation							29									(23	)
DIG							(7	)								(22	)
Other							(2	)								2
The MCV Partnership							—									60
Total Change						$	426								$	(185	)

CMS ERM: Net income in 2008 increased $242 million versus 2007. The increase is due to the absence of $217 million of costs incurred for the termination of certain electricity sales agreements and the rescission of a contract with Quicksilver recorded in 2007 and $33 million in net operating efficiencies from the absence of certain sales and supply contracts, offset partially by an $8 million net decrease in mark-to-market activity.

Net loss in 2007 increased by $144 million as $217 million of costs incurred for the termination of certain electricity sales agreements and the rescission of a contract with Quicksilver more than offset a $58 million net increase in mark-to-market gains, a $7 million reduction in fuel costs, and a $8 million net reduction in other expenses.

Activities associated with sale of international assets: These activities increased net income in 2008 by $164 million versus 2007 as the absences of $122 million of net impairment charges, $46 million of tax expense on deferred earnings, and $29 million of operating and maintenance expense recorded in 2007 more than offset the absence of the combined $33 million of net earnings and gains on the sale of these assets recorded in 2007. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

These activities increased net loss by $58 million in 2007 versus 2006. Taxes related to these assets increased net loss by $79 million as $46 million of tax expense on the recognition of previously deferred earnings recorded in 2007 replaced a benefit from the resolution of an IRS income tax audit recorded in 2006. Further increasing net loss was a $31 million net reduction in equity earnings from these businesses. The decreases were partially offset by a $19 million net decrease in impairment charges, a $14 million net gain on the sale of these assets, and a $19 million reduction in interest and other expenses. For additional information, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Environmental remediation: Our environmental remediation charges relate to our projections of future costs associated with Bay Harbor. These charges, net of tax, were $29 million in 2007 and $6 million in 2006. For additional information, see Note 4, Contingencies.

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DIG: Net income decreased $7 million in 2008 versus 2007. The decrease is due to $5 million of higher maintenance costs and a $2 million reduction in steam sales.

Net loss increased $22 million in 2007 versus 2006. The increase is primarily due to the absences of a $13 million favorable arbitration settlement and $11 million of third-party tolling revenue recorded in 2006 partly offset by a $2 million reduction in interest costs.

Other: Net decrease of $2 million in 2008 versus 2007 primarily due to a $9 million change in the valuation of our SERP investments as the $5 million gain on re-balancing recorded in 2007 was replaced by $4 million of expense for the other-than-temporary decline in the value of these investments recorded in 2008. The impact of the SERP investment activity more than offset $3 million of reduced interest expense and a $4 million reduction in other net expenses.

Net increase of $2 million in 2007 versus 2006 primarily due to a $5 million gain on the re-balancing of our SERP investments. This gain was offset partially by a $3 million net increase in other expenses.

MCV: We sold our interest in the MCV Partnership in November 2006. In 2006, our share of the MCV Partnership’s loss was $60 million, net of tax and minority interest. This was due primarily to mark-to-market losses and the net impact of the sale transaction, including asset impairment charges. These losses were partially offset by operating income and a property tax refund received in 2006.

Corporate Interest and Other Net Expenses

Years Ended December 31	2008			2007			Change			2007			2006			Change
	In Millions
Net loss	$	(85	)	$	(9	)	$	(76	)	$	(9	)	$	(153	)	$	144

For 2008, corporate interest and other net expenses were $85 million, an increase of $76 million versus 2007. The increase of $76 million primarily reflects the absence, in 2008, of the one-time recognition of certain tax benefits related to the sale of our international operations and reduced interest income. Partially offsetting the increase was the absence, in 2008, of the reduction in fair value of notes receivable from GasAtacama and premiums paid on the early retirement of CMS Energy debt in June 2007 and reduced interest expense due to lower debt levels in 2008.

For 2007, corporate interest and other net expenses were $9 million, a decrease of $144 million versus 2006. The $144 million decrease primarily reflects the absence, in 2007, of a charge for the settlement of our shareholder class action lawsuits partially offset by the absence of an insurance reimbursement received in June 2006. Also contributing to the decrease was the reduction in tax expense in 2007 related to the sale of our international operations. Partially offsetting the decrease was the absence, in 2007, of a tax benefit due to the resolution of an IRS income tax audit.

DISCONTINUED OPERATIONS

For 2008, there was no net income from discontinued operations. The $89 million net loss from discontinued operations in 2007 represents the net loss on the disposal of international businesses sold in 2007.

For 2007, the net loss from discontinued operations was $89 million versus $54 million of net income in 2006. The net loss on the disposal of international businesses in 2007 replaced earnings recorded for these businesses in 2006.

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. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies.

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Use of Estimates and Assumptions

In preparing our consolidated financial statements, we use estimates and assumptions that may affect reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, indemnifications and contingencies. Actual results may differ from estimated results due to changes in the regulatory environment, competition, foreign exchange, regulatory decisions, lawsuits, and other factors.

Contingencies: We record a liability for contingencies when we conclude that it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We consider all relevant factors in making these assessments.

Fair Value Measurements: We have assets and liabilities that we account for or disclose at fair value. Our fair value measurements are performed in accordance with SFAS No. 157, which requires 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 of our SERP assets, our derivative instruments, and the year-end measurement of our pension and OPEB plan assets. For a detailed discussion of the methods used to calculate our fair value measurements, see Note 2, Fair Value Measurements.

Income Taxes: The amount of income taxes we pay is subject to ongoing audits by federal, state, and foreign tax authorities, which can result in proposed assessments. Our estimate of the potential outcome of any uncertain tax issue is highly judgmental. We believe we have provided adequately for these exposures; however, our future results may include favorable or unfavorable adjustments to our estimated tax liabilities in the period the assessments are made or resolved or when statutes of limitation on potential assessments expire. Additionally, our judgment as to our ability to recover our deferred tax assets may change. We believe our valuation allowances related to our deferred tax assets are adequate, but future results may include favorable or unfavorable adjustments. As a result, our effective tax rate may fluctuate significantly over time.

Long-Lived Assets and Equity Method Investments: Our assessment of the recoverability of long-lived assets and equity method investments involves critical accounting estimates. We periodically perform tests of impairment if certain triggering events occur or if there has been a decline in value that may be other than temporary. Of our total assets, recorded at $14.901 billion at December 31, 2008, 62 percent represent long-lived assets and equity method investments that are subject to this type of analysis. We base our evaluations of impairment on such indicators as:

•  the nature of the assets,

•  projected future economic benefits,

•  regulatory and political environments,

•  historical and future cash flow and profitability measurements, and

•  other external market conditions and factors.

The estimates we use can change over time, which could have a material impact on our consolidated financial statements. For additional details, see Note 1, Corporate Structure and Accounting Policies — “Impairment of Long-Lived Assets and Equity Method Investments.”

Accounting for the Effects of Industry Regulation

Consumers’ involvement in a regulated industry requires us to use SFAS No. 71 to account for the effects of the regulators’ decisions that impact the timing and recognition of its revenues and expenses. As a result, Consumers may defer or recognize revenues and expenses differently than a non-regulated entity.

For example, Consumers may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate that Consumers will recover the expenses in future rates. Conversely, Consumers may record as regulatory liabilities items that non-regulated entities may normally recognize as

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revenues, if the actions of the regulator indicate that it will be required to refund the revenues to customers. Judgment is required to determine the appropriate accounting for items recorded as regulatory assets and liabilities. At December 31, 2008, Consumers had $2.438 billion recorded as regulatory assets and $1.988 billion recorded as regulatory liabilities.

Our PSCR and GCR cost recovery mechanisms also give rise to probable future revenues that will be recovered from customers or past overrecoveries that will be refunded to customers through the ratemaking process. Underrecoveries are included in Accrued power supply and gas revenue and overrecoveries are included in Accrued rate refunds on our Consolidated Balance Sheets. At December 31, 2008, we had $7 million recorded as regulatory assets for underrecoveries of power supply and gas costs and $7 million recorded as regulatory liabilities for overrecoveries of power supply and gas costs.

For additional details, see Note 1, Corporate Structure and Accounting Policies - “Utility Regulation.”

Financial and Derivative Instruments and Market Risk Information

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

Derivative Instruments: We use the criteria in SFAS No. 133 to determine if we need to account for certain contracts as derivative instruments. These criteria are complex and often require significant judgment in applying them to specific contracts. 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. For additional details on our derivatives, see Note 7, Financial and Derivative Instruments.

To determine the fair value of our derivatives, we generally use information from external sources, such as quoted market prices and other valuation information. For certain contracts, this information is not available and we use mathematical models to value our derivatives. The most material of our derivative liabilities, an electricity sales agreement held by CMS ERM, extends beyond the term for which quoted electricity prices are available. Thus, to value this derivative we use a valuation model that incorporates a proprietary forward pricing curve for electricity based on forward natural gas prices and an implied heat rate. Our model incorporates discounting, credit, and modeling risks. The model is sensitive to electricity and natural gas forward prices, and the fair value of this derivative liability will increase as these forward prices increase. We adjust our model each quarter to incorporate market data as it becomes available.

The fair values we calculate for our derivatives may change significantly as commodity prices and volatilities change. The cash returns we actually realize on our derivatives may be different from the fair values that we estimate. For derivatives in an asset position, our calculations of fair value include reserves of less than $1 million to reflect the credit risk of our counterparties. For derivatives in a liability position, our calculations include reserves of $1 million to reflect our own credit risk. For additional details on how we determine the fair values of our derivatives, see Note 2, Fair Value Measurements.

The types of contracts we typically classify as derivatives are interest rate swaps, financial transmission rights, fixed price fuel contracts, natural gas futures, electricity swaps, and forward and option contracts for electricity, natural gas, and foreign currencies. 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.

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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.

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 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 classified all of CMS ERM’s derivatives as non-trading derivatives.

Market Risk Information: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, foreign currency exchange rates, and equity security prices. We may enter into various risk management contracts to limit our exposure to these risks, including 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.

These contracts contain credit risk, which is the risk that our counterparties will fail to meet their contractual obligations. We reduce this risk using established policies and procedures, such as evaluating our counterparties’ credit quality and setting collateral requirements as necessary. If terms permit, we use standard agreements that allow us to net positive and negative exposures associated with the same counterparty. Given these policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings because of counterparty nonperformance.

The following risk sensitivities illustrate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical adverse change in market rates or prices of 10 percent. Potential losses could exceed the amounts shown in the sensitivity analyses if changes in market rates or prices were to exceed 10 percent.

Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital.

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

December 31	2008		2007
	In Millions
Variable-rate financing — before-tax annual earnings exposure	$	1	$	2
Fixed-rate financing — potential reduction in fair value(a)		208		172

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

Commodity Price Risk:  Operating in the energy industry, we are exposed to commodity price risk, which arises from fluctuations in the price of electricity, natural gas, coal, and other commodities. Commodity prices are influenced by a number of factors, including weather, changes in supply and demand, and liquidity of commodity markets. In order to manage commodity price risk, we may enter into various non-trading derivative contracts, such as forward purchase and sale contracts, options, and swaps.

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

December 31	2008		2007
	In Millions
Potential reduction in fair value:
Fixed price fuel contracts	$	1	$	—
Electricity swaps		—		4
Natural gas swaps and futures		1		1

Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available-for-sale investments.

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

December 31	2008		2007
	In Millions
Potential reduction in fair value of available-for-sale:
Equity securities	$	4	$	6
Debt securities		1		—
(Primarily SERP investments)

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

Retirement Benefits

Pension: We have external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. On September 1, 2005, the defined benefit Pension Plan was closed to new participants and we implemented the qualified DCCP, which provides an employer contribution of five percent of base pay to the existing 401(k) plan. An employee contribution is not required to receive the plan’s employer cash contribution. All employees hired on or after September 1, 2005 participate in this plan as part of their retirement benefit program. Previous cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date.

401(k): We provide an employer match in our 401(k) plan equal to 60 percent on eligible contributions up to the first six percent of an employee’s wages.

OPEB: We provide postretirement health and life benefits under our OPEB plan to qualifying retired employees.

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.

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The following table provides an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:

Expected	Pension Cost		OPEB Cost		Pension Contribution		OPEB Contribution
	In Millions
2009	$	101	$	77	$	300	$	53
2010		91		74		127		53
2011		88		72		105		53

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.

Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.25 percent to 8.00 percent) would increase estimated pension cost for 2009 by $3 million. Lowering the discount rate by 0.25 percent (from 6.50 percent to 6.25 percent) would increase estimated pension cost for 2009 by $5 million.

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

Accounting for Asset Retirement Obligations

We are required to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets at the end of their useful lives. We calculate the fair value of ARO liabilities using an expected present value technique that reflects assumptions about costs, inflation, and profit margin that third parties would consider to assume the obligation. We did not include a market risk premium in our ARO fair value estimates since a reasonable estimate could not be made.

If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, our gas transmission and electric and gas distribution assets have indeterminate lives and retirement cash flows that cannot be determined. However, we have recorded an ARO for our obligation to cut, purge, and cap abandoned gas distribution mains and gas services at the end of their useful lives. We have not recorded a liability for assets that have insignificant cumulative disposal costs, such as substation batteries. For additional details, see Note 9, Asset Retirement Obligations.

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 by holders for conversion,

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•  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, and

•  in September 2008, Consumers 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. Consumers’ accounts receivable sales program is planned for renewal in May 2009. Of our $1.392 billion in letters of credit and revolving credit facilities, $342 million are planned for renewal in 2009 and $1.050 billion are planned for renewal in 2012. Our senior notes maturities are $300 million in 2010, $300 million in 2011 and $150 million in 2012. Consumers’ FMB maturities are $350 million in 2009, $250 million in 2010 and $300 million in 2012. 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. If access to the capital markets is diminished or otherwise restricted, we would implement contingency plans to address debt maturities that may include reduced capital spending. For additional details, see Note 5, Financings and Capitalization.

In January 2009, the Board of Directors voted to increase the quarterly common stock dividend from $0.09 per share to $0.125 per share, for the first quarter of 2009. The dividend is payable February 27, 2009 to shareholders of record on February 6, 2009.

Cash Position, Investing, and Financing

Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2008, we had $248 million of consolidated cash, which includes $35 million of restricted cash and $9 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 $297 million in common stock dividends and Enterprises paid $950 million in common stock dividends, resulting from 2007 asset sales, to CMS Energy for the year ended December 31, 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.

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The following tables provide a summary of the major items affecting our cash flows from operating, investing and financing activities:

Operating Activities:

Years Ended December 31	2008		2007		Change			2007		2006		Change
	In Millions
Net cash provided by operating activities	$	559	$	25	$	534		$	25	$	690	$	(665	)
Reasons for the change:
Net income (loss)					$	515						$	(136	)
Non-cash operating activities(a)						(154	)						59
Accounts receivable and accrued revenue						371							(526	)
Inventories						(61	)						95
Accounts payable						40							(2	)
Postretirement benefits contributions						133							(115	)
Shareholder class action settlement payment						125							(125	)
Electric sales contract termination payment						(275	)						—
MCV Partnership gas supplier funds on deposit						—							147
Regulatory liabilities						(64	)						(173	)
Other assets and liabilities						(96	)						111
Total change					$	534						$	(665	)

(a) Represents adjustments to reconcile net income (loss) to net cash provided by operating activities, including depreciation and amortization, deferred income taxes, postretirement benefits expense, asset impairment charges, and other non-cash charges.

2008 versus 2007: Cash provided by operating activities increased primarily as a result of increased earnings and the timing of cash receipts from accounts receivable. We accelerate our collections from customer billings through the sale of accounts receivable. We sold $325 million of accounts receivable at the end of 2006, which reduced our collections from customers during 2007. We did not sell accounts receivable in 2007 and sold $170 million of accounts receivable during 2008. Also contributing to the increase in cash provided by operating activities were lower postretirement benefit contributions, the absence, in 2008, of a payment made to settle a shareholder class action lawsuit, and other timing differences. These increases were partially offset by a payment made by CMS ERM in February 2008 to terminate electric sales contracts, refunds to customers of excess Palisades decommissioning funds, the impact of higher commodity prices on inventory purchases, and increased accounts receivable billings at the end of 2008 due to regulatory actions and weather-driven demand.

2007 versus 2006: Cash provided by operating activities decreased primarily as result of decreased earnings and the absence, in 2007, of the sale of accounts receivable. Also contributing to the decrease in cash provided by operating activities were payments made to fund our Pension Plan and to settle a shareholder class action lawsuit, refunds to customers of excess Palisades decommissioning funds, and reduced cash distributions from international investments sold during 2007. These decreases were partially offset by a decrease in expenditures for gas inventory, as the milder winter in 2006 allowed us to accumulate more gas in our storage facilities, the absence of the release of the MCV Partnership gas supplier funds on deposit due to the sale of our interest in the MCV Partnership in 2006, and other timing differences.

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Investing Activities:

Years Ended December 31	2008			2007		Change			2007		2006			Change
	In Millions
Net cash provided by (used in) investing activities	$	(839	)	$	662	$	(1,501	)	$	662	$	(751	)	$	1,413
Reasons for the change:
Proceeds from asset sales, net of cash relinquished						$	(1,601	)						$	1,683
Proceeds from nuclear decommissioning trust funds							(333	)							311
Capital expenditures							471								(593	)
Other investing							(38	)							12
Total change						$	(1,501	)						$	1,413

2008 versus 2007: The increase in net cash used in investing activities reflects the absence, in 2008, of proceeds from asset sales and from our nuclear decommissioning trust funds. This increase was partially offset by a decrease in capital expenditures resulting from the absence of the Zeeland power plant purchase made in 2007.

2007 versus 2006: The increase in cash provided by investing activities was primarily due to proceeds from asset sales and the dissolution of our nuclear decommissioning trust funds. These changes were partially offset by an increase in capital expenditures primarily due to the purchase of the Zeeland power plant.

For additional details on asset sales, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Financing Activities:

Years Ended December 31	2008		2007			Change			2007			2006			Change
	In Millions
Net cash provided by (used in) financing activities	$	145	$	(692	)	$	837		$	(692	)	$	(436	)	$	(256	)
Reasons for the change:
Proceeds from notes, bonds and other long-term debt						$	881								$	415
Retirement of notes, bonds and other long-term debt							(35	)								(602	)
Other financing							(9	)								(69	)
Total change						$	837								$	(256	)

2008 versus 2007: The increase in net cash provided by financing activities was primarily due to an increase in proceeds from the issuance of long-term debt.

2007 versus 2006: The increase in cash used in financing activities was primarily due to an increase in net debt retirements and the payment of common stock dividends.

Restrictive Covenants: Our senior notes indenture requires us to maintain a minimum interest coverage ratio, as defined. Our $550 million revolving credit agreement requires us to maintain a maximum debt to EBITDA (Earnings Before Interest, Taxes, Depreciation, and Amortization) ratio, as defined, and a minimum interest coverage ratio, as defined. Consumers’ credit agreements require it to maintain a maximum debt to capital ratio, as defined. At December 31, 2008, we were in compliance with these requirements as detailed in the following table:

		(1) Minimum	Result at
		(2) Maximum	December 31,
Credit Agreement or Facility	Ratio	Requirement	2008
CMS senior notes indenture	Interest Coverage	(1)1.7 to 1.0	3.89 to 1.0
CMS revolving credit agreement	Debt to EBITDA	(2)7.0 to 1.0	4.71 to 1.0
CMS revolving credit agreement	Interest Coverage	(1)1.2 to 1.0	4.45 to 1.0
Consumers’ credit agreements	Debt to Capital	(2)0.7 to 1.0	0.52 to 1.0

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Credit Ratings: Our access to capital markets and costs of financing are influenced by the ratings of our securities. The following table displays our securities ratings along with those of Consumers as of December 31, 2008. The ratings outlook from S&P (Standard and Poor’s Rating Services),Moody’s (Moody’s Investor Services, Inc.) and Fitch (Fitch Ratings) on all securities is stable.

Issuer	Securities	S&P	Moody’s	Fitch
CMS Energy	Senior Unsecured Debt	BB+	Ba1	BB+
CMS Energy	Secured Bank Credit Facilities	−	Baa3	BBB-
CMS Energy	Trust Preferred Securities (Long-term debt - related parties)	BB	Ba2	BB
Consumers	Senior Secured Debt (FMB)	BBB	Baa1	BBB+
Consumers	Senior Unsecured Debt	BBB-	Baa2	BBB
Consumers	Securitization Bonds	AAA	Aaa	AAA
Consumers	Senior Secured Insured Quarterly Notes	AAA	Aaa	AAA
Consumers	Tax Exempt Bonds	BBB	Baa1	−
Consumers	Tax Exempt Bonds, LOC backed	AAA	Aaa	−

For additional details on long-term debt activity, see Note 5, Financings and Capitalization.

Obligations and Commitments

Contractual Obligations: The following table summarizes our contractual cash obligations for each of the periods presented. The table shows the timing of the obligations and their expected effect on our liquidity and cash flow in future periods. The table excludes all amounts classified as current liabilities on our Consolidated Balance Sheets, other than the current portion of long-term debt and capital and finance leases.

			Payments Due
			Less Than		One to		Three to		More Than
Contractual Obligations at December 31, 2008	Total		One Year		Three Years		Five Years		Five Years
	In Millions
Long-term debt(a)	$	6,348	$	489	$	1,037	$	1,197	$	3,625
Long-term debt — related parties(a)		178		—		—		—		178
Interest payments on long-term debt(b)		2,707		341		591		461		1,314
Capital and finance leases(c)		231		25		47		41		118
Interest payments on capital and finance leases(d)		122		13		25		22		62
Operating leases(e)		237		27		51		44		115
Purchase obligations(f)		14,699		2,201		2,391		1,545		8,562
Total contractual obligations	$	24,522	$	3,096	$	4,142	$	3,310	$	13,974

(a)	Principal amounts due on outstanding debt obligations, current and long-term, at December 31, 2008. For additional details on long-term debt, see Note 5, Financings and Capitalization.
(b)	Currently scheduled interest payments on both variable and fixed-rate long-term debt and long-term debt — related parties, current and long-term. Variable interest payments are based on contractual rates in effect at December 31, 2008.
(c)	Principal portion of lease payments under our capital and finance leases, comprised mainly of leased service vehicles, leased office furniture, and certain power purchase agreements.
(d)	Imputed interest on the capital leases.
(e)	Minimum noncancelable lease payments under our leases of railroad cars, certain vehicles, and miscellaneous office buildings and equipment, which are accounted for as operating leases.

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(f) Long-term contracts for purchase of commodities and services. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. These commodities and services include:

•  natural gas and associated transportation,

•  electricity, and

•  coal and associated transportation.

Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants’ availability or deliverability. These payments will approximate $36 million per month during 2009. If a plant is not available to deliver electricity, we will not be obligated to make these payments for that period. For additional details on power supply costs, see “Electric Utility Results of Operations” within this MD&A and Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters — Power Supply Costs.”

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 eligible accounts receivable at December 31, 2008, reduced from $325 million at December 31, 2007.

Capital Expenditures: For planning purposes, we forecast capital expenditures over a three-year period. 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. The following is a summary of our estimated capital expenditures, including lease commitments, for 2009 through 2011:

Years Ending December 31	2009		2010		2011
	In Millions
Electric utility operations(a)(b)	$	574	$	847	$	705
Gas utility operations(b)		276		287		251
Enterprises		1		1		—
Total	$	851	$	1,135	$	956

(a)	These amounts include estimates for capital expenditures that may be required by revisions to the Clean Air Act’s national air quality standards or potential renewable energy programs.
(b)	These amounts include estimates for capital expenditures related to information technology projects, facility improvements, and vehicle leasing.

Off-Balance Sheet Arrangements

CMS Energy and certain of its subsidiaries enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, surety bonds, letters of credit, and financial and performance guarantees. Indemnifications are usually agreements to reimburse a counterparty that may incur losses due to outside claims or breach of contract terms. The maximum payment we would be required to make under a number of these indemnities is not estimable. While we believe it is unlikely that we will incur any material losses related to indemnifications we have not recorded as liabilities, we cannot predict the impact of these contingent obligations on our liquidity and financial condition. For additional details on these and other guarantee arrangements, see Note 4, Contingencies, Other Contingencies — Indemnifications.

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.

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

ELECTRIC UTILITY BUSINESS OUTLOOK

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 through:

•  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-based plant at our Karn/Weadock Generating complex near Bay City, Michigan. We expect the plant to be in operation in 2017. Legislation enacted in Michigan in October 2008 provided guidelines with respect to the MPSC review and approval of energy resource plans and proposed power plants. We plan to file a new case with the MPSC that conforms to the new legislation.

Proposed Coal Plant Projects: In February 2009, the Michigan governor issued an executive directive that set forth additional requirements for the issuance of a permit to install a coal-based electric generating plant in the state of Michigan. The directive requires the MDEQ, before issuing an air permit for any coal-based electric generating plant, to consider, among other things,

•  whether additional generation is needed, and

•  whether other feasible and prudent alternatives to a new coal plant exist that would better protect the environment, including potential demand reduction measures and purchasing power from existing sources.

We are examining the legality of the directive, as well as its impact on our existing air permit application for our planned advanced clean coal plant. The Michigan attorney general issued an opinion that invalidated the governor’s directive on the basis that the governor’s directive exceeded the governor’s authority.

In February 2009, the Michigan governor also proposed a 45 percent reduction in the use of fossil fuel for electric generation by 2020. The governor’s office has subsequently advised us that the 45 percent is only a suggested target, and is intended to apply only to coal-based generation. If implemented, it will have a significant impact upon the operation and cost of existing and planned future coal-based power plants.

We cannot predict the impact of the governor’s statements or other factors on our future power supply plans.

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 the current volatility in the credit markets. Although our electric utility results are not dependent substantially upon a single customer, or even a few customers, those in the automotive sector represented four percent of our total 2008 electric revenue and two and a half percent of our 2008 electric operating income. We cannot predict the financial impact of the Michigan economy on our electric customer revenue.

Electric Deliveries: We experienced a decrease in electric deliveries of approximately 3.5 percent in 2008 compared with 2007, or 2.0 percent excluding impacts from differences in weather. This decrease reflects a decline in industrial economic activity and the cancellation of one wholesale customer contract. For 2009, we expect a decrease in electric deliveries of 2.5 percent compared with 2008, or 2.1 percent excluding impacts from differences in weather. Our outlook for 2009 includes continuing growth in deliveries to our largest-growing customer, which produces semiconductor and solar energy components. Excluding this customer’s growth, we expect electric

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deliveries in 2009 to decline 3.4 percent compared with 2008 or 3.0 percent excluding impacts from differences in weather. Our outlook 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 0.8 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, and

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

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 12.7 percent for summer 2009, or supply resources equal to 112.7 percent of projected firm summer peak load. We have purchased capacity and energy covering our Reserve Margin requirements for 2009 through 2010. Of the 2009 supply resources target, we expect 96.4 percent to come from our electric generating plants and long-term power purchase contracts, with other capacity and energy 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 $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.”

Renewable Energy Plan: Legislation enacted in Michigan in October 2008 prescribed renewable energy standards for energy and capacity. The energy standard requires that 10 percent of our electric sales volume come from renewable sources by 2015 with interim target requirements. Approximately four percent of our electric sales volume comes presently from renewable sources. The legislation also requires us to add new renewable energy capacity of 200 MW by year-end 2013 and 500 MW by year-end 2015, from owned renewable energy sources or power purchased agreements. We have secured more than 36,000 acres of land easements in Michigan’s Tuscola and Mason counties for potential wind generation development and we are collecting presently wind speed and other meteorological data at the sites.

In February 2009, we filed our Renewable Energy Plan with the MPSC. The plan details how we will meet the renewable energy standards for energy and capacity.

Energy Optimization Plan: Legislation enacted in Michigan in October 2008 requires utilities to prepare energy optimization plans and achieve annual sales reduction targets beginning in 2009 through 2015. In February 2009, we filed our Energy Optimization Plan with the MPSC, which details our proposed energy cost savings plan through incentives to reduce customer usage among all customer classes and the method of recovery of program costs.

Ancillary Services: In January 2009, MISO implemented an ancillary services market for the purchase and sale of regulation and contingency reserves. We include ancillary service costs in our PSCR.

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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 $817 million for equipment installation through 2017 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.

We plan to purchase additional nitrogen oxides emission allowances through 2010 at an estimated cost of $5 million per year. We also plan to purchase sulfur dioxide emission allowances, between 2013 and 2015, at an expected cost ranging from $9 million to $27 million per year. We expect to recover emissions allowance costs from our customers through the PSCR process.

Clean Air Interstate Rule: In March 2005, the EPA adopted the CAIR, which required additional coal-based 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. The court initially vacated the CAIR and the CAIR federal implementation plan in their entirety, but subsequently, the court changed course and remanded the rule to the EPA maintaining the rule in effect pending EPA revision. As a result, the CAIR still remains in effect, with the first annual nitrogen oxides compliance year beginning January 1, 2009. The EPA must now revise the rule to resolve the court’s concerns. The court did not set a timetable for the revision.

State and Federal Mercury Air Rules: In March 2005, the EPA issued the CAMR, which required initial reductions of mercury emissions from coal-based 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. The MDEQ is reviewing public comments made in response to a newly released mercury emissions reduction proposal. If this plan becomes effective, we estimate that the associated costs will be approximately $782 million by 2015.

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as RMRR 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 RMRR. In October 2008, we received another information request from the EPA under Section 114 of the Clean Air Act. We responded to this information request in December 2008.

In addition to the EPA’s information request, in October 2008, we received a NOV for three of our coal-based facilities relating to violations of NSR regulations, alleging ten projects from 1986 to 1998 were subject to NSR review. We met with the EPA in January 2009 and have additional meetings scheduled. If the EPA does not accept our interpretation of RMRR, we could be required to install additional pollution control equipment at some or all of our coal-based electric generating plants, surrender emission allowances, engage in supplemental environmental programs or 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. We consider it likely that Congress will enact greenhouse gas legislation, but the form of any final bill is difficult to predict. These laws, or similar state laws or rules, if enacted, could require us to replace equipment, install additional equipment for emission controls, purchase

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allowances, curtail operations, arrange for alternative sources of supply, 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.

In July 2008, the EPA 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. We submitted comments to the EPA on this issue in November 2008. In addition to the potential for federal actions related to greenhouse gas regulation, the State of Michigan has convened the Michigan Climate Action Council, a climate change stakeholder process. 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 existing power plants. The EPA compliance options in the rule were challenged before the U.S. Court of Appeals for the Second Circuit, which remanded the bulk of the rule back to the EPA for reconsideration in January 2007. In April 2008, the U.S. Supreme Court agreed to hear an industry challenge to the appellate court ruling in this case. A decision from the U.S Supreme Court is expected in the first half of 2009. The EPA is planning to issue a revised draft rule in 2009, following the court decision.

We estimate that capital expenditures to comply with these regulations will be approximately $128 million; however an unfavorable U.S. Supreme Court decision could increase expenditures significantly.

We will continue to monitor these developments and respond to their potential implications for our business, consolidated results of operations, cash flows, and financial position. For additional details on electric environmental matters, see Note 4, Contingencies, “Consumers’ Electric Utility Contingencies - Electric Environmental Matters.”

Stranded Cost Recovery: In October 2008, the Michigan legislature enacted legislation that amended the Customer Choice Act and directed the MPSC to approve rates that will allow recovery of Stranded Costs within five years. In January 2009, we filed an application with the MPSC requesting recovery of these Stranded Costs through a surcharge on both full service and ROA customers. At December 31, 2008, we had a regulatory asset for Stranded Costs of $71 million.

Electric Rate Case: In November 2008, we filed an application with the MPSC seeking an annual increase in revenue of $214 million based on an 11 percent authorized return on equity. The filing seeks recovery of costs associated with new plant investments including Clean Air Act investments, higher operating and maintenance costs, and the approval to recover costs associated with our advanced metering infrastructure program. The Michigan legislation enacted in October 2008 generally allows utilities to self-implement rates six months after filing, subject to refund, unless the MPSC finds good cause to prohibit such self-implementation. We cannot predict the financial impact or outcome of this proceeding.

Palisades Regulatory Proceedings: We sold Palisades to Entergy in April 2007. The MPSC order approving the transaction required 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 $109 million above the amount in the MPSC order. The distribution of these funds is still pending with the MPSC.

For additional details on electric rate matters, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters.”

GAS UTILITY BUSINESS OUTLOOK

Gas Deliveries: For 2009, we expect gas deliveries to decrease by 3.4 percent compared with 2008, or 4.7 percent, excluding impacts from differences in weather, due to continuing conservation and overall economic

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conditions in Michigan. We expect gas deliveries to average a decline of less than 1.6 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,

•  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.”

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. In December 2008, the MPSC approved a partial settlement agreement allowing us to implement the filed depreciation rates, on an interim basis, concurrent with the implementation of settled rates in our 2008 gas rate case. The interim depreciation rates reduce our depreciation expense by approximately $20 million per year and will remain in effect until a final order is issued in our gas depreciation case. 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.

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 could receive in the future. At December 31, 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.

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,

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•  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.

For additional details regarding Enterprises Uncertainties, see Note 4, Contingencies and Part I, Item 3. Legal Proceedings.

OTHER OUTLOOK

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

Emergency Shutoff Protection Rules: In February 2009, the MPSC issued rules that would put additional emergency shutoff protections and service limitation protections in place for our residential electric and natural gas customers. The protection exceeds previous shutoff rules as follows:

•  extends the protection period from March 31, 2009 to April 30, 2009,

•  includes protection for physically or mentally disabled customers of record,

•  expands the qualifications for low income shutoff protection, and

•  gives customers the payment options.

We are presently evaluating the impacts of these rules on our cash flows and financial position.

Litigation and Regulatory Investigation: We are the subject of an investigation by the DOJ regarding inaccurate pricing information provided by CMS MST to certain market publications. 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 I, Item 3. 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 included 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 was 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. In late December 2008, the SEC submitted a report on its study to Congress. The report concluded that mark-to-market accounting was not a major factor in recent bank failures, and recommended that existing fair value and mark-to-market accounting requirements remain in place. The report included recommendations for improving fair value accounting and reporting. We apply this accounting primarily to our derivative instruments and our SERP investments, and we will continue to monitor developments relating to the SEC report, including reactions and responses to the report’s recommendations, for potential impact to us.

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 carrying value of EnerBank’s loan portfolio was $190 million at December 31, 2008 and was funded by deposit liabilities of $176 million. Twelve-month rolling average default rates on loans held by EnerBank have risen from 1.0 percent at

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December 31, 2007 to 1.4 percent at December 31, 2008. Due to recent economic events, EnerBank expects the level of loan defaults to continue to increase throughout 2009 and into 2010, returning to lower levels thereafter.

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 was effective for us upon issuance, 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 for 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 illustrate the concepts. The standard was 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.

EITF Issue 06-11, Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards: This standard, which was effective for us January 1, 2008, 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.

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 amended SFAS No. 133 and FIN 45 to require enhanced disclosures for issuers of credit derivatives and financial guarantees. We have not issued any credit derivatives; thus, this standard applies only to our disclosures about guarantees we have issued. This standard involves disclosures only, and did not

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have a material effect on our consolidated financial statements. For additional details on our guarantees, see Note 4, Contingencies.

FSP FAS 140-4 and FIN 46(R)-8, Disclosures by Public Entities (Enterprises) about Transfers of Financial Assets and Interests in Variable Interest Entities: This standard, which was effective for us for the year ended December 31, 2008, requires companies to provide additional details about their continuing involvement with transferred financial assets and their involvement with VIEs. This standard involves disclosures only, and did not impact our consolidated income, cash flows, or financial position. For additional details, see Note 5, Financings and Capitalization, “Sale of Accounts Receivable,” and Note 17, Consolidation of Variable Interest Entities.

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. In addition, net income (loss) attributable to noncontrolling interests will be included in net income on our Consolidated Statements of Income (Loss). These changes involve presentation only, and will not otherwise impact our consolidated financial statements. The standard will also affect the accounting for changes in a parent’s ownership interest, including deconsolidation of a subsidiary. We will apply these provisions of SFAS No. 160 prospectively to any such transactions.

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 requires 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 the entity’s financial position, financial performance, and cash flows. This standard will not have a material 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. This standard will not have a material impact 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 May 2008, the FASB issued FSP APB 14-1, effective for us January 1, 2009 with retrospective application required. This standard will apply to our convertible debt securities, and will require us to account for the liability and equity components of these securities separately and in a manner that will reflect our borrowing rate for nonconvertible debt. We expect that the retrospective implementation of this standard will result in a reduction of Long-term debt of approximately $22 million, an increase in Current deferred income tax liabilities of approximately $3 million, an increase of Non-current deferred income tax liabilities of $6 million, an increase of Other paid-in capital of approximately $37 million, and an increase of Accumulated deficit of approximately $24 million as of January 1, 2009. We further expect that the implementation of this standard will increase reported interest expense, net of taxes, by approximately $4 million in 2009. 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 with retrospective application required. Under this standard, share-based payment 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. This standard will apply to our outstanding unvested restricted stock awards, which will be considered participating securities and thus will be included in the computation of basic EPS. Had this standard been in place in 2008, it would have reduced 2008 basic and diluted EPS by approximately $0.01. We consider this figure to be representative of the potential impact of this standard on future years’ EPS.

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” for the purpose of assessing potential derivative accounting or balance sheet classification issues. 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. This guidance applies to 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. These features are still considered indexed to our own stock under this new guidance, and thus, this standard will have no impact 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.

FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets: In December 2008, the FASB issued this standard, effective for us for the year ending December 31, 2009. The standard requires expanded annual disclosures about the plan assets in our defined benefit pension and OPEB plans. The required disclosures include information about investment allocation decisions, major categories of plan assets, the inputs and valuation techniques used in the fair value measurements, the effects of significant unobservable inputs on changes in plan assets, and significant concentrations of risk within plan assets. The standard involves disclosures only, and will not impact our consolidated income, cash flows, or financial position.

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CMS Energy Corporation

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

	Years Ended December 31
	2008			2007			2006
	In Millions
Operating Revenue	$	6,821		$	6,464		$	6,126
Earnings from Equity Method Investees		5			40			89
Operating Expenses
Fuel for electric generation		600			523			711
Fuel costs mark-to-market at the MCV Partnership		—			—			204
Purchased and interchange power		1,335			1,407			709
Cost of gas sold		2,277			2,172			2,131
Electric sales contract termination		—			279			—
Other operating expenses		837			976			1,136
Maintenance		193			201			297
Depreciation and amortization		589			540			550
General taxes		204			222			151
Asset impairment charges, net of insurance recoveries		—			204			459
Gain on asset sales, net		(9	)		(21	)		(79	)
		6,026			6,503			6,269
Operating Income (Loss)		800			1			(54	)
Other Income (Deductions)
Interest and dividends		30			96			76
Regulatory return on capital expenditures		33			31			26
Other income		15			41			31
Other expense		(37	)		(39	)		(21	)
		41			129			112
Fixed Charges
Interest on long-term debt		349			382			448
Interest on long-term debt — related parties		14			14			15
Other interest		33			48			27
Capitalized interest		(4	)		(6	)		(10	)
Preferred dividends of subsidiaries		—			—			3
		392			438			483
Income (Loss) Before Income Taxes		449			(308	)		(425	)
Income Tax Expense (Benefit)		142			(195	)		(188	)
Income (Loss) Before Minority Interests (Obligations), Net		307			(113	)		(237	)
Minority Interests (Obligations), Net		7			13			(104	)
Income (Loss) From Continuing Operations		300			(126	)		(133	)
Income (Loss) From Discontinued Operations, Net of Tax (Tax Benefit) of $1, $(1), and $32		—			(89	)		54
Net Income (Loss)		300			(215	)		(79	)
Preferred Dividends		11			11			11
Redemption Premium on Preferred Stock		—			1			—
Net Income (Loss) Available to Common Stockholders	$	289		$	(227	)	$	(90	)

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	Years Ended December 31
	2008		2007			2006
	In Millions, Except Per
	Share Amounts
CMS Energy
Net Income (Loss)
Net Income (Loss) Available to Common Stockholders	$	289	$	(227	)	$	(90	)
Basic Earnings (Loss) Per Average Common Share
Income (Loss) from Continuing Operations	$	1.29	$	(0.62	)	$	(0.66	)
Income (Loss) from Discontinued Operations		—		(0.40	)		0.25
Net Income (Loss) Attributable to Common Stock	$	1.29	$	(1.02	)	$	(0.41	)
Diluted Earnings (Loss) Per Average Common Share
Income (Loss) from Continuing Operations	$	1.23	$	(0.62	)	$	(0.66	)
Income (Loss) from Discontinued Operations		—		(0.40	)		0.25
Net Income (Loss) Attributable to Common Stock	$	1.23	$	(1.02	)	$	(0.41	)
Dividends Declared Per Common Share	$	0.36	$	0.20		$	—

The accompanying notes are an integral part of these statements.

CMS-35

CMS Energy Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31
	2008			2007			2006
	In Millions
Cash Flows from Operating Activities
Net income (loss)	$	300		$	(215	)	$	(79	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation and amortization, net of nuclear decommissioning of $-, $4, and $6		589			545			576
Deferred income taxes and investment tax credit		129			(221	)		(271	)
Minority interests (obligations), net		7			(8	)		(98	)
Asset impairment charges, net of insurance recoveries		—			204			459
Postretirement benefits expense		144			131			131
Electric sales contract termination		—			279			—
Shareholder class action settlement expense		—			—			125
Fuel costs mark-to-market at the MCV Partnership		—			—			204
Regulatory return on capital expenditures		(33	)		(31	)		(26	)
Capital lease and other amortization		36			55			44
Bad debt expense		51			37			28
Loss (gain) on the sale of assets		(9	)		112			(79	)
Earnings from equity method investees		(5	)		(40	)		(89	)
Cash distributions from equity method investees		4			18			75
Postretirement benefits contributions		(51	)		(184	)		(69	)
Shareholder class action settlement payment		—			(125	)		—
Electric sales contract termination payment		(275	)		—			—
Changes in other assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenues		(80	)		(451	)		75
Decrease (increase) in accrued power supply and gas revenue		35			99			(91	)
Increase in inventories		(71	)		(10	)		(105	)
Decrease in accounts payable		(5	)		(45	)		(43	)
Increase (decrease) in accrued expenses		(31	)		(31	)		39
Decrease in the MCV Partnership gas supplier funds on deposit		—			—			(147	)
Increase (decrease) in other current and non-current regulatory liabilities		(178	)		(114	)		59
Decrease in other current and non-current assets		12			37			58
Decrease in other current and non-current liabilities		(10	)		(17	)		(86	)
Net cash provided by operating activities		559			25			690
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)		(792	)		(1,263	)		(670	)
Cost to retire property		(34	)		(28	)		(78	)
Restricted cash and restricted short-term investments		1			49			124
Investments in nuclear decommissioning trust funds		—			(1	)		(21	)
Proceeds from nuclear decommissioning trust funds		—			333			22
Maturity of the MCV Partnership restricted investment securities held-to-maturity		—			—			130
Purchase of the MCV Partnership restricted investment securities held-to-maturity		—			—			(131	)
Proceeds from sale of assets		3			1,717			69
Cash relinquished from sale of assets		—			(113	)		(148	)
Increase in non-current notes receivable		(19	)		(32	)		(50	)
Other investing		2			—			2
Net cash provided by (used in) investing activities		(839	)		662			(751	)

CMS-36

	Years Ended December 31
	2008			2007			2006
	In Millions
Cash Flows from Financing Activities
Proceeds from notes, bonds, and other long-term debt		1,396			515			100
Issuance of common stock		9			15			8
Retirement of bonds and other long-term debt		(1,130	)		(1,095	)		(493	)
Redemption of preferred stock		(1	)		(32	)		—
Payment of common stock dividends		(82	)		(45	)		—
Payment of preferred stock dividends		(13	)		(13	)		(13	)
Payment of capital lease and financial lease obligations		(26	)		(20	)		(26	)
Debt issuance costs, financing fees, and other		(8	)		(17	)		(12	)
Net cash provided by (used in) financing activities		145			(692	)		(436	)
Effect of Exchange Rates on Cash		—			2			1
Net Decrease in Cash and Cash Equivalents		(135	)		(3	)		(496	)
Cash and Cash Equivalents, Beginning of Period		348			351			847
Cash and Cash Equivalents, End of Period	$	213		$	348		$	351
Other cash flow activities and non-cash investing and financing activities were:
Cash transactions
Interest paid (net of amounts capitalized)	$	364		$	432		$	487
Income taxes paid (net of refunds of $2, $- , and $2)		3			14			98
Non-cash transactions
Other assets placed under capital lease	$	5		$	229		$	7

The accompanying notes are an integral part of these statements.

CMS-37

CMS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31
	2008		2007
	In Millions
ASSETS
Plant and Property (At cost)
Electric utility	$	8,965	$	8,555
Gas utility		3,622		3,467
Enterprises		390		391
Other		33		34
		13,010		12,447
Less accumulated depreciation, depletion and amortization		4,428		4,166
		8,582		8,281
Construction work-in-progress		608		447
		9,190		8,728
Equity Investments
Enterprises		5		6
Other		6		5
		11		11
Current Assets
Cash and cash equivalents at cost, which equals fair value		213		348
Restricted cash at cost, which equals fair value		35		34
Accounts receivable and accrued revenue, less allowances of $26 in 2008 and $21 in 2007		851		837
Notes receivable		95		68
Accrued power supply and gas revenue		7		45
Accounts receivable and notes receivable — related parties		—		2
Inventories at average cost
Gas in underground storage		1,168		1,123
Materials and supplies		110		86
Generating plant fuel stock		127		125
Deferred property taxes		165		158
Regulatory assets — postretirement benefits		19		19
Prepayments and other		37		35
		2,827		2,880
Non-current Assets
Regulatory Assets
Securitized costs		416		466
Postretirement benefits		1,431		921
Customer Choice Act		90		149
Other		482		504
Deferred income taxes		—		99
Notes receivable, less allowances of $34 in 2008 and $33 in 2007		186		168
Other		268		266
		2,873		2,573
Total Assets	$	14,901	$	14,192

CMS-38

	December 31
	2008			2007
	In Millions
STOCKHOLDERS’ INVESTMENT AND LIABILITIES
Capitalization
Common stockholders’ equity
Common stock, authorized 350.0 shares; outstanding 226.4 shares and 225.1 shares, respectively	$	2		$	2
Other paid-in capital		4,496			4,480
Accumulated other comprehensive loss		(28	)		(144	)
Accumulated deficit		(2,007	)		(2,208	)
		2,463			2,130
Preferred stock of subsidiary		44			44
Preferred stock		243			250
Long-term debt		5,859			5,385
Long-term debt — related parties		178			178
Non-current portion of capital and finance lease obligations		206			225
		8,993			8,212
Minority Interests		52			53
Current Liabilities
Current portion of long-term debt, capital and finance lease obligations		514			722
Notes payable		—			1
Accounts payable		466			430
Accrued rate refunds		7			19
Accounts payable — related parties		—			1
Accrued interest		107			103
Accrued taxes		289			308
Deferred income taxes		100			41
Regulatory liabilities		120			164
Electric sales contract termination liability		2			279
Argentine currency impairment reserve		—			197
Other		258			208
		1,863			2,473
Non-current Liabilities
Regulatory Liabilities
Cost of removal		1,203			1,127
Income taxes, net		519			533
Other		146			313
Postretirement benefits		1,502			858
Asset retirement obligation		206			198
Deferred investment tax credit		54			58
Deferred income taxes		46			—
Other		317			367
		3,993			3,454
Commitments and Contingencies (Notes 4, 5, 7, 10 and 12)
Total Stockholders’ Investment and Liabilities	$	14,901		$	14,192

The accompanying notes are an integral part of these statements.

CMS-39

CMS Energy Corporation

Consolidated Statements of Common Stockholders’ Equity

	Years Ended December 31
	2008			2007			2006			2008			2007			2006
	Number of Shares in Thousands									In Millions
Common Stock
At beginning and end of period										$	2		$	2		$	2
Other Paid-in Capital
At beginning of period		225,146			222,783			220,497			4,480			4,468			4,436
Common stock repurchased		(38	)		(318	)		(98	)		(1	)		(5	)		(2	)
Common stock reacquired		(445	)		(19	)		(59	)		—			—			—
Common stock issued		1,751			2,339			2,375			17			30			33
Common stock reissued		—			361			68			—			6			1
Redemption of preferred stock		—			—			—			—			(19	)		—
At end of period		226,414			225,146			222,783			4,496			4,480			4,468
Accumulated Other Comprehensive Loss
Retirement benefits liability
At beginning of period											(15	)		(23	)		(19	)
Retirement benefits liability adjustments(a)											—			—			3
Net gain (loss) arising during the period(a)											(12	)		7			—
Amortization of net actuarial loss(a)											—			1			—
Adjustment to initially apply FASB Statement No. 158											—			—			(7	)
At end of period											(27	)		(15	)		(23	)
Investments
At beginning of period											—			14			9
Unrealized gain (loss) on investments(a)											(15	)		1			5
Reclassification adjustments included in net income (loss)(a)											15			(15	)		—
At end of period											—			—			14
Derivative instruments
At beginning of period											(1	)		(12	)		35
Unrealized loss on derivative instruments(a)											—			(3	)		(15	)
Reclassification adjustments included in net income (loss)(a)											—			14			(32	)
At end of period											(1	)		(1	)		(12	)
Foreign currency translation
At beginning of period											(128	)		(297	)		(313	)
Sale of interests in TGN(a)											128			—			—
Sale of Argentine assets(a)											—			128			—
Sale of Brazilian assets(a)											—			36			—
Other foreign currency translations(a)											—			5			16
At end of period											—			(128	)		(297	)
At end of period											(28	)		(144	)		(318	)
Accumulated Deficit
At beginning of period											(2,208	)		(1,918	)		(1,828	)
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											—			(18	)		—
Net income (loss)(a)											300			(215	)		(79	)
Preferred stock dividends declared											(11	)		(11	)		(11	)
Common stock dividends declared											(82	)		(45	)		—
Redemption of preferred stock(a)											—			(1	)		—
At end of period											(2,007	)		(2,208	)		(1,918	)
Total Common Stockholders’ Equity										$	2,463		$	2,130		$	2,234

CMS-40

	Years Ended December 31
	2008			2007			2006
	In Millions
(a) Disclosure of Comprehensive Income (Loss):
Net income (loss)	$	300		$	(215	)	$	(79	)
Retirement benefits liability:
Retirement benefits liability adjustments, net of tax of $1 in 2006		—			—			3
Net gain (loss) arising during the period, net of tax (tax benefit) of ($6) in 2008 and $5 in 2007		(12	)		7			—
Amortization of net actuarial loss, net of tax of $-		—			1			—
Investments:
Unrealized gain (loss) on investments, net of tax (tax benefit) of ($9) in 2008, $- in 2007 and $2 in 2006		(15	)		1			5
Reclassification adjustments included in net income (loss), net of tax (tax benefit) of $9 in 2008 and ($7) in 2007		15			(15	)		—
Derivative instruments:
Unrealized loss on derivative instruments, net of tax (tax benefit) of $- in 2008, $2 in 2007, and $(11) in 2006		—			(3	)		(15	)
Reclassification adjustments included in net income (loss), net of tax (tax benefit) of $- in 2008, $7 in 2007, and $(19) in 2006		—			14			(32	)
Foreign currency translation:
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, net of tax of $- in 2008, $2 in 2007, and $9 in 2006		—			5			16
Total Comprehensive Income (Loss)	$	416		$	(41	)	$	(102	)

The accompanying notes are an integral part of these statements.

CMS-41

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Unbilled revenues are estimated by applying an average billed rate for each customer class based on actual billed volume distributions. Our unbilled revenues, which are recorded as Accounts receivable on our Consolidated Balance Sheets, were $507 million at December 31, 2008 and $490 million at December 31, 2007. We record sales tax on a net basis and exclude it from revenues. We recognize revenues on sales of marketed electricity, natural gas, and other energy products at delivery.

Accounting for Legal Fees: We expense legal fees as incurred; fees incurred but not yet billed are accrued based on estimates of work performed. This policy also applies to fees incurred on behalf of employees and officers related to indemnification agreements; these fees are billed directly to us.

Accounting for MISO Transactions: MISO requires that we submit hourly day-ahead and real-time bids and offers for energy at locations across the MISO region. Consumers and CMS ERM account for MISO transactions on a net hourly basis in each of the real-time and day-ahead markets, and net transactions across all MISO energy market locations. We record net purchases in a single hour in “Purchased and interchange power” and net sales in a single hour in “Operating Revenue” in the Consolidated Statements of Income (Loss). We record net sale billing adjustments when we receive invoices. We record expense accruals for future net purchases adjustments based on historical experience, and reconcile accruals to actual expenses when we receive invoices.

Capitalized Interest: We capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest is limited to the actual interest cost incurred. Consumers capitalizes AFUDC on regulated construction projects and includes these amounts in plant in service.

Cash and Cash Equivalents: Cash and cash equivalents include short-term, highly liquid investments with original maturities of three months or less.

Collective Bargaining Agreements: At December 31, 2008, the Union represented 45 percent of Consumers’ employees. The Union represents Consumers’ operating, maintenance, construction, and call center employees.

CMS-42

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Determination of Pension and OPEB MRV of Plan Assets: We determine the MRV for pension plan assets, as defined in SFAS No. 87, as the fair value of plan assets on the measurement date, adjusted by the gains or losses that will not be admitted into MRV until future years. We reflect each year’s assets gain or loss in MRV in equal amounts over a five-year period beginning on the date the original amount was determined. We determine the MRV for OPEB plan assets, as defined in SFAS No. 106, as the fair value of assets on the measurement date. We use the MRV in the calculation of net pension and OPEB costs.

Earnings Per Share: We calculate basic and diluted EPS using the weighted-average number of shares of common stock and dilutive potential common stock outstanding during the period. Potential common stock, for purposes of determining diluted EPS, includes the effects of dilutive stock options, warrants and convertible securities. We compute the effect on potential common stock using the treasury stock method or the if-converted method, as applicable. Diluted EPS excludes the impact of antidilutive securities, which are those securities resulting in an increase in EPS or a decrease in loss per share. For EPS computation, see Note 6, Earnings Per Share.

Financial and Derivative Instruments: We record debt and equity securities classified as available-for-sale at fair value determined primarily from quoted market prices. On a specific identification basis, we report unrealized gains and losses from changes in fair value of certain available-for-sale debt and equity securities, net of tax, in equity as part of AOCL. We exclude unrealized losses from earnings unless the related changes in fair value are determined to be other than temporary.

In accordance with SFAS No. 133, if a contract is a derivative and does not qualify for the normal purchases and sales exception, we record it on our Consolidated Balance Sheets at its fair value. If a derivative qualifies for cash flow hedge accounting, we report changes in its fair value in AOCL; otherwise, we report the changes in earnings.

For additional details regarding financial and derivative instruments, see Note 7, Financial and Derivative Instruments.

Impairment of Long-Lived Assets and Equity Method Investments: We perform tests of impairment if certain triggering events occur, or if there has been a decline in value that may be other than temporary.

We evaluate our long-lived assets held-in-use for impairment by calculating the undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. If the undiscounted future cash flows are less than the carrying amount, we recognize an impairment loss equal to the amount by which the carrying amount exceeds the fair value. We estimate the fair value of the asset using quoted market prices, market prices of similar assets, or discounted future cash flow analyses.

We also assess our equity method investments for impairment whenever there has been a decline in value that is other than temporary. This assessment requires us to determine the fair values of our equity method investments. We determine fair value using valuation methodologies, including discounted cash flows, and we assess the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. We record an impairment if the fair value is less than the carrying value and the decline in value is considered to be other than temporary.

For additional details, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

International Operations and Foreign Currency: We completed the sale of our international assets in 2007. Previously, our subsidiaries and affiliates whose functional currency was not the U.S. dollar translated their assets and liabilities into U.S. dollars at the exchange rates in effect at the end of the fiscal period. We translated revenue and expense accounts of these subsidiaries and affiliates into U.S. dollars at the average exchange rates that prevailed during the period. We showed these foreign currency translation adjustments in the stockholders’ equity

CMS-43

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

section on our Consolidated Balance Sheets. We include exchange rate fluctuations on transactions denominated in a currency other than the functional currency, except those that are hedged, in determining net income.

For additional details on the sale of our international assets, see Note 3, Asset Sales, Discontinued Operations and Impairment Charges.

Inventory: We use the weighted-average cost method for valuing working gas, recoverable cushion gas in underground storage facilities, and materials and supplies inventory. We also use this method for valuing coal inventory, and we classify these costs as generating plant fuel stock on our Consolidated Balance Sheets.

We classify emission allowances as materials and supplies inventory and use the average cost method to remove amounts from inventory as we use the emission allowances to generate power.

Maintenance and Depreciation: We charge property repairs and minor property replacement to maintenance expense. We use the direct expense method to account for planned major maintenance activities. We charge planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements.

We depreciate utility property using a composite method, in which we apply a single MPSC-approved depreciation rate to the gross investment in a particular class of property within the electric and gas divisions. We perform depreciation studies periodically to determine appropriate group lives. The composite depreciation rates for our properties are as follows:

Years Ended December 31	2008			2007			2006
Electric utility property		3.0	%		3.0	%		3.1	%
Gas utility property		3.6	%		3.6	%		3.6	%
Other property		8.5	%		8.7	%		8.2	%

CMS-44

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

Years Ended December 31	2008		2007		2006
	In Millions
Other income
Interest and dividends — related parties	$	—	$	—	$	8
Gain on SERP investment		—		22		—
Return on stranded and security costs		5		6		5
MCV Partnership emission allowance sales		—		—		8
Electric restructuring return		1		2		4
Foreign currency gain		2		1		—
Gain on investment		—		7		1
Refund of surety bond premium		—		—		1
All other		7		3		4
Total other income	$	15	$	41	$	31

Years Ended December 31	2008			2007			2006
	In Millions
Other expense
Accretion expense	$	—		$	—		$	(4	)
Unrealized investment loss		(24	)		—			—
Loss on reacquired and extinguished debt		—			(22	)		(5	)
Abandoned Midland project		—			(8	)		—
Derivative loss on debt tender offer		—			(3	)		—
Civic and political expenditures		(5	)		(2	)		(2	)
Donations		—			—			(9	)
All other		(8	)		(4	)		(1	)
Total other expense	$	(37	)	$	(39	)	$	(21	)

Property, Plant, and Equipment: We record property, plant, and equipment at original cost when placed into service. When utility property is retired, or otherwise disposed of in the ordinary course of business, we charge the original cost to accumulated depreciation, along with associated cost of removal, net of salvage. We recognize gains or losses on the retirement or disposal of non-regulated assets in income. Our internal-use computer software costs are capitalized or expensed in accordance with Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. For additional details, see Note 9, Asset Retirement Obligations and Note 13, Property, Plant, and Equipment. Cost of removal collected from our customers, but not spent, is recorded as a regulatory liability.

We capitalize AFUDC on regulated major construction projects. AFUDC represents the estimated cost of debt and a reasonable return on equity funds used to finance construction additions. We record the offsetting credit as a reduction of interest for the amount representing the borrowed funds component and as other income for the equity funds component in the Consolidated Statements of Income (Loss). When construction is completed and the

CMS-45

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

property is placed in service, we depreciate and recover the capitalized AFUDC from our customers over the life of the related asset. The following table shows our electric, gas and common composite AFUDC capitalization rates:

Years Ended December 31	2008			2007			2006
AFUDC capitalization rate		7.7	%		7.4	%		7.5	%

Property Taxes: Property taxes are based upon the taxable value of Consumers’ real and personal property assessed by local units of government within the State of Michigan. We record property tax expense ratably over the fiscal year of the taxing authority for which the taxes are levied based on budgeted Consumers’ customer sales. The deferred property tax balance represents the amount of Consumers’ accrued property tax, which will be recognized over future governmental fiscal periods.

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.

Restricted Cash: We classify restricted cash dedicated for repayment of Securitization bonds as a current asset, as the related payments occur within one year.

Trade Receivables and Notes Receivable: Accounts receivable are primarily composed of trade receivables and unbilled receivables. We record our accounts receivable at cost which approximates fair value. We establish an allowance for uncollectible accounts and loan losses based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. We assess late payment fees on trade receivables based on contractual past-due terms established with customers. We charge accounts deemed uncollectible to operating expense.

At December 31, 2008, Non-current notes receivable included EnerBank’s loans totaling $186 million, net of an allowance for loan losses of $4 million. EnerBank provides unsecured, fixed-rate installment loans to homeowners to finance the purchase of home improvements.

Unamortized Debt Premium, Discount, and Expense: We capitalize premiums, discounts, and issuance costs of long-term debt and amortize those costs over the terms of the debt issues. For the non-regulated portions of our businesses, we expense any refinancing costs as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and issuance costs and amortize them over the terms of the newly issued debt.

Utility Regulation: Consumers is subject to the actions of the MPSC and the FERC and prepares its consolidated financial statements in accordance with the provisions of SFAS No. 71. As a result, Consumers may defer or recognize revenues and expenses differently than a non-regulated entity. For example, Consumers may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate that Consumers will recover the expenses in future rates. Conversely, Consumers may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate that Consumers will be required to refund the revenues to customers.

We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets.

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December 31	End of Recovery or Refund Period	2008		2007
	In Millions
Assets Earning a Return:
Customer Choice Act	2010	$	90	$	149
Stranded Costs	See Note 4		71		68
Electric restructuring implementation plan	2009		3		14
Manufactured gas plant sites (Note 4)	2018		31		33
Other(a)	various		44		50
Assets Not Earning a Return:
Postretirement Benefits (Note 8)	various		1,450		940
Securitized costs (Note 5)	2015		416		466
Unamortized debt costs	n/a		66		74
ARO (Note 9)	n/a		92		85
Big Rock nuclear decommissioning and related costs (Note 4)	n/a		129		129
Manufactured gas plant sites (Note 4)	n/a		38		17
Palisades sales transaction costs (Notes 3 and 4)	n/a		—		28
Other(a)	2011		8		6
Total regulatory assets(b)		$	2,438	$	2,059
Palisades refund — Current (Note 4)(c)	2009	$	120	$	164
Cost of removal (Note 9)	n/a		1,203		1,127
Income taxes, net (Note 10)	n/a		519		533
ARO (Note 9)	n/a		137		141
Palisades refund — Non-current (Note 4)(c)	2008		—		140
Other(a)	various		9		32
Total regulatory liabilities(b)		$	1,988	$	2,137

(a)	At December 31, 2008 and 2007, other regulatory assets include a gas inventory regulatory asset and OPEB and pension expense incurred in excess of the MPSC-approved amount. We will recover these regulatory assets from our customers by 2011. Other regulatory liabilities include liabilities related to the sale of sulfur dioxide allowances and AFUDC collected in excess of the MPSC-approved amount.
(b)	At December 31, 2008 and 2007, we classified $19 million of regulatory assets as current regulatory assets. At December 31, 2008, we classified $120 million of regulatory liabilities as current regulatory liabilities. At December 31, 2007, we classified $164 million of regulatory liabilities as current regulatory liabilities.
(c)	The MPSC order approving the Palisades and Big Rock ISFSI sale transaction required that we credit $255 million of excess sales proceeds and decommissioning amounts to our retail customers by December 2008. For 2007, the current portion of regulatory liabilities for Palisades refunds represents the remaining portion of this obligation, plus interest. There are additional excess sales proceeds and decommissioning fund balances above the amount in the MPSC order. For 2007, the non-current portion of regulatory liabilities for Palisades refunds represents this obligation, plus interest. For 2008, these additional excess sales proceeds are reported in the current portion of regulatory liabilities for Palisades refunds as it is probable the proceeds will be credited to customers within one year. For additional details, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters.”

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Our PSCR and GCR cost recovery mechanisms also represent probable future revenues that will be recovered from customers or previously collected revenues that will be refunded to customers through the ratemaking process. Underrecoveries are included in Accrued power supply and gas revenue and overrecoveries are included in Accrued rate refunds on our Consolidated Balance Sheets. For additional details on PSCR, see Note 4, Contingencies, “Consumers’ Electric Utility Rate Matters — Power Supply Costs” and for additional details on GCR, see Note 4, Contingencies, “Consumers’ Gas Utility Rate Matters — Gas Cost Recovery.”

We reflect the following regulatory assets and liabilities for underrecoveries and overrecoveries on our Consolidated Balance Sheets:

Years Ended December 31	2008		2007
	In Millions
Regulatory Assets for PSCR and GCR
Underrecoveries of power supply and gas costs	$	7	$	45
Regulatory Liabilities for PSCR and GCR
Overrecoveries of power supply and gas costs	$	7	$	19

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. In addition, net income (loss) attributable to noncontrolling interests will be included in net income on our Consolidated Statements of Income (Loss). These changes involve presentation only, and will not otherwise impact our consolidated financial statements. The standard will also affect the accounting for changes in a parent’s ownership interest, including deconsolidation of a subsidiary. We will apply these provisions of SFAS No. 160 prospectively to any such transactions.

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 requires 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 the entity’s financial position, financial performance, and cash flows. This standard will not have a material 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. This standard will not have a material impact 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 May 2008, the FASB issued FSP APB 14-1, effective for us January 1, 2009

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with retrospective application required. This standard will apply to our convertible debt securities, and will require us to account for the liability and equity components of these securities separately and in a manner that will reflect our borrowing rate for nonconvertible debt. We expect that the retrospective implementation of this standard will result in a reduction of Long-term debt of approximately $22 million, an increase in Current deferred income tax liabilities of approximately $3 million, an increase of Non-current deferred income tax liabilities of $6 million, an increase of Other paid-in capital of approximately $37 million, and an increase of Accumulated deficit of approximately $24 million as of January 1, 2009. We further expect that the implementation of this standard will increase reported interest expense, net of taxes, by approximately $4 million in 2009. 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 with retrospective application required. Under this standard, share-based payment 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. This standard will apply to our outstanding unvested restricted stock awards, which will be considered participating securities and thus will be included in the computation of basic EPS. Had this standard been in place in 2008, it would have reduced 2008 basic and diluted EPS by approximately $0.01. We consider this figure to be representative of the potential impact of this standard on future years’ EPS.

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” for the purpose of assessing potential derivative accounting or balance sheet classification issues. 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. This guidance applies to 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. These features are still considered indexed to our own stock under this new guidance, and thus, this standard will have no impact 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.

FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets: In December 2008, the FASB issued this standard, effective for us for the year ending December 31, 2009. The standard requires expanded annual disclosures about the plan assets in our defined benefit pension and OPEB plans. The required disclosures include information about investment allocation decisions, major categories of plan assets, the inputs and valuation techniques used in the fair value measurements, the effects of significant unobservable inputs on changes in plan assets, and significant concentrations of risk within plan assets. The standard involves disclosures only, and will not impact our consolidated income, cash flows, or financial position.

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

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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 year ended December 31, 2008. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we held during the year ended December 31, 2008.

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

•  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 this 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 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 became effective on 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, nonqualified deferred compensation plan assets and liabilities, and financial instruments disclosed in Note 7, Financial and Derivative Instruments, “Financial Instruments.” SFAS No. 157 also applied to the year-end measurement of fair values of our pension and OPEB plan assets. For details on the accounting of our pension and OPEB plans, see Note 8, Retirement Benefits. The implementation of SFAS No. 157 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 was effective for us upon issuance, 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 the FASB and was effective for us for the quarter ended September 30, 2008. The standard was to be applied prospectively. The guidance in this standard and the joint guidance provided by the FASB and the SEC did not affect our fair value measurements.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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 reported at fair value on a recurring basis at December 31, 2008.

	Total			Level 1			Level 2			Level 3
	In Millions
Assets:
Cash Equivalents	$	176		$	176		$	—		$	—
Nonqualified Deferred Compensation Plan Assets		5			5			—			—
SERP
Equity Securities		39			39			—			—
Debt Securities		29			—			29			—
Derivative Instruments:
CMS ERM Non-trading electricity/gas contracts(a)		1			—			1			—
Total	$	250		$	220		$	30		$	—
Liabilities:
Nonqualified Deferred Compensation Plan Liabilities	$	(5	)	$	(5	)	$	—		$	—
Derivative Instruments:
CMS ERM Non-trading electricity/gas contracts(b)		(17	)		(2	)		—			(15	)
Interest rate collar		(1	)		—			—			(1	)
Foreign exchange forward		(1	)		—			(1	)		—
Fixed price fuel contracts		(1	)		—			(1	)		—
Total(c)	$	(25	)	$	(7	)	$	(2	)	$	(16	)

(a)	This amount is gross and excludes the immaterial 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 immaterial impact of offsetting derivative assets and liabilities under master netting arrangements and the $2 million impact of offsetting cash margin deposits paid by CMS ERM to other parties. We report the fair values of our derivative liabilities net of these impacts within Other liabilities on our Consolidated Balance Sheets.
(c)	At December 31, 2008, liabilities classified as Level 3 represent 64 percent of total liabilities measured at fair value.

Cash Equivalents: Our cash equivalents consist of money market funds with daily liquidity. The funds invest in U.S. Treasury notes, other government-backed securities, and repurchase agreements collateralized by U.S. Treasury notes.

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 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

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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 movements 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.

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.

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. These 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. Adjustments for credit risk using the approach outlined above are not materially different than the adjustments that would result from using credit default swap rates for the contracts we currently hold. For details about our derivative contracts, see Note 7, Financial and Derivative Instruments.

Interest Rate Collar: Grayling Generating Station Limited Partnership executed an interest rate collar contract as an economic hedge of the variable interest rate charged on its outstanding revenue bonds. This interest rate collar was valued using an income approach that incorporated forward interest rates and a consideration of appropriate credit risk in discounting projected cashflows. Due to the use of unobservable assumptions in the credit risk component, we have classified the fair value of this contract as Level 3. We record the fair value of this derivative in Other non-current liabilities on our Consolidated Balance Sheets. For additional information on our interest rate collar, see Note 7, Financial and Derivative Instruments, “Derivative Instruments.”

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Foreign Exchange Forward: We executed this foreign exchange forward contract as an economic hedge of an exposure to the Moroccan dirham/US dollar exchange rate. This contract was valued using an income approach that incorporated forward exchange rates and a consideration of appropriate credit risk in discounting projected cashflows. We recorded the fair value of this derivative in Other current liabilities on our Consolidated Balance Sheets at December 31, 2008. For additional information on our foreign exchange forward, see Note 7, Financial and Derivative Instruments, “Derivative Instruments.”

Fixed Price Fuel Contracts: Under certain fixed price fuel contracts, we have effectively locked in a price per gallon for gasoline and diesel fuel we will purchase from January 2009 through November 2009. These contracts are valued using an income approach that incorporated forward national fuel prices adjusted to reflect conditions in Michigan. The fair values of these contracts are included in Other current liabilities on our Consolidated Balance Sheets. For additional information on our fixed fuel price contracts, see Note 7, Financial and Derivative Instruments, “Derivative Instruments.”

Assets and 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:

	CMS ERM
	Non-trading
	contracts
	In Millions
Balance at December 31, 2007	$	(19	)
Total gains (realized and unrealized)
Included in earnings(a)		2
Purchases, sales, issuances, and settlements (net)		1
Balance at December 31, 2008		(16	)
Unrealized gains included in earnings for the year ended December 31, 2008 relating to assets and liabilities still held at December 31, 2008(a)	$	3

(a) Realized and unrealized gains 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).

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 year ended December 31, 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, 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, and the rights to any proceeds Enterprises will receive if it sells its stock interest in CMS Generation San Nicolas Company.

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 and we recognized an $8 million 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,

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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 December 31, 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 year ended December 31, 2007:

							Disposal of
				Continuing			Discontinued
				Operations			Operations
		Cash		Pretax			Pretax
Month sold	Business	Proceeds		Gain (Loss)			Gain (Loss)
		In Millions
March	El Chocon(a)	$	50	$	34		$	—
March	Argentine/Michigan businesses(b)		130		(5	)		(278	)
April	Palisades(c)		333		—			—
April	SENECA(d)		106		—			46
May	Middle East, Africa and India businesses(e)		792		(15	)		96
June	CMS Energy Brasil S.A.(f)		201		—			3
August	GasAtacama(g)		80		—			—
October	Jamaica(h)		14		1			—
Various	Other		11		6			—
	Total	$	1,717	$	21		$	(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 2007.
(c)	We sold Palisades to Entergy for $380 million and as of December 31, 2007, received $363 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 (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.
(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.
(h)	We sold our investment in Jamaica to AEI.

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The following table summarizes our asset sales for the year ended December 31, 2006:

				Continuing
				Operations
		Gross Cash		Pretax
Month sold	Business/Project	Proceeds		Gain
		In Millions
October	Land in Ludington, Michigan	$	6	$	2
November	MCV GP II(a)		61		77
Various	Other		2		—
	Total	$	69	$	79

(a) In November 2006, we sold all of our interests in the Consumers’ subsidiaries that held the MCV Partnership and the MCV Facility to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments.

Because of the MCV PPA, the transaction is a sale and leaseback for accounting purposes. We have continuing involvement with the MCV Partnership through an existing guarantee associated with the future operations of the MCV Facility. As a result, we accounted for the MCV Facility as a financing for accounting purposes and not a sale. The value of the finance obligation was based on an allocation of the transaction proceeds to the fair values of the net assets sold and fair value of the MCV Facility under the financing. The total proceeds were less than the fair value of the net assets sold. As a result, there were no proceeds remaining to allocate to the MCV Facility; therefore, we recorded no finance obligation.

The transaction resulted in an after-tax loss of $41 million, which includes a reclassification of $30 million of AOCI into earnings, an $80 million impairment charge on the MCV Facility, an $8 million gain on the removal of our interests in the MCV Partnership and the MCV Facility, and $1 million benefit in general taxes. Upon the sale of our interests in the MCV Partnership and the FMLP, we were no longer the primary beneficiary of these entities and the entities were deconsolidated.

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):

Years Ended December 31	2008		2007			2006
	In Millions
Revenues	$	—	$	235		$	684
Discontinued operations:
Pretax income (loss) from discontinued operations	$	1	$	(90	)	$	86
Income tax expense (benefit)		1		(1	)		32
Income (Loss) From Discontinued Operations	$	—	$	(89	)(a)	$	54

(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).

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 for 2007 and $17 million for 2006 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 recorded no impairments of long-lived assets for the year ended December 31, 2008. The following table summarizes asset impairments at our Enterprises business segment for the years ended December 31, 2007 and December 31, 2006:

Years Ended December 31	2007		2006
	In Millions
Asset impairments:
TGN(a)	$	140	$	—
GasAtacama(b)		35		239
Jamaica(c)		22		—
PowerSmith(d)		5		—
Prairie State(e)		2		—
MCV Partnership(f)		—		218
Other		—		2
Total asset impairments	$	204	$	459

(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 2007, we recognized a $75 million deferred credit in Asset impairment charges, net of insurance recoveries, in our Consolidated Statements of Income (Loss).
(b)	In 2007, we recorded an impairment charge to reflect the fair value of our investment in GasAtacama as determined in sale negotiations. In 2006, we performed an impairment analysis of our investment in GasAtacama and concluded that there had been a decline in fair value that was other than temporary. We recorded an impairment charge in the third quarter of 2006.
(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.
(f)	We recorded an impairment charge of $218 million to recognize the reduction in fair value of the MCV Facility’s real estate assets.

4: CONTINGENCIES

CMS Energy Contingencies

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

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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. There were two recent dismissals of the CMS Energy defendants: Missouri Public Service Commission, state court on January 13, 2009, and Breckenridge, federal court on January 8, 2009. On February 23, 2009, the court also granted CMS Energy’s motion to dismiss for lack of jurisdiction. Appeals are expected in both cases. The other cases in several jurisdictions remain pending. We cannot predict the financial impact or outcome of these matters.

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 voluntarily executed an AOC under Superfund and approved a Removal Action Work Plan to address issues 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 measures 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, Beeland, 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. The EPA has denied the appeal. One appeal relating to the state permit remains pending in the state court. Groups opposed to the injection well filed a lawsuit in Antrim County seeking an injunction against development of the well. In January 2009, the trial judge issued a preliminary injunction. Beeland is considering an appeal of the court’s order.

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:

•  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 a cumulative charge, which includes accretion expense, related to Bay Harbor of $141 million. At December 31, 2008, we have a recorded liability of $62 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. We based the discount rate on the interest rate for 30-year U.S. Treasury securities on December 31, 2007, the date of the last major revision to our remediation cost

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estimate. The undiscounted amount of the remaining obligation is $75 million. We expect to pay $21 million in 2009, $12 million in 2010, $3 million 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,

•  delays in developing a long-term water disposal option,

•  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 material adverse effect on CMS Energy’s liquidity and financial condition 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 no 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 of up to $10 million.

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.

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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. A number of factors, including the number of potentially responsible parties involved with each site, affect our share of the total liability. As of December 31, 2008, we have recorded a liability of $2 million, the minimum amount of our range of possible outcomes 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. Periodically, we receive information about new sites, which leads us to review our response activity estimates. Any significant change in the underlying 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 estimates of NREPA and Superfund liability.

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. 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 fourteen 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 RMRR 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 RMRR. In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. We responded to this information request in December 2008. In addition to the EPA’s information request, in October 2008, we received a NOV for three of our coal-based facilities relating to violations of NSR regulations, alleging ten projects from 1986 to 1998 were subject to NSR review. We met with the EPA in January 2009 and have additional meetings scheduled. If the EPA does not accept our interpretation of RMRR, we could be required to install additional pollution control equipment at some or all of our coal-based electric generating plants, surrender emission allowances, engage in supplemental environmental programs 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.

Clean Air Interstate Rule: In March 2005, the EPA adopted the CAIR, which required additional coal-based 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. The court initially vacated the CAIR and the CAIR federal implementation plan in their entirety, but subsequently, the court changed course and remanded the rule to the EPA maintaining the rule in effect pending EPA revision. As a result, the CAIR still remains in effect, with the first annual nitrogen oxides compliance year beginning January 1, 2009. The EPA must now revise the rule to resolve the court’s concerns. The court did not set a timetable for the revision. We cannot predict the financial impact or outcome of this matter.

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Litigation: Our transmission charges 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 will 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

Stranded Cost Recovery: In November 2004, the MPSC approved recovery of our Stranded Costs incurred in 2002 and 2003 plus interest through the period of collection through a surcharge on ROA customers. Since the MPSC order, we have experienced a downward trend in ROA customers, although recently this trend has slightly reversed. In October 2008, the Michigan legislature enacted legislation that amended the Customer Choice Act and directed the MPSC to approve rates that will allow recovery of Stranded Costs within five years. In January 2009, we filed an application with the MPSC requesting recovery of these Stranded Costs through a surcharge on both full service and ROA customers. At December 31, 2008, we had a regulatory asset for Stranded Costs of $71 million.

Power Supply Costs: The PSCR process is designed to allow us to recover all of our power supply 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 PSCR reconciliation filing currently pending with the MPSC:

Power Supply Cost Recovery Reconciliation
		Net Under-	PSCR Cost
PSCR Year	Date Filed	recovery	of Power Sold	Description of Net Underrecovery
2007	March 2008	$42 million(a)	$1.628 billion	In our 2007 PSCR Plan we expected to offset power supply costs by including a $44 million credit for Palisades sale proceeds due customers. However, the MPSC directed that the Palisades sale proceeds be refunded through bill credits outside of the PSCR process.

(a) This amount includes 2006 underrecoveries as allowed by the MPSC order in our 2007 PSCR plan 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 of $42 million. We self-implemented a 2008 PSCR charge in January 2008. In November 2008, the MPSC issued an order approving our PSCR plan factor.

2009 PSCR Plan: In September 2008, we submitted our 2009 PSCR plan filing to the MPSC. The plan seeks approval to apply a uniform maximum PSCR factor of $0.02680 per kWh for all classes of customers. The plan also seeks approval to recover an expected $22 million discount in power supply charges provided to a large industrial customer. The MPSC approved the discount in 2005 to promote long-term investments in the industrial infrastructure of Michigan. We self-implemented a 2009 PSCR charge in January 2009.

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.

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Electric Rate Case: In November 2008, we filed an application with the MPSC seeking an annual increase in revenue of $214 million based on an 11 percent authorized return on equity. The filing seeks recovery of costs associated with new plant investments including Clean Air Act investments, higher operating and maintenance costs, and the approval to recover costs associated with our advanced metering infrastructure program. The following table details the components of the requested increase in revenue:

Components of the Increase in Revenue
	In Millions
Operating and maintenance	$	50
Rate of return		17
Rate base		76
Book depreciation on new investment		14
Property taxes on new investment		9
Gross margin		43
Other		5
Total	$	214

This is the first electric rate case under the new streamlined regulatory process enacted by the Michigan legislation in October 2008. The new provisions generally allows utilities to self-implement rates six months after filing, subject to refund, unless the MPSC finds good cause to prohibit such self-implementation. The new provisions require the MPSC to issue an order 12 months after filing or the rates, as filed, become permanent. We cannot predict the financial impact or outcome of this proceeding.

Palisades Regulatory Proceedings: The MPSC order approving the Palisades sale transaction required 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 2007 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 of $109 million to customers. The distribution of these funds is still pending with the MPSC.

Other Consumers’ Electric Utility Contingencies

The MCV PPA: We have a 35-year power purchase agreement that began in 1990 with the MCV Partnership to purchase 1,240 MW of electricity. In June 2008, the MPSC approved an amended and restated MCV PPA, which took effect in October 2008. The 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,

•  a $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.

Capacity and energy charges, net of RCP replacement energy and benefits, under the MCV PPA were $320 million in 2008, $464 million in 2007, and $411 million in 2006. We estimate that capacity and energy charges under the MCV PPA will range from $240 million to $330 million annually.

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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. At December 31, 2008, 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 for 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 December 31, 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 provide a $162 million letter of credit to Entergy as security for this obligation.

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 2008, we estimated our remaining costs to be between $38 million and $52 million. We expect to fund most of these costs through proceeds from insurance settlements and MPSC-approved rates.

At December 31, 2008, we have a liability of $38 million and a regulatory asset of $69 million that, 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 $5 million and $6 million over the next five years. Periodically, we review these response activity cost estimates. Any significant change in the underlying assumptions, such as an increase in the number of sites, changes in remediation techniques or legal and regulatory requirements, could affect our estimates of annual response activity costs and MGP liability.

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

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July 2008, we responded to a second set of data requests from the FERC. The FERC has also taken depositions 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
GCR Year	Date Filed	recovery	of Gas 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 plan for year 2008-2009: In February 2009, the MPSC issued an order for our 2008-2009 GCR plan year. The order approved a base GCR ceiling factor of $8.17 per mcf for April 2008 through March 2009, subject to a quarterly ceiling price adjustment mechanism.

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 March 2009 is $8.17 per mcf. We are currently anticipating an underrecovery will occur during the 2008-2009 GCR year.

GCR plan for year 2009-2010: In December 2008, we filed an application with the MPSC seeking approval of a GCR plan for our 2009-2010 GCR plan year. Our request proposed the use of a base GCR ceiling factor of $8.10 per mcf, plus a quarterly GCR ceiling price adjustment contingent upon future events. We expect to self-implement a 2009 GCR charge in April 2009.

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

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. In December 2008, the MPSC approved a partial settlement agreement allowing us to implement the filed depreciation rates, on an interim basis, concurrent with the implementation of settled rates in our 2008 gas rate case. The interim depreciation rates reduce our depreciation expense by approximately $20 million per year and will remain in effect until a final order is issued in our gas depreciation case. 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.

2008 Gas Rate Case: In December 2008, the MPSC approved a settlement agreement authorizing a rate increase of $22 million, based on a 10.55 percent authorized return on equity, for service rendered on and after December 24, 2008. The settlement includes a $20 million decrease in depreciation rates and requires that we not request a new gas general rate increase prior to May 1, 2009.

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Other Contingencies — Indemnifications

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 January 2009, we paid $18 million, which was charged against a tax indemnification liability established when we recorded the sale of Jorf Lasfar, and accordingly it did 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 believes that Barr was paid properly on gas sales and that he was not 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. There is disagreement 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 suffered minimal, if any, damages. 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 we would have received had we issued the guarantee as a single item.

The following table describes our guarantees at December 31, 2008:

						FIN 45
			Maximum			Carrying
Guarantee Description	Issue Date	Expiration Date	Obligation			Amount
	In Millions
Indemnifications from asset sales and other agreements	Various	Indefinite	$	1,445	(a)	$	84	(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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

	purchase agreements and the failure of title to the assets or stock we sold 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)	In May 2007, CMS Energy provided an indemnification to TAQA in connection with the sale of its ownership interests in businesses in the Middle East, Africa, and India. This indemnification is capped at $50 million and expires two years after the May 2, 2007 sale closing date. The indemnification covers claims related to the following matters:
	• a dispute between Neyveli and the TNEB regarding the capital costs to be reflected in the tariff paid by the TNEB to Neyveli, and
	• various matters, including the lack of a valid site lease and current operating license for Takoradi.
	As of December 31, 2008, we have recorded an $84 million liability in connection with indemnities related to the sale of certain subsidiaries, including a $50 million liability related to the indemnification to TAQA described in the preceding paragraphs. The TAQA indemnification liability may be resolved during 2009, and our ultimate payment obligation could be materially less than the amount we have accrued for the indemnification.
(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 Agreement to provide power and steam to Dow Bay Harbor remediation efforts	Nonperformance or non-payment by a subsidiary under a related contract MCV Partnership’s nonperformance or non-payment under a related contract Owners exercising put options requiring us to purchase property

At December 31, 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 Bay Harbor 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, due to a number of factors, we are unable to estimate the maximum potential obligation. These factors include unspecified exposure under certain agreements. We consider the likelihood that we would be required to perform or incur significant losses related to these indemnities to be remote.

CMS-65

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Other: In addition to the matters disclosed in 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.

Contractual Commitments

Purchase Obligations: The following table summarizes our contractual cash obligations for each of the periods presented.

Purchase Obligations at December 31, 2008
			Payments Due
			Less Than		One to		Three to		More Than
	Total		One Year		Three Years		Five Years		Five Years
	In Millions
Purchase obligations(a)	$	14,699	$	2,201	$	2,391	$	1,545	$	8,562

(a)	Long-term contracts for purchase of commodities and services. These obligations include operating contracts used to ensure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include:
	• natural gas and associated transportation,
	• electricity, and
	• and associated transportation.

CMS-66

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

5: FINANCINGS AND CAPITALIZATION

Long-term debt at December 31 follows:

	Interest Rate (%)			Maturity	2008			2007
					In Millions
CMS Energy Corporation
Senior notes		7.750		2010	$	300		$	300
		8.500		2011		300			300
		6.300		2012		150			150
		Variable	(a)	2013		150			150
		6.875		2015		125			125
		6.550		2017		250			250
		3.375	(b)	2023		140			150
		2.875	(b)	2024		288			288
						1,703			1,713
Revolving Credit Facility						105			—
Total — CMS Energy Corporation						1,808			1,713
Consumers Energy Company
First mortgage bonds(c)		4.250		2008		—			250
		4.800		2009		200			200
		4.400		2009		150			150
		4.000		2010		250			250
		5.000		2012		300			300
		5.375		2013		375			375
		6.000		2014		200			200
		5.000		2015		225			225
		5.500		2016		350			350
		5.150		2017		250			250
		5.650		2018		250			—
		6.125		2019		350			—
		5.650		2020		300			300
		5.650		2035		142			145
		5.800		2035		175			175
						3,517			3,170
Senior notes		6.375		2008		—			159
		6.875		2018		180			180
Securitization bonds		5.495	(d)	2009-2015		277			309
Nuclear fuel disposal liability				(e)		162			159
Tax-exempt pollution control revenue bonds		Various		2010-2035		161			161
Total — Consumers Energy Company						4,297			4,138
Other Subsidiaries
EnerBank brokered certificates of deposit		4.374	(f)	2009-2018		176			153
Genesee tax exempt bonds		7.500		2009-2021		57			59
Grayling tax exempt bonds		Variable	(g)	2009-2012		19			24
Total — other subsidiaries						252			236
Total principal amount outstanding						6,357			6,087
Current amounts						(489	)		(692	)
Net unamortized discount						(9	)		(10	)
Total long-term debt					$	5,859		$	5,385

(a) The variable rate senior notes bear interest at three-month LIBOR plus 95 basis points (5.7025 percent at December 31, 2008 which reset to 2.0444 percent in January 2009).

CMS-67

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(b)	Contingently convertible notes. See the “Contingently Convertible Securities” section in this Note for further discussion of the conversion features.
(c)	The weighted-average interest rate for our FMB was 5.329 percent at December 31, 2008 and 5.131 percent at December 31, 2007.
(d)	Represents the weighted-average interest rate at December 31, 2008 (5.442 percent at December 31, 2007).
(e)	The maturity date is uncertain.
(f)	Represents the weighted-average interest rate for EnerBank’s brokered certificates of deposit at December 31, 2008 (5.198 percent at December 31, 2007). These deposits are sold through investment brokers in large pools with each certificate within the pool having a face value of $1,000. They cannot be withdrawn until maturity, except in the case of death or incompetence of the holder.
(g)	The interest rate for the tax exempt bonds was 0.910 percent at December 31, 2008 and 3.530 percent at December 31, 2007.

Financings: The following is a summary of significant long-term debt transactions during 2008:

	Principal
	(In millions)		Interest Rate (%)			Issue/Retirement 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 FMB. Consumers used the proceeds to redeem $28 million of insured tax-exempt bonds in April 2008.

(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. Consumers used the proceeds to redeem $68 million of insured tax-exempt bonds in April 2008.

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.

CMS-68

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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.

First Mortgage Bonds: Consumers secures its FMB by a mortgage and lien on substantially all of its property. Consumers’ ability to issue FMB is restricted by certain provisions in the First Mortgage Bond Indenture and the need for regulatory approvals under federal law. Restrictive issuance provisions in the First Mortgage Bond Indenture include achieving a two-times interest coverage ratio and having sufficient unfunded net property additions.

Regulatory Authorization for Financings: The FERC has authorized Consumers to have outstanding at any one time, up to $1.0 billion of secured and unsecured short-term securities for general corporate purposes. The remaining availability is $550 million at December 31, 2008.

The FERC has also authorized Consumers to issue and sell up to $1.5 billion of secured and unsecured long-term securities for general corporate purposes. The remaining availability is $950 million at December 31, 2008.

The authorizations are for the period ending June 30, 2010. Any long-term issuances during the authorization period are exempt from the FERC’s competitive bidding and negotiated placement requirements.

Securitization Bonds: Certain regulatory assets collateralize securitization bonds. The bondholders have no recourse to our other assets. Through Consumers’ rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses. The surcharges collected are remitted to a trustee and are not available to creditors of Consumers or creditors of Consumers’ affiliates. Securitization surcharges totaled $53 million in 2008 and $48 million in 2007.

Long-Term Debt — Related Parties: CMS Energy formed a statutory wholly owned business trust for the sole purpose of issuing preferred securities and lending the gross proceeds to itself. The sole assets of the trust consists of the debentures described in the following table. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trust issued. We determined that we do not hold the controlling financial interest in our trust preferred security structure. Accordingly, this entity is reflected in Long-term debt — related parties on our Consolidated Balance Sheets.

The following is a summary of Long-term debt — related parties at December 31:

Debenture and related party	Interest Rate (%)		Maturity		2008		2007
					In Millions
Convertible subordinated debentures, CMS Energy Trust I		7.75		2027	$	178	$	178

In the event of default, holders of the Trust Preferred Securities would be entitled to exercise and enforce the trust’s creditor rights against us, which may include acceleration of the principal amount due on the debentures. We have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debentures, related indenture and trust documents, provide full and unconditional guarantees for the trust’s obligations under the preferred securities. Our maximum exposure for the trust’s obligations is recorded on our balance sheet as Long-term debt — related parties in the amount of $178 million.

Debt Maturities: At December 31, 2008, the aggregate annual contractual maturities for long-term debt and long-term debt — related parties for the next five years are:

	Payments Due
	2009		2010		2011		2012		2013
	In Millions
Long-term debt and long-term debt — related parties	$	489	$	673	$	364	$	618	$	579

CMS-69

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at December 31, 2008:

						Outstanding
		Amount of		Amount		Letters of		Amount
Company	Expiration Date	Facility		Borrowed		Credit		Available
	In Millions
CMS Energy(a)	April 2, 2012	$	550	$	105	$	24	$	421
Consumers	March 30, 2012		500		—		172		328
Consumers(b)	November 30, 2009		192		—		192		—
Consumers	September 9, 2009		150		—		—		150

(a)	Average borrowings during 2008 totaled $212 million, with a weighted average annual interest rate of 3.59 percent, at LIBOR plus 0.75 percent. At December 31, 2008, the annual interest rate on the amount borrowed was 2.0 percent.
(b)	Secured revolving letter of credit facility.

Dividend Restrictions: Under provisions of our senior notes indenture, at December 31, 2008, payment of common stock dividends was limited to $585 million.

Under the provisions of its articles of incorporation, at December 31, 2008, Consumers had $331 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 stock 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.

During 2008, CMS Energy received $297 million of common stock dividends from Consumers.

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we sell eligible accounts receivable to a wholly owned, consolidated, bankruptcy-remote special-purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $250 million of the receivables at December 31, 2008, reduced from $325 million at December 31, 2007. The special purpose entity sold $170 million in receivables at December 31, 2008 and no receivables at December 31, 2007. The purchaser of the receivables has no recourse against our other assets for failure of a debtor to pay when due and no right to any receivables not sold. We have neither recorded a gain or loss on the receivables sold nor retained any interest in the receivables sold. We continue to service the receivables sold to the special-purpose entity.

The following table summarizes certain cash flows under our accounts receivable sales program:

Years Ended December 31	2008		2007
	In Millions
Administrative fees	$	1	$	3
Net cash flow as a result of accounts receivable financing	$	170	$	(325	)
Collections from customers	$	6,060	$	5,881

Capitalization: The authorized capital stock of CMS Energy consists of:

•  350 million shares of CMS Energy Common Stock, par value $0.01 per share, and

•  10 million shares of CMS Energy Preferred Stock, par value $0.01 per share.

CMS-70

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Preferred Stock: Details about our outstanding preferred stock follow:

	Number of Shares
December 31	2008		2007		2008		2007
					In Millions
Preferred stock 4.50% convertible, Authorized 10,000,000 shares		4,978,000		5,000,000	$	249	$	250

At December 31, 2008, $6 million of the total amount outstanding that was tendered for conversion in December 2008 is classified in current liabilities on our consolidated balance sheets. See the “Contingently Convertible Securities” section in this Note for further discussion of the convertible preferred stock.

In February 2007, we repurchased our non-voting preferred subsidiary interest of $11 million and redeemed it for a cash payment of $32 million. We reversed the original $19 million addition to paid-in-capital and charged a $1 million redemption premium to accumulated deficit.

Preferred Stock of Subsidiary: Details about Consumers’ preferred stock outstanding follow:

			Optional
			Redemption		Number of Shares
December 31	Series		Price		2008		2007		2008		2007
									In Millions
Preferred stock
Cumulative $100 par value, Authorized 7,500,000 shares, with no mandatory redemption	$	4.16	$	103.25		68,451		68,451	$	7	$	7
	$	4.50	$	110.00		373,148		373,148		37		37
Total Preferred stock of subsidiary									$	44	$	44

Contingently Convertible Securities: At December 31, 2008, the significant terms of our contingently convertible securities were as follows:

					Adjusted		Adjusted
			Outstanding		Conversion		Trigger
Security	Maturity		(In millions)		Price		Price
4.50% preferred stock		—	$	249	$	9.51	$	11.42
3.375% senior notes		2023	$	140	$	10.26	$	12.31
2.875% senior notes		2024	$	288	$	14.18	$	17.02

We have the right to require the 4.50 percent preferred stock to be converted if the closing price of our common stock remains at or above $12.37 for 20 of any 30 consecutive trading days. The holders of the 3.375 percent senior notes have the right to require us to purchase the notes at par on July 15, 2013 and 2018. The holders of the 2.875 percent senior notes have the right to require us to purchase the notes at par on December 1, 2011, 2014, and 2019.

The securities become convertible for a calendar quarter if the price of our common stock remains at or above the trigger price for 20 of 30 consecutive trading days ending on the last trading day of the previous quarter. The trigger price at which these securities become convertible is 120 percent of the conversion price. The conversion and trigger prices are subject to adjustment under certain circumstances, including payments or distributions to our common stockholders. The conversion and trigger price adjustment is made when the cumulative change in conversion and trigger prices is one percent or more.

All of our contingently convertible securities, if converted, require us to pay cash up to the principal (or par) amount of the securities. Any conversion value in excess of that amount is paid in shares of our common stock.

During December 2008, no trigger price contingencies were met.

CMS-71

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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.

In December 2008, $6 million of 4.50 percent preferred stock was tendered for conversion. The conversion price determined in January 2009 was $10.92 per share. The conversion resulted in the issuance of 84,592 shares of common stock and payment of $6 million in January 2009.

6: EARNINGS PER SHARE

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

Years Ended December 31	2008			2007			2006
	In Millions, Except
	per Share Amounts
Income (Loss) Available to Common Stockholders
Income (Loss) from Continuing Operations	$	300		$	(126	)	$	(133	)
Less Preferred Dividends and Redemption Premiums		(11	)		(12	)		(11	)
Income (Loss) from Continuing Operations Available to Common Stockholders Basic and Diluted		289			(138	)		(144	)
Average Common Shares Outstanding Applicable to Basic and Diluted EPS
Weighted Average Shares — Basic		223.9			222.6			219.9
Add dilutive impact of Contingently Convertible Securities		10.4			—			—
Add dilutive Options, Warrants and Restricted Stock Awards		0.5			—			—
Weighted Average Shares — Diluted		234.8			222.6			219.9
Earnings (Loss) Per Average Common Share Available to Common Stockholders
Basic	$	1.29		$	(0.62	)	$	(0.66	)
Diluted	$	1.23		$	(0.62	)	$	(0.66	)

Contingently Convertible Securities:  When we have positive income from continuing operations, 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, our contingently convertible securities would have contributed an additional 19.7 million shares to the calculation of diluted EPS for 2007, and 11.3 million shares for 2006. For additional details on our contingently convertible securities, see Note 5, Financings and Capitalization.

Stock Options, Warrants and Restricted Stock Awards:  For the year ended December 31, 2008, outstanding options and warrants to purchase 0.6 million shares of common stock had no impact on diluted EPS, since the exercise price was greater than the average market price of common stock. These stock options have the potential to dilute EPS in the future. Had there been positive income from continuing operations, 1.1 million shares of unvested restricted stock awards and options and warrants to purchase 0.3 million shares of common stock would have been included in the calculation of diluted EPS for the year ended December 31, 2007. For the year ended December 31, 2006, had there been positive income from continuing operations, 1.0 million shares of unvested restricted stock awards and options and warrants to purchase 0.5 million shares of common stock would have been included in the calculation of diluted EPS.

CMS-72

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Convertible Debentures:  For the years ended December 31, 2008, 2007, and 2006, 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 $9 million 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.

In June 2008, the FASB issued FSP EITF 03-6-1, effective for us January 1, 2009 with retrospective application required. Under this standard, share-based payment 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. This standard will apply to our outstanding unvested restricted stock awards, which will be considered participating securities and thus will be included in the computation of basic EPS. Had this standard been in place in 2008, it would have reduced 2008 basic and diluted EPS by approximately $0.01. We consider this figure to be representative of the potential impact of this standard on future years’ EPS.

7: FINANCIAL AND DERIVATIVE INSTRUMENTS

Financial Instruments: The carrying amounts of cash, current accounts and notes receivable, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments or other valuation techniques.

The cost or carrying amount and fair value of our long-term financial instruments were as follows:

	2008				2007
	Cost or				Cost or
	Carrying				Carrying
December 31	Amount		Fair Value		Amount		Fair Value
	In Millions
Securities held to maturity	$	3	$	3	$	3	$	3
Securities available for sale		68		68		75		75
Notes receivable, net		186		201		163		170
Long-term debt(a)		6,348		5,962		6,077		6,287
Long-term debt — related parties		178		107		178		173

(a) Includes current maturities of $489 million at December 31, 2008 and $692 million at December 31, 2007. Settlement of long-term debt is generally not expected until maturity.

A summary of our investment securities follows:

	2008								2007
			Unrealized		Unrealized		Fair				Unrealized		Unrealized		Fair
December 31	Cost		Gains		Losses		Value		Cost		Gains		Losses		Value
	In Millions
Available for sale:
Equity securities	$	39	$	—	$	—	$	39	$	62	$	—	$	—	$	62
Debt securities		29		—		—		29		13		—		—		13
Held to maturity:
Debt securities		3		—		—		3		3		—		—		3

CMS-73

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Equity securities classified as available for sale consist of an investment in a Standard & Poor’s 500 Index mutual fund. Debt securities classified as available for sale consist of investment-grade municipal bonds. Debt securities classified as held to maturity consist of municipal bonds and mortgage-backed securities held by EnerBank.

During 2008, the fair value of our SERP investment in equity securities declined to $39 million. We determined that this decline in fair value was other than temporary. Accordingly, we reclassified net unrealized losses of $24 million ($15 million, net of tax) from AOCL to Other expense in the Consolidated Statements of Income (Loss) and established a new cost basis of $39 million for these investments, which was equal to fair value at December 31, 2008.

The fair value of debt securities by contractual maturity at December 31, 2008 is as follows:

	In Millions
Due one year or less	$	1
Due after one year through five years		12
Due after five years through ten years		13
Due after ten years		6
Total	$	32

During 2008, the proceeds from sales of SERP securities were $2 million. Gross losses realized were immaterial. During 2007, the proceeds from sales of SERP securities were $64 million, and $23 million of gross gains and $1 million of gross losses were realized. We reclassified net gains of $15 million, net of tax of $7 million, from AOCL and included this amount in net loss in 2007. The proceeds from sales of SERP securities were $6 million during 2006. Gross gains and losses were immaterial in 2006.

Derivative Instruments: In order to limit our exposure to certain market risks, primarily changes in interest rates, commodity prices, and foreign currency exchange rates, 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

CMS-74

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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.

The following table summarizes our derivative instruments:

December 31	2008								2007
			Fair			Unrealized					Fair			Unrealized
Derivative Instruments	Cost		Value			Loss			Cost		Value			Loss
	In Millions
Interest rate collar	$	—	$	(1	)	$	(1	)	$	—	$	—		$	—
Fixed price fuel contracts		—		(1	)		(1	)		—		—			—
Electricity and gas contracts		—		(16	)		(16	)		—		(23	)		(23	)
Foreign exchange forward		—		(1	)		(1	)		—		—			—

Interest Rate Collar:  Grayling Generating Station Limited Partnership executed this interest rate collar contract as an economic hedge of the variable interest rate charged on its outstanding revenue bonds. We record the fair value of this derivative in Other non-current liabilities on our Consolidated Balance Sheets. We recorded the mark-to-market loss on this derivative in Other expense on our Consolidated Statements of Income (Loss).

Fixed Price Fuel Contracts:  Consumers entered into two financial contracts to fix economically the price of gasoline and diesel fuel it purchases for its fleet vehicles and equipment. Under these agreements, Consumers has effectively locked in a price per gallon for gasoline and diesel fuel it will purchase from January through November 2009. We record the fair value of these derivatives in Other current liabilities on our Consolidated Balance Sheets. We recorded the mark-to-market losses on these derivatives in Other expense on our Consolidated Statements of Income (Loss).

Electricity and Gas 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 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 classified all of CMS ERM’s derivatives as non-trading derivatives.

We record the fair value of these contracts in 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 $2 million at December 31, 2008 and $4 million at December 31, 2007.

Foreign Exchange Forward:  We executed this foreign exchange forward contract as an economic hedge of an exposure to the Moroccan dirham/US dollar exchange rate. This exposure resulted from a tax indemnification, under which we agreed to pay an amount equal to 150 million Moroccan dirhams (approximately $18 million) to the

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purchaser of our previous interest in Jorf Lasfar. We settled this obligation and the related derivative in January 2009. We recorded the fair value of this derivative in Other current liabilities on our Consolidated Balance Sheets at December 31, 2008. We recorded the mark-to-market loss on this derivative in Other expense on our Consolidated Statements of Income (Loss). For further details on the related tax indemnification, see Note 4, Contingencies, “Other Contingencies — Indemnifications — Moroccan Tax Claim.”

Credit Risk:  Our swaps, options, and forward contracts contain credit risk, which is the risk that our counterparties will fail to meet their contractual obligations. We reduce this risk through using established policies and procedures. For each counterparty, we assess credit quality by considering credit ratings, financial condition, and other available information. We establish a credit limit for each counterparty based upon our evaluation of its credit quality. We monitor our exposure to potential loss under each contract and take action when appropriate.

CMS ERM enters into contracts primarily with companies in the electric and gas industry. This industry concentration may have a positive or negative impact on our exposure to credit risk based on how similar changes in economic conditions, the weather, or other conditions affect these counterparties. CMS ERM reduces its credit risk exposure by using industry-standard agreements that allow for netting positive and negative exposures associated with the same counterparty. Typically, these agreements also allow each party to demand adequate assurance of future performance from the other party, when there is reason to do so.

The following table illustrates our exposure to potential losses at December 31, 2008, if each counterparty within this industry concentration failed to meet its contractual obligations. This table includes contracts accounted for as financial instruments. It does not include trade accounts receivable, derivative contracts that qualify as normal purchases and sales under SFAS No. 133, or other contracts that we do not account for as derivatives.

							Net Exposure		Net Exposure
	Exposure						from Investment		from Investment
	Before		Collateral		Net		Grade		Grade
	Collateral(a)		Held		Exposure		Companies		Companies (%)
	In Millions
CMS ERM	$	1	$	—	$	1	$	1		100	%

(a) Exposure is reflected net of payables or derivative liabilities if netting arrangements exist.

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.

8: RETIREMENT BENEFITS

We provide retirement benefits to our employees under a number of different 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.

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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.

On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of five percent of base pay to the existing employees’ 401(k) plan. No employee contribution is required in order to receive the plan’s employer contribution. All employees hired on and after September 1, 2005 participate in this plan. Participants in the cash balance pension plan, in effect from July 1, 2003 to September 1, 2005, also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP expense was $3 million for the year ended December 31, 2008 and $2 million for the years ended December 31, 2007 and 2006.

SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code. SERP trust earnings are taxable and trust assets are included in our consolidated assets. Trust assets were $69 million at December 31, 2008 and $95 million at December 31, 2007. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $80 million at December 31, 2008 and $83 million at December 31, 2007. A contribution of $25 million was made to the trust in December 2007.

On April 1, 2006, we implemented a DC SERP and froze further new participation in the defined benefit SERP. The DC SERP provides participants benefits ranging from 5 percent to 15 percent of total compensation. The DC SERP requires a minimum of five years of participation before vesting. Our contributions to the plan, if any, will be placed in a grantor trust. Trust assets were less than $1 million at December 31, 2008 and 2007. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The DC SERP expense was less than $1 million for the years ended December 31, 2008, 2007 and 2006.

401(k): The employer’s match for the 401(k) plan is 60 percent on eligible contributions up to the first six percent of an employee’s wages. The total 401(k) plan cost was $16 million for the year ended December 31, 2008, $14 million for the year ended December 31, 2007 and $15 million for the year end December 31, 2006.

EISP: We implemented a nonqualified EISP in 2002 to provide flexibility in separation of employment by officers, a selected group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premiums for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was less than $1 million for the years ended December 31, 2008 and 2007 and $1 million for the year ended December 31, 2006. The ABO for the EISP was $4 million at December 31, 2008 and December 31, 2007.

OPEB: The OPEB plan covers all regular full-time employees who are covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least 10 full years of applicable continuous service. Regular full-time employees who qualify for a pension plan disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs were based on the assumption that costs would increase 8.0 percent for those under 65 and 9.5 percent for those over 65 in 2008. The 2009 rate of increase for OPEB health costs for those under 65 is expected to be 8.5 percent and for those over 65 is expected to be 8.0 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2017 and for those over 65 by 2017 and thereafter.

The health care cost trend rate assumption affects the estimated costs recorded. A one percentage point change in the assumed health care cost trend assumption would have the following effects:

	One Percentage		One Percentage
	Point Increase		Point Decrease
	In Millions
Effect on total service and interest cost component	$	16	$	(13	)
Effect on postretirement benefit obligation	$	177	$	(155	)

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Upon adoption of SFAS No. 106 in 1992, we recorded a liability of $466 million for the accumulated transition obligation and a corresponding regulatory asset for anticipated recovery in utility rates. For additional details, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation.” The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years.

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 required 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 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 year ended December 31, 2008.

Assumptions: The following tables recap the weighted-average assumptions used in our retirement benefits plans to determine benefit obligations and net periodic benefit cost:

Weighted Average For Benefit Obligations:

	Pension & SERP						OPEB
Years Ended December 31	2008		2007		2006		2008		2007		2006
Discount rate(a)		6.50%		6.40%		5.65%		6.50%		6.50%		5.65%
Expected long-term rate of return on plan assets(b)		8.25%		8.25%		8.25%		7.75%		7.75%		7.75%
Mortality table(c)		2000		2000		2000		2000		2000		2000
Rate of compensation increase:
Pension		4.00%		4.00%		4.00%
SERP		5.50%		5.50%		5.50%

Weighted Average For Net Periodic Benefit Cost:

	Pension & SERP						OPEB
Years Ended December 31	2008		2007		2006		2008		2007		2006
Discount rate(a)		6.40%		5.65%		5.75%		6.50%		5.65%		5.75%
Expected long-term rate of return on plan assets(b)		8.25%		8.25%		8.50%		7.75%		7.75%		8.00%
Mortality table(c)		2000		2000		2000		2000		2000		2000
Rate of compensation increase:
Pension		4.00%		4.00%		4.00%
SERP		5.50%		5.50%		5.50%

(a) The discount rate is set to reflect the rates at which benefits can be effectively settled. It is set equal to the equivalent single rate that results from a yield curve analysis that incorporates projected benefit payments specific to our pension and other postretirement benefit plans, and the yields on high quality corporate bonds rated Aa or better.

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(b)

We determine our long-term rate of return by considering historical market returns, the current and expected future economic environment, the capital market principles of risk and return, and the expert opinions of individuals and firms with financial market knowledge. We consider the asset allocation of the portfolio in forecasting the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. Annually, we review for reasonableness and appropriateness of the forecasted returns for various classes of assets used to construct an expected return model.

(c)

The mortality assumption is based on the RP-2000 mortality tables with projection of future mortality improvements using Scale AA, which aligns with the IRS prescriptions for cash funding valuations under the Pension Protection Act.

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

	Pension & SERP
Years Ended December 31	2008			2007			2006
	In Millions
Net periodic pension cost
Service cost	$	43		$	50		$	51
Interest expense		101			91			88
Expected return on plan assets		(81	)		(79	)		(85	)
Amortization of:
Net loss		41			46			43
Prior service cost		6			7			7
Net periodic pension cost		110			115			104
Regulatory adjustment(a)		4			(22	)		(11	)
Net periodic pension cost after regulatory adjustment	$	114		$	93		$	93

	OPEB
Years Ended December 31	2008			2007			2006
	In Millions
Net periodic OPEB cost Service cost	$	22		$	25		$	23
Interest expense		72			69			64
Expected return on plan assets		(66	)		(62	)		(57	)
Amortization of:
Net loss		9			22			20
Prior service credit		(10	)		(10	)		(10	)
Net periodic OPEB cost		27			44			40
Regulatory adjustment(a)		3			(6	)		(2	)
Net periodic OPEB cost after regulatory adjustment	$	30		$	38		$	38

(a) Regulatory adjustments are the differences between amounts included in rates and the periodic benefit cost calculated pursuant to SFAS No. 87 and SFAS No. 106. The pension regulatory asset had a balance of $29 million at December 31, 2008 and $33 million at December 31, 2007. The OPEB regulatory asset had a balance of $5 million at December 31, 2008 and $8 million at December 31, 2007.

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The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized into net periodic benefit cost over the next fiscal year from the regulatory asset is $44 million and from AOCL is $3 million. The estimated net loss and prior service credit for OPEB plans that will be amortized into net periodic benefit cost over the next fiscal year from the regulatory asset is $23 million and from AOCL is $1 million.

We amortize gains and losses in excess of 10 percent of the greater of the benefit obligation and the MRV over the average remaining service period. The estimated time of amortization of gains and losses is 12 years for pension and 14 years for OPEB. Prior service cost amortization is established in the years in which the prior service cost first occurred, and are based on the same amortization period in all future years until the prior service costs are fully recognized. The estimated time of amortization of new prior service costs is 12 years for pension and 10 years for OPEB.

Reconciliations: The following table reconciles the funding of our retirement benefits plans with our retirement benefits plans’ liability:

	Pension Plan						SERP						OPEB
Years Ended December 31	2008			2007			2008			2007			2008			2007
	In Millions
Benefit obligation at beginning of period	$	1,565		$	1,576		$	95		$	92		$	1,136		$	1,243
Service cost		45			49			1			1			24			25
Interest cost		103			86			7			5			78			69
Actuarial loss (gain)		(66	)		30			(3	)		1			81			(128	)
Palisades sale		—			(38	)		—			—			—			(20	)
Benefits paid		(123	)		(138	)		(5	)		(4	)		(53	)		(53	)
Benefit obligation at end of period(a)		1,524			1,565			95			95			1,266			1,136
Plan assets at fair value at beginning of period		1,078			1,040			—			—			852			798
Actual return on plan assets		(231	)		89			—			—			(201	)		55
Company contribution		—			109			5			4			64			52
Palisades sale		—			(22	)		—			—			—			(5	)
Actual benefits paid(b)		(123	)		(138	)		(5	)		(4	)		(53	)		(48	)
Plan assets at fair value at end of period		724			1,078			—			—			662			852
Funded status at end of measurement period		(800	)		(487	)		(95	)		(95	)		(604	)		(284	)
Additional VEBA Contributions or Non-Trust Benefit Payments		—			—			—			—			—			12
Funded status at December 31(c)	$	(800	)	$	(487	)	$	(95	)	$	(95	)	$	(604	)	$	(272	)

(a)	The Medicare Prescription Drug, Improvement and Modernization Act of 2003 establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy, which is tax-exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. The Medicare Part D annualized reduction in net OPEB cost was $25 million for 2008 and $28 million for 2007. The reduction includes $7 million for 2008 and 2007 in capitalized OPEB costs.
(b)	We received $6 million in 2008 and $4 million in 2007 for Medicare Part D Subsidy payments.
(c)	Liabilities for retirement benefits comprised $1.494 billion classified as non-current and $5 million classified as current for the year ended December 31, 2008, and $850 million classified as non-current and $4 million classified as current for the year ended December 31, 2007.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table provides pension PBO, ABO and fair value of plan assets:

Years Ended December 31	2008		2007
	In Millions
Pension PBO	$	1,524	$	1,565
Pension ABO		1,240		1,231
Fair value of Pension Plan assets	$	724	$	1,078

Items Not Yet Recognized as a Component of Net Periodic Benefit Cost: The following table recaps the amounts recognized in SFAS No. 158 regulatory assets and AOCL that have not been recognized as components of net periodic benefit cost. For additional details on regulatory assets, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation.”

	Pension & SERP				OPEB
Years Ended December 31	2008		2007		2008			2007
	In Millions
Regulatory assets
Net loss	$	835	$	636	$	595		$	265
Prior service cost (credit)		33		39		(78	)		(89	)
AOCL
Net loss (gain)		50		46		(9	)		(22	)
Prior service cost (credit)		3		3		(3	)		(3	)
Total amounts recognized in regulatory assets and AOCL	$	921	$	724	$	505		$	151

Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:

	Pension						OPEB
Years Ended December 31	2008			2007			2008			2007
Asset Category:
Fixed Income		37	%		30	%		55	%		34	%
Equity Securities		50	%		60	%		45	%		66	%
Alternative Strategy		13	%		10	%		—			—

We contributed $51 million to our OPEB plan in 2008 and we plan to contribute $53 million to our OPEB plan in 2009. Of the $51 million OPEB contribution made during 2008, $10 million was contributed to the 401(h) component of the qualified pension plan and the remaining $41 million was contributed to the VEBA trust accounts. We did not contribute to our Pension Plan in 2008, but plan to contribute $300 million to our Pension Plan in 2009. Contributions include required and discretionary amounts. Actual future contributions will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the plans.

In 2008, the consultant for the Pension Plan, recommended an adjustment to the target asset allocation for Pension Plan assets. The recommended revised target asset allocation for the Pension Plan assets was 50 percent equity, 30 percent fixed income, and 20 percent alternative strategy investments from the previous target of 60 percent equity, 30 percent fixed income and 10 percent alternative strategy investments. This recommendation was thoroughly reviewed and approved by our Benefit Administration Committee. This adjustment is being made gradually by the allocation of contributions into alternative assets and the drawdown of equities to cover plan benefit payments and distributions. This revised target asset allocation is expected to continue to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor’s 500 Index, with lesser allocations to the Standard & Poor’s MidCap and SmallCap Indexes and Foreign Equity Funds. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers as well as

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high-yield and global bond funds. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. We use annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies to evaluate the need for adjustments to the portfolio allocation.

We established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers and through direct contributions from the non-utility subsidiaries. We invest the equity portions of the union and non-union health care VEBA trusts in a Standard & Poor’s 500 Index fund. We invest the fixed-income portion of the union health care VEBA trust in domestic investment grade taxable instruments. We invest the fixed-income portion of the non-union health care VEBA trust in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA trust are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.

SFAS No. 132(R) Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:

	Pension		SERP		OPEB(a)
	In Millions
2009	$	72	$	5	$	57
2010		78		5		60
2011		85		5		62
2012		96		6		64
2013		106		6		65
2014-2018		669		39		363

(a) OPEB benefit payments are net of employee contributions and expected Medicare Part D prescription drug subsidy payments. The subsidies to be received are estimated to be $6 million for 2009 and 2010, $7 million for 2011, $8 million for 2012 and 2013 and $50 million combined for 2014 through 2018.

9: ASSET RETIREMENT OBLIGATIONS

SFAS No. 143, Accounting for Asset Retirement Obligations: This standard requires us to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability at December 31, 2008 would increase by $10 million.

If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Historically, our gas transmission and electric and gas distribution assets have indeterminate lives and retirement cash flows that cannot be determined. During 2007, however, we implemented a new fixed asset accounting system that facilitates ARO accounting estimates for gas distribution mains and services. The new system enabled us to calculate a reasonable estimate of the fair value of the cost to cut, purge, and cap abandoned gas distribution mains and services at the end of their useful lives. We recorded a $101 million ARO liability and an asset of equal value at December 31, 2007. We have not recorded a liability for assets that have insignificant cumulative disposal costs, such as substation batteries.

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: This Interpretation clarified the term “conditional asset retirement obligation” used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments and the cut, purge, and cap of abandoned gas distribution mains and services qualify as conditional AROs, as defined by FIN 47.

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The following table lists the assets that we have legal obligations to remove at the end of their useful lives and for which we have an ARO liability recorded:

	In Service
ARO Description	Date	Long-Lived Assets
December 31, 2008
Closure of coal ash disposal areas	Various	Generating plants coal ash areas
Closure of wells at gas storage fields	Various	Gas storage fields
Indoor gas services equipment relocations	Various	Gas meters located inside structures
Asbestos abatement	1973	Electric and gas utility plant
Gas distribution cut, purge & cap	Various	Gas distribution mains & services
Natural gas-based power plant	1997	Gas fueled power plant
Close gas treating plant and gas wells	Various	Gas transmission and storage

No assets have been restricted for purposes of settling AROs.

	ARO											ARO
	Liability									Cash flow		Liability
ARO Description	12/31/06		Incurred		Settled(a)			Accretion		Revisions		12/31/07
	In Millions
Palisades-decommission	$	401	$	—	$	(410	)	$	7	$	2	$	—
Big Rock-decommission		2		—		(3	)		1		—		—
Coal ash disposal areas		57		—		(4	)		6		—		59
Wells at gas storage fields		1		—		—			—		—		1
Indoor gas services relocations		1		—		—			—		—		1
Asbestos abatement		35		—		(1	)		2		—		36
Gas distribution cut, purge, cap		—		101		—			—		—		101
Natural gas-based power plant		1		—		(1	)		—		—		—
Close gas treating plant and gas wells		2		—		(2	)		—		—		—
Total	$	500	$	101	$	(421	)	$	16	$	2	$	198

	ARO												ARO
	Liability										Cash flow		Liability
ARO Description	12/31/07		Incurred			Settled(a)			Accretion		Revisions		12/31/08
	In Millions
Palisades-decommission	$	—	$	—		$	—		$	—	$	—	$	—
Big Rock-decommission		—		—			—			—		—		—
Coal ash disposal areas		59		—			(3	)		6		—		62
Wells at gas storage fields		1		—			—			—		—		1
Indoor gas services relocations		1		—			—			—		—		1
Asbestos abatement		36		—			(2	)		2		—		36
Gas distribution cut, purge, cap		101		(1	)		(2	)		7		—		105
Natural gas-based power plant		—		—			—			—		—		—
Close gas treating plant and gas wells		—		—			—			1		—		1
Total	$	198	$	(1	)	$	(7	)	$	16	$	—	$	206

(a) Cash payments of $7 million in 2008 and $5 million in 2007 are included in the Other current and non-current liabilities line in Net cash provided by operating activities in our Consolidated Statements of Cash Flows. In

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April 2007, we sold Palisades to Entergy and paid Entergy to assume ownership and responsibility for the Big Rock ISFSI. Our AROs related to Palisades and the Big Rock ISFSI ended with the sale, and we removed the related ARO liabilities from our Consolidated Balance Sheets. We also removed the Big Rock ARO related to the plant in the second quarter of 2007 due to the completion of decommissioning.

10: INCOME TAXES

CMS Energy and its subsidiaries file a consolidated federal income tax return and a combined Michigan income tax return. Income taxes generally are allocated based on each company’s separate taxable income in accordance with the CMS Energy tax sharing agreement.

We use deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service lives of the related properties. We use ITC to reduce current income taxes payable.

AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2008, we had AMT credit carryforwards of $272 million that do not expire, federal tax loss carryforwards of $1.302 billion that expire from 2023 through 2028 and Michigan tax loss carryforwards of $383 million that expire in 2018. In addition, we have a net benefit of $160 million for future Michigan tax deductions which were granted as part of the Michigan Business Tax legislation of 2007. We do not believe that a valuation allowance is required, as we expect to use the loss carryforwards prior to their expiration. We also have general business credit carryforwards of $20 million that expire from 2009 through 2028. We have provided $2 million of valuation allowances for these items. It is reasonably possible that further adjustments will be made to the valuation allowance within one year.

In January 2009, the State of Michigan enacted changes to the Michigan Business Tax, which were retroactive to January 1, 2008. These changes included the decoupling from federal bonus depreciation, which reduces the Michigan tax loss carryforward previously discussed by approximately $160 million.

The significant components of income tax expense (benefit) on continuing operations consisted of:

Years Ended December 31	2008			2007			2006
	In Millions
Current income taxes:
Federal	$	4		$	229		$	133
Federal income tax benefit of operating loss carryforwards		—			(209	)		(31	)
State and local		9			1			—
Foreign		—			—			(2	)
	$	13		$	21		$	100
Deferred income taxes:
Federal	$	137		$	(212	)	$	(281	)
State and local		(4	)		—			—
Foreign		—			—			(3	)
	$	133		$	(212	)	$	(284	)
Deferred ITC, net		(4	)		(4	)		(4	)
Tax expense/(benefit)	$	142		$	(195	)	$	(188	)

Current tax expense reflects the settlement of income tax audits for prior years, as well as the provision for the current year’s income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in our consolidated

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financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which can result in proposed assessments. Our estimate of the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities at December 31, 2008 are adequate for all years.

The principal components of deferred income tax assets (liabilities) recognized on our Consolidated Balance Sheets are as follows:

December 31	2008			2007
	In Millions
Current Assets and (Liabilities):
Deferred charges	$	1		$	107
Tax loss and credit carryforwards		148			—
Reserves and accruals		20			—
Employee benefits		(96	)		8
Gas inventory		(219	)		(204	)
Other		46			48
Net Current (Liability)	$	(100	)	$	(41	)
Noncurrent Assets and (Liabilities):
Tax loss and credit carryforwards	$	775		$	761
SFAS No. 109 regulatory liability		205			207
Reserves and accruals		43			92
Currency translation adjustment		—			77
Foreign investments inflation indexing		30			23
Employee benefits		101			64
Valuation allowance		(32	)		(32	)
Property		(968	)		(840	)
Securitized costs		(161	)		(180	)
Nuclear decommissioning (including unrecovered costs)		(20	)		(18	)
Other		(19	)		(55	)
Net Noncurrent Asset/(Liability)	$	(46	)	$	99
Total Deferred Income Tax Asset/(Liability)	$	(146	)	$	58

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The actual income tax expense (benefit) on continuing operations differs from the amount computed by applying the statutory federal tax rate of 35 percent to income (loss) before income taxes as follows:

Years Ended December 31	2008			2007			2006
	In Millions
Income (loss) from continuing operations before income taxes
Domestic	$	440		$	(124	)	$	(118	)
Foreign		2			(197	)		(203	)
Total		442			(321	)		(321	)
Statutory federal income tax rate		x 35	%		x 35	%		x 35	%
Expected income tax expense (benefit)		155			(112	)		(112	)
Increase (decrease) in taxes from:
Property differences		3			9			13
Income tax effect of foreign investments		—			47			(29	)
ITC amortization		(4	)		(4	)		(4	)
State and local income taxes, net of federal benefit		3			—			—
Medicare Part D exempt income		(9	)		(10	)		(10	)
Tax exempt income		(1	)		(1	)		(3	)
Tax contingency reserves		—			—			(15	)
Valuation allowance		(6	)		(121	)		23
IRS settlement/credit restoration		—			—			(49	)
Other, net		1			(3	)		(2	)
Recorded income tax benefit	$	142		$	(195	)	$	(188	)
Effective tax rate		32.1	%		60.7	%		58.6	%

In June 2006, the IRS concluded its audit of CMS Energy and its subsidiaries and adjusted taxable income for the years ended December 31, 1987 through December 31, 2001. The overall cumulative increase to taxable income related primarily to the disallowance of the simplified service cost method with respect to certain self-constructed utility assets, resulting in a deferral of these expenses to future years. Reduction of our income tax provision is primarily due to the restoration and utilization of previously written off income tax credits. The years 2002 through 2007 are currently open under the statute of limitations and 2002 through 2005 are currently under audit by the IRS.

As of December 31, 2006, U.S. income taxes were not recorded on the undistributed earnings of foreign subsidiaries that had been or were intended to be reinvested indefinitely. During the first quarter of 2007, we announced we had signed agreements or plans to sell substantially all of our foreign assets or subsidiaries. These sales resulted in the recognition in 2007 of $71 million of U.S. income tax expense associated with the change in our assumption regarding permanent reinvestment of these undistributed earnings, with $46 million of this amount reflected in income from continuing operations and $25 million in discontinued operations. Additionally, gains on the sales of our international investments resulted in the release of $121 million of valuation allowance during 2007.

On January 1, 2007 we adopted the provisions of FIN 48. As a result of the implementation of FIN 48, we recorded a charge for additional uncertain tax benefits of $11 million, which was accounted for as a reduction of our beginning retained earnings. Included in this amount was an increase in our valuation allowance of $100 million, decreases to tax reserves of $61 million and a decrease to deferred tax liabilities of $28 million.

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A reconciliation of the beginning and ending amount of unrecognized tax benefits in accordance with FIN 48 is as follows:

	(In Millions)
Year Ended December 31	2008		2007
Balance at beginning of period	$	51	$	151
Reductions for prior year tax positions		—		(101	)
Additions for prior year tax positions		12		1
Statute lapses		—		—
Additions for current year tax positions		2		—
Settlements		—		—
Balance at end of period	$	65	$	51

Included in the balance at December 31, 2008 are $55 million of tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, other than interest and penalties, the disallowance of the shorter deductibility period would not affect the annual effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period. As of December 31, 2008, remaining uncertain tax benefits that would reduce our effective tax rate in future years are $10 million. It is reasonably possible that, within the next twelve months, we will settle with the IRS on our simplified service cost methodology, a timing issue. An estimate of a settlement range cannot be made at this point.

As of December 31, 2007 we had accrued $2 million of net interest expense on our uncertain tax liabilities. We accrued a net additional $1 million of interest on tax liabilities during 2008. The total net interest liability is $6 million as of December 31, 2008, $3 million of which relates to uncertain tax positions. We have not accrued any penalties with respect to uncertain tax benefits. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

11: STOCK-BASED COMPENSATION

We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee directors based on their contributions to the successful management of the company. The Plan has a five-year term, expiring in May 2009.

All grants under the Plan for 2008, 2007, and 2006 were in the form of TSR restricted stock and time-lapse restricted stock. Restricted stock recipients receive shares of CMS Energy Common Stock that have full dividend and voting rights. TSR restricted stock vesting is contingent on meeting a three-year service requirement and specific market conditions. Half of the market condition is based on the achievement of specified levels of TSR over a three-year period and half is based on a comparison of our TSR with the median shareholders’ return of a peer group over the same three-year period. Depending on the performance of the market, a recipient may earn a total award ranging from zero to 150 percent of the initial grant. Time-lapse restricted stock vests after a service period of five years for awards granted prior to 2004, and three years for awards granted in 2004 and thereafter. Restricted stock awards granted to officers in 2006 were entirely TSR restricted stock. Awards granted to officers in 2007 and 2008 were 80 percent TSR restricted stock and 20 percent time-lapsed restricted stock.

All restricted stock awards are subject to forfeiture if employment terminates before vesting. However, if certain minimum service requirements are met or are waived by action of the Compensation and Human Resources Committee of the Board of Directors, restricted shares may vest fully upon:

•  retirement,

•  disability, or

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•  change of control of CMS Energy, as defined by the Plan.

The Plan also allows for stock options, stock appreciation rights, phantom shares, and performance units, none of which were granted in 2008, 2007, or 2006.

Shares awarded or subject to stock options, phantom shares, and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such awards to any recipient exceed 250,000 shares in any fiscal year. We may issue awards of up to 3,384,080 shares of common stock under the Plan at December 31, 2008. Shares for which payment or exercise is in cash, as well as forfeited shares or stock options, may be awarded or granted again under the Plan.

The following table summarizes restricted stock activity under the Plan:

				Weighted-Average
				Grant Date
	Number of			Fair Value
Restricted Stock	Shares			per Share
Nonvested at December 31, 2007		1,681,454		$	13.52
Granted(a)		739,350		$	10.38
Vested		(171,004	)	$	13.67
Forfeited(b)		(445,500	)	$	15.34
Nonvested at December 31, 2008		1,804,300		$	12.10

(a)	During 2008, we granted 482,240 TSR shares and 257,110 time-lapse shares of restricted stock.
(b)	During 2008, 432,500 TSR shares granted in 2005 were forfeited due to the failure to meet the specific market conditions.

We expense the awards’ fair value over the required service period. As a result, we recognize all compensation expense for share-based awards that have accelerated service provisions upon retirement by the period in which the employee becomes eligible to retire. We calculate the fair value of time-lapse restricted stock based on the price of our common stock on the grant date. We calculate the fair value of TSR restricted stock awards on the grant date using a Monte Carlo simulation. We base expected volatilities on the historical volatility of the price of CMS Energy Common Stock.

The risk-free rate for each valuation was based on the three-year U.S. Treasury yield at the award grant date. The following table summarizes the significant assumptions used to estimate the fair value of the TSR restricted stock awards:

	2008			2007			2006
Expected volatility		19.70	%		19.11	%		20.51	%
Expected dividend yield		2.67	%		1.20	%		0.00	%
Risk-free rate		2.83	%		4.59	%		4.82	%

The total fair value of shares vested was $2 million in 2008, $15 million in 2007, and $4 million in 2006. Compensation expense related to restricted stock was $8 million in 2008, $10 million in 2007, and $9 million in 2006. The total related income tax benefit recognized in income was $3 million in 2008, $3 million in 2007, and $3 million in 2006. At December 31, 2008, there was $7 million of total unrecognized compensation cost related to restricted stock. We expect to recognize this cost over a weighted-average period of 2.3 years.

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The following table summarizes stock option activity under the Plan:

	Options
	Outstanding,
	Fully Vested,			Weighted-Average		Weighted-Average		Aggregate
	and			Exercise Price		Remaining		Intrinsic
Stock Options	Exercisable			per Share		Contractual Term		Value
								(In millions)
Outstanding at December 31, 2007		1,213,905		$	21.51		3.8 years	$	(5	)
Granted		—			—
Exercised		(173,000	)	$	6.45
Cancelled or Expired		(233,365	)	$	32.42
Outstanding at December 31, 2008		807,540		$	21.58		2.8 years	$	(9	)

Stock options give the holder the right to purchase common stock at the market price on the grant date. Stock options are exercisable upon grant, and expire up to ten years and one month from the grant date. We issue new shares when recipients exercise stock options. The total intrinsic value of stock options exercised was $1 million in 2008, $9 million in 2007, and $1 million in 2006. Cash received from exercise of these stock options was $1 million in 2008.

Since we have utilized tax loss carryforwards, we were not able to realize the excess tax benefits upon exercise of stock options and vesting of restricted stock. Therefore, we did not recognize the related excess tax benefits in equity. As of December 31, 2008, we have $17 million of unrealized excess tax benefits.

The following table summarizes the weighted average grant date fair value:

Years Ended December 31	2008		2007		2006
Weighted average grant date fair value per share
Restricted stock granted	$	10.38	$	14.18	$	13.84
Stock options granted(a)		—		—		—

(a) No stock options were granted in 2008, 2007, or 2006.

SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of SFAS No. 123(R) instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective.

12: LEASES

We lease various assets, including service vehicles, railcars, gas pipeline capacity and buildings. In accordance with SFAS No. 13, we account for a number of our power purchase agreements as capital and operating leases.

Operating leases for coal-carrying railcars have lease terms expiring over the next 15 years. These leases contain fair market value extension and buyout provisions, with some providing for predetermined extension period rentals. Capital leases for our vehicle fleet operations have a maximum term of 120 months and TRAC end-of-life provisions.

We have capital leases for gas transportation pipelines to the Karn generating complex and Zeeland power plant. The capital lease for the gas transportation pipeline into the Karn generating complex has a term of 15 years with a provision to extend the contract from month to month. The capital lease for the gas transportation pipeline to the Zeeland power plant has a lease term of 12 years with a renewal provision at the end of the contract. The

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remaining term of our long-term power purchase agreements range between 2 and 22 years. Most of our power purchase agreements contain provisions at the end of the initial contract terms to renew the agreements annually.

Consumers is authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. The following table summarizes our capital and operating lease expenses:

Years Ended December 31	2008			2007			2006
	In Millions
Capital lease expense	$	46		$	34		$	15
Operating lease expense		28			25			21
Income from subleases		(1	)		(2	)		(2	)

Minimum annual rental commitments under our non-cancelable leases at December 31, 2008 are:

	Capital		Finance		Operating
	Leases		Lease(a)		Leases
	In Millions
2009	$	16	$	23	$	27
2010		15		22		26
2011		13		21		25
2012		15		20		25
2013		8		20		19
2014 and thereafter		48		133		115
Total minimum lease payments		115		239	$	237
Less imputed interest		58		65
Present value of net minimum lease payments		57		174
Less current portion		12		13
Non-current portion	$	45	$	161

(a)	In April 2007, we sold Palisades to Entergy and entered into a 15-year power purchase agreement to buy all of the capacity and energy produced by Palisades, up to the annual average capacity of 798 MW. We provided $30 million in security to Entergy for our power purchase agreement obligation in the form of a letter of credit. We estimate that capacity and energy payments under the Palisades power purchase agreement will average $320 million annually. Our total purchases of capacity and energy under the Palisades power purchase agreement were $298 million in 2008 and $180 million in 2007.
	Because of the Palisades power purchase agreement and our continuing involvement with the Palisades assets, we accounted for the disposal of Palisades as a financing and not a sale. SFAS No. 98 specifies the accounting required for a seller’s sale and simultaneous leaseback involving real estate. We have continuing involvement with Palisades through security provided to Entergy for our power purchase agreement obligation, our DOE liability and other forms of involvement. As a result, we accounted for the Palisades plant, which is the real estate asset subject to the leaseback, as a financing for accounting purposes and not a sale. As a financing, no gain on the sale of Palisades was recognized in the Consolidated Statements of Income (Loss). We accounted for the remaining non-real estate assets and liabilities associated with the transaction as a sale.
	As a financing, the Palisades plant remains on our Consolidated Balance Sheets and we continue to depreciate it. We recorded the related proceeds as a finance obligation with payments recorded to interest expense and the finance obligation based on the amortization of the obligation over the life of the Palisades power purchase

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agreement. The value of the finance obligation was based on an allocation of the transaction proceeds to the fair values of the net assets sold and fair value of the Palisades plant asset under the financing. Total amortization and interest charges under the financing were $23 million in 2008 and $18 million in 2007.

13: PROPERTY, PLANT, AND EQUIPMENT

The following table is a summary of our property, plant, and equipment:

	Estimated
	Depreciable
December 31	Life in Years		2008		2007
			In Millions
Electric:
Generation		18-85	$	3,357	$	3,328
Distribution		12-75		4,766		4,496
Other		7-40		551		438
Capital and finance leases(a)				291		293
Gas:
Underground storage facilities(b)		30-65		270		267
Transmission		13-75		473		570
Distribution		30-80		2,460		2,286
Other		5-50		398		320
Capital leases(a)				21		24
Enterprises:
IPP		3-45		379		378
CMS Electric and Gas		n/a		—		2
Other		3-25		11		11
Other:		7-71		33		34
Construction work-in-progress				608		447
Less accumulated depreciation, depletion, and amortization(c)				4,428		4,166
Net property, plant, and equipment(d)			$	9,190	$	8,728

(a)	Capital and finance leases presented in this table are gross amounts. Accumulated amortization of capital and finance leases was $79 million at December 31, 2008 and $62 million at December 31, 2007. Additions were $6 million and Retirements and adjustments were $3 million during 2008. Additions were $229 million during 2007, which includes $197 million related to assets under the Palisades finance lease. Retirements and adjustments were $26 million during 2007.
(b)	Includes base natural gas in underground storage of $26 million at December 31, 2008 and December 31, 2007, which is not subject to depreciation.
(c)	At December 31, 2008, accumulated depreciation, depletion, and amortization included $4.241 billion from our utility plant assets and $187 million from other plant assets. At December 31, 2007, accumulated depreciation, depletion, and amortization included $3.992 billion from our utility plant assets and $174 million from other plant assets.
(d)	At December 31, 2008, utility plant additions were $629 million and utility plant retirements, including other plant adjustments, were $60 million. At December 31, 2007, utility plant additions, including capital leases, were $1.303 billion and utility plant retirements, including other plant adjustments, were $1.094 billion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Asset Acquisition:  In December 2007, we purchased a 935 MW gas-based generating plant located in Zeeland, Michigan for $519 million from an affiliate of LS Power Group. The original cost of the plant was $350 million and the plant acquisition adjustment was $213 million. This results in an increase to property, plant, and equipment of $519 million, net of $44 million of accumulated depreciation. The purchase also increased capital leases by $12 million. For additional details on the Zeeland finance lease, see Note 12, Leases.

Included in net property, plant and equipment are intangible assets. The following table summarizes our intangible assets:

	Amortization		2008				2007
December 31	Life				Accumulated				Accumulated
Description	in years		Gross Cost(a)		Amortization		Gross Cost(a)		Amortization
					In Millions
Software development		7-15	$	370	$	192	$	207	$	170
Plant acquisition adjustments		40		214		6		214		—
Rights of way		50-75		118		33		116		32
Leasehold improvements		various		11		9		19		16
Franchises and consents		various		14		6		14		5
Other intangibles		various		20		14		20		14
Total			$	747	$	260	$	590	$	237

(a) Intangible asset additions for our utility plant were $163 million during 2008, which included $161 million related to the installation and operation of our new integrated business software system. Intangible asset additions for our utility plant were $232 million during 2007, which included the Zeeland $213 million plant acquisition adjustment. Retirements were $23 million during 2007.

Pretax amortization expense related to intangible assets was $32 million for the year ended December 31, 2008, $21 million for the year ended December 31, 2007, and $23 million for the year ended December 31, 2006. We expect intangible assets amortization to range between $25 million and $29 million per year over the next five years.

14: EQUITY METHOD INVESTMENTS

We account for certain investments in other companies and partnerships using the equity method, in accordance with APB Opinion No. 18, when we have significant influence, typically when ownership is more than 20 percent but less than a majority. Earnings from equity method investments were $5 million in 2008, $40 million in 2007, and $89 million in 2006. The amount of consolidated retained earnings that represents undistributed earnings from these equity method investments was $1 million at December 31, 2008, $22 million at December 31, 2007, and $14 million at December 31, 2006.

If assets or income from continuing operations associated with any of our individual equity method investments, or on an aggregate basis by any combination of equity method investments, exceed 10 percent of our consolidated assets or income, then we must present summarized financial data of that subsidiary or combination of subsidiaries in our notes. At December 31, 2008, no individual equity method investment or combination of investments exceeded the 10 percent threshold.

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The following is summarized financial information for equity method investments that exceeded the 10 percent threshold at December 31, 2007 and December 31, 2006:

Income Statement Data

	Year Ended
	December 31, 2007
	Total(b)
	In Millions
Operating revenue	$	598
Operating expenses		448
Operating income		150
Other expense, net		69
Net income	$	81

	Year Ended
	December 31, 2006
	Jorf
	Lasfar(a)		Total(b)
	In Millions
Operating revenue	$	482	$	2,093
Operating expenses		317		1,600
Operating income		165		493
Other expense, net		57		252
Net income	$	108	$	241

Balance Sheet Data

	December 31, 2007
	Total(b)
	In Millions
Assets
Current assets	$	7
Property, plant and equipment, net		6
Other assets		177
	$	190
Liabilities
Current liabilities	$	4
Long-term debt and other non-current liabilities		—
Equity		186
	$	190

(a)	We sold our investment in Jorf Lasfar in 2007. At December 31, 2006, our investment in Jorf Lasfar was $313 million. Our share of net income from Jorf Lasfar was $16 million for the period January 1, 2007 through May 1, 2007, and $54 million for the year ended December 31, 2006.
(b)	Amounts include financial data from equity method investments through the date of sale.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

15: JOINTLY OWNED REGULATED UTILITY FACILITIES

We have investments in jointly owned regulated utility facilities, as shown in the following table:

	Ownership		Net				Accumulated				Construction
	Share		Investment(a)				Depreciation				Work in Progress
December 31	(%)		2008		2007		2008		2007		2008		2007
	In Millions
Campbell Unit 3		93.3	$	675	$	664	$	360	$	337	$	19	$	44
Ludington		51.0		61		65		107		104		7		1
Distribution		Various		96		89		41		44		3		5

(a) Net investment is the amount of utility plant in service less accumulated depreciation.

We include our share of the direct expenses of the jointly owned plants in operating expenses. We share operation, maintenance, and other expenses of these jointly owned utility facilities in proportion to each participant’s undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities.

16: 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. These reportable segments are:

•  electric utility, consisting of regulated activities associated with the generation and distribution of electricity in Michigan through our subsidiary, Consumers,

•  gas utility, consisting of regulated activities associated with the transportation, storage, and distribution of natural gas in Michigan through our subsidiary, Consumers, and

•  enterprises, consisting of various subsidiaries engaging primarily in domestic independent power production.

Accounting policies of our segments are as described in Note 1, Corporate Structure and Accounting Policies. Our consolidated financial statements reflect the assets, liabilities, revenues, and expenses of the individual segments when appropriate. We allocate accounts among the segments when common accounts are attributable to more than one segment. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, other operation and maintenance expense, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue, and pension provisions are allocated based on labor dollars.

We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income (loss) by segment. The “Other” segment includes corporate interest and other expenses, and certain deferred income taxes. We have reclassified certain amounts in 2006 to include CMS Capital results in the Other segment.

CMS-94

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following tables provide financial information by reportable segment:

Years Ended December 31	2008			2007			2006
	In Millions
Operating Revenues
Electric utility	$	3,594		$	3,443		$	3,302
Gas utility		2,827			2,621			2,373
Enterprises		379			383			438
Other		21			17			13
	$	6,821		$	6,464		$	6,126
Earnings from Equity Method Investees
Enterprises	$	5		$	39		$	87
Other		—			1			2
	$	5		$	40		$	89
Depreciation and Amortization
Electric utility	$	438		$	397		$	380
Gas utility		136			127			122
Enterprises		11			12			44
Other		4			4			4
	$	589		$	540		$	550
Fixed Charges
Electric utility	$	185		$	192		$	164
Gas utility		60			69			73
Enterprises		6			9			66
Other		141			168			177
	$	392		$	438		$	480
Income Tax Expense (Benefit)
Electric utility	$	153		$	100		$	95
Gas utility		45			47			18
Enterprises		(10	)		(183	)		(145	)
Other		(46	)		(159	)		(156	)
	$	142		$	(195	)	$	(188	)
Net Income (Loss) Available to Common Stockholders
Electric utility	$	271		$	196		$	199
Gas utility		89			87			37
Enterprises		14			(412	)		(227	)
Discontinued operations(a)		—			(89	)		54
Other		(85	)		(9	)		(153	)
	$	289		$	(227	)	$	(90	)

CMS-95

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Years Ended December 31	2008		2007		2006
	In Millions
Investments
Enterprises	$	5	$	6	$	556
Other		6		5		10
	$	11	$	11	$	566
Total Assets
Electric utility(b)	$	8,904	$	8,492	$	8,516
Gas utility(b)		4,565		4,102		3,950
Enterprises		313		982		1,901
Other		1,119		616		958
	$	14,901	$	14,192	$	15,325
Capital Expenditures(c)
Electric utility	$	553	$	1,319	$	462
Gas utility		241		168		172
Enterprises		3		5		42
Other		—		—		1
	$	797	$	1,492	$	677

Geographic Areas(d)

	2008		2007			2006
	In Millions
United States
Operating revenue	$	6,821	$	6,462		$	6,123
Operating income	$	799	$	151		$	85
Total Assets	$	14,898	$	14,187		$	14,077
International
Operating revenue	$	—	$	2		$	3
Operating income (loss)	$	1	$	(150	)	$	(139	)
Total Assets	$	3	$	5		$	1,248

(a)	Amounts include income tax expense of $1 million for December 31, 2008, an income tax benefit of $1 million for December 31, 2007, and income tax expense of $32 million for December 31, 2006.
(b)	Amounts include a portion of Consumers’ other common assets attributable to both the electric and gas utility businesses.
(c)	Amounts include purchase of nuclear fuel and capital lease additions. Amounts also include a portion of Consumers’ capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.
(d)	Revenues are based on the country location of customers.

CMS-96

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

17: CONSOLIDATION OF VARIABLE INTEREST ENTITIES

FIN 46(R) requires the consolidation of entities that are VIEs if the reporting company determines that it will absorb a majority of the VIE’s expected losses, receive a majority of the VIE’s residual returns, or both. The company that is required to consolidate the VIE is called the primary beneficiary. Variable interests are contractual, ownership or other interests in an entity that change as the fair value of the entity’s net assets, excluding variable interests, change. An entity is considered to be a VIE when its capital is insufficient to permit it to finance its activities without additional subordinated financial support or its equity investors, as a group, lack the characteristics of having a controlling financial interest. When determining whether we are the primary beneficiary of a VIE we examine the following factors:

•  related party agreements such as operating and maintenance agreements, power purchase agreements and leases,

•  ownership interest, and

•  allocation of expected losses and return based on discounted cash flows at a weighted average cost of capital.

We are the primary beneficiary of three VIEs through our ownership interests in the following partnerships:

			Total
	Nature of		Generating
Name (Ownership Interest)	the Entity	Financing of Partnership	Capacity
T.E.S. Filer City (50)%	Coal-based power generator	Non-recourse long-term debt that matured in December 2007.	70 MW
Grayling (50)%	Wood waste-based power generator	Sale of revenue bonds that mature in November 2012 and bear interest at variable rates. The debt is recourse to the partnership, but not the individual partners, and secured by a letter of credit equal to the outstanding balance.	40 MW
Genesee (50)%	Wood waste-based power generator	Sale of revenue bonds that mature in 2021 and bear interest at fixed rates. The debt is non-recourse to the partnership and secured by a CMS Energy guarantee capped at $3 million annually.	38 MW
Total			148 MW

We consolidated these entities for all periods presented.

We have operating and management contracts with these partnerships and we are the primary purchaser of power from each partnership through long-term power purchase agreements. We also have reduced dispatch agreements with Grayling and Genesee, which allow the relative facilities to be dispatched based on the market price of wood waste. This results in fuel cost savings, which the partnerships share with us.

The partnerships have third-party obligations totaling $76 million at December 31, 2008 and $83 million at December 31, 2007. Property, plant, and equipment serving as collateral for these obligations have a carrying value of $145 million at December 31, 2008 and $180 million at December 31, 2007. Other than through outstanding letters of credit and guarantees of $5 million, the creditors of these partnerships do not have recourse to the general credit of CMS Energy. We have not provided financial or other support during the periods presented that were not previously contractually required.

Additionally, through our trust preferred security structure, we hold an interest in a variable interest entity in which we are not the primary beneficiary. We deconsolidated the entity and reflected it as Long-term debt-Related parties. Our maximum exposure to loss through our interest is limited to our Long-term debt-Related parties balance of $178 million. For additional information, see Note 5, Financings and Capitalization, “Long-Term Debt-Related Parties.”

CMS-97

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

18: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)

	2008
Quarters Ended	March 31		June 30			Sept. 30		Dec. 31
	In Millions, Except Per Share Amounts
Operating revenue	$	2,184	$	1,365		$	1,428	$	1,844
Operating income		253		155			212		180
Income from continuing operations		106		50			80		64
Income (loss) from discontinued operations(a)		—		(1	)		1		—
Net income		106		49			81		64
Preferred dividends		3		3			2		3
Net income available to common stockholders		103		46			79		61
Income from continuing operations per average common share — basic		0.46		0.21			0.35		0.27
Income from continuing operations per average common share — diluted		0.44		0.20			0.33		0.27
Basic earnings per average common share(b)		0.46		0.20			0.36		0.27
Diluted earnings per average common share(b)		0.44		0.19			0.34		0.27
Common stock prices(c)
High		17.16		15.83			14.91		12.58
Low		13.35		13.78			12.09		8.81

	2007
Quarters Ended	March 31			June 30			Sept. 30		Dec. 31(d)
	In Millions, Except Per Share Amounts
Operating revenue	$	2,189		$	1,319		$	1,282	$	1,674
Operating income (loss)		(24	)		7			212		(194	)
Income (loss) from continuing operations		(33	)		(55	)		84		(122	)
Income (loss) from discontinued operations(a)		(178	)		91			—		(2	)
Net income (loss)		(211	)		36			84		(124	)
Preferred dividends		3			3			2		3
Redemption premium on preferred stock		1			—			—		—
Net income (loss) available to common stockholders		(215	)		33			82		(127	)
Income (loss) from continuing operations per average common share — basic		(0.17	)		(0.26	)		0.37		(0.56	)
Income (loss) from continuing operations per average common share — diluted		(0.17	)		(0.26	)		0.34		(0.56	)
Basic earnings (loss) per average common share(b)		(0.97	)		0.15			0.37		(0.57	)
Diluted earnings (loss) per average common share(b)		(0.97	)		0.15			0.34		(0.57	)
Common stock prices(c)
High		18.21			18.93			17.90		17.91
Low		16.00			16.78			15.48		16.06

(a)	Net of tax.
(b)	Sum of the quarters may not equal the annual earnings (loss) per share due to changes in shares outstanding.
(c)	Based on New York Stock Exchange composite transactions.
(d)	The quarter ended December 31, 2007 includes a $181 million net after-tax charge resulting from an electricity sales agreement termination.

CMS-98

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of

CMS Energy Corporation

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), of cash flows, and of common stockholders’ equity present fairly, in all material respects, the financial position of CMS Energy Corporation and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 10 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain income tax provisions in 2007.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 25, 2009

CMS-99

Report of Independent Registered Public Accounting Firm

To the Partners and the Management Committee of

Midland Cogeneration Venture Limited Partnership:

In our opinion, the accompanying statements of operations and of cash flows present fairly, in all material respects, the results of operations and cash flows of Midland Cogeneration Venture Limited Partnership for the period ended November 21, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 19, 2007

CMS-100

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of
CMS Energy Corporation

We have audited the accompanying consolidated statements of income (loss), common stockholders’ equity, and cash flows of CMS Energy Corporation (a Michigan Corporation) for the year ended December 31, 2006. Our audit also included the financial statement schedules as it relates to 2006 listed in the Index at Item 15(a)(2). These financial statements and schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedules based on our audit. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a former 49% owned variable interest entity which has been consolidated through the date of sale, November 21, 2006 (Note 3), which statements reflect total revenues constituting 8.9% in 2006 of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for the period indicated above for Midland Cogeneration Venture Limited Partnership, is based solely on the report of the other auditors.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated results of CMS Energy Corporation’s operations and its cash flows for the year ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

As discussed in Note 8 to the consolidated financial statements, in accordance with Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” the Company changed its method of accounting for the funded status of its defined benefit pension and other postretirement benefit plans in 2006.

/s/  Ernst & Young LLP

Detroit, Michigan

February 21, 2007, except for “Discontinued

Operations” in Note 3 as to which the date

is February 20, 2008

CMS-101

2008 CONSOLIDATED FINANCIAL STATEMENTS

CE-1

CONSUMERS ENERGY COMPANY

SELECTED FINANCIAL INFORMATION

		2008		2007		2006		2005			2004
Operating revenue (in millions)	($)		6,421		6,064		5,721		5,232			4,711
Earnings from equity method investees (in millions)	($)		—		—		1		1			1
Income (loss) before cumulative effect of change in accounting principle (in millions)	($)		364		312		186		(96	)		280
Cumulative effect of change in accounting (in millions)	($)		—		—		—		—			(1	)
Net income (loss) (in millions)	($)		364		312		186		(96	)		279
Net income (loss) available to common stockholder (in millions)	($)		362		310		184		(98	)		277
Cash provided by operations (in millions)	($)		873		440		474		639			595
Capital expenditures, excluding capital lease additions (in millions)	($)		789		1,258		646		572			508
Total assets (in millions)(a)	($)		14,246		13,401		12,845		13,178			12,811
Long-term debt, excluding current portion (in millions)(a)	($)		3,908		3,692		4,127		4,303			4,000
Long-term debt — related parties, excluding current portion (in millions)	($)		—		—		—		—			326
Non-current portion of capital and finance lease obligations (in millions)	($)		206		225		42		308			315
Total preferred stock (in millions)	($)		44		44		44		44			44
Number of preferred shareholders at year-end			1,584		1,641		1,728		1,823			1,931
Book value per common share at year-end	($)		44.05		43.37		35.17		33.03			28.68
Number of full-time equivalent employees at year-end			7,697		7,614		8,026		8,114			8,050
Electric statistics
Sales (billions of kWh)			37		39		38		39			38
Customers (in thousands)			1,814		1,799		1,797		1,789			1,772
Average sales rate per kWh	(¢)		9.48		8.65		8.46		6.73			6.88
Gas Utility Statistics
Sales and transportation deliveries (bcf)			338		340		309		350			385
Customers (in thousands)(b)			1,713		1,710		1,714		1,708			1,691
Average sales rate per mcf	($)		11.25		10.66		10.44		9.61			8.04

(a)

Until their sale in November 2006 , we were the primary beneficiary of both the MCV Partnership and the FMLP. As a result, we consolidated their assets, liabilities and activities into our consolidated financial statements as of and for the years ended December 31, 2005 and 2004. These partnerships had third-party obligations totaling $482 million at December 31, 2005 and $582 million at December 31, 2004. Property, plant and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005 and $1.426 billion at December 31, 2004.

(b)

Excludes off-system transportation customers.

CE-2

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.

FORWARD-LOOKING STATEMENTS AND INFORMATION

This Form 10-K 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. These factors include our inability to predict or control:

•  the price of CMS Energy Common Stock, capital and financial market conditions and the effect of these 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 CMS Energy, including its:

•  revenues,

•  capital expenditure program and related earnings growth,

•  ability to collect accounts receivable from our customers,

•  cost of capital and availability of capital, and

•  Pension Plan and postretirement benefit plans assets and required contributions,

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

•  the 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 applicable laws, rules, regulations, principles or practices or in their interpretation, including with respect to taxes, environmental and accounting matters, that could have an impact on our business,

•  the impact of any future regulations or laws regarding:

•  carbon dioxide, mercury and other greenhouse gas emissions,

•  limitations on the use of coal-based electric power plants, and

•  renewable portfolio standards and energy efficiency mandates,

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

CE-3

Consumers Energy Company

•  adverse regulatory or legal interpretations or decisions, including those related to environmental laws and regulations, and potential environmental remediation costs associated with these interpretations or decisions, including but not limited to those that may affect our RMRR classification under NSR regulation,

•  potentially adverse regulatory treatment or failure to receive timely regulatory orders concerning a number of significant questions currently or potentially before the MPSC, including:

•  adequate and timely recovery of:

•  Clean Air Act capital and operating costs and other environmental and safety-related expenditures,

•  power supply and natural gas supply costs,

•  additional electric and gas rate-based investments,

•  increased MISO energy and transmission costs,

•  costs associated with energy efficiency investments and state or federally mandated renewable resource standards,

•  Big Rock decommissioning funding shortfalls,

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

•  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, and their impact on our cash flow and working capital,

•  the impact of construction material prices and 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 these 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, and stability of insurance providers,

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

•  achievement of capital expenditure and operating expense goals,

•  earnings volatility resulting from the GAAP requirement that we apply mark-to-market accounting to certain energy commodity contracts,

CE-4

Consumers Energy Company

•  changes in financial or regulatory accounting principles or policies,

•  a possible future requirement to comply with International Financial Reporting Standards, which differ from GAAP in various ways including the present lack of special accounting treatment for regulated activities similar to that provided under SFAS No. 71,

•  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,

•  population growth or decline in the geographic areas where we do business,

•  changes in the economic and financial viability of our suppliers, customers, and other counterparties and the continued ability of these third parties to perform their obligations to us,

•  the effectiveness of our risk management policies and procedures,

•  our ability to achieve generation planning goals and the occurrence and duration of planned or unplanned generation outages,

•  adverse outcomes regarding tax positions due to the difficulty in quantifying tax effects of business decisions and reserves, and

•  other business or investment matters 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 details regarding these and other uncertainties, see the “Outlook” section included in this MD&A, Note 4, Contingencies, and Part I, 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.

CE-5

Consumers Energy Company

Our forecast calls for investing in excess of $6 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.

In October 2008, the Michigan governor signed into law a comprehensive energy reform package. In February 2009, we filed our renewable energy plan and energy optimization plan with the MPSC in order to conform to various aspects of this legislation.

As we work to implement plans to serve our customers in the future, the cost of energy and related cash flow issues continue to challenge us. Natural gas prices and eastern coal prices have been volatile. 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. There is additional uncertainty associated with state and federal legislative and regulatory proposals related to regulation of carbon dioxide emissions, particularly associated with coal-based generation. We are closely monitoring these developments for the effect on our future plans.

We are 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 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, improve customer service, 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 adversely impacted by the continued downturn and uncertainty in Michigan’s automotive industry. There also has been a sharp economic 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 (Loss) Available To Common Stockholder

Years Ended December 31	2008		2007		Change			2007		2006			Change
	In Millions
Electric	$	271	$	196	$	75		$	196	$	199			(3	)
Gas		89		87		2			87		37			50
Other (Includes The MCV Partnership interest)		2		27		(25	)		27		(52	)		79
Net Income Available to Common Stockholder	$	362	$	310	$	52		$	310	$	184		$	126

For 2008, our net income available to our common stockholder was $362 million, compared to $310 million for 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 increased depreciation expense.

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,	$	109
•	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
•	absence of nuclear operating and maintenance costs,		25
•	increase in gas delivery revenue primarily due to the MPSC’s August 2007 gas rate order,		20
•	decrease in electric deliveries,		(51	)
•	decrease in other income,		(48	)
•	increase in depreciation expense, and		(31	)
•	other net decreases		(1	)
Total change		$	52

For 2007, our net income available to our common stockholder was $310 million, compared to $184 million for 2006. In 2006, we sold our ownership interest in the MCV Partnership. Accordingly, in 2007, we no longer experienced mark-to-market losses on certain long-term gas contracts and associated financial hedges at the MCV Partnership. The increase in 2007 also reflects higher net income from our gas utility due to colder weather and gas rate increases authorized in November 2006 and August 2007. Partially offsetting these gains was a small decrease in electric net income, influenced by several factors, including regulatory disallowances in 2007, higher property taxes, and higher electric deliveries.

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Specific changes to net income available to our common stockholder for 2007 versus 2006 are:

		In Millions
•	lower operating and maintenance costs primarily due to the sale of Palisades in April 2007,	$	82
•	decrease in losses from our ownership interest in the MCV Partnership primarily due to the absence, in 2007, of mark-to-market losses on certain long-term gas contracts and financial hedges,		60
•	increase in gas delivery revenue primarily due to the MPSC’s November 2006 and August 2007 gas rate orders,		47
•	decrease in other income tax adjustments primarily due to higher expected utilization of capital loss carryforwards,		14
•	increase in electric revenue primarily due to favorable weather and higher surcharge revenue,		16
•	increase in gas delivery revenue primarily due to colder weather,		12
•	decrease due to electric revenue being used to offset costs incurred under our power purchase agreement with Entergy,		(88	)
•	increase in general taxes, primarily due to higher property tax expense,		(14	)
•	increase in interest charges, and		(7	)
•	other net increases to income		4
Total change		$	126

Electric Utility Results Of Operations

Years Ended December 31	2008		2007		Change			2007		2006		Change
	In Millions
Net income	$	271	$	196	$	75		$	196	$	199	$	(3	)
Reasons for the change:
Electric deliveries and rate increase					$	89						$	(118	)
Surcharge revenue						15							6
Power supply costs and related revenue						18							(17	)
Non-commodity revenue						(14	)						(12	)
Depreciation and other operating expenses						40							150
Other income						(46	)						26
General taxes						15							(15	)
Interest charges						11							(18	)
Income taxes						(53	)						(5	)
Total change					$	75						$	(3	)

Electric deliveries and rate increase: For 2008, electric delivery revenues increased $89 million versus 2007 primarily due to additional revenue of $168 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 $79 million primarily due to lower deliveries. Deliveries to end-use customers were 37.5 billion kWh, a decrease of 1.3 billion kWh or 3 percent versus 2007. Approximately 45 percent of the decrease in electric deliveries was due to weather.

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For 2007, electric delivery revenues decreased $118 million versus 2006. The decrease was primarily due to $136 million of revenue related to Palisades that was designated toward the recovery of PSCR costs consistent with the MPSC order related to the sale in April 2007. Partially offsetting the decrease were increased electric delivery revenues of $14 million, as deliveries to end-use customers were 38.8 billion kWh, an increase of 0.3 billion kWh or 0.8 percent versus 2006. The increase in electric deliveries was primarily due to favorable weather. Also contributing to the increase was $2 million of additional revenue from the inclusion of the Zeeland power plant in rates and $2 million related to the return of additional former ROA customers.

Surcharge revenue: For 2008, surcharge revenue increased $15 million versus 2007. The increase was primarily due to the April 2008 MPSC order allowing recovery of pension and OPEB 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.

For 2007, surcharge revenue increased $6 million versus 2006. The increase was primarily due to a surcharge that we began collecting in the first quarter of 2006 that the MPSC authorized under Section 10d(4) of the Customer Choice Act.

Power supply costs and related revenue: For 2008, PSCR revenue increased by $18 million versus 2007. The increase primarily reflects the absence of a 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.

For 2007, PSCR revenue decreased by $17 million versus 2006. This decrease primarily reflects amounts excluded from recovery in the 2006 PSCR reconciliation case. The decrease also reflects the absence, in 2007, of an increase in power supply revenue associated with the 2005 PSCR reconciliation case.

Non-commodity revenue: For 2008, non-commodity revenue decreased $14 million versus 2007 primarily due to the absence, in 2008, of METC transmission services revenue. The METC transmission service agreement expired in April 2007.

For 2007, non-commodity revenue decreased $12 million versus 2006 primarily due to lower METC transmission services revenue.

Depreciation and other operating expenses: For 2008, depreciation and other operating expenses decreased $40 million versus 2007. The decrease was primarily due to the absence of operating expenses of Palisades, which was sold 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 pension and OPEB expense due to the April 2008 MPSC order allowing recovery of certain costs through a surcharge, increased depreciation and amortization expense due to more plant in service and increased amortization of certain regulatory assets. For additional details on our power purchase agreement with the MCV Partnership, see Note 4, Contingencies, “Other Electric Contingencies.”

For 2007, depreciation and other operating expenses decreased $150 million versus 2006. The decrease was primarily due to lower operating expenses of Palisades, which was sold in April 2007. Also contributing to the decrease was the absence, in 2007, of costs incurred in 2006 related to a refueling outage at Palisades, and lower overhead line maintenance and storm restoration costs. These decreases were offset partially by increased depreciation and amortization expense due to more plant in service and increased amortization of certain regulatory assets.

Other income: For 2008, other income decreased $46 million versus 2007. The decrease was primarily due to reduced interest income, reflecting lower levels of short-term cash investments, 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 a charge that recognized an other-than-temporary decline in the fair value of our SERP investments.

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For 2007, other income increased $26 million versus 2006 primarily due to higher interest income on short-term cash investments. The increase in short-term cash investments was primarily due to proceeds from the Palisades sale and equity infusions from CMS Energy.

General taxes: For 2008, general tax expense decreased $15 million versus 2007 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 an income tax. The decrease was partially offset by higher property tax expense.

For 2007, general tax expense increased $15 million versus 2006 primarily due to higher property tax expense, reflecting higher millage rates and lower property tax refunds versus 2006.

Interest charges: For 2008, interest charges decreased $11 million versus 2007 primarily due to lower interest associated with amounts to be refunded to our 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.

For 2007, interest charges increased $18 million versus 2006. The increase was primarily due to interest on amounts to be refunded to customers as a result of the sale of Palisades as ordered by the MPSC and interest charges related to the IRS settlement.

Income taxes: For 2008, income taxes increased $53 million versus 2007. The increase primarily reflects $47 million due to higher earnings and $6 million due to the inclusion of the Michigan Business Tax.

For 2007, income taxes increased $5 million versus 2006 primarily due to the absence, in 2007, of a $4 million income tax benefit from the restoration and utilization of income tax credits resulting from the resolution of an IRS income tax audit.

Gas Utility Results of Operations

Years Ended December 31	2008		2007		Change			2007		2006		Change
	In Millions
Net income	$	89	$	87	$	2		$	87	$	37	$	50
Reasons for the change:
Gas deliveries and rate increase					$	44						$	91
Gas wholesale and retail services, other gas revenues, and other income						(28	)						14
Other operating expenses						(24	)						(19	)
General taxes and depreciation						(1	)						(11	)
Interest charges						9							4
Income taxes						2							(29	)
Total change					$	2						$	50

Gas deliveries and rate increase: For 2008, gas delivery revenues increased $44 million versus 2007 primarily due to additional revenue of $33 million from the MPSC’s August 2007 and December 2008 gas rate orders. Also contributing to the increase was higher gas delivery revenue of $11 million. Gas deliveries, including miscellaneous transportation to end-use customers, were 304 bcf, an increase of 4 bcf or 1.3 percent. The increase in gas deliveries was due to colder weather in 2008.

For 2007, gas delivery revenues increased $91 million versus 2006 primarily due to additional revenue of $81 million from the MPSC’s November 2006 and August 2007 gas rate orders. Gas delivery revenues also increased $10 million as gas deliveries, including miscellaneous transportation to end-use customers, were 300 bcf,

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an increase of 18 bcf or 6.4 percent. The increase in gas deliveries was primarily due to colder weather, partially offset by higher system losses.

Gas wholesale and retail services, other gas revenues, and other income: For 2008, gas wholesale and retail services, other gas revenues, and other income decreased $28 million versus 2007. The decrease was primarily due to lower interest income reflecting lower short-term investments, and lower pipeline capacity optimization revenue. Also contributing to the decrease was a charge that recognized an other-than-temporary decline in the fair value of our SERP investments.

For 2007, gas wholesale and retail services, other gas revenues, and other income increased $14 million versus 2006. The increase was primarily due to higher interest income on short-term cash investments. The increase in short-term cash investments was primarily due to proceeds from the Palisades sale and equity infusions from CMS Energy.

Other operating expenses: For 2008, other operating expenses increased $24 million versus 2007 primarily due to higher uncollectible accounts expense and higher operating expense across our storage, transmission and distribution systems.

For 2007, other operating expenses increased $19 million versus 2006 primarily due to higher uncollectible accounts expense and payments, beginning in November 2006, to a fund that provides energy assistance to low-income customers.

General taxes and depreciation: For 2008, general taxes and depreciation increased $1 million versus 2007. The increase was primarily due to higher depreciation and increased property taxes. The increase was partially offset by decreased general taxes 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 an income tax.

For 2007, general taxes and depreciation increased $11 million versus 2006. The increase in general taxes reflects higher property tax expense due to higher millage rates and lower property tax refunds versus 2006. The increase in depreciation expense is primarily due to higher plant in service.

Interest charges: For 2008, interest charges decreased $9 million versus 2007 primarily due to lower average debt levels and a lower average interest rate.

For 2007, interest charges decreased $4 million versus 2006 primarily due to lower average debt levels and a lower average interest rate versus 2006.

Income taxes: For 2008, income taxes decreased $2 million versus 2007. The decrease reflects $4 million related to the tax treatment of items related to property, plant and equipment, as required by the MPSC orders. This decrease was partially offset by a $1 million increase due to the inclusion of the Michigan Business Tax and $1 million related to the forfeiture of restricted stock.

For 2007, income taxes increased $29 million versus 2006 primarily due to higher earnings by the gas utility.

Other Nonutility Results of Operations

Years Ended December 31	2008		2007		Change			2007		2006			Change
	In Millions
Net income (loss)	$	2	$	27	$	(25	)	$	27	$	(52	)	$	79

For 2008, net income from other nonutility operations was $2 million, a decrease of $25 million versus 2007. The decrease was primarily due to the absence, in 2008, of certain income tax benefits.

For 2007, net income from other nonutility operations was $27 million, an increase of $79 million versus 2006. In late 2006, we sold our ownership interest in the MCV Partnership. Accordingly, in 2007, the increase in earnings primarily reflects the absence, in 2007, of mark-to-market losses on certain long-term gas contracts and associated

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financial hedges at the MCV Partnership. Also contributing to the increase was lower income tax expense, reflecting higher expected utilization of capital loss carryforwards. See Note 9, Income Taxes, for further details.

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. For additional accounting policies, see Note 1, Corporate Structure and Accounting Policies.

Use of Estimates and Assumptions

In preparing our consolidated financial statements, we use estimates and assumptions that may affect reported amounts and disclosures. We use accounting estimates for asset valuations, depreciation, amortization, financial and derivative instruments, employee benefits, indemnifications and contingencies. Actual results may differ from estimated results due to changes in the regulatory environment, competition, regulatory decisions, lawsuits, and other factors.

Contingencies: We record a liability for contingencies when we conclude that it is probable that a liability has been incurred and the amount of loss can be reasonably estimated. We consider all relevant factors in making these assessments.

Fair Value Measurements: We have assets and liabilities that we account for or disclose at fair value. Our fair value measurements are performed in accordance with SFAS No. 157, which requires 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 of our SERP assets, our investment in CMS Energy Common Stock, and the year-end measurement of our pension and OPEB plan assets. For a detailed discussion of the methods used to calculate our fair value measurements, see Note 2, Fair Value Measurements.

Long-Lived Assets and Investments: Our assessment of the recoverability of long-lived assets and investments involves critical accounting estimates. We periodically perform tests of impairment if certain conditions triggering events occur or if there has been a decline in value that may be other than temporary. Of our total assets, recorded at $14.246 billion at December 3l, 2008, 63 percent represent long-lived assets and investments that are subject to this type of analysis. We base our evaluations of impairment on such indicators as:

•  the nature of the assets,

•  projected future economic benefits,

•  regulatory and political environments,

•  historical and future cash flow and profitability measurements, and

•  other external market conditions and factors.

The estimates we use can change over time, which could have a material impact on our consolidated financial statements. For additional details, see Note 1, Corporate Structure and Accounting Policies, “Impairment of Investments and Long-Lived Assets.”

Accounting for the Effects of Industry Regulation

Our involvement in a regulated industry requires us to use SFAS No. 71 to account for the effects of the regulators’ decisions that impact the timing and recognition of our revenues and expenses. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity.

For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate that we will recover the expenses in future rates. Conversely, we may record as

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regulatory liabilities items that non-regulated entities may normally recognize as revenues, if the actions of the regulator indicate that we will be required to refund the revenues to customers. Judgment is required to determine the appropriate accounting for items recorded as regulatory assets and liabilities. At December 31, 2008, we had $2.438 billion recorded as regulatory assets and $1.988 billion recorded as regulatory liabilities.

Our PSCR and GCR cost recovery mechanisms also give rise to probable future revenues that will be recovered from customers or past overrecoveries that will be refunded to customers through the ratemaking process. Underrecoveries are included in Accrued power supply and gas revenue and overrecoveries are included in Accrued rate refunds on our Consolidated Balance Sheets. At December 31, 2008, we had $7 million recorded as regulatory assets for underrecoveries of power supply and gas costs and $7 million recorded as regulatory liabilities for overrecoveries of power supply and gas costs.

For additional details, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation.”

Accounting for Financial and Derivative Instruments and Market Risk Information

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

Derivative Instruments: We use the criteria in SFAS No. 133 to determine if we need to account for certain contracts as derivative instruments. These criteria are complex and often require significant judgment in applying them to specific contracts. 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. For additional details on our derivatives, see Note 6, Financial and Derivative Instruments.

To determine the fair value of our derivatives, we generally use information from external sources, such as quoted market prices and other valuation information. Our valuations use various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The fair values we calculate for our derivatives may change significantly as commodity prices and volatilities change. The cash returns we actually realize on our derivatives may be different from the fair values that we estimate. For derivatives in an asset position, our calculations of fair value include reserves to reflect the credit risk of our counterparties. For derivatives in a liability position, our calculations include reserves to reflect our own credit risk. At December 31, 2008, the amount of credit reserves we have recorded is immaterial. For additional details on how we determine the fair values of our derivatives, see Note 2, Fair Value Measurements.

The types of contracts we typically classify as derivatives are financial transmission rights, fixed price fuel contracts, and forward and option contracts for natural gas and foreign currencies. 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.

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Market Risk Information: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, foreign currency exchange rates, and equity security prices. We may enter into various risk management contracts to limit our exposure to these risks, including swaps, options, 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.

These contracts contain credit risk, which is the risk that our counterparties will fail to meet their contractual obligations. We reduce this risk using established policies and procedures, such as evaluating our counterparties’ credit quality and setting collateral requirements as necessary. If terms permit, we use standard agreements that allow us to net positive and negative exposures associated with the same counterparty. Given these policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings because of counterparty nonperformance.

The following risk sensitivities illustrate the potential loss in fair value, cash flows, or future earnings from our financial instruments, including our derivative contracts, assuming a hypothetical adverse change in market rates or prices of 10 percent. Potential losses could exceed the amounts shown in the sensitivity analyses if changes in market rates or prices were to exceed 10 percent.

Interest Rate Risk: We are exposed to interest rate risk resulting from issuing fixed-rate and variable-rate financing instruments, and from interest rate swap agreements. We use a combination of these instruments to manage this risk as deemed appropriate, based upon market conditions. These strategies are designed to provide and maintain a balance between risk and the lowest cost of capital.

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

December 31	2008		2007
	In Millions
Variable-rate financing — before tax annual earnings exposure	$	1	$	1
Fixed-rate financing — potential reduction in fair value(a)		136		116

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

Commodity Price Risk: Operating in the energy industry, we are exposed to commodity price risk, which arises from fluctuations in the price of electricity, natural gas, coal, and other commodities. Commodity prices are influenced by a number of factors, including weather, changes in supply and demand, and liquidity of commodity markets. In order to manage commodity price risk, we may enter into various non-trading derivative contracts, such as fixed price fuel contracts.

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

December 31	2008		2007
	In Millions
Potential reduction in fair value:
Fixed price fuel contracts	$	1	$	—

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Investment Securities Price Risk: Our investments in debt and equity securities are exposed to changes in interest rates and price fluctuations in equity markets. The following table shows the potential effect of adverse changes in interest rates and fluctuations in equity prices on our available-for-sale investments.

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

December 31	2008		2007
	In Millions
Potential reduction in fair value of available-for-sale equity securities (SERP investments and investment in CMS Energy common stock)	$	4	$	7

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

Retirement Benefits

Pension: We have external trust funds to provide retirement pension benefits to our employees under a non-contributory, defined benefit Pension Plan. On September 1, 2005, the defined benefit Pension Plan was closed to new participants and we implemented the qualified DCCP, which provides an employer contribution of five percent of base pay to the existing 401(k) plan. An employee contribution is not required to receive the plan’s employer cash contribution. All employees hired on or after September 1, 2005 participate in this plan as part of their retirement benefit program. Previous cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date.

401(k): We provide an employer match in our 401(k) plan equal to 60 percent on eligible contributions up to the first six percent of an employee’s wages.

OPEB: We provide postretirement health and life benefits under our OPEB plan to qualifying retired employees.

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 an estimate of our pension cost, OPEB cost, and cash contributions for the next three years:

Expected	Pension Cost		OPEB Cost		Pension Contribution		OPEB Contribution
	In Millions
2009	$	98	$	78	$	291	$	52
2010		88		75		123		52
2011		85		73		102		52

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

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will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the Pension Plan.

Lowering the expected long-term rate of return on the Pension Plan assets by 0.25 percent (from 8.25 percent to 8.00 percent) would increase estimated pension cost for 2009 by $3 million. Lowering the discount rate by 0.25 percent (from 6.50 percent to 6.25 percent) would increase estimated pension cost for 2009 by $5 million.

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

Accounting For Asset Retirement Obligations

We are required to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. We have legal obligations to remove some of our assets at the end of their useful lives. We calculate the fair value of ARO liabilities using an expected present value technique, that reflects assumptions about costs, inflation, and profit margin that third parties would consider to assume the obligation. We did not include a market risk premium in our ARO fair value estimates since a reasonable estimate could not be made.

If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is recognized when a reasonable estimate of fair value can be made. Generally, our gas transmission and electric and gas distribution assets have indeterminate lives and retirement cash flows that cannot be determined. However, we have recorded an ARO for our obligation to cut, purge, and cap abandoned gas distribution mains and gas services at the end of their useful lives. We have not recorded a liability for assets that have insignificant cumulative disposal costs, such as substation batteries. For additional details, see Note 8, Asset Retirement Obligations.

Related Party Transactions

We enter into a number of significant transactions with related parties. These transactions include:

•  purchase and sale of electricity from and to Enterprises,

•  payment of parent company overhead costs to CMS Energy, and

•  investment in CMS Energy Common Stock.

Transactions involving the power supply purchases from certain affiliates of Enterprises are based upon avoided costs under PURPA and competitive bidding. The payment of parent company overhead costs is based on the use of accepted industry allocation methodologies. These payments are for costs that generally occur in the normal course of business.

For additional details on related party transactions, see Note 1, Corporate Structure and Accounting Policies, “Related Party Transactions.”

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,

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•  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 accounts receivable sales program is planned for renewal in May 2009. Of our $842 million in letters of credit and revolving credit facilities, $342 million are planned for renewal in 2009 and $500 million are planned for renewal in 2012. Our FMB maturities are $350 million in 2009, $250 million in 2010 and $300 million in 2012. 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. If access to the capital markets is diminished or otherwise restricted, we would implement contingency plans to address debt maturities that may include reduced capital spending. 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 December 31, 2008, we had $94 million of consolidated cash, which includes $25 million of restricted cash.

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The following tables provide a summary of the major items affecting our cash flows from operating, investing and financing activities:

Operating Activities:

Years Ended December 31	2008		2007		Change			2007		2006		Change
	In Millions
Net cash provided by operating activities	$	873	$	440	$	433		$	440	$	474	$	(34	)
Reasons for the change:
Net income					$	52						$	126
Non-cash operating activities(a)						209							(62	)
Accounts receivable and accrued revenue						363							(466	)
Inventories						(84	)						109
Accounts payable						24							9
Accrued taxes						(144	)						181
MCV Partnership gas supplier funds on deposit						—							147
Postretirement benefits contributions						123							(105	)
Regulatory liabilities						(64	)						(173	)
Other assets and liabilities						(46	)						200
Total change					$	433						$	(34	)

(a) Represents adjustments to reconcile net income to net cash provided by operating activities including depreciation and amortization, deferred income taxes, postretirement benefits expense, asset impairment charges, and other non-cash charges.

2008 versus 2007: Cash provided by operating activities increased primarily as a result of increased earnings and the timing of cash receipts from accounts receivable. We accelerate our collections from customer billings through the sale of accounts receivable. We sold $325 million of accounts receivable at the end of 2006, which reduced our collections from customers during 2007. We did not sell accounts receivable in 2007 and sold $170 million of accounts receivable during 2008. Also contributing to the increase in cash provided by operating activities were lower postretirement benefit contributions and other timing differences. These increases were partially offset by refunds to customers of excess Palisades decommissioning funds, the impact of higher commodity prices on inventory purchases, and increased accounts receivable billings at the end of 2008 due to regulatory actions and weather-driven demand.

2007 versus 2006: The decrease in cash provided by operating activities was primarily due to the absence, in 2007, of the sale of accounts receivable, a payment to fund our Pension Plan, and refunds to customers of excess Palisades decommissioning funds. These decreases were partially offset by increased earnings, the absence, in 2007, of tax payments made to the parent related to the 2006 IRS income tax audit, the absence of the release of the MCV Partnership gas supplier funds on deposit due to the sale of our interest in the MCV Partnership in 2006, a decrease in expenditures for gas inventory as the milder winter in 2006 allowed us to accumulate more gas in our storage facilities and other timing differences.

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Investing Activities:

Years Ended December 31	2008			2007			Change			2007			2006			Change
	In Millions
Net cash used in investing activities	$	(823	)	$	(583	)	$	(240	)	$	(583	)	$	(673	)	$	90
Reasons for the change:
Proceeds from asset sales, net of cash relinquished							$	(337	)							$	416
Proceeds from nuclear decommissioning trust funds								(333	)								311
Capital expenditures								469									(612	)
Other investing								(39	)								(25	)
Total change							$	(240	)							$	90

2008 versus 2007: The increase in net cash used in investing activities reflects the absence, in 2008, of asset sale proceeds and proceeds from our nuclear decommissioning trust funds. This increase was partially offset by a decrease in capital expenditures resulting from the absence of the Zeeland power plant purchase made in 2007.

2007 versus 2006: The decrease in net cash used in investing activities was primarily due to proceeds from the sale of Palisades and the related dissolution of our nuclear decommissioning trust funds. This decrease was partially offset by an increase in capital expenditures primarily due to the purchase of the Zeeland power plant.

Financing Activities:

Years Ended December 31	2008			2007		Change			2007		2006			Change
	In Millions
Net cash provided by (used in) financing activities	$	(176	)	$	301	$	(477	)	$	301	$	(180	)	$	481
Reasons for the change:
Proceeds from issuance of long-term debt						$	600							$	—
Retirement of long-term debt							(410	)							183
Payment of common stock dividends							(46	)							(104	)
Stockholder’s contribution, net							(650	)							450
Other financing							29								(48	)
Total change						$	(477	)						$	481

2008 versus 2007: The increase in net cash used in financing activities was primarily due to the absence of contributions from the parent, partially offset by an increase in net proceeds from long-term debt.

2007 versus 2006: The increase in net cash provided by financing activities was primarily due to an increase in contributions from the parent and a decrease in retirement of long-term debt. These changes were partially offset by an increase in common stock dividend payments.

Restrictive Covenants: Our credit agreements require us to maintain a debt to capital ratio, as defined, at a maximum of 0.70 to 1.0. At December 31, 2008, this debt to capital ratio was 0.52 to 1.0.

Credit Ratings: Our access to capital markets and costs of financing are influenced by the ratings of our securities. The following table displays our securities ratings as of December 31, 2008. The ratings outlook from

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S&P (Standard and Poor’s Rating Services),Moody’s (Moody’s Investor Services, Inc.) and Fitch (Fitch Ratings) on all securities is stable.

Securities	S&P	Moody’s	Fitch
Senior Secured Debt (FMB)	BBB	Baa1	BBB+
Senior Unsecured Debt	BBB-	Baa2	BBB
Securitization Bonds	AAA	Aaa	AAA
Senior Secured Insured Quarterly Notes	AAA	Aaa	AAA
Tax Exempt Bonds	BBB	Baa1	—
Tax Exempt Bonds, LOC backed	AAA	Aaa	—

For additional details on long-term debt activity, see Note 5, Financings and Capitalization.

Obligations and Commitments

Contractual Obligations: The following table summarizes our contractual cash obligations for each of the periods presented. The table shows the timing of the obligations and their expected effect on our liquidity and cash flow in future periods. The table excludes all amounts classified as current liabilities on our Consolidated Balance Sheets, other than the current portion of long-term debt and capital and finance leases.

	Payments Due
Contractual Obligations			Less Than		One to		Three to		More Than
at December 31, 2008	Total		One Year		Three Years		Five Years		Five Years
	In Millions
Long-term debt(a)	$	4,291	$	383	$	380	$	755	$	2,773
Interest payments on long-term debt(b)		1,814		213		378		332		891
Capital and finance leases(c)		231		25		47		41		118
Interest payments on capital and finance leases(d)		122		13		25		22		62
Operating leases(e)		237		27		51		44		115
Purchase obligations(f)		14,699		2,201		2,391		1,545		8,562
Purchase obligations — related parties(f)		1,570		78		166		168		1,158
Total contractual obligations	$	22,964	$	2,940	$	3,438	$	2,907	$	13,679

(a)	Principal amounts due on outstanding debt obligations, current and long-term, at December 31, 2008. For additional details on long-term debt, see Note 5, Financings and Capitalization.
(b)	Currently scheduled interest payments on both variable and fixed-rate long-term debt, current and long-term. Variable interest payments are based on contractual rates in effect at December 31, 2008.
(c)	Principal portion of lease payments under our capital and finance leases, comprised mainly of leased service vehicles, leased office furniture, and certain power purchase agreements.

(d) Imputed interest on the capital leases.

(e) Minimum noncancelable lease payments under our leases of railroad cars, certain vehicles, and miscellaneous office buildings and equipment, which are accounted for as operating leases.

(f) Long-term contracts for purchase of commodities and services. These obligations include operating contracts used to assure adequate supply with generating facilities that meet PURPA requirements. These commodities and services include:

•  natural gas and associated transportation,

•  electricity, and

•  coal and associated transportation.

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Our purchase obligations include long-term power purchase agreements with various generating plants, which require us to make monthly capacity payments based on the plants’ availability or deliverability. These payments will approximate $40 million per month during 2009. If a plant is not available to deliver electricity, we will not be obligated to make these payments for that period. For additional details on power supply costs, see “Electric Utility Results of Operations” within this MD&A and Note 4, Contingencies, “Electric Rate Matters — Power Supply Costs.”

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

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

Off-Balance sheet Arrangements

Off-Balance Sheet Arrangements: We enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, surety bonds, letters of credit, and financial and performance guarantees. Indemnifications are usually agreements to reimburse a counterparty that may incur losses due to outside claims or breach of contract terms. The maximum payment we would be required to make under a number of these indemnities is not estimable. While we believe it is unlikely that we will incur any material losses related to indemnifications we have not recorded as liabilities, we cannot predict the impact of these contingent obligations on our liquidity and financial condition. For additional details on these arrangements, see Note 4, Contingencies, Other Contingencies — Indemnifications — Guarantees and Indemnifications.

Sale of Accounts Receivable: Under our revolving accounts receivable sales program, we may sell up to $250 million of eligible accounts receivable at December 31, 2008, reduced from $325 million at December 31, 2007.

Capital Expenditures: For planning purposes, we forecast capital expenditures over a three-year period. 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. The following is a summary of our estimated capital expenditures, including lease commitments, for 2009 through 2011:

Years Ending December 31	2009		2010		2011
	In Millions
Construction	$	628	$	748	$	664
Clean Air(a)		69		197		105
New Customers		70		87		91
Other(b)		83		102		96
Total	$	850	$	1,134	$	956
Electric utility operations(a)(b)	$	574	$	847	$	705
Gas utility operations(b)		276		287		251
Total	$	850	$	1,134	$	956

(a)	These amounts include estimates for capital expenditures that may be required by revisions to the Clean Air Act’s national air quality standards or potential renewable energy programs.
(b)	These amounts include estimates for capital expenditures related to information technology projects, facility improvements, and vehicle leasing.

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

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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

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 through:

•  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-based plant at our Karn/Weadock Generating complex near Bay City, Michigan. We expect the plant to be in operation in 2017. Legislation enacted in Michigan in October 2008 provided guidelines with respect to the MPSC review and approval of energy resource plans and proposed power plants. We plan to file a new case with the MPSC that conforms to the new legislation.

Proposed Coal Plant Projects: In February 2009, the Michigan governor issued an executive directive that set forth additional requirements for the issuance of a permit to install a coal-based electric generating plant in the state of Michigan. The directive requires the MDEQ, before issuing an air permit for any coal-based electric generating plant, to consider, among other things,

•  whether additional generation is needed, and

•  whether other feasible and prudent alternatives to a new coal plant exist that would better protect the environment, including potential demand reduction measures and purchasing power from existing sources.

We are examining the legality of the directive, as well as its impact on our existing air permit application for our planned advanced clean coal plant. The Michigan attorney general issued an opinion that invalidated the governor’s directive on the basis that the governor’s directive exceeded the governor’s authority.

In February 2009, the Michigan governor also proposed a 45 percent reduction in the use of fossil fuel for electric generation by 2020. The governor’s office has subsequently advised us that the 45 percent is only a suggested target, and is intended to apply only to coal-based generation. If implemented, it will have a significant impact upon the operation and cost of existing and planned future coal-based power plants.

We cannot predict the impact of the governor’s statements or other factors on our future power supply plans.

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 the current volatility in the credit markets. Although our electric utility results are not dependent substantially upon a single customer, or even a few customers, those in the automotive sector represented four percent of our total 2008 electric revenue and two and a half percent of our 2008 electric operating income. We cannot predict the financial impact of the Michigan economy on our electric customer revenue.

Electric Deliveries: We experienced a decrease in electric deliveries of approximately 3.5 percent in 2008 compared with 2007, or 2.0 percent excluding impacts from differences in weather. This decrease reflects a decline

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in industrial economic activity and the cancellation of one wholesale customer contract. For 2009, we expect a decrease in electric deliveries of 2.5 percent compared with 2008, or 2.1 percent excluding impacts from differences in weather. Our outlook for 2009 includes continuing growth in deliveries to our largest-growing customer, which produces semiconductor and solar energy components. Excluding this customer’s growth, we expect electric deliveries in 2009 to decline 3.4 percent compared with 2008 or 3.0 percent excluding impacts from differences in weather. Our outlook 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 0.8 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, and

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

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 12.7 percent for summer 2009, or supply resources equal to 112.7 percent of projected firm summer peak load. We have purchased capacity and energy covering our Reserve Margin requirements for 2009 through 2010. Of the 2009 supply resources target, we expect 96.4 percent to come from our electric generating plants and long-term power purchase contracts, with other capacity and energy 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 $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.”

Renewable Energy Plan: Legislation enacted in Michigan in October 2008 prescribed renewable energy standards for energy and capacity. The energy standard requires that 10 percent of our electric sales volume come from renewable sources by 2015 with interim target requirements. Approximately four percent of our electric sales volume comes presently from renewable sources. The legislation also requires us to add new renewable energy capacity of 200 MW by year-end 2013 and 500 MW by year-end 2015, from owned renewable energy sources or power purchased agreements. We have secured more than 36,000 acres of land easements in Michigan’s Tuscola and Mason counties for potential wind generation development and we are collecting presently wind speed and other meteorological data at the sites.

In February 2009, we filed our Renewable Energy Plan with the MPSC. The plan details how we will meet the renewable energy standards for energy and capacity.

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Energy Optimization Plan: Legislation enacted in Michigan in October 2008 requires utilities to prepare energy optimization plans and achieve annual sales reduction targets beginning in 2009 through 2015. In February 2009, we filed our Energy Optimization Plan with the MPSC, which details our proposed energy cost savings plan through incentives to reduce customer usage among all customer classes and the method of recovery of program costs.

Ancillary Services: In January 2009, MISO implemented an ancillary services market for the purchase and sale of regulation and contingency reserves. We include ancillary service costs in our PSCR.

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.

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 $817 million for equipment installation through 2017 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.

We plan to purchase additional nitrogen oxides emission allowances through 2010 at an estimated cost of $5 million per year. We also plan to purchase sulfur dioxide emission allowances, between 2013 and 2015, at an estimated cost ranging from $9 million to $27 million per year. We expect to recover emissions allowance costs from our customers through the PSCR process.

Clean Air Interstate Rule: In March 2005, the EPA adopted the CAIR, which required additional coal-based 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. The court initially vacated the CAIR and the CAIR federal implementation plan in their entirety, but subsequently, the court changed course and remanded the rule to the EPA maintaining the rule in effect pending EPA revision. As a result, the CAIR still remains in effect, with the first annual nitrogen oxides compliance year beginning January 1, 2009. The EPA must now revise the rule to resolve the court’s concerns. The court did not set a timetable for the revision.

State and Federal Mercury Air Rules: In March 2005, the EPA issued the CAMR, which required initial reductions of mercury emissions from coal-based 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. The MDEQ is reviewing public comments made in response to a newly released mercury emissions reduction proposal. If this plan becomes effective, we estimate that the associated costs will be approximately $782 million by 2015.

Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as RMRR 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 RMRR. In October 2008, we received another information request from the EPA under Section 114 of the Clean Air Act. We responded to this information request in December 2008.

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In addition to the EPA’s information request, in October 2008, we received a NOV for three of our coal-based facilities relating to violations of NSR regulations, alleging ten projects from 1986 to 1998 were subject to NSR review. We met with the EPA in January 2009 and have additional meetings scheduled. If the EPA does not accept our interpretation of RMRR, we could be required to install additional pollution control equipment at some or all of our coal-based electric generating plants, surrender emission allowances, engage in supplemental environmental programs or 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. We consider it likely that Congress will enact greenhouse gas legislation, but the form of any final bill is difficult to predict. 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, arrange for alternative sources of supply, 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.

In July 2008, the EPA 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. We submitted comments to the EPA on this issue in November 2008. In addition to the potential for federal actions related to greenhouse gas regulation, the State of Michigan has convened the Michigan Climate Action Council, a climate change stakeholder process. 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 existing power plants. The EPA compliance options in the rule were challenged before the U.S. Court of Appeals for the Second Circuit, which remanded the bulk of the rule back to the EPA for reconsideration in January 2007. In April 2008, the U.S. Supreme Court agreed to hear an industry challenge to the appellate court ruling in this case. A decision from the U.S Supreme Court is expected in the first half of 2009. The EPA is planning to issue a revised draft rule in 2009, following the court decision.

We estimate that capital expenditures to comply with these regulations will be approximately $128 million; however an unfavorable U.S. Supreme Court decision could increase expenditures significantly.

We will continue to monitor these developments and respond to their potential implications for our business, consolidated results of operations, cash flows, and financial position. For additional details on electric environmental matters, see Note 4, Contingencies, “Electric Contingencies — Electric Environmental Matters.”

Stranded Cost Recovery: In October 2008, the Michigan legislature enacted legislation that amended the Customer Choice Act and directed the MPSC to approve rates that will allow recovery of Stranded Costs within five years. In January 2009, we filed an application with the MPSC requesting recovery of these Stranded Costs through a surcharge on both full service and ROA customers. At December 31, 2008, we had a regulatory asset for Stranded Costs of $71 million.

Electric Rate Case: In November 2008, we filed an application with the MPSC seeking an annual increase in revenue of $214 million based on an 11 percent authorized return on equity. The filing seeks recovery of costs associated with new plant investments including Clean Air Act investments, higher operating and maintenance costs, and the approval to recover costs associated with our advanced metering infrastructure program. The Michigan legislation enacted in October 2008 generally allows utilities to self-implement rates six months after filing, subject to refund, unless the MPSC finds good cause to prohibit such self-implementation. We cannot predict the financial impact or outcome of this proceeding.

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Palisades Regulatory Proceedings: We sold Palisades to Entergy in April 2007. The MPSC order approving the transaction required 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 $109 million above the amount in the MPSC order. The distribution of these funds is still pending with the MPSC.

For additional details on electric rate matters, see Note 4, Contingencies, “Electric Rate Matters.”

GAS BUSINESS OUTLOOK

Gas Deliveries: For 2009, we expect gas deliveries to decrease by 3.4 percent compared with 2008, or 4.7 percent, excluding impacts from differences in weather, due to continuing conservation and overall economic conditions in Michigan. We expect gas deliveries to average a decline of less than 1.6 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,

•  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 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. In December 2008, the MPSC approved a partial settlement agreement allowing us to implement the filed depreciation rates, on an interim basis, concurrent with the implementation of settled rates in our 2008 gas rate case. The interim depreciation rates reduce our depreciation expense by approximately $20 million per year and will remain in effect until a final order is issued in our gas depreciation case. 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.

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.

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OTHER OUTLOOK

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

Emergency Shutoff Protection Rules: In February 2009, the MPSC issued rules that would put additional emergency shutoff protections and service limitation protections in place for our residential electric and natural gas customers. The protection exceeds previous shutoff rules as follows:

•  extends the protection period from March 31, 2009 to April 30, 2009,

•  includes protection for physically or mentally disabled customers of record,

•  expands the qualifications for low income shutoff protection, and

•  gives customers the payment options.

We are presently evaluating the impacts of these rules on our cash flows and financial position.

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 I, Item 3. 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 included 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 was 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. In late December 2008, the SEC submitted a report on its study to Congress. The report concluded that mark-to-market accounting was not a major factor in recent bank failures, and recommended that existing fair value and mark-to-market accounting requirements remain in place. The report included recommendations for improving fair value accounting and reporting. We apply this accounting primarily to our investment in CMS Energy Common Stock and our SERP investments, and we will continue to monitor developments relating to the SEC report, including reactions and responses to the report’s recommendations, for potential impact to us.

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 was effective for us upon issuance, 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.

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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 for 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 illustrate the concepts. The standard was 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, which was effective for us January 1, 2008, 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.

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 amended SFAS No. 133 and FIN 45 to require enhanced disclosures for issuers of credit derivatives and financial guarantees. We have not issued any credit derivatives; thus, this standard applies only to our disclosures about guarantees we have issued. This standard involves disclosures only, and did not have a material effect on our consolidated financial statements. For additional details on our guarantees, see Note 4, Contingencies.

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. In addition, net income attributable to noncontrolling interests will be included in net income on our Consolidated Statements of Income. These changes involve presentation only, and will not otherwise impact our consolidated financial statements. The standard will also affect the accounting for changes in a parent’s ownership interest,

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Consumers Energy Company

including deconsolidation of a subsidiary. We will apply these provisions of SFAS No. 160 prospectively to any such transactions.

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 requires 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 the entity’s financial position, financial performance, and cash flows. This standard will not have a material 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. This standard will not have a material impact 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.

FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets: In December 2008, the FASB issued this standard, effective for us for the year ending December 31, 2009. The standard requires expanded annual disclosures about the plan assets in our defined benefit pension and OPEB plans. The required disclosures include information about investment allocation decisions, major categories of plan assets, the inputs and valuation techniques used in the fair value measurements, the effects of significant unobservable inputs on changes in plan assets, and significant concentrations of risk within plan assets. The standard involves disclosures only, and will not impact our consolidated income, cash flows, or financial position.

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Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF INCOME

	Years Ended December 31
	2008			2007			2006
	In Millions
Operating Revenue	$	6,421		$	6,064		$	5,721
Earnings from Equity Method Investees		—			—			1
Operating Expenses
Fuel for electric generation		483			385			672
Fuel costs mark-to-market at the MCV Partnership		—			—			204
Purchased and interchange power		1,313			1,370			647
Purchased power — related parties		75			79			74
Cost of gas sold		2,079			1,918			1,770
Other operating expenses		766			808			895
Maintenance		169			183			284
Depreciation and amortization		574			524			527
General taxes		195			217			150
Asset impairment charges		—			—			218
Loss (gain) on asset sales, net		1			(2	)		(79	)
		5,655			5,482			5,362
Operating Income		766			582			360
Other Income (Deductions)
Interest		25			69			62
Interest and dividends — related parties		1			1			—
Regulatory return on capital expenditures		33			31			26
Other income		12			32			20
Other expense		(28	)		(14	)		(12	)
		43			119			96
Interest Charges Interest on long-term debt		229			234			281
Interest on long-term debt — related parties		—			2			5
Other interest		22			34			13
Capitalized interest		(4	)		(6	)		(10	)
		247			264			289
Income Before Income Taxes		562			437			167
Income Tax Expense		198			125			91
Income Before Minority Obligations, Net		364			312			76
Minority Obligations, Net		—			—			(110	)
Net Income		364			312			186
Preferred Stock Dividends		2			2			2
Net Income Available to Common Stockholder	$	362		$	310		$	184

The accompanying notes are an integral part of these statements.

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Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31
	2008			2007			2006
	In Millions
Cash Flows from Operating Activities
Net income	$	364		$	312		$	186
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization (includes nuclear decommissioning of $—, $4 and $6)		574			524			527
Deferred income taxes and investment tax credit		196			55			(113	)
Regulatory return on capital expenditures		(33	)		(31	)		(26	)
Minority obligations, net		—			—			(110	)
Fuel costs mark-to-market at the MCV Partnership		—			—			204
Asset impairment charges		—			—			218
Postretirement benefits expense		141			124			122
Capital lease and other amortization		30			44			37
Bad debt expense		47			33			30
Loss (gain) on sale of assets		1			(2	)		(79	)
Earnings from equity method investees		—			—			(1	)
Postretirement benefits contributions		(50	)		(173	)		(68	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, notes receivable and accrued revenue		(79	)		(442	)		24
Decrease (increase) in accrued power supply and gas revenue		35			99			(91	)
Increase in inventories		(89	)		(5	)		(114	)
Increase (decrease) in accounts payable		1			(23	)		(32	)
Increase (decrease) in accrued expenses		(15	)		(15	)		35
Increase (decrease) in accrued taxes		(64	)		80			(101	)
Decrease in the MCV Partnership gas supplier funds on deposit		—			—			(147	)
Increase (decrease) in other current and non-current regulatory liabilities		(178	)		(114	)		59
Decrease (increase) in other current and non-current assets		14			(7	)		(50	)
Decrease in other current and non-current liabilities		(22	)		(19	)		(36	)
Net cash provided by operating activities		873			440			474
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)		(789	)		(1,258	)		(646	)
Cost to retire property		(34	)		(28	)		(78	)
Restricted cash and restricted short-term investments		—			32			126
Investments in nuclear decommissioning trust funds		—			(1	)		(21	)
Proceeds from nuclear decommissioning trust funds		—			333			22
Maturity of the MCV Partnership restricted investment securities held-to-maturity		—			—			130
Purchase of the MCV Partnership restricted investment securities held-to-maturity		—			—			(131	)
Cash proceeds from sale of assets		—			337			69
Cash relinquished from sale of assets		—			—			(148	)
Other investing		—			2			4
Net cash used in investing activities		(823	)		(583	)		(673	)

The accompanying notes are an integral part of these statements.

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Consumers Energy Company

	Years Ended December 31
	2008			2007			2006
	In Millions
Cash Flows from Financing Activities
Proceeds from issuance of long term debt		600			—			—
Retirement of long-term debt		(444	)		(34	)		(217	)
Payment of common stock dividends		(297	)		(251	)		(147	)
Payment of capital and finance lease obligations		(26	)		(20	)		(26	)
Stockholder’s contribution, net		—			650			200
Payment of preferred stock dividends		(2	)		(1	)		(2	)
Increase (decrease) in notes payable		—			(42	)		15
Debt issuance and financing costs		(7	)		(1	)		(3	)
Net cash provided by (used in) financing activities		(176	)		301			(180	)
Net Increase (Decrease) in Cash and Cash Equivalents		(126	)		158			(379	)
Cash and Cash Equivalents, Beginning of Period		195			37			416
Cash and Cash Equivalents, End of Period	$	69		$	195		$	37
Other cash flow activities and non-cash investing and financing activities were:
Cash transactions
Interest paid (net of amounts capitalized)	$	206		$	242		$	279
Income taxes paid (net of refunds, $—, $98, and $39)		84			—			306
Non-cash transactions
Other assets placed under capital lease	$	5		$	229		$	7

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Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31
	2008		2007
	In Millions
ASSETS
Plant and Property (at cost)
Electric	$	8,965	$	8,555
Gas		3,622		3,467
Other		15		15
		12,602		12,037
Less accumulated depreciation, depletion, and amortization		4,242		3,993
		8,360		8,044
Construction work-in-progress		607		447
		8,967		8,491
Investments
Stock of affiliates		19		32
Current Assets
Cash and cash equivalents at cost, which equals fair value		69		195
Restricted cash at cost, which equals fair value		25		25
Accounts receivable and accrued revenue, less allowances of $24 in 2008 and $16 in 2007		829		810
Notes receivable		93		67
Accrued power supply and gas revenue		7		45
Accounts receivable — related parties		2		4
Inventories at average cost
Gas in underground storage		1,168		1,123
Materials and supplies		103		79
Generating plant fuel stock		118		100
Deferred property taxes		165		158
Regulatory assets — postretirement benefits		19		19
Prepayments and other		30		28
		2,628		2,653
Non-current Assets
Regulatory assets Securitized costs		416		466
Postretirement benefits		1,431		921
Customer Choice Act		90		149
Other		482		504
Other		213		185
		2,632		2,225
Total Assets	$	14,246	$	13,401

The accompanying notes are an integral part of these statements.

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Consumers Energy Company

	December 31
	2008			2007
	In Millions
STOCKHOLDER’S INVESTMENT AND LIABILITIES
Capitalization
Common stockholder’s equity
Common stock, authorized 125.0 shares; outstanding 84.1 shares for both periods	$	841		$	841
Paid-in capital		2,482			2,482
Accumulated other comprehensive loss		(1	)		—
Retained earnings		383			324
		3,705			3,647
Preferred stock		44			44
Long-term debt		3,908			3,692
Non-current portion of capital and finance lease obligations		206			225
		7,863			7,608
Current Liabilities
Current portion of long-term debt, capital and finance lease obligations		408			470
Accounts payable		444			403
Accrued rate refunds		7			19
Accounts payable — related parties		14			13
Accrued interest		69			65
Accrued taxes		289			353
Deferred income taxes		277			151
Regulatory liabilities		120			164
Other		151			150
		1,779			1,788
Non-current Liabilities
Deferred income taxes		792			713
Regulatory liabilities
Cost of removal		1,203			1,127
Income taxes, net		519			533
Other		146			313
Postretirement benefits		1,436			813
Asset retirement obligations		205			198
Deferred investment tax credit		54			58
Other		249			250
		4,604			4,005
Commitments and Contingencies (Notes 4, 5, 6, 9, and 11)
Total Stockholder’s Investment and Liabilities	$	14,246		$	13,401

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CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

	Years Ended December 31
	2008			2007			2006
	In Millions
Common Stock
At beginning and end of period(a)	$	841		$	841		$	841
Other Paid-in Capital
At beginning of period		2,482			1,832			1,632
Stockholder’s contribution		—			650			200
At end of period		2,482			2,482			1,832
Accumulated Other Comprehensive Income
Retirement benefits liability
At beginning of period		(15	)		(8	)		(2	)
Retirement benefits liability adjustments(b)		6			—			—
Net gain (loss) arising during the period(b)		2			(7	)		—
Adjustment to initially apply FASB Statement No. 158, net of tax		—			—			(6	)
At end of period		(7	)		(15	)		(8	)
Investments
At beginning of period		15			23			18
Unrealized gain (loss) on investments(b)		(19	)		(1	)		5
Reclassification adjustments included in net income(b)		10			(7	)		—
At end of period		6			15			23
Derivative instruments
At beginning of period		—			—			56
Unrealized loss on derivative instruments(b)		—			—			(21	)
Reclassification adjustments included in net income(b)		—			—			(35	)
At end of period		—			—			—
Total Accumulated Other Comprehensive Income (Loss)		(1	)		—			15
Retained Earnings
At beginning of period		324			270			233
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(b)		364			312			186
Cash dividends declared — Common Stock		(297	)		(251	)		(147	)
Cash dividends declared — Preferred Stock		(2	)		(2	)		(2	)
At end of period		383			324			270
Total Common Stockholder’s Equity	$	3,705		$	3,647		$	2,958

The accompanying notes are an integral part of these statements.

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Consumers Energy Company

	Years Ended December 31
	2008			2007			2006
	In Millions
(a) Number of shares of common stock outstanding was 84,108,789 for all periods presented
(b) Disclosure of Comprehensive Income:
Net income	$	364		$	312		$	186
Retirement benefits liability
Retirement benefits liability adjustment, net of tax of $2 in 2008		6			—			—
Net gain (loss) arising during the period, net of tax (tax benefit) of $1 in 2008, and $(4) in 2007		2			(7	)		—
Investments
Unrealized gain (loss) on investments, net of tax (tax benefit) of $(10) in 2008, $(1) in 2007, and $2 in 2006		(19	)		(1	)		5
Reclassification adjustments included in net income, net of tax (tax benefit) of $6 in 2008 and $(3) in 2007		10			(7	)		—
Derivative instruments
Unrealized loss on derivative instruments, net of tax benefit of $(11) in 2006		—			—			(21	)
Reclassification adjustments included in net income, net of tax benefit of $(19) in 2006		—			—			(35	)
Total Comprehensive Income	$	363		$	297		$	135

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Consumers Energy Company

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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. Unbilled revenues are estimated by applying an average billed rate for each customer class based on actual billed volume distributions. Our unbilled revenues, which are recorded as Accounts receivable on our Consolidated Balance Sheets, were $507 million at December 31, 2008 and $490 million at December 31, 2007. We record sales tax on a net basis and exclude it from revenues.

Accounting for Legal Fees: We expense legal fees as incurred; fees incurred but not yet billed are accrued based on estimates of work performed. This policy also applies to fees incurred on behalf of employees and officers related to indemnification agreements; these fees are billed directly to us.

Accounting for MISO Transactions: MISO requires that we submit hourly day-ahead and real-time bids and offers for energy at locations across the MISO region. We account for MISO transactions on a net hourly basis in each of the real-time and day-ahead markets, and net transactions across all MISO energy market locations. We record net purchases in a single hour in “Purchased and interchange power” and net sales in a single hour in “Operating Revenue” in the Consolidated Statements of Income. We record expense accruals for future net purchases adjustments based on historical experience, and reconcile accruals to actual expenses when we receive invoices.

Capitalized Interest: We capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest is limited to the actual interest cost incurred. Our regulated businesses capitalize AFUDC on regulated construction projects and include these amounts in plant in service.

Cash and Cash Equivalents: Cash and cash equivalents include short-term, highly-liquid investments with original maturities of three months or less.

Collective Bargaining Agreements: At December 31, 2008, the Union represented approximately 45 percent of our employees. The Union represents Consumers’ operating, maintenance, and construction employees and our call center employees.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Determination of Pension and OPEB MRV of Plan Assets: We determine the MRV for pension plan assets, as defined in SFAS No. 87, as the fair value of plan assets on the measurement date, adjusted by the gains or losses that will not be admitted into MRV until future years. We reflect each year’s assets gain or loss in MRV in equal amounts over a five-year period beginning on the date the original amount was determined. We determine the MRV for OPEB plan assets, as defined in SFAS No. 106, as the fair value of assets on the measurement date. We use the MRV in the calculation of net pension and OPEB costs.

Financial and Derivative Instruments: We record debt and equity securities classified as available-for-sale at fair value determined primarily from quoted market prices. On a specific identification basis, we report unrealized gains and losses from changes in fair value of certain available-for-sale debt and equity securities, net of tax, in equity as part of AOCL. We exclude unrealized losses from earnings unless the related changes in fair value are determined to be other than temporary.

In accordance with SFAS No. 133, if a contract is a derivative and does not qualify for the normal purchases and sales exception, we record it on our Consolidated Balance Sheets at its fair value. If a derivative qualifies for cash flow hedge accounting, we report changes in its fair value in AOCL; otherwise, we report the changes in earnings.

For additional details regarding financial and derivative instruments, see Note 6, Financial and Derivative Instruments.

Impairment of Investments and Long-Lived Assets: We perform tests of impairment if certain triggering events occur, or if there has been a decline in value that may be other than temporary.

We evaluate our long-lived assets held-in-use for impairment by calculating the undiscounted future cash flows expected to result from the use of the asset and its eventual disposition. If the undiscounted future cash flows are less than the carrying amount, we recognize an impairment loss equal to the amount by which the carrying amount exceeds the fair value. We estimate the fair value of the asset using quoted market prices, market prices of similar assets, or discounted future cash flow analyses.

We also assess our investments for impairment whenever there has been a decline in value that is other than temporary. This assessment requires us to determine the fair values of our investments. We determine fair value using valuation methodologies, including discounted cash flows and the ability of the investee to sustain an earnings capacity that justifies the carrying amount of the investment. We record an impairment if the fair value is less than the carrying value and the decline in value is considered to be other than temporary.

For additional details, see Note 3, Asset Sales and Impairment Charges.

Inventory: We use the weighted average cost method for valuing working gas and recoverable cushion gas in underground storage facilities and materials and supplies inventory. We also use this method for valuing coal inventory and classify these costs as generating plant fuel stock on our Consolidated Balance Sheets.

We classify emission allowances as materials and supplies inventory and use the average cost method to remove amounts from inventory as we use the emission allowances to generate power.

Maintenance and Depreciation: We charge property repairs and minor property replacement to maintenance expense. We use the direct expense method to account for planned major maintenance activities. We charge planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements.

We depreciate utility property using a composite method, in which we apply a single MPSC-approved depreciation rate to the gross investment in a particular class of property within the electric and gas divisions. We

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

perform depreciation studies periodically to determine appropriate group lives. The composite depreciation rates for our properties are as follows:

Years Ended December 31	2008		2007		2006
Electric utility property		3.0%		3.0%		3.1%
Gas utility property		3.6%		3.6%		3.6%
Other property		8.5%		8.7%		8.2%

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

Years Ended December 31	2008		2007		2006
	In Millions
Other income
Electric restructuring return	$	1	$	2	$	4
Return on stranded and security costs		5		6		5
MCV Partnership emission allowance sales		—		—		8
Gain on SERP investment		—		10		—
Gain on investment		—		7		—
Gain on stock		—		4		1
All other		6		3		2
Total other income	$	12	$	32	$	20

Years Ended December 31	2008			2007			2006
	In Millions
Other expense
Unrealized investment loss	$	(17	)	$	—		$	—
Civic and political expenditures		(5	)		(2	)		(2	)
Donations		—			—			(9	)
Abandoned Midland Project		—			(8	)		—
All other		(6	)		(4	)		(1	)
Total other expense	$	(28	)	$	(14	)	$	(12	)

Property, Plant, and Equipment: We record property, plant, and equipment at original cost when placed into service. When utility property is retired, or otherwise disposed of in the ordinary course of business, we charge the original cost to accumulated depreciation, along with associated cost of removal, net of salvage. We recognize gains or losses on the retirement or disposal of non-regulated assets in income. Our internal-use computer software costs are capitalized or expensed in accordance with Statement of Position 98-1, Accounting for the Costs of Computer Software Developed or Obtained for Internal Use. For additional details, see Note 8, Asset Retirement Obligations and Note 12, Property, Plant, and Equipment. Cost of removal collected from our customers, but not spent, is recorded as a regulatory liability.

We capitalize AFUDC on regulated major construction projects. AFUDC represents the estimated cost of debt and a reasonable return on equity funds used to finance construction additions. We record the offsetting credit as a reduction of interest for the amount representing the borrowed funds component and as other income for the equity funds component in the Consolidated Statements of Income. When construction is completed and the property is

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placed in service, we depreciate and recover the capitalized AFUDC from our customers over the life of the related asset. The following table shows our electric, gas and common composite AFUDC capitalization rates:

Years Ended December 31	2008			2007			2006
AFUDC capitalization rate		7.7	%		7.4	%		7.5	%

Property Taxes: Property taxes are based upon the taxable value of Consumers’ real and personal property assessed by local units of government within the State of Michigan. We record property tax expense ratably over the fiscal year of the taxing authority for which the taxes are levied based on budgeted customer sales. The deferred property tax balance represents the amount of accrued property tax, which will be recognized over future governmental fiscal periods.

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 or cash flow for the periods presented.

Related Party Transactions: We recorded income and expense from related parties as follows:

Description	Related Party	2008			2007			2006
		In Millions
Type of Income:
Dividend Income	CMS Energy	$	1		$	1		$	—
Type of Expense:
Electric generating capacity and energy	Affiliates of Enterprises		(75	)		(79	)		(74	)
Interest expense on note payable	CMS Energy and Consumers’ affiliated Trust Preferred Securities Companies		—			(2	)		(5	)
Gas transportation(a)	CMS Bay Area Pipeline, L.L.C.		—			(1	)		(4	)

(a) CMS Bay Area Pipeline, L.L.C. was sold to Lucid Energy in March 2007.

We own 1.8 million shares of CMS Energy Common Stock with a fair value of $19 million at December 31, 2008. For additional details on our investment in CMS Energy Common Stock, see Note 6, Financial and Derivative Instruments.

Restricted Cash: We classify restricted cash dedicated for repayment of Securitization bonds as a current asset, as the related payments occur within one year.

Trade Receivables: Accounts receivable is primarily composed of trade receivables and unbilled receivables. We record our accounts receivable at cost which approximates fair value. We establish an allowance for uncollectible accounts based on historical losses and management’s assessment of existing economic conditions, customer trends, and other factors. We assess late payment fees on trade receivables based on contractual past-due terms established with customers. We charge accounts deemed uncollectible to operating expense.

Unamortized Debt Premium, Discount, and Expense: We capitalize premiums, discounts, and issuance costs of long-term debt and amortize those costs over the terms of the debt issues. For the non-regulated portions of our businesses, we expense any refinancing costs as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and issuance costs and amortize them over the terms of the newly issued debt.

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Utility Regulation: We are subject to the actions of the MPSC and the FERC and prepare our consolidated financial statements in accordance with the provisions of SFAS No. 71. As a result, we may defer or recognize revenues and expenses differently than a non-regulated entity. For example, we may record as regulatory assets items that a non-regulated entity normally would expense if the actions of the regulator indicate that we will recover the expenses in future rates. Conversely, we may record as regulatory liabilities items that non-regulated entities may normally recognize as revenues if the actions of the regulator indicate that we will be required to refund revenues to customers.

We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets.

	End of
	recovery or
December 31	refund period	2008		2007
	In Millions
Assets Earning a Return:
Customer Choice Act	2010	$	90	$	149
Stranded Costs	See Note 4		71		68
Electric restructuring implementation plan	2009		3		14
Manufactured gas plant sites (Note 4)	2018		31		33
Other(a)	various		44		50
Assets Not Earning a Return:
Postretirement Benefits (Note 7)	various		1,450		940
Securitized costs (Note 5)	2015		416		466
Unamortized debt costs	n/a		66		74
ARO (Note 8)	n/a		92		85
Big Rock nuclear decommissioning and related costs (Note 4)	n/a		129		129
Manufactured gas plant sites (Note 4)	n/a		38		17
Palisades sales transaction costs (Notes 3 and 4)	n/a		—		28
Other(a)	2011		8		6
Total regulatory assets(b)		$	2,438	$	2,059
Palisades refund — Current (Note 4)(c)	2009	$	120	$	164
Cost of removal (Note 8)	n/a		1,203		1,127
Income taxes, net (Note 9)	n/a		519		533
ARO (Note 8)	n/a		137		141
Palisades refund — Non-current (Note 4)(c)	2008		—		140
Other(a)	various		9		32
Total regulatory liabilities(b)		$	1,988	$	2,137

(a) At December 31, 2008 and 2007, other regulatory assets include a gas inventory regulatory asset and OPEB and pension expense incurred in excess of the MPSC-approved amount. We will recover these regulatory assets from our customers by 2011. Other regulatory liabilities include liabilities related to the sale of sulfur dioxide allowances and AFUDC collected in excess of the MPSC-approved amount.

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(b)

At December 31, 2008 and 2007, we classified $19 million of regulatory assets as current regulatory assets. At December 31, 2008, we classified $120 million of regulatory liabilities as current regulatory liabilities. At December 31, 2007, we classified $164 million of regulatory liabilities as current regulatory liabilities.

(c)

The MPSC order approving the Palisades and Big Rock ISFSI sale transaction required that we credit $255 million of excess sales proceeds and decommissioning amounts to our retail customers by December 2008. For 2007, the current portion of regulatory liabilities for Palisades refunds represents the remaining portion of this obligation, plus interest. There are additional excess sales proceeds and decommissioning fund balances above the amount in the MPSC order. For 2007, the non-current portion of regulatory liabilities for Palisades refunds represents this obligation, plus interest. For 2008, these additional excess sales proceeds are reported in the current portion of regulatory liabilities for Palisades refunds as it is probable the proceeds will be credited to customers within one year. For additional details, see Note 4, Contingencies, “Electric Rate Matters.”

Our PSCR and GCR cost recovery mechanisms also represent probable future revenues that will be recovered from customers or previously collected revenues that will be refunded to customers through the ratemaking process. Underrecoveries are included in Accrued power supply and gas revenue and overrecoveries are included in Accrued rate refunds on our Consolidated Balance Sheets. For additional details on PSCR, see Note 4, Contingencies, “Electric Rate Matters — Power Supply Costs” and for additional details on GCR, see Note 4, Contingencies, “Gas Rate Matters — Gas Cost Recovery.”

We reflect the following regulatory assets and liabilities for underrecoveries and overrecoveries on our Consolidated Balance Sheets:

Years Ended December 31	2008		2007
	In Millions
Regulatory Assets for PSCR and GCR underrecoveries of power supply and gas costs	$	7	$	45
Regulatory Liabilities for PSCR and GCR overrecoveries of power supply and gas costs	$	7	$	19

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. In addition, net income attributable to noncontrolling interests will be included in net income on our Consolidated Statements of Income. These changes involve presentation only, and will not otherwise impact our consolidated financial statements. The standard will also affect the accounting for changes in a parent’s ownership interest, including deconsolidation of a subsidiary. We will apply these provisions of SFAS No. 160 prospectively to any such transactions.

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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 requires 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 the entity’s financial position, financial performance, and cash flows. This standard will not have a material impact 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. This standard will not have a material impact 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.

FSP FAS 132(R)-1, Employers’ Disclosures about Postretirement Benefit Plan Assets: In December 2008, the FASB issued this standard, effective for us for the year ending December 31, 2009. The standard requires expanded annual disclosures about the plan assets in our defined benefit pension and OPEB plans. The required disclosures include information about investment allocation decisions, major categories of plan assets, the inputs and valuation techniques used in the fair value measurements, the effects of significant unobservable inputs on changes in plan assets, and significant concentrations of risk within plan assets. The standard involves disclosures only, and will not impact our consolidated income, cash flows, or financial position.

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 year ended December 31, 2008. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we held during the year ended December 31, 2008.

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

•  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

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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 this 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 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 became effective on 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 available-for-sale investment securities, nonqualified deferred compensation plan assets and liabilities, derivative instruments, and the financial instruments disclosed in Note 6, Financial and Derivative Instruments, “Financial Instruments.” SFAS No. 157 also applied to the year-end measurement of fair values of our pension and OPEB plan assets. For details on the accounting of our pension and OPEB plans, see Note 7, Retirement Benefits. The implementation of SFAS No. 157 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 was effective for us upon issuance, 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 the FASB and was effective for us for the quarter ended September 30, 2008. The standard was to be applied prospectively. The guidance in this standard and the joint guidance provided by the FASB and the SEC did not affect 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 reported at fair value on a recurring basis at December 31, 2008.

	Total			Level 1			Level 2
	In Millions
Assets:
Cash Equivalents	$	56		$	56		$	—
CMS Energy Common Stock		19			19			—
Nonqualified Deferred Compensation Plan Assets		3			3			—
SERP
Equity Securities		25			25			—
Debt Securities		19			—			19
Total	$	122		$	103		$	19
Liabilities:
Nonqualified Deferred Compensation Plan Liabilities	$	(3	)	$	(3	)	$	—
Derivative Instruments:
Fixed price fuel contracts		(1	)		—			(1	)
Total	$	(4	)	$	(3	)	$	(1	)

Cash Equivalents: Our cash equivalents consist of money market funds with daily liquidity. The funds invest in U.S. Treasury notes, other government-backed securities, and repurchase agreements collateralized by U.S. Treasury notes.

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 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 movements 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.

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Fixed price fuel contracts: Under certain agreements, we have effectively locked in a price per gallon for gasoline and diesel fuel we will purchase from January 2009 through November 2009. These contracts are valued using an income approach that incorporated forward national fuel prices adjusted to reflect conditions in Michigan. The fair values of these contracts are included in Other current liabilities on our Consolidated Balance Sheets. For additional information on our fixed fuel price contracts, see Note 6, Financial and Derivative Instruments, “Derivative Instruments.”

At December 31, 2008, we did not have any assets or liabilities classified as Level 3.

3: ASSET SALES AND IMPAIRMENT CHARGES

Asset Sales

The impacts of our asset sales are included in Loss (gain) on asset sales, net in our Consolidated Statements of Income. Asset sales were immaterial for the year ended December 31, 2008.

For the year ended December 31, 2007, we sold the following assets:

		Gross Cash		Pretax
Month sold	Business/Project	Proceeds		Gain
		In Millions
April	Palisades(a)	$	333	$	—
Various	Other		4		2
	Total	$	337	$	2

(a) We sold Palisades to Entergy for $380 million and as of December 31, 2007, received $363 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.

For the year ended December 31, 2006, we sold the following assets:

		Gross Cash		Pretax
Month sold	Business/Project	Proceeds		Gain
		In Millions
October	Land in Ludington, Michigan	$	6	$	2
November	MCV GP II(a)		61		77
Various	Other		2		—
	Total	$	69	$	79

(a) In November 2006, we sold all of our interests in the Consumers’ subsidiaries that held the MCV Partnership and the MCV Facility to an affiliate of GSO Capital Partners and Rockland Capital Energy Investments.

Because of the MCV PPA, the transaction is a sale and leaseback for accounting purposes. We have continuing involvement with the MCV Partnership through an existing guarantee associated with the future operations of the MCV Facility. As a result, we accounted for the MCV Facility as a financing for accounting purposes and not a sale. The value of the finance obligation was based on an allocation of the transaction proceeds to the fair values of the

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net assets sold and fair value of the MCV Facility under the financing. The total proceeds were less than the fair value of the net assets sold. As a result, there were no proceeds remaining to allocate to the MCV Facility; therefore, we recorded no finance obligation.

The transaction resulted in an after-tax loss of $41 million, which includes a reclassification of $30 million of AOCI into earnings, an $80 million impairment charge on the MCV Facility, an $8 million gain on the removal of our interests in the MCV Partnership and the MCV Facility, and $1 million benefit in general taxes. Upon the sale of our interests in the MCV Partnership and the FMLP, we were no longer the primary beneficiary of these entities and the entities were deconsolidated.

Impairment Charges

We recorded no impairments of long-lived assets for the years ended December 31, 2008 and December 31, 2007. For the year ended December 31, 2006, we recorded an impairment charge of $218 million to recognize the reduction in fair value of the MCV Facility’s real estate assets. The result was an $80 million reduction to our consolidated net income after considering tax effects and minority interest.

4: CONTINGENCIES

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 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. A number of factors, including the number of potentially responsible parties involved with each site, affect our share of the total liability. As of December 31, 2008, we have recorded a liability of $2 million, the minimum amount of our range of possible outcomes 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. Periodically, we receive information about new sites, which leads us to review our response activity estimates. Any significant change in the underlying 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 estimates of NREPA and Superfund liability.

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. 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 fourteen 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.

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Routine Maintenance Classification: The EPA has alleged that some utilities have incorrectly classified major plant modifications as RMRR 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 RMRR. In October 2008, we received another information request from the EPA pursuant to Section 114 of the Clean Air Act. We responded to this information request in December 2008. In addition to the EPA’s information request, in October 2008, we received a NOV for three of our coal-based facilities relating to violations of NSR regulations, alleging ten projects from 1986 to 1998 were subject to NSR review. We met with the EPA in January 2009 and have additional meetings scheduled. If the EPA does not accept our interpretation of RMRR, we could be required to install additional pollution control equipment at some or all of our coal-based electric generating plants, surrender emission allowances, engage in supplemental environmental programs 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.

Clean Air Interstate Rule: In March 2005, the EPA adopted the CAIR, which required additional coal-based 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. The court initially vacated the CAIR and the CAIR federal implementation plan in their entirety, but subsequently, the court changed course and remanded the rule to the EPA maintaining the rule in effect pending EPA revision. As a result, the CAIR still remains in effect, with the first annual nitrogen oxides compliance year beginning January 1, 2009. The EPA must now revise the rule to resolve the court’s concerns. The court did not set a timetable for the revision. We cannot predict the financial impact or outcome of this matter.

Litigation: Our transmission charges 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 will 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

Stranded Cost Recovery: In November 2004, the MPSC approved recovery of our Stranded Costs incurred in 2002 and 2003 plus interest through the period of collection through a surcharge on ROA customers. Since the MPSC order, we have experienced a downward trend in ROA customers, although recently this trend has slightly reversed. In October 2008, the Michigan legislature enacted legislation that amended the Customer Choice Act and directed the MPSC to approve rates that will allow recovery of Stranded Costs within five years. In January 2009, we filed an application with the MPSC requesting recovery of these Stranded Costs through a surcharge on both full service and ROA customers. At December 31, 2008, we had a regulatory asset for Stranded Costs of $71 million.

Power Supply Costs: The PSCR process is designed to allow us to recover all of our power supply 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.

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The following table summarizes our PSCR reconciliation filing currently pending with the MPSC:

Power Supply Cost Recovery Reconciliation

		Net Under-	PSCR Cost
PSCR Year	Date Filed	recovery	of Power Sold	Description of Net Underrecovery
2007	March 2008	$42 million(a)	$1.628 billion	In our 2007 PSCR Plan we expected to offset power supply costs by including a $44 million credit for Palisades sale proceeds due customers. However, the MPSC directed that the Palisades sale proceeds be refunded through bill credits outside of the PSCR process.

(a) This amount includes 2006 underrecoveries as allowed by the MPSC order in our 2007 PSCR plan 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 of $42 million. We self-implemented a 2008 PSCR charge in January 2008. In November 2008, the MPSC issued an order approving our PSCR plan factor.

2009 PSCR Plan: In September 2008, we submitted our 2009 PSCR plan filing to the MPSC. The plan seeks approval to apply a uniform maximum PSCR factor of $0.02680 per kWh for all classes of customers. The plan also seeks approval to recover an expected $22 million discount in power supply charges provided to a large industrial customer. The MPSC approved the discount in 2005 to promote long-term investments in the industrial infrastructure of Michigan. We self-implemented a 2009 PSCR charge in January 2009.

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: In November 2008, we filed an application with the MPSC seeking an annual increase in revenue of $214 million based on an 11 percent authorized return on equity. The filing seeks recovery of costs associated with new plant investments including Clean Air Act investments, higher operating and maintenance costs, and the approval to recover costs associated with our advanced metering infrastructure program. The following table details the components of the requested increase in revenue:

Components of the increase in revenue	In Millions
Operating and maintenance	$	50
Rate of return		17
Rate base		76
Book depreciation on new investment		14
Property taxes on new investment		9
Gross margin		43
Other		5
Total	$	214

This is the first electric rate case under the new streamlined regulatory process enacted by the Michigan legislation in October 2008. The new provisions generally allows utilities to self-implement rates six months after filing, subject to refund, unless the MPSC finds good cause to prohibit such self-implementation. The new provisions require the MPSC to issue an order 12 months after filing or the rates, as filed, become permanent. We cannot predict the financial impact or outcome of this proceeding.

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Palisades Regulatory Proceedings: The MPSC order approving the Palisades sale transaction required 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 2007 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 of $109 million to customers. The distribution of these funds is still pending with the MPSC.

Other Electric Contingencies

The MCV PPA: We have a 35-year power purchase agreement that began in 1990 with the MCV Partnership to purchase 1,240 MW of electricity. In June 2008, the MPSC approved an amended and restated MCV PPA, which took effect in October 2008. The 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,

•  a $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.

Capacity and energy charges, net of RCP replacement energy and benefits, under the MCV PPA were $320 million in 2008, $464 million in 2007, and $411 million in 2006. We estimate that capacity and energy charges under the MCV PPA will range from $240 million to $330 million annually.

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. At December 31, 2008, 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 for the recovery of our nuclear fuel storage costs and the payment to Entergy, until the litigation regarding these costs is

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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 December 31, 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 provide a $162 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 2008, we estimated our remaining costs to be between $38 million and $52 million. We expect to fund most of these costs through proceeds from insurance settlements and MPSC-approved rates.

At December 31, 2008, we have a liability of $38 million and a regulatory asset of $69 million that, 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 $5 million and $6 million over the next five years. Periodically, we review these response activity cost estimates. Any significant change in the underlying assumptions, such as an increase in the number of sites, changes in remediation techniques or legal and regulatory requirements, could affect our estimates of annual response activity costs and MGP liability.

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 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
GCR Year	Date Filed	recovery	of Gas 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 plan for year 2008-2009: In February 2009, the MPSC issued an order for our 2008-2009 GCR plan year. The order approved a base GCR ceiling factor of $8.17 per mcf for April 2008 through March 2009, subject to a quarterly ceiling price adjustment mechanism.

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,

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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 March 2009 is $8.17 per mcf. We are currently anticipating an underrecovery will occur during the 2008-2009 GCR year.

GCR plan for year 2009-2010: In December 2008, we filed an application with the MPSC seeking approval of a GCR plan for our 2009-2010 GCR plan year. Our request proposed the use of a base GCR ceiling factor of $8.10 per mcf, plus a quarterly GCR ceiling price adjustment contingent upon future events. We expect to self-implement a 2009 GCR charge in April 2009.

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

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. In December 2008, the MPSC approved a partial settlement agreement allowing us to implement the filed depreciation rates, on an interim basis, concurrent with the implementation of settled rates in our 2008 gas rate case. The interim depreciation rates reduce our depreciation expense by approximately $20 million per year and will remain in effect until a final order is issued in our gas depreciation case. 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.

2008 Gas Rate Case: In December 2008, the MPSC approved a settlement agreement authorizing a rate increase of $22 million, based on a 10.55 percent authorized return on equity, for service rendered on and after December 24, 2008. The settlement includes a $20 million decrease in depreciation rates and requires that we not request a new gas general rate increase prior to May 1, 2009.

Other Contingencies — Indemnifications

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 we would have received had we issued the guarantee as a single item.

The following table describes our guarantees at December 31, 2008:

		Expiration	Maximum
Guarantee Description	Issue Date	Date	Obligation
		In Millions
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 December 31, 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.

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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, due to a number of factors, we are unable to estimate the maximum potential obligation. These factors include unspecified exposure under certain agreements. 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, 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.

Contractual Commitments

Purchase Obligations: The following table summarizes our contractual cash obligations for each of the periods presented.

Purchase Obligations at December 31, 2008

			Payments Due
			Less Than		One to		Three to		More Than
	Total		One Year		Three Years		Five Years		Five Years
	In Millions
Purchase obligations(a)	$	14,699	$	2,201	$	2,391	$	1,545	$	8,562
Purchase obligations — related parties(a)		1,570		78		166		168		1,158

(a) Long-term contracts for purchase of commodities and services. These obligations include operating contracts used to ensure adequate supply with generating facilities that meet PURPA requirements. The commodities and services include:

•  natural gas and associated transportation,

•  electricity, and

•  coal and associated transportation.

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5: FINANCINGS AND CAPITALIZATION

Long-term debt at December 31 follows:

	Interest Rate (%)			Maturity	2008			2007
					(In Millions)
First mortgage bonds(a)		4.250		2008	$	—		$	250
		4.800		2009		200			200
		4.400		2009		150			150
		4.000		2010		250			250
		5.000		2012		300			300
		5.375		2013		375			375
		6.000		2014		200			200
		5.000		2015		225			225
		5.500		2016		350			350
		5.150		2017		250			250
		5.650		2018		250			—
		6.125		2019		350			—
		5.650		2020		300			300
		5.650		2035		142			145
		5.800		2035		175			175
						3,517			3,170
Senior notes		6.375		2008		—			159
		6.875		2018		180			180
Securitization bonds		5.495	(b)	2009-2015		277			309
Nuclear fuel disposal liability				(c)		162			159
Tax-exempt pollution control revenue bonds		Various		2010-2035		161			161
Total principal amount outstanding						4,297			4,138
Current amounts						(383	)		(440	)
Net unamortized discount						(6	)		(6	)
Total long-term debt					$	3,908		$	3,692

(a)	The weighted-average interest rate for our FMB was 5.329 percent at December 31, 2008 and 5.131 percent at December 31, 2007.
(b)	Represents the weighted-average interest rate at December 31, 2008 (5.442 percent at December 31, 2007).
(c)	The maturity date is uncertain.

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Financings: The following is a summary of significant long-term debt transactions during 2008:

				Issue/Retirement
	Principal		Interest Rate (%)	Date	Maturity Date
	(In millions)
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 FMB. We used the proceeds to redeem $28 million of insured tax-exempt bonds in April 2008.

(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. We used the proceeds to redeem $68 million of insured tax-exempt bonds in April 2008.

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.

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.

First Mortgage Bonds: We secure our FMB by a mortgage and lien on substantially all of our property. Our ability to issue FMB is restricted by certain provisions in the First Mortgage Bond Indenture and the need for regulatory approvals under federal law. Restrictive issuance provisions in our First Mortgage Bond Indenture include achieving a two-times interest coverage ratio and having sufficient unfunded net property additions.

Regulatory Authorization for Financings: The FERC has authorized us to have outstanding at any one time, up to $1.0 billion of secured and unsecured short-term securities for general corporate purposes. The remaining availability is $550 million at December 31, 2008.

The FERC has also authorized us to issue and sell up to $1.5 billion of secured and unsecured long-term securities for general corporate purposes. The remaining availability is $950 million at December 31, 2008.

The authorizations are for the period ending June 30, 2010. Any long-term issuances during the authorization period are exempt from the FERC’s competitive bidding and negotiated placement requirements.

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Securitization Bonds: Certain regulatory assets collateralize securitization bonds. The bondholders have no recourse to our other assets. Through our rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses. The surcharges collected are remitted to a trustee and are not available to our creditors or creditors of our affiliates. Securitization surcharges totaled $53 million in 2008 and $48 million in 2007.

Debt Maturities: At December 31, 2008, the aggregate annual contractual maturities for long-term debt for the next five years are:

	Payments Due
	2009		2010		2011		2012		2013
	In Millions
Long-term debt	$	383	$	343	$	37	$	339	$	416

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at December 31, 2008:

					Outstanding
	Amount of		Amount		Letters of		Amount
Expiration Date	Facility		Borrowed		Credit		Available
	In Millions
March 30, 2012	$	500	$	—	$	172	$	328
November 30, 2009(a)		192		—		192		—
September 9, 2009		150		—		—		150

(a) Secured revolving letter of credit facility.

Dividend Restrictions: Under the provisions of our articles of incorporation, at December 31, 2008, we had $331 million of unrestricted retained earnings available to pay common stock dividends. Provisions of the Federal Power Act and the Natural Gas Act effectively restrict dividends to the amount of our retained earnings. Several decisions from the FERC suggest that under a variety of circumstances our common stock dividends would not be limited to amounts in our 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.

During 2008, we paid $297 million in common stock dividends to CMS Energy.

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we sell eligible accounts receivable to a wholly owned, consolidated, bankruptcy-remote special-purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $250 million of the receivables at December 31, 2008, reduced from $325 million at December 31, 2007. The special purpose entity sold $170 million in receivables at December 31, 2008 and no receivables at December 31, 2007. The purchaser of the receivables has no recourse against our other assets for failure of a debtor to pay when due and no right to any receivables not sold. We have neither recorded a gain or loss on the receivables sold nor retained any interest in the receivables sold. We continue to service the receivables sold to the special-purpose entity.

The following table summarizes certain cash flows under our accounts receivable sales program:

Years Ended December 31	2008		2007
	In Millions
Administrative fees	$	1	$	3
Net cash flow as a result of accounts receivable financing	$	170	$	(325	)
Collections from customers	$	6,060	$	5,881

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Preferred Stock: Details about our outstanding preferred stock follow:

			Optional
			Redemption		Number of Shares
December 31	Series		Price		2008		2007		2008		2007
									In Millions
Preferred stock
Cumulative $100 par value, Authorized 7,500,000 shares, with no mandatory redemption	$	4.16	$	103.25		68,451		68,451	$	7	$	7
	$	4.50	$	110.00		373,148		373,148		37		37
Total Preferred stock									$	44	$	44

6: FINANCIAL AND DERIVATIVE INSTRUMENTS

Financial Instruments: The carrying amounts of cash, current accounts and notes receivable, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments or other valuation techniques.

The book value and fair value of our long-term debt instruments follows:

	2008				2007
	Book		Fair		Book		Fair
December 31	Value		Value		Value		Value
	In Millions
Long-term debt(a)	$	4,291	$	4,073	$	4,132	$	4,099

(a) Includes current maturities of $383 million at December 31, 2008 and $440 million at December 31, 2007. Settlement of long-term debt is generally not expected until maturity.

The summary of our available-for-sale investment securities follows:

	2008								2007
			Unrealized		Unrealized		Fair				Unrealized		Unrealized		Fair
December 31	Cost		Gains		Losses		Value		Cost		Gains		Losses		Value
	In Millions
Common stock of CMS Energy(a)	$	8	$	11	$	—	$	19	$	8	$	24	$	—	$	32
SERP:
Equity securities		25		—		—		25		35		—		—		35
Debt securities		19		—		—		19		7		—		—		7

(a) At December 31, 2008 and 2007, we held 1.8 million shares of CMS Energy Common Stock.

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

During 2008, the fair value of our SERP investment in equity securities declined to $25 million. We determined that this decline in fair value was other than temporary. Accordingly, we reclassified net unrealized losses of $16 million ($10 million, net of tax) from AOCL to Other expense in the Consolidated Statements of Income and established a new cost basis of $25 million for these investments, which was equal to fair value at December 31, 2008.

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The fair value of available-for-sale debt securities by contractual maturity at December 31, 2008 is as follows:

	In Millions
Due one year or less	$	1
Due after one year through five years		8
Due after five years through ten years		7
Due after ten years		3
Total	$	19

During 2008, the proceeds from sales of SERP securities were $2 million. Gross losses realized were immaterial. During 2007, the proceeds from sales of SERP securities were $29 million, and $11 million of gross gains and $1 million of gross losses were realized. We reclassified net gains of $7 million, net of tax of $3 million, from AOCL and included this amount in net income in 2007. The proceeds from sales of SERP securities were $3 million during 2006. Gross gains and losses were immaterial in 2006.

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

Fixed price fuel contracts: In December 2008, we entered into two financial contracts to fix economically the price of gasoline and diesel fuel we purchase for our fleet vehicles and equipment. Under these agreements, we have effectively locked in a price per gallon for gasoline and diesel fuel we will purchase from January through November 2009. At December 31, 2008, the fair value of these derivatives was a liability of $1 million. We record the fair value of these derivatives in Other current liabilities on our Consolidated Balance Sheets. We recorded the mark-to-market losses on these derivatives in Other expense on our Consolidated Statements of Income.

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7: RETIREMENT BENEFITS

We provide retirement benefits to our employees under a number of different 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.

On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of five percent of base pay to the existing employees’ 401(k) plan. No employee contribution is required in order to receive the plan’s employer contribution. All employees hired on and after September 1, 2005 participate in this plan. Participants in the cash balance pension plan, in effect from July 1, 2003 to September 1, 2005, also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP expense was $3 million for the year ended December 31, 2008 and $2 million for the years ended December 31, 2007 and 2006.

SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code. SERP trust earnings are taxable and trust assets are included in our consolidated assets. Consumers’ trust assets were $45 million at December 31, 2008 and $53 million at December 31, 2007. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $47 million at December 31, 2008 and $48 million at December 31, 2007. A contribution of $21 million was made to the trust in December 2007.

On April 1, 2006, we implemented a DC SERP and froze further new participation in the defined benefit SERP. The DC SERP provides participants benefits ranging from 5 percent to 15 percent of total compensation. The DC SERP requires a minimum of five years of participation before vesting. Our contributions to the plan, if any, will be placed in a grantor trust. Trust assets were less than $1 million at December 31, 2008 and 2007. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The DC SERP expense was less than $1 million for the years ended December 31, 2008, 2007 and 2006.

401(k): The employer’s match for the 401(k) plan is 60 percent on eligible contributions up to the first six percent of an employee’s wages. The total 401(k) plan cost was $15 million for the year ended December 31, 2008 and $14 million for the years ended December 31, 2007 and 2006.

EISP: We implemented a nonqualified EISP in 2002 to provide flexibility in separation of employment by officers, a selected group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premiums for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was less than

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

$1 million for each of the years ended December 31, 2008, 2007 and 2006. The ABO for the EISP was $1 million at December 31, 2008 and December 31, 2007.

OPEB: The OPEB plan covers all regular full-time employees who are covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least 10 full years of applicable continuous service. Regular full-time employees who qualify for a pension plan disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs were based on the assumption that costs would increase 8.0 percent for those under 65 and 9.5 percent for those over 65 in 2008. The 2009 rate of increase for OPEB health costs for those under 65 is expected to be 8.5 percent and for those over 65 is expected to be 8.0 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2017 and for those over 65 by 2017 and thereafter.

The health care cost trend rate assumption affects the estimated costs recorded. A one percentage point change in the assumed health care cost trend assumption would have the following effects:

	One Percentage		One Percentage
	Point Increase		Point Decrease
	In Millions
Effect on total service and interest cost component	$	15	$	(13	)
Effect on postretirement benefit obligation	$	172	$	(150	)

Upon adoption of SFAS No. 106 in 1992, we recorded a liability of $466 million for the accumulated transition obligation and a corresponding regulatory asset for anticipated recovery in utility rates. For additional details, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation.” The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years.

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 required 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 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 year ended December 31, 2008.

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Assumptions: The following tables recap the weighted-average assumptions used in our retirement benefits plans to determine benefit obligations and net periodic benefit cost:

Weighted Average For Benefit Obligations:

	Pension & SERP									OPEB
Years Ended December 31	2008			2007			2006			2008			2007			2006
Discount rate(a)		6.50	%		6.40	%		5.65	%		6.50	%		6.50	%		5.65	%
Expected long-term rate of return on plan assets(b)		8.25	%		8.25	%		8.25	%		7.75	%		7.75	%		7.75	%
Mortality table(c)		2000			2000			2000			2000			2000			2000
Rate of compensation increase:
Pension		4.00	%		4.00	%		4.00	%
SERP		5.50	%		5.50	%		5.50	%

Weighted Average For Net Periodic Benefit Cost:

	Pension & SERP									OPEB
Years Ended December 31	2008			2007			2006			2008			2007			2006
Discount rate(a)		6.40	%		5.65	%		5.75	%		6.50	%		5.65	%		5.75	%
Expected long-term rate of return on plan assets(b)		8.25	%		8.25	%		8.50	%		7.75	%		7.75	%		8.00	%
Mortality table(c)		2000			2000			2000			2000			2000			2000
Rate of compensation increase:
Pension		4.00	%		4.00	%		4.00	%
SERP		5.50	%		5.50	%		5.50	%

(a)	The discount rate is set to reflect the rates at which benefits can be effectively settled. It is set equal to the equivalent single rate that results from a yield curve analysis that incorporates projected benefit payments specific to our pension and other postretirement benefit plans, and the yields on high quality corporate bonds rated Aa or better.
(b)	We determine our long-term rate of return by considering historical market returns, the current and expected future economic environment, the capital market principles of risk and return, and the expert opinions of individuals and firms with financial market knowledge. We consider the asset allocation of the portfolio in forecasting the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. Annually, we review for reasonableness and appropriateness of the forecasted returns for various classes of assets used to construct an expected return model.
(c)	The mortality assumption is based on the RP-2000 mortality tables with projection of future mortality improvements using Scale AA, which aligns with the IRS prescriptions for cash funding valuations under the Pension Protection Act.

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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:

	Pension & SERP
Years Ended December 31	2008			2007			2006
	In Millions
Net periodic pension cost
Service cost	$	41		$	47		$	47
Interest expense		96			84			81
Expected return on plan assets		(78	)		(75	)		(80	)
Amortization of:
Net loss		40			44			41
Prior service cost		6			7			7
Net periodic pension cost		105			107			96
Regulatory adjustment(a)		4			(22	)		(11	)
Net periodic pension cost after regulatory adjustment	$	109		$	85		$	85

	OPEB
Years Ended December 31	2008			2007			2006
	In Millions
Net periodic OPEB cost
Service cost	$	21		$	24		$	22
Interest expense		69			65			60
Expected return on plan assets		(61	)		(57	)		(53	)
Amortization of:
Net loss		10			23			20
Prior service credit		(10	)		(10	)		(10	)
Net periodic OPEB cost		29			45			39
Regulatory adjustment(a)		3			(6	)		(2	)
Net periodic OPEB cost after regulatory adjustment	$	32		$	39		$	37

(a) Regulatory adjustments are the differences between amounts included in rates and the periodic benefit cost calculated pursuant to SFAS No. 87 and SFAS No. 106. The pension regulatory asset had a balance of $29 million at December 31, 2008 and $33 million at December 31, 2007. The OPEB regulatory asset had a balance of $5 million at December 31, 2008 and $8 million at December 31, 2007.

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized into net periodic benefit cost over the next fiscal year from the regulatory asset is $44 million. The estimated net loss and prior service credit for OPEB plans that will be amortized into net periodic benefit cost over the next fiscal year from the regulatory asset is $23 million.

We amortize gains and losses in excess of 10 percent of the greater of the benefit obligation and the MRV over the average remaining service period. The estimated time of amortization of gains and losses is 12 years for pension and 14 years for OPEB. Prior service cost amortization is established in the years in which the prior service cost first occurred, and are based on the same amortization period in all future years until the prior service costs are fully

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recognized. The estimated time of amortization of new prior service costs is 12 years for pension and 10 years for OPEB.

Reconciliations: The following table reconciles the funding of our retirement benefits plans with our retirement benefits plans’ liability:

	Pension Plan						SERP						OPEB
Years Ended December 31	2008			2007			2008			2007			2008			2007
	In Millions
Benefit obligation at beginning of period	$	1,565		$	1,576		$	61		$	47		$	1,082		$	1,179
Service cost		45			49			1			1			23			24
Interest cost		103			86			4			3			74			65
Actuarial loss (gain)		(66	)		30			(2	)		12			91			(115	)
Palisades sale		—			(38	)		—			—			—			(20	)
Benefits paid		(123	)		(138	)		(2	)		(2	)		(51	)		(51	)
Benefit obligation at end of period(a)		1,524			1,565			62			61			1,219			1,082
Plan assets at fair value at beginning of period		1,078			1,040			—			—			785			734
Actual return on plan assets		(231	)		89			—			—			(185	)		51
Company contribution		—			109			2			2			62			51
Palisades sale		—			(22	)		—			—			—			(5	)
Actual benefits paid(b)		(123	)		(138	)		(2	)		(2	)		(50	)		(46	)
Plan assets at fair value at end of period		724			1,078			—			—			612			785
Funded status at end of measurement period		(800	)		(487	)		(62	)		(61	)		(607	)		(297	)
Additional VEBA Contributions or Non-Trust Benefit Payments		—			—			—			—			—			12
Funded status at December 31(c)(d)	$	(800	)	$	(487	)	$	(62	)	$	(61	)	$	(607	)	$	(285	)

(a)	The Medicare Prescription Drug, Improvement and Modernization Act of 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy, which is tax-exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. The Medicare Part D annualized reduction in net OPEB cost was $24 million for 2008 and $27 million for 2007. The reduction includes $7 million for 2008 and 2007 in capitalized OPEB costs.
(b)	We received $5 million in 2008 and $4 million in 2007 for Medicare Part D Subsidy payments.
(c)	Liabilities for retirement benefits comprised $1.429 billion classified as non-current and $2 million classified as current for the year ended December 31, 2008, and $805 million classified as non-current and $2 million classified as current for the year ended December 31, 2007.
(d)	Of the $800 million funded status of Pension Plan at December 31, 2008, $762 million is attributable to Consumers. Of the $487 million funded status of the Pension Plan at December 31, 2007, $461 million is attributable to Consumers, based on allocation of expenses.

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The following table provides pension PBO, ABO and fair value of plan assets:

Years Ended December 31	2008		2007
	In Millions
Pension PBO	$	1,524	$	1,565
Pension ABO		1,240		1,231
Fair value of Pension Plan assets	$	724	$	1,078

Items Not Yet Recognized as a Component of Net Periodic Benefit Cost: The following table recaps the amounts recognized in SFAS No. 158 regulatory assets and AOCL that have not been recognized as components of net periodic benefit cost. For additional details on regulatory assets, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation.”

	Pension & SERP				OPEB
Years Ended December 31	2008		2007		2008			2007
	In Millions
Regulatory assets
Net loss	$	835	$	636	$	595		$	265
Prior service cost (credit)		33		39		(78	)		(89	)
AOCL
Net loss		8		18		—			—
Prior service cost		1		1		—			—
Total amounts recognized in regulatory assets and AOCL	$	877	$	694	$	517		$	176

Plan Assets: The following table recaps the categories of plan assets in our retirement benefits plans:

	Pension						OPEB
Years Ended December 31	2008			2007			2008			2007
Asset Category:
Fixed Income		37	%		30	%		55	%		34	%
Equity Securities		50	%		60	%		45	%		66	%
Alternative Strategy		13	%		10	%		—			—

We contributed $50 million to our OPEB plan in 2008 and we plan to contribute $52 million to our OPEB plan in 2009. Of the $50 million OPEB contribution made during 2008, $10 million was contributed to the 401(h) component of the qualified pension plan and the remaining $40 million was contributed to the VEBA trust accounts. We did not contribute to our Pension Plan in 2008, but plan to contribute $291 million to our Pension Plan in 2009. Contributions include required and discretionary amounts. Actual future contributions will depend on future investment performance, changes in future discount rates, and various other factors related to the populations participating in the plans.

In 2008, the consultant for the Pension Plan, recommended an adjustment to the target asset allocation for Pension Plan assets. The recommended revised target asset allocation for the Pension Plan assets was 50 percent equity, 30 percent fixed income, and 20 percent alternative strategy investments from the previous target of 60 percent equity, 30 percent fixed income and 10 percent alternative strategy investments. This recommendation was thoroughly reviewed and approved by our Benefit Administration Committee. This adjustment is being made gradually by the allocation of contributions into alternative assets and the drawdown of equities to cover plan benefit payments and distributions. This revised target asset allocation is expected to continue to maximize the

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long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor’s 500 Index, with lesser allocations to the Standard & Poor’s MidCap and SmallCap Indexes and Foreign Equity Funds. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers as well as high-yield and global bond funds. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. We use annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies to evaluate the need for adjustments to the portfolio allocation.

We established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers and through direct contributions from the non-utility subsidiaries. We invest the equity portions of the union and non-union health care VEBA trusts in a Standard & Poor’s 500 Index fund. We invest the fixed-income portion of the union health care VEBA trust in domestic investment grade taxable instruments. We invest the fixed-income portion of the non-union health care VEBA trust in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA trust are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.

SFAS No. 132(R) Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:

	Pension		SERP		OPEB(a)
	In Millions
2009	$	72	$	2	$	53
2010		78		2		55
2011		85		2		58
2012		96		2		60
2013		106		2		61
2014-2018		669		9		338

(a) OPEB benefit payments are net of employee contributions and expected Medicare Part D prescription drug subsidy payments. The subsidies to be received are estimated to be $5 million for 2009, $6 million for 2010 and 2011, $7 million for 2012, $8 million for 2013 and $46 million combined for 2014 through 2018.

8: ASSET RETIREMENT OBLIGATIONS

SFAS No. 143, Accounting for Asset Retirement Obligations: This standard requires us to record the fair value of the cost to remove assets at the end of their useful lives, if there is a legal obligation to remove them. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability at December 31, 2008 would increase by $10 million.

If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Historically, our gas transmission and electric and gas distribution assets have indeterminate lives and retirement cash flows that cannot be determined. During 2007, however, we implemented a new fixed asset accounting system that facilitates ARO accounting estimates for gas distribution mains and services. The new system enabled us to calculate a reasonable estimate of the fair value of the cost to cut, purge, and cap abandoned gas distribution mains and services at the end of their useful lives. We recorded a $101 million ARO liability and an asset of equal value at December 31, 2007. We have not recorded a liability for assets that have insignificant cumulative disposal costs, such as substation batteries.

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FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: This Interpretation clarified the term “conditional asset retirement obligation” used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments and the cut, purge, and cap of abandoned gas distribution mains and services qualify as conditional AROs, as defined by FIN 47.

The following table lists the assets that we have legal obligations to remove at the end of their useful lives and for which we have an ARO liability recorded:

	In Service
ARO Description	Date		Long-Lived Assets
December 31, 2008
Closure of coal ash disposal areas		Various	Generating plants coal ash areas
Closure of wells at gas storage fields		Various	Gas storage fields
Indoor gas services equipment relocations		Various	Gas meters located inside structures
Asbestos abatement		1973	Electric and gas utility plant
Gas distribution cut, purge & cap		Various	Gas distribution mains & services

No assets have been restricted for purposes of settling AROs.

	ARO											ARO
	Liability									Cash flow		Liability
ARO Description	12/31/06		Incurred		Settled(a)			Accretion		Revisions		12/31/07
	In Millions
Palisades — decommission	$	401	$	—	$	(410	)	$	7	$	2	$	—
Big Rock — decommission		2		—		(3	)		1		—		—
Coal ash disposal areas		57		—		(4	)		6		—		59
Wells at gas storage fields		1		—		—			—		—		1
Indoor gas services relocations		1		—		—			—		—		1
Asbestos abatement		35		—		(1	)		2		—		36
Gas distribution cut, purge, cap		—		101		—			—		—		101
Total	$	497	$	101	$	(418	)	$	16	$	2	$	198

	ARO												ARO
	Liability										Cash flow		Liability
ARO Description	12/31/07		Incurred			Settled(a)			Accretion		Revisions		12/31/08
	In Millions
Palisades — decommission	$	—	$	—		$	—		$	—	$	—	$	—
Big Rock — decommission		—		—			—			—		—		—
Coal ash disposal areas		59		—			(3	)		6		—		62
Wells at gas storage fields		1		—			—			—		—		1
Indoor gas services relocations		1		—			—			—		—		1
Asbestos abatement		36		—			(2	)		2		—		36
Gas distribution cut, purge, cap		101		(1	)		(2	)		7		—		105
Total	$	198	$	(1	)	$	(7	)	$	15	$	—	$	205

(a) Cash payments of $7 million in 2008 and $5 million in 2007 are included in the Other current and non-current liabilities line in Net cash provided by operating activities in our Consolidated Statements of Cash Flows. In

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April 2007, we sold Palisades to Entergy and paid Entergy to assume ownership and responsibility for the Big Rock ISFSI. Our AROs related to Palisades and the Big Rock ISFSI ended with the sale, and we removed the related ARO liabilities from our Consolidated Balance Sheets. We also removed the Big Rock ARO related to the plant in the second quarter of 2007 due to the completion of decommissioning.

9: INCOME TAXES

We join in the filing of a consolidated federal income tax return and a combined Michigan income tax return with CMS Energy and its subsidiaries. Income taxes generally are allocated based on each company’s separate taxable income in accordance with the CMS Energy tax sharing agreement. We had tax related payables to CMS Energy of $75 million in 2008 and $154 million in 2007.

We utilize deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service life of related properties. We use ITC to reduce current income taxes payable.

At December 31, 2008, we had federal tax loss carryforwards of $77 million that expire from 2023 through 2028. In addition, we have a net benefit of $194 million for future Michigan tax deductions which were granted as part of the Michigan Business Tax legislation of 2007. We do not believe that valuation allowances are required, as we expect to fully utilize the loss carryforwards prior to their expiration.

The significant components of income tax expense (benefit) consisted of:

Years Ended December 31	2008			2007			2006
	In Millions
Current income taxes:
Federal	$	(10	)	$	114		$	212
Federal income tax benefit of operating loss carryforwards		—			(44	)		(8	)
State and local		12			—			—
	$	2		$	70		$	204
Deferred income taxes:
Federal	$	200		$	59		$	(109	)
State		—			—			—
	$	200		$	59		$	(109	)
Deferred ITC, net		(4	)		(4	)		(4	)
Tax expense	$	198		$	125		$	91

Current tax expense reflects the settlement of income tax audits for prior years, as well as the provision for current year’s income taxes. Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in our consolidated financial statements. Deferred tax assets and liabilities are classified as current or non-current according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

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The principal components of deferred tax assets (liabilities) recognized on our Consolidated Balance Sheets are as follows:

December 31	2008			2007
	In Millions
Current Assets and (Liabilities):
Tax loss and credit carryforwards	$	8		$	—
Employee benefits		(100	)		5
Gas inventory		(219	)		(204	)
Other		34			48
Net Current (Liability)	$	(277	)	$	(151	)
Noncurrent Assets and (Liabilities):
Tax loss and credit carryforwards	$	213		$	249
SFAS No. 109 regulatory liability		205			207
Nuclear decommissioning (including unrecovered costs)		(20	)		(18	)
Property		(1,056	)		(919	)
Securitized costs		(161	)		(180	)
Employee benefits		80			39
Other		(53	)		(91	)
Net Noncurrent (Liability)	$	(792	)	$	(713	)
Total Deferred Income Tax (Liability)	$	(1,069	)	$	(864	)

The actual income tax expense (benefit) differs from the amount computed by applying the statutory federal tax rate of 35 percent to income (loss) before income taxes as follows:

Years Ended December 31	2008			2007			2006
	In Millions
Income before income taxes and minority obligations, net		562			437			277
Statutory federal income tax rate		x 35	%		x 35	%		x 35	%
Expected income tax expense		197			153			97
Increase (decrease) in taxes from:
Property differences		3			9			13
IRS settlement/credit restoration		—			—			(19	)
State and local income tax, net		8			—			—
Medicare part D exempt income		(8	)		(9	)		(10	)
ITC amortization		(4	)		(3	)		(4	)
Valuation allowance		—			(23	)		15
Other, net		2			(2	)		(1	)
Recorded income tax expense	$	198		$	125		$	91
Effective tax rate		35.2	%		28.6	%		32.9	%

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The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities at December 31, 2008 are adequate for all years.

In June 2006, the IRS concluded its most recent audit of CMS Energy and its subsidiaries, and adjusted taxable income for the years ended December 31, 1987 through December 31, 2001. The overall cumulative increase to taxable income related primarily to the disallowance of the simplified service cost method with respect to certain self-constructed utility assets, resulting in a deferral of these expenses to future periods. The adjustments to taxable income have been allocated based upon Consumers’ separate taxable income in accordance with CMS Energy’s tax sharing agreement. We made a payment to CMS Energy for our share of these audit adjustments of $232 million, and reduced our 2006 income tax provision by $19 million, primarily for the restoration and utilization of previously written off income tax credits. The years 2002 through 2007 are open under the statute of limitations and 2002 through 2005 are currently under audit by the IRS.

On January 1, 2007 we adopted the provisions of FIN 48. As a result of the implementation of FIN 48, we recorded a charge for additional uncertain tax benefits of $5 million, accounted for as a reduction of our beginning retained earnings. Included in this amount was an increase in our valuation allowance of $7 million, increases to tax reserves of $55 million and a decrease to deferred tax liabilities of $57 million. The capital gains of 2007 provided for the release of $23 million of valuation allowance, as reflected in our effective tax rate reconciliation.

A reconciliation of the beginning and ending amount of unrecognized tax benefits in accordance with FIN 48 is as follows:

	(In millions)
Year ended December 31	2008		2007
Balance at beginning of period	$	41	$	51
Reductions for prior year tax positions		—		(11	)
Additions for prior year tax positions		12		1
Statute lapses		—		—
Additions for current year tax positions		2		—
Settlements		—		—
Balance at end of period	$	55	$	41

The balance of $55 million is entirely attributable to tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. Because of the impact of deferred tax accounting, the disallowance of the shorter deductibility period would not affect the annual effective tax rate. Since all our remaining uncertain tax benefits relate only to timing issues, at December 31, 2008, there are no uncertain benefits that would reduce our effective tax rate in future years. It is reasonably possible that, within the next twelve months, we will settle with the IRS on our simplified service cost methodology, a timing issue. An estimate of a settlement range cannot be made at this point.

We accrued an additional $1 million of net interest on tax liabilities during 2008. The total net interest liability is $3 million as of December 31, 2008, none of which is related to uncertain tax positions. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

10: STOCK-BASED COMPENSATION

We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee directors based on their contributions to the successful management of the company. The Plan has a five-year term, expiring in May 2009.

CE-71

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

All grants under the Plan for 2008, 2007, and 2006 were in the form of TSR restricted stock and time-lapse restricted stock. Restricted stock recipients receive shares of CMS Energy Common Stock that have full dividend and voting rights. TSR restricted stock vesting is contingent on meeting a three-year service requirement and specific market conditions. Half of the market condition is based on the achievement of specified levels of TSR over a three-year period and half is based on a comparison of our TSR with the median shareholders’ return of a peer group over the same three-year period. Depending on the performance of the market, a recipient may earn a total award ranging from zero to 150 percent of the initial grant. Time-lapse restricted stock vests after a service period of five years for awards granted prior to 2004, and three years for awards granted in 2004 and thereafter. Restricted stock awards granted to officers in 2006 were entirely TSR restricted stock. Awards granted to officers in 2007 and 2008 were 80 percent TSR restricted stock and 20 percent time-lapsed restricted stock.

All restricted stock awards are subject to forfeiture if employment terminates before vesting. However, if certain minimum service requirements are met or are waived by action of the Compensation and Human Resources Committee of the Board of Directors, restricted shares may vest fully upon:

•  retirement,

•  disability, or

•  change of control of CMS Energy, as defined by the Plan.

The Plan also allows for stock options, stock appreciation rights, phantom shares, and performance units, none of which were granted in 2008, 2007, or 2006.

Shares awarded or subject to stock options, phantom shares, and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such awards to any recipient exceed 250,000 shares in any fiscal year. We may issue awards of up to 3,384,080 shares of common stock under the Plan at December 31, 2008. Shares for which payment or exercise is in cash, as well as forfeited shares or stock options, may be awarded or granted again under the Plan.

The following table summarizes restricted stock activity under the Plan:

				Weighted-Average
				Grant Date Fair Value
Restricted Stock	Number of Shares			per Share
Nonvested at December 31, 2007		1,375,079		$	13.54
Granted(a)		672,370		$	10.43
Vested		(135,804	)	$	13.71
Forfeited(b)		(343,725	)	$	15.60
Nonvested at December 31, 2008		1,567,920		$	12.03

(a)	During 2008, we granted 432,656 TSR shares and 239,714 time-lapse shares of restricted stock.
(b)	During 2008, 338,725 TSR shares granted in 2005 were forfeited due to the failure to meet the specific market conditions.

We expense the awards’ fair value over the required service period. As a result, we recognize all compensation expense for share-based awards that have accelerated service provisions upon retirement by the period in which the employee becomes eligible to retire. We calculate the fair value of time-lapse restricted stock based on the price of our common stock on the grant date. We calculate the fair value of TSR restricted stock awards on the grant date using a Monte Carlo simulation. We base expected volatilities on the historical volatility of the price of CMS Energy Common Stock.

CE-72

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The risk-free rate for each valuation was based on the three-year U.S. Treasury yield at the award grant date. The following table summarizes the significant assumptions used to estimate the fair value of the TSR restricted stock awards:

	2008			2007			2006
Expected volatility		19.70	%		19.11	%		20.51	%
Expected dividend yield		2.67	%		1.20	%		0.00	%
Risk-free rate		2.83	%		4.59	%		4.82	%

The total fair value of shares vested was $2 million in 2008, $10 million in 2007, and $2 million in 2006. Compensation expense related to restricted stock was $7 million in 2008, $7 million in 2007, and $7 million in 2006. The total related income tax benefit recognized in income was $2 million in 2008, $2 million in 2007, and $2 million in 2006. At December 31, 2008, there was $6 million of total unrecognized compensation cost related to restricted stock. We expect to recognize this cost over a weighted-average period of 2.3 years.

The following table summarizes stock option activity under the Plan:

				Weighted-		Weighted-
	Options			Average		Average
	Outstanding,			Exercise		Remaining		Aggregate
	Fully Vested,			Price per		Contractual		Intrinsic
Stock Options	and Exercisable			Share		Term		Value
	(In millions)
Outstanding at December 31, 2007		686,226		$	21.83		3.6 years	$	(3	)
Granted		—			—
Exercised		(44,561	)(a)		6.35
Cancelled or Expired		(143,879	)(b)		35.85
Outstanding at December 31, 2008		497,786			19.81		2.9 years	$	(1	)

(a)	Exercised shares of 8,000 relate to improper allocation of exercised shares to Consumers in 2007.
(b)	Cancelled or expired shares of 64,000 relate to improper allocation of cancelled shares to Consumers in 2007.

Stock options give the holder the right to purchase common stock at the market price on the grant date. Stock options are exercisable upon grant, and expire up to ten years and one month from the grant date. We issue new shares when recipients exercise stock options. The total intrinsic value of stock options exercised was less than $1 million in 2008, $6 million in 2007, and $1 million in 2006. Cash received from exercise of these stock options was less than $1 million in 2008.

The following table summarizes the weighted average grant date fair value:

Years Ended December 31	2008		2007		2006
Weighted average grant date fair value per share
Restricted stock granted	$	10.43	$	14.12	$	13.82
Stock options granted(a)		—		—		—

(a) No stock options were granted in 2008, 2007, or 2006.

SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of SFAS No. 123(R) instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective.

CE-73

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

11: LEASES

We lease various assets, including service vehicles, railcars, gas pipeline capacity and buildings. In accordance with SFAS No. 13, we account for a number of our power purchase agreements as capital and operating leases.

Operating leases for coal-carrying railcars have lease terms expiring over the next 15 years. These leases contain fair market value extension and buyout provisions, with some providing for predetermined extension period rentals. Capital leases for our vehicle fleet operations have a maximum term of 120 months and TRAC end-of-life provisions.

We have capital leases for gas transportation pipelines to the Karn generating complex and Zeeland power plant. The capital lease for the gas transportation pipeline into the Karn generating complex has a term of 15 years with a provision to extend the contract from month to month. The capital lease for the gas transportation pipeline to the Zeeland power plant has a lease term of 12 years with a renewal provision at the end of the contract. The remaining term of our long-term power purchase agreements range between 2 and 22 years. Most of our power purchase agreements contain provisions at the end of the initial contract term to renew the agreement annually.

We are authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. The following table summarizes our capital and operating lease expenses:

Years Ended December 31	2008		2007		2006
	In Millions
Capital lease expense	$	46	$	34	$	15
Operating lease expense		27		23		19

Minimum annual rental commitments under our non-cancelable leases at December 31, 2008 are:

	Capital		Finance		Operating
	Leases		Lease(a)		Leases
	In Millions
2009	$	16	$	23	$	27
2010		15		22		26
2011		13		21		25
2012		15		20		25
2013		8		20		19
2014 and thereafter		47		133		115
Total minimum lease payments		114		239	$	237
Less imputed interest		57		65
Present value of net minimum lease payments		57		174
Less current portion		12		13
Non-current portion	$	45	$	161

(a) In April 2007, we sold Palisades to Entergy and entered into a 15-year power purchase agreement to buy all of the capacity and energy produced by Palisades, up to the annual average capacity of 798 MW. We provided $30 million in security to Entergy for our power purchase agreement obligation in the form of a letter of credit. We estimate that capacity and energy payments under the Palisades power purchase agreement will average $320 million annually. Our total purchases of capacity and energy under the Palisades power purchase agreement were $298 million in 2008 and $180 million in 2007.

CE-74

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Because of the Palisades power purchase agreement and our continuing involvement with the Palisades assets, we accounted for the disposal of Palisades as a financing and not a sale. SFAS No. 98 specifies the accounting required for a seller’s sale and simultaneous leaseback involving real estate. We have continuing involvement with Palisades through security provided to Entergy for our power purchase agreement obligation, our DOE liability and other forms of involvement. As a result, we accounted for the Palisades plant, which is the real estate asset subject to the leaseback, as a financing for accounting purposes and not a sale. As a financing, no gain on the sale of Palisades was recognized in the Consolidated Statements of Income. We accounted for the remaining non-real estate assets and liabilities associated with the transaction as a sale.

As a financing, the Palisades plant remains on our Consolidated Balance Sheets and we continue to depreciate it. We recorded the related proceeds as a finance obligation with payments recorded to interest expense and the finance obligation based on the amortization of the obligation over the life of the Palisades power purchase agreement. The value of the finance obligation was based on an allocation of the transaction proceeds to the fair values of the net assets sold and fair value of the Palisades plant asset under the financing. Total amortization and interest charges under the financing were $23 million in 2008 and $18 million in 2007.

12: PROPERTY, PLANT, AND EQUIPMENT

The following table is a summary of our property, plant, and equipment:

	Estimated
	Depreciable
December 31	Life in Years		2008		2007
			In Millions
Electric:
Generation		18-85	$	3,357	$	3,328
Distribution		12-75		4,766		4,496
Other		7-40		551		438
Capital and finance leases(a)				291		293
Gas:
Underground storage facilities(b)		30-65		270		267
Transmission		13-75		473		570
Distribution		30-80		2,460		2,286
Other		5-50		398		320
Capital leases(a)				21		24
Other:
Non-utility property		7-71		15		15
Construction work-in-progress				607		447
Less accumulated depreciation, depletion, and amortization(c)				4,242		3,993
Net property, plant, and equipment(d)			$	8,967	$	8,491

(a) Capital and finance leases presented in this table are gross amounts. Accumulated amortization of capital and finance leases was $79 million at December 31, 2008 and $62 million at December 31, 2007. Additions were $5 million and Retirements and adjustments were $3 million during 2008. Additions were $229 million during 2007, which includes $197 million related to assets under the Palisades finance lease. Retirements and adjustments were $26 million during 2007.

CE-75

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(b)	Includes base natural gas in underground storage of $26 million at December 31, 2008 and December 31, 2007, which is not subject to depreciation.
(c)	At December 31, 2008, accumulated depreciation, depletion, and amortization included $4.241 billion from our utility plant and $1 million related to our non-utility plant assets. At December 31, 2007, accumulated depreciation, depletion, and amortization included $3.992 billion from our utility plant and $1 million related to our non-utility plant assets.
(d)	At December 31, 2008, utility plant additions were $629 million and utility plant retirements, including other plant adjustments, were $60 million. At December 31, 2007, utility plant additions were $1.303 billion and utility plant retirements, including other plant adjustments, were $1.094 billion.

Asset Acquisition: In December 2007, we purchased a 935 MW gas-based generating plant located in Zeeland, Michigan for $519 million from an affiliate of LS Power Group. The original cost of the plant was $350 million and the plant acquisition adjustment was $213 million. This results in an increase to property, plant, and equipment of $519 million, net of $44 million of accumulated depreciation. The purchase also increased capital leases by $12 million. For additional details on the Zeeland finance lease, see Note 11, Leases.

Included in net property, plant and equipment are intangible assets. The following table summarizes our intangible assets:

December 31			2008				2007
	Amortization				Accumulated				Accumulated
Description	Life in years		Gross Cost(a)		Amortization		Gross Cost(a)		Amortization
	In Millions
Software development		7-15	$	370	$	192	$	207	$	170
Plant acquisition adjustments		40		214		6		214		—
Rights of way		50-75		118		33		116		32
Leasehold improvements		various		11		9		19		16
Franchises and consents		n/a		14		6		14		5
Other intangibles		n/a		18		13		18		13
Total			$	745	$	259	$	588	$	236

(a) Intangible asset additions were $163 million during 2008, which included $161 million related to the installation and operation of our new integrated business software system. Intangible asset additions for our utility plant were $232 million during 2007, which included the Zeeland $213 million plant acquisition adjustment. Retirements were $23 million during 2007.

Pretax amortization expense related to intangible assets was $32 million for the year ended December 31, 2008, $21 million for the year ended December 31, 2007, and $22 million for the year ended December 31, 2006. We expect intangible assets amortization to range between $25 million and $29 million per year over the next five years.

CE-76

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

13: JOINTLY OWNED REGULATED UTILITY FACILITIES

We have investments in jointly owned regulated utility facilities, as shown in the following table:

							Accumulated				Construction
	Ownership		Net Investment(a)				Depreciation				Work in Progress
December 31	Share		2008		2007		2008		2007		2008		2007
	(%)						In Millions
Campbell Unit 3		93.3	$	675	$	664	$	360	$	337	$	19	$	44
Ludington		51.0		61		65		107		104		7		1
Distribution		Various		96		89		41		44		3		5

(a) Net investment is the amount of utility plant in service less accumulated depreciation.

We include our share of the direct expenses of the jointly owned plants in operating expenses. We share operation, maintenance, and other expenses of these jointly owned utility facilities in proportion to each participant’s undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities.

14: 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 electric utility segment consists of regulated activities associated with the generation and distribution of electricity in Michigan. The gas utility segment consists of regulated activities associated with the transportation, storage, and distribution of natural gas in Michigan.

Accounting policies of our segments are as described in Note 1, Corporate Structure and Accounting Policies. Our consolidated financial statements reflect the assets, liabilities, revenues, and expenses of the two individual segments when appropriate. We allocate accounts between the electric and gas segments where common accounts are attributable to both segments. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, construction expense, leased property, taxes or functional surveys. For example, customer receivables are allocated based on revenue, and pension provisions are allocated based on labor dollars.

We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income available to common stockholder by segment. The “Other” segment includes our consolidated special purpose entity for the sale of trade receivables, and in 2006 the MCV Partnership and the FMLP.

CE-77

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following tables provide financial information by reportable segment:

Years Ended December 31	2008		2007			2006
	In Millions
Operating Revenues
Electric	$	3,594	$	3,443		$	3,302
Gas		2,827		2,621			2,374
Other		—		—			45
	$	6,421	$	6,064		$	5,721
Earnings from Equity Method Investees
Electric	$	—	$	—		$	1
Depreciation and Amortization
Electric	$	438	$	397		$	380
Gas		136		127			122
Other		—		—			25
	$	574	$	524		$	527
Interest Charges
Electric	$	185	$	193		$	167
Gas		60		70			73
Other		2		1			49
	$	247	$	264		$	289
Income Tax Expense (Benefit)
Electric	$	153	$	100		$	95
Gas		45		47			18
Other		—		(22	)		(22	)
	$	198	$	125		$	91
Net Income (Loss) Available to Common Stockholder
Electric	$	271	$	196		$	199
Gas		89		87			37
Other		2		27			(52	)
	$	362	$	310		$	184
Investments in Equity Method Investees
Electric	$	—	$	—		$	5
Total Assets
Electric(a)	$	8,904	$	8,492		$	8,516
Gas(a)		4,565		4,102			3,950
Other		777		807			379
	$	14,246	$	13,401		$	12,845
Capital Expenditures(b)
Electric	$	553	$	1,319		$	462
Gas		241		168			172
Other		—		—			19
	$	794	$	1,487		$	653

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

CE-78

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(b) Amounts include capital lease additions and a portion of our capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.

15: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)

	2008
Quarters Ended	March 31		June 30		Sept. 30		Dec. 31
	In Millions
Operating revenue	$	2,091	$	1,263	$	1,307	$	1,760
Operating income		250		139		199		178
Net income		130		60		91		83
Preferred stock dividends		1		—		1		—
Net income available to common stockholder		129		60		90		83

	2007
Quarters Ended	March 31		June 30		Sept. 30		Dec. 31
	In Millions
Operating revenue	$	2,055	$	1,247	$	1,172	$	1,590
Operating income		209		104		124		145
Net income		113		44		60		95
Preferred stock dividends		1		—		—		1
Net income available to common stockholder		112		44		60		94

CE-79

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder of Consumers Energy Company

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income (loss), of cash flows, and of common stockholder’s equity present fairly, in all material respects, the financial position of Consumers Energy Company and its subsidiaries at December 31, 2008 and December 31, 2007, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2008 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedules listed in the accompanying index present fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedules, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 9 to the consolidated financial statements, the Company changed the manner in which it accounts for uncertain income tax provisions in 2007.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 25, 2009

CE-80

Report of Independent Registered Public Accounting Firm

To the Partners and the Management Committee of

Midland Cogeneration Venture Limited Partnership:

In our opinion, the accompanying statements of operations and of cash flows present fairly, in all material respects, the results of operations and cash flows of Midland Cogeneration Venture Limited Partnership for the period ended November 21, 2006 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan

February 19, 2007

CE-81

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder of Consumers Energy Company

We have audited the accompanying consolidated statements of income, common stockholder’s equity, and cash flows of Consumers Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) for the year ended December 31, 2006. Our audit also included the financial statement schedule as it relates to 2006 listed in the Index at Item 15(a)(2). These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a former 49% owned variable interest entity which has been consolidated through the date of sale, November 21, 2006 (Note 3), which statements reflect total revenues constituting 9.5% in 2006 of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for the period indicated above for Midland Cogeneration Venture Limited Partnership, is based solely on the report of the other auditors.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated results of Consumers Energy Company’s operations and its cash flows for the year ended December 31, 2006, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 7 to the consolidated financial statements, in accordance with Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R),” the Company changed its method of accounting for the funded status of its defined benefit pension and other postretirement benefit plans in 2006.

/s/  Ernst & Young LLP

Detroit, Michigan

February 21, 2007

CE-82

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE

CMS Energy

None.

Consumers

None.

ITEM 9A. CMS ENERGY’S CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures: Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on such evaluation, CMS Energy’s CEO and CFO have concluded that its disclosure controls and procedures were effective as of December 31, 2008.

Management’s Annual Report on Internal Control Over Financial Reporting: CMS Energy’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). CMS Energy’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes policies and procedures that:

•  pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of CMS Energy;

•  provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of CMS Energy are being made only in accordance with authorizations of management and directors of CMS Energy; and

•  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of CMS Energy’s assets that could have a material effect on its financial statements.

Management, including its CEO and CFO, does not expect that its internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Under the supervision and with the participation of management, including its CEO and CFO, CMS Energy conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2008. In making this evaluation, management used the criteria set forth in the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, CMS Energy’s management concluded that its internal control over financial reporting was effective as of December 31, 2008. The effectiveness of CMS Energy’s internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8.

Changes in Internal Control over Financial Reporting: There have been no changes in CMS Energy’s internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

CO-1

ITEM 9A(T). CONSUMERS’ CONTROLS AND PROCEDURES

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures: Under the supervision and with the participation of management, including its CEO and CFO, Consumers conducted an evaluation of its disclosure controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on such evaluation, Consumers’ CEO and CFO have concluded that its disclosure controls and procedures were effective as of December 31, 2008.

Management’s Annual Report on Internal Control Over Financial Reporting:  Consumers’ management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Consumers’ internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP and includes policies and procedures that:

•  pertain to the maintenance of records that in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of Consumers;

•  provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of Consumers are being made only in accordance with authorizations of management and directors of Consumers; and

•  provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of Consumers’ assets that could have a material effect on its financial statements.

Management, including its CEO and CFO, does not expect that its internal controls will prevent or detect all errors and all fraud. A control system, no matter how well designed and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. In addition, any evaluation of the effectiveness of controls is subject to risks that those internal controls may become inadequate in future periods because of changes in business conditions, or that the degree of compliance with the policies or procedures deteriorates.

Under the supervision and with the participation of management, including its CEO and CFO, Consumers conducted an evaluation of the effectiveness of its internal control over financial reporting as of December 31, 2008. In making this evaluation, management used the criteria set forth in the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on such evaluation, Consumers’ management concluded that its internal control over financial reporting was effective as of December 31, 2008. The effectiveness of Consumers’ internal control over financial reporting as of December 31, 2008, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears under Item 8.

Changes in Internal Control over Financial Reporting: There have been no changes in Consumers’ internal control over financial reporting during the most recently completed fiscal quarter that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

CMS Energy

None.

Consumers

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

CMS Energy

Information that is required in Item 10 regarding directors, executive officers and corporate governance is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

CODE OF ETHICS

CMS Energy has adopted a code of ethics that applies to its CEO, CFO and Chief Accounting Officer (“CAO”), as well as all other officers and employees of CMS Energy and its affiliates, including Consumers. CMS Energy has also adopted a Directors Code of Conduct that applies to its directors. The code of ethics, included in CMS Energy’s Code of Conduct and Statement of Ethics Handbook, and the Directors Code of Conduct can be found on CMS Energy’s website at www.cmsenergy.com. CMS Energy’s Code of Conduct and Statement of Ethics, including the code of ethics, is administered by the Chief Compliance Officer of CMS Energy, who reports directly to the Audit Committee of CMS Energy’s Boards of Directors. The Directors Code of Conduct is administered by the Audit Committee of the Board. Any alleged violation of the Directors Code of Conduct by a director will be investigated by disinterested members of the Audit Committee of the Board, or if none, by disinterested members of the entire Board. Any amendment to, or waiver from, a provision of CMS Energy’s code of ethics that applies to CMS Energy’s CEO, CFO, CAO or persons performing similar functions will be disclosed on CMS Energy’s website at www.cmsenergy.com under “Compliance and Ethics.”

Consumers

Information that is required in Item 10 regarding Consumers’ directors, executive officers and corporate governance is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

CODE OF ETHICS

Consumers has adopted a code of ethics that applies to its CEO, CFO and Chief Accounting Officer (“CAO”), as well as all other officers and employees of Consumers and its affiliates. Consumers has also adopted a Directors Code of Conduct that applies to its directors. The code of ethics, included in Consumers’ Code of Conduct and Statement of Ethics Handbook, and the Directors Code of Conduct can be found on Consumers’ website at www.cmsenergy.com. Consumers’ Code of Conduct and Statement of Ethics, including the code of ethics, is administered by the Chief Compliance Officer of Consumers, who reports directly to the Audit Committee of Consumers’ board of directors. The Directors Code of Conduct is administered by the Audit Committee of Consumers’ board of directors. Any alleged violation of the Directors Code of Conduct by a director will be investigated by disinterested members of the Audit Committee of Consumers’ board of directors, or if none, by disinterested members of the entire board of directors. Any amendment to, or waiver from, a provision of Consumers’ code of ethics that applies to Consumers’ CEO, CFO, CAO or persons performing similar functions will be disclosed on Consumers’ website at www.consumersenergy.com under “Compliance and Ethics.”

ITEM 11. EXECUTIVE COMPENSATION

Information that is required in Item 11 regarding executive compensation of CMS Energy’s and Consumers’ executive officers is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS

CMS Energy

Information that is required in Item 12 regarding securities authorized for issuance under equity compensation plans and security ownership of certain beneficial owners and management is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

Consumers

Information that is required in Item 12 regarding securities authorized for issuance under equity compensation plans and security ownership of certain beneficial owners and management of Consumers is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
AND DIRECTOR INDEPENDENCE

CMS Energy

Information that is required in Item 13 regarding certain relationships and related transactions, and director independence is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

Consumers

Information that is required in Item 13 regarding certain relationships and related transactions, and director independence regarding Consumers is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

CMS Energy

Information that is required in Item 14 regarding principal accountant fees and services is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

Consumers

Information that is required in Item 14 regarding principal accountant fees and services relating to Consumers is included in CMS Energy’s definitive proxy statement, which is incorporated by reference herein.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1)	Financial Statements and Reports of Independent Public Accountants for CMS Energy and Consumers are included in each company’s ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA and are incorporated by reference herein.
(a)(2)	Index to Financial Statement Schedules.

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		Page
Schedule I	Condensed Financial Information of Registrant CMS Energy-Parent Company
	Condensed Statements of Income (Loss)	CO-12
	Statements of Cash Flows	CO-13
	Condensed Balance Sheets	CO-14
	Notes to Condensed Financial Statements	CO-16
Schedule II	Valuation and Qualifying Accounts and Reserves
	CMS Energy Corporation	CO-18
	Consumers Energy Company	CO-18
Report of Independent Registered Public Accounting Firm
	CMS Energy Corporation	CMS-99
	Consumers Energy Company	CE-80

Schedules other than those listed above are omitted because they are either not required, not applicable or the required information is shown in the financial statements or notes thereto. Columns omitted from schedules filed have been omitted because the information is not applicable.

(a)(3)	Exhibits for CMS Energy and Consumers are listed after Item 15(b) below and are incorporated by reference herein.
(b)	Exhibits, including those incorporated by reference.

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CMS ENERGY’S AND CONSUMERS’ EXHIBITS

The agreements included as exhibits to this Form 10-K filing are included to provide information regarding the terms of the agreements and are not intended to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by each of the parties to each of the agreements that were made exclusively for the benefit of the parties involved in each of the agreements and should not be treated as statements of fact. The representations and warranties were made as a way to allocate risk if one or more of those statements prove to be incorrect. The statements were qualified by disclosures to the parties to each of the agreements and may not be reflected in each of the agreements. The agreements may apply standards of materiality that are different than standards applied to other investors. Additionally, the statements were made as of the date of the agreements or as specified in the agreements and have not been updated.

The representations and warranties may not describe the actual state of affairs. Additional information about us may be found in this filing, at www.cmsenergy.com, and through the SEC’s website at http://www.sec.gov.

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(3)(a)	1-9513	(99)(a)	—	Restated Articles of Incorporation of CMS Energy, effective June 1, 2004 (Form 8-K filed June 3, 2004)
(3)(b)			—	CMS Energy Corporation Bylaws, amended and restated as of January 22, 2009
(3)(c)	1-5611	3(c)	—	Restated Articles of Incorporation of Consumers effective June 7, 2000 (2000 Form 10-K)
(3)(d)			—	Consumers Energy Company Bylaws, amended and restated as of January 22, 2009
(4)(a)	2-65973	(b)(1)-4	—	Indenture dated as of September 1, 1945, between Consumers and Chemical Bank (successor to Manufacturers Hanover Trust Company), as Trustee, including therein indentures supplemental thereto through the Forty-third Supplemental Indenture dated as of May 1, 1979 (Form S-16 filed November 13, 1979) Indentures Supplemental thereto:
	1-5611	(4)(a)	—	71st dated as of 3/06/98 (1997 Form 10-K)
	1-5611	(4)(d)	—	90th dated as of 4/30/03 (1st qtr. 2003 Form 10-Q)
	1-5611	(4)(a)	—	91st dated as of 5/23/03 (3rd qtr. 2003 Form 10-Q)
	1-5611	(4)(b)	—	92nd dated as of 8/26/03 (3rd qtr. 2003 Form 10-Q)
	1-5611	(4)(a)	—	96th dated as of 8/17/04 (Form 8-K filed August 20, 2004)
	333-120611	(4)(e)(xv)	—	97th dated as of 9/1/04 (Consumers Form S-3 dated November 18, 2004)
	1-5611	4.4	—	98th dated as of 12/13/04 (Form 8-K filed December 13, 2004)
	1-5611	(4)(a)(i)	—	99th dated as of 1/20/05 (2004 Form 10-K)
	1-5611	4.2	—	100th dated as of 3/24/05 (Form 8-K filed March 30, 2005)
	1-5611	4.2	—	102nd dated as of 4/13/05 (Form 8-K filed April 13, 2005)
	1-5611	4.2	—	104th dated as of 8/11/05 (Form 8-K filed August 11, 2005)
	1-5611	4(b)	—	105th dated as of 3/30/07 (2007 Form 10-K)
	1-5611	4(a)	—	106th dated as of 11/30/07 (2007 Form 10-K)
	1-5611	(4)(a)	—	107th dated as of 3/1/08 (1st qtr. 2008 Form 10-Q)
	1-5611	4.1	—	108th dated as of 3/14/08 (Form 8-K filed March 14, 2008)
	1-5611	4.1	—	109th dated as of 9/11/08 (Form 8-K filed September 16, 2008)
	1-5611	4.1	—	110th dated as of 9/12/08 (Form 8-K filed September 12, 2008)
(4)(b)	1-5611	(4)(b)	—	Indenture dated as of January 1, 1996 between Consumers and The Bank of New York Mellon, as Trustee (1995 Form 10-K)
(4)(c)	1-5611	(4)(c)	—	Indenture dated as of February 1, 1998 between Consumers and The Bank of New York Mellon (formerly The Chase Manhattan Bank), as Trustee (1997 Form 10-K)

CO-6

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(4)(d)	33-47629	(4)(a)*	—	Indenture dated as of September 15, 1992 between CMS Energy and NBD Bank, as Trustee (Form S-3 filed May 1, 1992) Indentures Supplemental thereto:
	333-58686	(4)(a)*	—	11th dated as of 3/29/01 (Form S-8 filed April 11, 2001)
	1-9513	(4)(d)(i)*	—	15th dated as of 9/29/04 (2004 Form 10-K)
	1-9513	(4)(d)(ii)*	—	16th dated as of 12/16/04 (2004 Form 10-K)
	1-9513	4.2*	—	17th dated as of 12/13/04 (Form 8-K filed December 13, 2004)
	1-9513	4.2*	—	18th dated as of 1/19/05 (Form 8-K filed January 20, 2005)
	1-9513	4.2*	—	19th dated as of 12/13/05 (Form 8-K filed December 15, 2005)
	1-9513	4.2*	—	20th dated as of 7/3/07 (Form 8-K filed July 5, 2007)
	1-9513	4.3*	—	21st dated as of 7/3/07 (Form 8-K filed July 5, 2007)
(4)(e)	1-9513	(4a)*	—	Indenture dated as of June 1, 1997, between CMS Energy and The Bank of New York Mellon, as trustee (Form 8-K filed July 1, 1997) Indentures Supplemental thereto:
	1-9513	(4)(b)*	—	1st dated as of 6/20/97 (Form 8-K filed July 1, 1997)
(4)(f)			—	Certificate of Designation of 4.50% Cumulative Convertible Preferred Stock dated as of December 20, 2004, corrected February 27, 2006
(10)(a)	1-9513	10.2*	—	$300 million Seventh Amended and Restated Credit Agreement dated as of April 2, 2007 among CMS Energy Corporation, the Banks, the Administrative Agent, Collateral Agent, Syndication Agent and Documentation Agents all defined therein (Form 8-K filed April 3, 2007) Amendments thereto:
	1-9513	10(a)*	—	Amendment No. 1 dated as of December 19, 2007 (2007 Form 10-K)
(10)(b)*			—	Amendment No. 2 dated as of January 23, 2009
				Assumptions thereto:
(10)(c)	1-9513	10.1*	—	Assumption and Acceptance dated January 8, 2008 (Form 8-K filed January 11, 2008)
(10)(d)	1-9513	10(b)*	—	Fourth Amended and Restated Pledge and Security Agreement dated as of April 2, 2007 among CMS Energy and Collateral Agent, as defined therein (2007 Form 10-K)
(10)(e)	1-9513	10(c)*	—	Amended and Restated Cash Collateral Agreement dated as of April 2, 2007, made by CMS Energy to the Administrative Agent for the lenders and Collateral Agent, as defined therein (2007 Form 10-K)
10)(f)	1-5611	10.1	—	$500 million Fourth Amended and Restated Credit Agreement dated as of March 30, 2007 among Consumers Energy Company, the Banks, the Administrative Agent, the Collateral Agent, the Syndication Agent and the Documentation Agents all as defined therein (Form 8-K filed April 3, 2007)
(10)(g)	1-9513	(10)(e)	—	2004 Form of Executive Severance Agreement (2007 Form 10-K)
(10)(h)	1-9513	(10)(f)	—	2004 Form of Officer Severance Agreement (2007 Form 10-K)
(10)(i)	1-9513	(10)(g)	—	2004 Form of Change-in-Control Agreement (2007 Form 10-K)
(10)(j)	1-9513	(10)(h)	—	CMS Energy’s Performance Incentive Stock Plan effective February 3, 1988, as amended June 1, 2004 and as further amended effective November 30, 2007 (2007 Form 10-K)
(10)(k)	1-9513	(10)(i)	—	CMS Deferred Salary Savings Plan effective December 1, 1989 and as further amended effective December 1, 2007 (2007 Form 10-K)
(10)(l)			—	Amendment to the Deferred Salary Savings Plan dated December 21, 2008

CO-7

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(10)(m)			—	Annual Officer Incentive Compensation Plan for CMS Energy Corporation and its Subsidiaries effective January 1, 2004, amended and restated effective as of January 1, 2008
(10)(n)			—	Amendment to the Officer’s Incentive Compensation Plan dated December 21, 2008
(10)(o)	1-9513	(10)(k)	—	Supplemental Executive Retirement Plan for Employees of CMS Energy/Consumers Energy Company effective January 1, 1982, as further amended December 1, 2007 (2007 Form 10-K)
(10)(p)			—	Amendment to the Defined Benefit Supplemental Executive Retirement Plan dated December 21, 2008
(10)(q)	1-9513	(10)(l)	—	Defined Contribution Supplemental Executive Retirement Plan effective April 1, 2006 and as further amended effective December 1, 2007 (2007 Form 10-K)
(10)(r)			—	Amendment to the Defined Contribution Supplemental Executive Retirement Plan dated December 21, 2008
(10)(s)			—	2009 Form of Change in Control Agreement
(10)(t)			—	2009 Form of Officer Separation Agreement
(10)(u)	1-9513	(10)(v)	—	Amended and Restated Investor Partner Tax Indemnification Agreement dated as of June 1, 1990 among Investor Partners, CMS Midland as Indemnitor and CMS Energy as Guarantor (1990 Form 10-K)
(10)(v)	1-9513	(10)(y)*	—	Environmental Agreement dated as of June 1, 1990 made by CMS Energy to The Connecticut National Bank and Others (1990 Form 10-K)
(10)(w)	1-5611	(10)(y)	—	Unwind Agreement dated as of December 10, 1991 by and among CMS Energy, Midland Group, Ltd., Consumers, CMS Midland, Inc., MEC Development Corp. and CMS Midland Holdings Company (1991 Form 10-K)
(10)(x)	1-5611	(10)(z)	—	Stipulated AGE Release Amount Payment Agreement dated as of June 1, 1990, among CMS Energy, Consumers and The Dow Chemical Company (1991 Form 10-K)
(10)(y)	1-5611	(10)(aa)*	—	Parent Guaranty dated as of June 14, 1990 from CMS Energy to MCV, each of the Owner Trustees, the Indenture Trustees, the Owner Participants and the Initial Purchasers of Senior Bonds in the MCV Sale Leaseback transaction, and MEC Development (1991 Form 10-K)
(10)(z)	1-8157	10.41	—	Contract for Firm Transportation of Natural Gas between Consumers Power Company and Trunkline Gas Company, dated November 1, 1989, and Amendment, dated November 1, 1989 (1989 Form 10-K of PanEnergy Corp.)
(10)(aa)	1-8157	10.41	—	Contract for Firm Transportation of Natural Gas between Consumers Power Company and Trunkline Gas Company, dated November 1, 1989 (1991 Form 10-K of PanEnergy Corp.)
(10)(bb)	1-2921	10.03	—	Contract for Firm Transportation of Natural Gas between Consumers Power Company and Trunkline Gas Company, dated September 1, 1993 (1993 Form 10-K)
(10)(cc)	1-5611	(10)(a)	—	Asset Sale Agreement dated as of July 11, 2006 by and among Consumers Energy Company as Seller and Entergy Nuclear Palisades, LLC as Buyer (2nd qtr. 2006 Form 10-Q)
(10)(dd)	1-5611	(10)(b)	—	Palisades Nuclear Power Plant Power Purchase Agreement dated as of July 11, 2006 between Entergy Nuclear Palisades, LLC and Consumers Energy Company (2nd qtr. 2006 Form 10-Q)

CO-8

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(10)(ee)	1-9513	99.2*	—	Letter of Intent dated January 31, 2007 between CMS Enterprises Company and Lucid Energy LLC (Form 8-K filed February 1, 2007)
(10)(ff)	1-9513	99.2*	—	Agreement of Purchase and Sale, by and between CMS Enterprises Company and Abu Dhabi National Energy Company PJSC dated as of February 3, 2007 (Form 8-K filed February 6, 2007)
(10)(gg)	1-9513	99.2*	—	Memorandum of Understanding dated February 13, 2007 between CMS Energy Corporation and Petroleos de Venezuela, S.A. (Form 8-K filed February 14, 2007)
(10)(hh)	1-9513	10.1*	—	Common Agreement dated March 12, 2007 between CMS Enterprises Company and Lucid Energy, LLC (Form 8-K filed March 14, 2007)
(10)(ii)	1-9513	10.2*	—	Agreement of Purchase and Sale dated March 12, 2007 by and among CMS Enterprises Company, CMS Energy Investment, LLC, and Lucid Energy, LLC and Michigan Pipeline and Processing, LLC (Form 8-K filed March 14, 2007)
(10)(jj)	1-9513	10.3*	—	Agreement of Purchase and Sale dated March 12, 2007 by and among CMS Enterprises Company, CMS Generation Holdings Company, CMS International Ventures, LLC, and Lucid Energy, LLC and New Argentine Generation Company, LLC (Form 8-K filed March 14, 2007)
(10)(kk)	1-9513	10.1*	—	Agreement of Purchase and Sale dated as of March 30, 2007 between CMS Energy Corporation and Petroleos de Venezuela, S.A. (Form 8-K filed April 5, 2007)
(10)(ll)	1-9513	10.1*	—	Share Purchase Agreement dated as of April 12, 2007 by and among CMS Electric and Gas, L.L.C., CMS Energy Brasil S.A. and CPFL Energia S.A. together with CMS Energy Corporation (solely for the limited purposes of Section 8.9) (Form 8-K filed April 17, 2007)
(10)(mm)	1-5611	99.2	—	Purchase and Sale Agreement by and between Broadway Gen Funding, LLC as Seller and Consumers Energy Company as Buyer dated as of May 24, 2007 (Form 8-K filed May 29, 2007)
(10)(nn)	1-9513	99.2*	—	Amended and Restated Securities Purchase Agreement by and among CMS International Ventures, L.L.C., CMS Capital L.L.C., CMS Gas Argentina Company and CMS Enterprises and AEI Chile Holdings LTD together with Ashmore Energy International (for purposes of the Parent Guarantee) dated as of June 1, 2007 (Form 8-K filed June 4, 2007)
(10)(oo)	1-9513	99.3*	—	Stock Purchase Agreement by and among Hydra-Co Enterprises, Inc., HCO-Jamaica, Inc., and AEI Central America LTD together with Ashmore Energy International dated as of May 31, 2007 (Form 8-K filed June 4, 2007)
(10)(pp)	1-9513	99.1*	—	Securities Purchase Agreement by and among CMS International Ventures, L.L.C., CMS Capital, L.L.C., CMS Gas Argentina Company and CMS Enterprises Company and Pacific Energy LLC together with Empresa Nacional De Electricdad S.A. (for purposes of the Parent Guarantee) dated as of July 11, 2007 (Form 8-K filed July 11, 2007)
(10)(qq)	1-9513	(10)(a)*	—	Form of Indemnification Agreement between CMS Energy Corporation and its Directors, effective as of November 1, 2007 (3rd qtr. 2007 Form 10-Q)

CO-9

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(10)(rr)	1-5611	(10)(b)	—	Form of Indemnification Agreement between Consumers Energy Company and its Directors, effective as of November 1, 2007 (3rd qtr. 2007 Form 10-Q)
(10)(ss)	1-5611	10.1	—	$200 million Letter of Credit Reimbursement Agreement dated as of November 30, 2007 between Consumers Energy Company and the Bank of Nova Scotia (Form 8-K filed December 6, 2007)
(10)(tt)			—	First Amendment to Reimbursement Agreement dated as of September 25, 2008
(10)(uu)	1-5611	10.1	—	$150 million Revolving Credit Agreement dated as of September 11, 2008 among Consumers Energy Company, the Banks, Agent and an LC Issuer, Co-Syndication Agents, and Documentation Agent all as defined therein (Form 8-K filed September 16, 2008)
(10)(vv)	1-5611	10(a)	—	Settlement Agreement and Amended and Restated Power Purchase Agreement between Consumers Energy Company and Midland Cogeneration Venture Limited Partnership (2nd qtr. 2008 Form 10-Q)
(10)(ww)			—	Receivables Purchase Agreement dated as of May 22, 2003 among Consumers Receivables Funding II, LLC, Consumers Energy Company, Falcon Asset Securitization Corporation, The Financial Institutions from time to time parties hereto, as Financial Institutions, and Bank One, NA, as Administrative Agent, as amended by Amendment No. 1 dated as of August 18, 2003, Amendment No. 2 dated, as of October 10, 2003, Amendment No. 3 dated as of May 20, 2004, Amendment No. 4 dated, as of September 28, 2004, Amendment No. 5 dated as of May 19, 2005, Amendment No. 6 dated as of September 8, 2005, Amendment No. 7 dated as of December 22, 2005, Amendment No. 8 dated as of March 13, 2006, Amendment No. 9 dated as of May 18, 2006, Amendment No. 10 dated as of August 15, 2006, Amendment No. 11 dated as of May 18, 2007, Amendment No. 12 dated as of August 14, 2007, Amendment No. 13 dated as of August 12, 2008, Amendment No. 14 dated as of November 5, 2008, and Amendment No. 15 dated as of February 12, 2009
(10)(xx)			—	Receivables Sale Agreement, dated as of May 22, 2003, between Consumers Energy Company, as Originator and Consumers Receivables Funding II, LLC, as Buyer, as amended by Amendment No. 1 dated as of May 20, 2004 and as amended by Amendment No. 2 dated as of August 15, 2006
(12)(a)			—	Statement regarding computation of CMS Energy’s Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends
(12)(b)			—	Statement regarding computation of Consumers’ Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends
(16)(a)	1-9513	16.1	—	Letter from Ernst & Young to the Securities and Exchange Commission dated January 25, 2007 (Form 8-K filed January 25, 2007)
(16)(b)	1-9513	16.1	—	Letter from Ernst & Young to the Securities and Exchange Commission dated February 28, 2007 (Form 8-K filed February 28, 2007)
(21)			—	Subsidiaries of CMS Energy and Consumers

CO-10

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(23)(a)			—	Consent of PricewaterhouseCoopers LLP for CMS Energy
(23)(b)			—	Consent of Ernst & Young LLP for CMS Energy
(23)(c)			—	Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV
(23)(d)			—	Consent of PricewaterhouseCoopers LLP for Consumers Energy
(23)(e)			—	Consent of Ernst & Young LLP for Consumers Energy
(23)(f)			—	Consent of PricewaterhouseCoopers LLP for Consumers Energy re: MCV
(24)(a)			—	Power of Attorney for CMS Energy
(24)(b)			—	Power of Attorney for Consumers
(31)(a)			—	CMS Energy’s certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31)(b)			—	CMS Energy’s certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31)(c)			—	Consumers’ certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(31)(d)			—	Consumers’ certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(32)(a)			—	CMS Energy’s certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(32)(b)			—	Consumers’ certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Obligations of only CMS Energy but not of Consumers.

Exhibits listed above that have heretofore been filed with the SEC pursuant to various acts administered by the Commission, and which were designated as noted above, are hereby incorporated herein by reference and made a part hereof with the same effect as if filed herewith.

CO-11

CMS ENERGY CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CMS Energy — Parent Company

Condensed Statements of Income (Loss)

Years Ended December 31	2008			2007			2006
	In Millions
Dividends from Consolidated Subsidiaries	$	1,247		$	251		$	147
Operating Expenses
Depreciation and amortization		(3	)		(3	)		(3	)
Gain on asset sales, net		—			81			—
Shareholder class action settlement		—			—			(125	)
Other operating income (deductions)		(5	)		(10	)		13
		(8	)		68			(115	)
Total Operating Income		1,239			319			32
Other Income (Deductions)
Equity in undistributed earnings of subsidiaries		(814	)		(393	)		(55	)
Interest income		1			3			—
Other deductions		(4	)		(24	)		(6	)
		(817	)		(414	)		(61	)
Fixed Charges
Interest on long-term debt		119			144			156
Interest on preferred securities		14			14			14
Intercompany interest expense and other		48			70			24
		181			228			194
Income (Loss) Before Income Taxes		241			(323	)		(223	)
Income Tax Benefit		(59	)		(138	)		(155	)
Income (Loss) From Continuing Operations		300			(185	)		(68	)
Loss From Discontinued Operations		—			(30	)		(11	)
Net Income (Loss)		300			(215	)		(79	)
Preferred Dividends		11			11			11
Redemption Premium on Preferred Stock		—			1			—
Net Income (Loss) Available to Common Stockholders	$	289		$	(227	)	$	(90	)

The accompanying condensed notes are an integral part of these statements

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CMS ENERGY CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CMS Energy — Parent Company

Statements of Cash Flows

Years Ended December 31	2008			2007			2006
	In Millions
Cash Flows From Operating Activities
Net income (loss)	$	300		$	(215	)	$	(79	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Loss (earnings) of equity method subsidiaries		(433	)		142			(92	)
Dividends received from subsidiaries		1,247			251			147
Depreciation and amortization		3			3			3
Gain on sale of assets		—			(81	)		—
Shareholder class action settlement expense		—			—			125
Decrease (increase) in accounts receivable		—			11			(2	)
Increase (decrease) in accounts payable		(2	)		(3	)		2
Shareholder class action settlement payment		—			(125	)		—
Change in other assets and liabilities		(60	)		(58	)		2
Net cash provided by (used in) operating activities		1,055			(75	)		106
Cash Flows From Investing Activities
Investment in subsidiaries		(22	)		(660	)		(216	)
Changes in notes receivable, net		—			42			(15	)
Net cash used in investing activities		(22	)		(618	)		(231	)
Cash Flows From Financing Activities
Proceeds from bank loans and notes		665			400			—
Proceeds from issuance of common stock		9			15			8
Retirement of bank loans and notes		(570	)		(958	)		(75	)
Redemption of preferred stock		(1	)		(1	)		—
Payment of common stock dividends		(82	)		(45	)		—
Payment of preferred stock dividends		(11	)		(11	)		(11	)
Debt issuance costs and financing fees		—			(1	)		(5	)
Changes in notes payable, net		(1,043	)		1,294			208
Net cash provided by (used in) financing activities		(1,033	)		693			125
Net Change in Cash and Temporary Cash Investments	$	—		$	—		$	—
Cash and Temporary Cash Investments, Beginning of Period	$	—		$	—		$	—
Cash and Temporary Cash Investments, End of Period	$	—		$	—		$	—

The accompanying condensed notes are an integral part of these statements

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CMS ENERGY CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CMS Energy — Parent Company

Condensed Balance Sheets

December 31	2008			2007
	In Millions
Assets
Property, Plant and Equipment, at cost	$	16		$	16
Less accumulated depreciation		(15	)		(12	)
		1			4
Investment in Subsidiaries		4,913			5,593
Current Assets
Cash and temporary cash investments		—			—
Notes and accrued interest receivable		1			1
Accrued taxes receivable		41			—
Accounts receivable, including intercompany and related parties		4			4
Deferred income taxes		5			61
		51			66
Non-current Assets
Deferred income taxes		348			320
Other investment — SERP		16			22
Other		40			81
		404			423
Total Assets	$	5,369		$	6,086

The accompanying condensed notes are an integral part of these statements

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CMS ENERGY CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CMS Energy — Parent Company

Condensed Balance Sheets

December 31	2008			2007
	In Millions
Stockholders’ Investment and Liabilities
Capitalization
Common stockholders’ equity	$	2,463		$	2,130
Nonredeemable preferred stock		243			250
Long-term debt
Senior Notes		1,808			1,564
Related Party		178			178
Unamortized Discount		(4	)		(5	)
		4,688			4,117
Current Liabilities
Current portion of long-term debt		—			150
Accounts and notes payable, including intercompany and related parties		615			1,660
Accrued interest, including intercompany		34			36
Accrued taxes		—			97
Other		11			5
		660			1,948
Non-Current Liabilities
Postretirement benefits		21			21
Total Stockholders’ Investment and Liabilities	$	5,369		$	6,086

The accompanying condensed notes are an integral part of these statements

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CMS ENERGY CORPORATION

SCHEDULE I — CONDENSED FINANCIAL INFORMATION OF REGISTRANT

CMS Energy — Parent Company

Notes to Condensed Financial Statements

1:  Summary of Significant Accounting Policies

Corporate Structure and Basis of Presentation: CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers Energy and Enterprises. The condensed financial statements of CMS Energy — Parent Company reflect the investments in wholly owned subsidiaries using the equity method of accounting.

Use of Estimates: CMS Energy is 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 condensed financial statements when it is probable that a loss will be incurred in the future as a result of a current event, and when an amount can be reasonably estimated.

2:  Contingencies

Securities Class Action Lawsuits: On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the “MOU”) dated December 28, 2006, subject to court approval, regarding settlement of the two class action lawsuits. The settlement was approved by a special committee of independent directors and by the full board of directors. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. Under the terms of the MOU, the litigation settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. On September 6, 2007, the court issued a final order approving the settlement. CMS Energy made a payment of approximately $123 million plus interest on the settlement balance on September 20, 2007. CMS Energy’s insurers paid approximately $77 million, the balance of the settlement amount, directly to the settlement account. In entering into the MOU, CMS Energy made no admission of liability under the two class action lawsuits.

3:  Financings

Long-term debt, including current maturities was $1.804 billion at December 31, 2008 and $1.559 billion at December 31, 2007. Long-term debt — related parties was $178 million at December 31, 2008 and December 31, 2007.

At December 31, 2008, the annual maturities for long-term debt and long-term debt — related parties for the next five years are:

	Payments Due
	2009		2010		2011		2012		2013
	(In Millions)
Long-term debt and long-term debt — related parties	$	—	$	300	$	300	$	255	$	150

Additional details on long-term debt, dividend restrictions and capitalization are included in Note 5, Financings and Capitalization to the Annual Report.

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4:  Related Party Transactions

Common Stock: Consumers Energy held 1.8 million shares of CMS Energy’s common stock at December 31, 2008 and December 31, 2007.

Cash Dividends Paid: Our consolidated subsidiaries, Consumers Energy and Enterprises paid the following common stock dividends to CMS Energy for the years ended December 31:

	2008		2007		2006
	(In Millions)
Dividends:
Consumers Energy	$	297	$	251	$	147
Enterprises		950		—		—
Total	$	1,247	$	251	$	147

5:  Guaranty

We have issued a guaranty on behalf of our wholly owned subsidiary, CMS ERM, to support its payment obligations to a third-party under certain commodity purchase or swap agreements. Our maximum potential obligation under the guaranty is $5 million, plus expenses.

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CMS ENERGY CORPORATION

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

	Balance at		Charged		Charged/Accrued				Balance
	Beginning		to		to other				at End
Description	of Period		Expense		Accounts		Deductions		of Period
	(In Millions)
Accumulated provision for uncollectible accounts:
2008	$	21	$	51	$	—	$	46	$	26
2007	$	25	$	37	$	7	$	34	$	21
2006	$	25	$	30	$	—	$	30	$	25
Deferred tax valuation allowance:
2008	$	32	$	—	$	7	$	7	$	32
2007	$	72	$	—	$	81	$	121	$	32
2006	$	10	$	31	$	42	$	11	$	72
Allowance for notes receivable, including related parties:
2008	$	33	$	—	$	1	$	—	$	34
2007	$	101	$	—	$	1	$	69	$	33
2006	$	49	$	55	$	1	$	4	$	101

CONSUMERS ENERGY COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

YEARS ENDED DECEMBER 31, 2008, 2007 AND 2006

	Balance at		Charged		Charged/Accrued				Balance
	Beginning		to		to other				at End
Description	of Period		Expense		Accounts		Deductions		of Period
	(In Millions)
Accumulated provision for uncollectible accounts:
2008	$	16	$	47	$	—	$	39	$	24
2007	$	14	$	33	$	—	$	31	$	16
2006	$	13	$	30	$	—	$	29	$	14
Deferred tax valuation allowance:
2008	$	—	$	—	$	—	$	—	$	—
2007	$	15	$	—	$	8	$	23	$	—
2006	$	—	$	16	$	—	$	1	$	15

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, CMS Energy Corporation has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of February 2009.

CMS ENERGY CORPORATION

By  /s/  David W. Joos

David W. Joos

President and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of CMS Energy Corporation and in the capacities indicated and on the 25th day of February 2009.

Signature		Title
(i)	Principal executive officer:
	/s/  David W. Joos David W. Joos	President and Chief Executive Officer
(ii)	Principal financial officer:
	/s/  Thomas J. Webb Thomas J. Webb	Executive Vice President and Chief Financial Officer
(iii)	Controller or principal accounting officer:
	/s/  Glenn P. Barba Glenn P. Barba	Vice President, Controller and Chief Accounting Officer
(iv)	A majority of the Directors:
	* Merribel S. Ayres	Director
	* Jon E. Barfield	Director
	* Richard M. Gabrys	Director
	* David W. Joos	Director
	* Philip R. Lochner, Jr.	Director
	* Michael T. Monahan	Director

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Signature		Title
	* Joseph F. Paquette, Jr.	Director
	* Percy A. Pierre	Director
	* Kenneth L. Way	Director
	* Kenneth Whipple	Director
	* John B. Yasinsky	Director
*By	/s/  Thomas J. Webb Thomas J. Webb, Attorney-in-Fact

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Consumers Energy Company has duly caused this Annual Report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 25th day of February 2009.

CONSUMERS ENERGY COMPANY

By  /s/  David W. Joos

David W. Joos

Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report has been signed below by the following persons on behalf of Consumers Energy Company and in the capacities indicated and on the 25th day of February 2009.

Signature		Title
(i)	Principal executive officer:
	/s/  David W. Joos David W. Joos	Chief Executive Officer
(ii)	Principal financial officer:
	/s/  Thomas J. Webb Thomas J. Webb	Executive Vice President and Chief Financial Officer
(iii)	Controller or principal accounting officer:
	/s/  Glenn P. Barba Glenn P. Barba	Vice President, Controller and Chief Accounting Officer
(iv)	A majority of the Directors:
	* Merribel S. Ayres	Director
	* Jon E. Barfield	Director
	* Richard M. Gabrys	Director
	* David W. Joos	Director
	* Philip R. Lochner, Jr.	Director
	* Michael T. Monahan	Director
	* Joseph F. Paquette, Jr.	Director

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Signature		Title
	* Percy A. Pierre	Director
	* Kenneth L. Way	Director
	* Kenneth Whipple	Director
	* John B. Yasinsky	Director
*By	/s/  Thomas J. Webb Thomas J. Webb, Attorney-in-Fact

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EXHIBITS

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CMS ENERGY’S AND CONSUMERS’ EXHIBIT INDEX

Exhibits			Description
	(3)(b)	—	CMS Energy Corporation Bylaws, amended and restated as of January 22, 2009
	(3)(d)	—	Consumers Energy Company Bylaws, amended and restated as of January 22, 2009
	(4)(f)	—	Certificate of Designation of 4.50% Cumulative Convertible Preferred Stock dated as of December 20, 2004, corrected February 27, 2006
	(10)(b)	—	Amendment No. 2 dated as of January 23, 2009 to $300 million CMS Energy Seventh Amended and Restated Credit Agreement
	(10)(l)	—	Amendment to the Deferred Salary Savings Plan dated December 21, 2008
	(10)(m)	—	Annual Officer Incentive Compensation Plan for CMS Energy Corporation and its Subsidiaries effective January 1, 2004, amended and restated effective as of January 1, 2008
	(10)(n)	—	Amendment to the Officer’s Incentive Compensation Plan dated December 21, 2008
	(10)(p)	—	Amendment to the Defined Benefit Supplemental Executive Retirement Plan dated December 21, 2008
	(10)(r)	—	Amendment to the Defined Contribution Supplemental Executive Retirement Plan dated December 21, 2008
	(10)(s)	—	2009 Form of Change in Control Agreement
	(10)(t)	—	2009 Form of Officer Separation Agreement
	(10)(tt)	—	First Amendment to Reimbursement Agreement dated as of September 25, 2008
	(10)(ww)	—	Receivables Purchase Agreement dated as of May 22, 2003 among Consumers Receivables Funding II, LLC, Consumers Energy Company, Falcon Asset Securitization Corporation, The Financial Institutions from time to time parties hereto, as Financial Institutions, and Bank One, NA, as Administrative Agent, as amended by Amendment No. 1 dated as of August 18, 2003, Amendment No. 2 dated, as of October 10, 2003, Amendment No. 3 dated as of May 20, 2004, Amendment No. 4 dated, as of September 28, 2004, Amendment No. 5 dated as of May 19, 2005, Amendment No. 6 dated as of September 8, 2005, Amendment No. 7 dated as of December 22, 2005, Amendment No. 8 dated as of March 13, 2006, Amendment No. 9 dated as of May 18, 2006, Amendment No. 10 dated as of August 15, 2006, Amendment No. 11 dated as of May 18, 2007, Amendment No. 12 dated as of August 14, 2007, Amendment No. 13 dated as of August 12, 2008, Amendment No. 14 dated as of November 5, 2008, and Amendment No. 15 dated as of February 12, 2009
	(10)(xx)	—	Receivables Sale Agreement, dated as of May 22, 2003, between Consumers Energy Company, as Originator and Consumers Receivables Funding II, LLC, as Buyer, as amended by Amendment No. 1 dated as of May 20, 2004 and as amended by Amendment No. 2 dated as of August 15, 2006
	(12)(a)	—	Statement regarding computation of CMS Energy’s Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends
	(12)(b)	—	Statement regarding computation of Consumers’ Ratio of Earnings to Fixed Charges and Combined Fixed Charges and Preferred Dividends
	(21)	—	Subsidiaries of CMS Energy and Consumers
	(23)(a)	—	Consent of PricewaterhouseCoopers LLP for CMS Energy
	(23)(b)	—	Consent of Ernst & Young LLP for CMS Energy
	(23)(c)	—	Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV
	(23)(d)	—	Consent of PricewaterhouseCoopers LLP for Consumers Energy
	(23)(e)	—	Consent of Ernst & Young LLP for Consumers Energy
	(23)(f)	—	Consent of PricewaterhouseCoopers LLP for Consumers Energy re: MCV
	(24)(a)	—	Power of Attorney for CMS Energy
	(24)(b)	—	Power of Attorney for Consumers
	(31)(a)	—	CMS Energy’s certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	(31)(b)	—	CMS Energy’s certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	(31)(c)	—	Consumers’ certification of the CEO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

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Exhibits			Description
	(31)(d)	—	Consumers’ certification of the CFO pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
	(32)(a)	—	CMS Energy’s certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	(32)(b)	—	Consumers’ certifications pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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