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, 2007

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
CMS Energy Trust I	7.75% Quarterly Income Preferred Securities	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.  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 Exchange Act Rule 12b-2).

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 $3.863 billion for the 224,583,688 CMS Energy Common Stock shares outstanding on June 30, 2007 based on the closing sale price of $17.20 for CMS Energy Common Stock, as reported by the New York Stock Exchange on such date.

There were 225,177,071 shares of CMS Energy Common Stock outstanding on February 19, 2008. On February 19, 2008, 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 2008 annual meeting of shareholders to be held May 16, 2008, is incorporated by reference in Part III, except for the compensation and human resources committee report and audit committee report contained therein.

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, 2007

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’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 nor any of CMS Energy’s 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	32
Item 3.	Legal Proceedings	32
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 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-5
Item 14.	Principal Accountant Fees and Services	CO-5
PART IV:
Item 15.	Exhibits, Financial Statement Schedules	CO-5

2

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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
ALJ	Administrative Law Judge
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”
APT	Australian Pipeline Trust
ARO	Asset retirement obligation
Bay Harbor	A residential/commercial real estate area located near Petoskey, Michigan. In 2002, CMS Energy sold its interest in Bay Harbor.
bcf	One billion cubic feet of gas
Big Rock	Big Rock Point nuclear power plant
Big Rock ISFSI	Big Rock Independent Spent Fuel Storage Installation
Board of Directors	Board of Directors of CMS Energy
Broadway Gen Funding LLC	Broadway Gen Funding LLC, a non-affiliated company
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
CAMR	Clean Air Mercury Rule
CEO	Chief Executive Officer
CFO	Chief Financial Officer
CFTC	Commodity Futures Trading Commission
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 CMS Energy
CMS Energy	CMS Energy Corporation, the parent of Consumers and Enterprises
CMS Energy Common Stock or common stock	Common stock of CMS Energy, par value $.01 per share
CMS Electric and Gas	CMS Electric & Gas Company, L.L.C., a subsidiary of Enterprises
CMS ERM	CMS Energy Resource Management Company, formerly CMS MST, a subsidiary of Enterprises
CMS Field Services	CMS Field Services, Inc., a former wholly owned subsidiary of CMS Gas Transmission
CMS Gas Transmission	CMS Gas Transmission Company, a wholly owned subsidiary of Enterprises
CMS Generation	CMS Generation Co., a former wholly owned subsidiary of Enterprises

4

CMS International Ventures	CMS International Ventures LLC, a subsidiary of Enterprises
CMS Land	CMS Land Company, a wholly owned subsidiary of CMS Energy
CMS Midland	Midland Cogeneration Venture Group II, LLC, successor to CMS Midland Inc., formerly a subsidiary of Consumers that had a 49 percent ownership interest in the MCV Partnership
CMS MST	CMS Marketing, Services and Trading Company, a wholly owned subsidiary of Enterprises, whose name was changed to CMS ERM effective January 2004
CMS Oil and Gas	CMS Oil and Gas Company, formerly a subsidiary of Enterprises
Consumers	Consumers Energy Company, a subsidiary of CMS Energy
Court of Appeals	Michigan Court of Appeals
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 enacted in June 2000
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
DTE Energy	DTE Energy Company, a non-affiliated company
EISP	Executive Incentive Separation Plan
EITF	Emerging Issues Task Force
EITF Issue 02-03	EITF Issue No. 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities”
EITF Issue 06-11	EITF Issue No. 06-11, “Accounting for Income Tax Benefits of Dividends on Share-Based Payment Awards”
El Chocon	A 1,200 MW hydro power plant located in Argentina, in which CMS Generation formerly held a 17.2 percent ownership interest
Entergy	Entergy Corporation, a non-affiliated company
Enterprises	CMS Enterprises Company, a subsidiary of CMS Energy
EPA	U.S. Environmental Protection Agency
EPS	Earnings per share
Exchange Act	Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FIN 14	FASB Interpretation No. 14, Reasonable Estimation of Amount of a Loss
FIN 46(R)	Revised FASB Interpretation No. 46, Consolidation of Variable Interest Entities
FIN 47	FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations
FIN 45	FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others

5

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 (ultimate successor to City Bank Farmers Trust Company), 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
FSP	FASB Staff Position
FSP FIN 39-1	FASB Staff Position on FASB Interpretation No. 39-1, Amendment of FASB Interpretation No. 39
GAAP	Generally Accepted Accounting Principles
GasAtacama	GasAtacama Holding Limited, a limited liability partnership that manages GasAtacama S.A., which includes an integrated natural gas pipeline and electric generating plant in Argentina and Chile and Atacama Finance Company, in which CMS International Ventures formerly owned a 50 percent interest
GCR	Gas cost recovery
Goldfields	A pipeline business in Australia, in which CMS Energy formerly held a 39.7 percent ownership interest
GVK	GVK Facility, a 250 MW gas fired power plant located in South Central India, in which CMS Generation formerly held a 33 percent interest
GWh	Gigawatt hour (a unit of energy equal to one million kilowatt hours)
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-fueled power plant in Morocco, in which CMS Generation formerly owned a 50 percent interest
Jubail	A 240 MW natural gas cogeneration power plant in Saudi Arabia, in which CMS Generation formerly owned a 25 percent interest
kilovolts	One 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)
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
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.
MCV Partnership	Midland Cogeneration Venture Limited Partnership

6

MCV PPA	The Power Purchase Agreement between Consumers and the MCV Partnership with a 35-year term commencing in March 1990, as amended, and as interpreted by the Settlement Agreement dated as of January 1, 1999 between the MCV Partnership and Consumers
MD&A	Management’s Discussion and Analysis
MDEQ	Michigan Department of Environmental Quality
MDL	Multidistrict Litigation
METC	Michigan Electric Transmission Company, LLC, a non-affiliated company owned by ITC Holdings Corporation and a member of MISO
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.
MMBtu	Million British Thermal Units
Moody’s	Moody’s Investors Service, 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)
Neyveli	CMS Generation Neyveli Ltd, a 250 MW lignite-fired power station located in India, in which CMS International Ventures formerly owned a 50 percent interest
NMC	Nuclear Management Company LLC, formed in 1999 by Northern States Power Company (now Xcel Energy Inc.), Alliant Energy, Wisconsin Electric Power Company, and Wisconsin Public Service Company to operate and manage nuclear generating facilities owned by the utilities
NREPA	Michigan Natural Resources and Environmental Protection Act
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 subsidiaries Trunkline, Pan Gas Storage, Panhandle Storage, and Panhandle Holdings, a former wholly owned subsidiary of CMS Gas Transmission
Parmelia	A business located in Australia comprised of a pipeline, processing facilities, and a gas storage facility, a former 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
Pension Plan	The trusteed, non-contributory, defined benefit pension plan of Panhandle, Consumers and CMS Energy
PowerSmith	A 124 MW natural gas power plant located in Oklahoma, in which CMS Generation formerly held a 6.25% limited partner ownership interest
PSCR	Power supply cost recovery
PUHCA	Public Utility Holding Company Act
PURPA	Public Utility Regulatory Policies Act of 1978
Quicksilver	Quicksilver Resources, Inc., a non-affiliated company

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RAKTL	Ronald A. Katz Technology Licensing L.P., a non-affiliated company
RCP	Resource Conservation Plan
Reserve Margin	The amount of unused available electric capacity at peak demand as a percentage of total electric capacity
ROA	Retail Open Access, which allows electric generation customers to choose alternative electric suppliers pursuant to the Customer Choice Act.
S&P	Standard & Poor’s Ratings Group, a division of The McGraw-Hill Companies, Inc.
SEC	U.S. Securities and Exchange Commission
Section 10d(4) Regulatory Asset	Regulatory asset as described in Section 10d(4) of the Customer Choice Act, as amended
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 subsidiary of CMS International Ventures
SERP	Supplemental Executive Retirement Plan
SFAS	Statement of Financial Accounting Standards
SFAS No. 5	SFAS No. 5, “Accounting for Contingencies”
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. 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. 143	SFAS No. 143, “Accounting for Asset Retirement Obligations”
SFAS No. 144	SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”
SFAS No. 157	SFAS No. 157, “Fair Value Measurement”
SFAS No. 158	SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R)”
SFAS No. 159	SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115”
SFAS No. 160	SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - an amendment of ARB No. 51”
Shuweihat	A power and desalination plant located in the United Arab Emirates, in which CMS Generation formerly owned a 20 percent interest
SLAP	Scudder Latin American Power Fund
SRLY	Separate Return Limitation Year

8

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
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
Taweelah	Al Taweelah A2, a power and desalination plant of Emirates CMS Power Company located in the United Arab Emirates, in which CMS Generation formerly held a 40 percent interest
TGN	A natural gas transportation and pipeline business located in Argentina, in which CMS Gas Transmission owns a 23.54 percent interest
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 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
TTT	Gas title transfer tracking fees and services
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
Zeeland	A 935 MW gas-fired power plant located in Zeeland, Michigan

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PART I

ITEM 1. BUSINESS

GENERAL

CMS Energy

CMS Energy was formed in Michigan in 1987 and is an energy holding company operating through subsidiaries in the United States, primarily in Michigan. Its two principal subsidiaries are Consumers and Enterprises. Consumers is a public utility 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 various subsidiaries and certain equity investments, is engaged primarily in domestic independent power production.

CMS Energy’s consolidated operating revenue was $6.464 billion in 2007, $6.126 billion in 2006, and $5.879 billion in 2005. 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 automotive, metal, chemical and food products industries as well as a diversified group of other industries. In 2007, 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 $6.064 billion in 2007, $5.721 billion in 2006, and $5.232 billion in 2005.

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 in 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 $3.443 billion in 2007, $3.302 billion in 2006, and $2.701 billion in 2005. Consumers’ electric utility operations include the generation, purchase, distribution and sale of electricity. At year-end 2007, Consumers was authorized to provide 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 5 percent of Consumers’ 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 such customers is not reasonably likely to have a material adverse effect on its financial condition.

Consumers’ electric utility operations are seasonal. The summer months typically increase the use of electric energy, primarily due to the use of air conditioners and other cooling equipment. In 2007, Consumers’ electric deliveries were 39 billion kWh, which included ROA deliveries of 1 billion kWh. In 2006, Consumers’ electric deliveries were 38 billion kWh, which included ROA deliveries of 1 billion kWh.

Consumers’ 2007 summer peak demand was 8,183 MW excluding ROA loads and 8,391 MW including ROA loads. For the 2006-07 winter period, Consumers’ peak demand was 5,985 MW excluding ROA loads and 6,178 MW including ROA loads. Alternative electric suppliers were providing generation services to ROA customers of 315 MW at December 31, 2007 and 300 MW at December 31, 2006. Consumers had an 11 percent Reserve Margin target for summer 2007. Consumers owns or controls capacity necessary to supply approximately 118 percent of projected firm peak load for summer 2008.

In 2007, through the Midwest Energy Market, long-term purchase contracts, options, spot market and other seasonal purchases, Consumers purchased up to 3,979 MW of net capacity from others, which amounted to 49 percent of Consumers’ total system requirements.

12

  Electric Utility Properties

Generation: At December 31, 2007, Consumers’ electric generating system consisted of the following:

		2007			2007 Net
		Summer Net			Generation
	Size 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			4,320
J H Campbell 3 — West Olive	1 Unit, 1980		765	(a)		3,540
D E Karn — Essexville	2 Units, 1959-1961		515			3,663
B C Cobb — Muskegon	2 Units, 1956-1957		312			2,151
J R Whiting — Erie	3 Units, 1952-1953		328			2,394
J C Weadock — Essexville	2 Units, 1955-1958		306			1,835
Total coal generation			2,841			17,903
Oil/Gas Generation
B C Cobb — Muskegon	3 Units, 1999-2000(b)		183			7
D E Karn — Essexville	2 Units, 1975-1977		1,276			215
Zeeland — Zeeland	1 Unit, 2002		—			—	(c)
Total oil/gas generation			1,459			222
Hydroelectric
Conventional Hydro Generation	13 Plants, 1906-1949		73			416
Ludington Pumped Storage	6 Units, 1973		955	(d)		(478	)(e)
Total hydroelectric			1,028			(62	)
Nuclear Generation
Palisades — South Haven	1 Unit, 1971		—			1,781	(f)
Gas/Oil Combustion Turbine
Various Plants	7 Plants, 1966-1971		345			19
Zeeland — Zeeland	2 Units, 2001		—			—	(c)
Total gas/Oil Combustion Turbine			345			19
Total owned generation			5,673			19,863
Purchased and Interchange Power
Capacity			3,627	(g)
Total			9,300

(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 Power Supply Cooperative, Inc.

(b)	Cobb 1-3 are retired coal-fired units that were converted to gas-fired. Units were placed back into service in the years indicated.
(c)	Zeeland was purchased on December 21, 2007. It consists of two simple cycle combustion turbines and a combined cycle plant consisting of two combustion turbines and one steam turbine. The plant was not used by Consumers during 2007.
(d)	Represents Consumers’ 51 percent share of the capacity of Ludington. Detroit Edison owns 49 percent.
(e)	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.
(f)	Palisades was sold in April 2007 and Consumers entered into a 15-year power purchase agreement for all of the capacity and energy produced by Palisades, up to the annual average capacity of 798 MW.

13

(g) Includes 1,240 MW of purchased contract capacity from the MCV Facility and 778 MW of purchased contract capacity from the Palisades plant.

Distribution: Consumers’ distribution system includes:

•  390 miles of high-voltage distribution radial lines operating at 120 kilovolts and above;

•  4,216 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;

•  55,656 miles of electric distribution overhead lines;

•  9,780 miles of underground distribution lines; and

•  substations having an aggregate transformer capacity of 23,143,920 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	2007			2006			2005			2004			2003
Coal		17,903			17,744			19,711			18,810			20,091
Nuclear		1,781			5,904			6,636			5,346			6,151
Oil		112			48			225			193			242
Gas		129			161			356			38			129
Hydro		416			485			387			445			335
Net pumped storage		(478	)		(426	)		(516	)		(538	)		(517	)
Total net generation		19,863			23,916			26,799			24,294			26,431

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

	Cost per Million Btu
Fuel Consumed	2007		2006		2005		2004		2003
Coal	$	2.04	$	2.09	$	1.78	$	1.43	$	1.33
Oil		8.21		8.68		5.98		4.68		3.92
Gas		10.29		8.92		9.76		10.07		7.62
Nuclear		0.42		0.24		0.34		0.33		0.34
All Fuels(a)		2.07		1.72		1.64		1.26		1.16

(a) Weighted average fuel costs.

Consumers has four generating plant sites that burn coal. In 2007, these plants produced a combined total of 17,903 million kWh of electricity, which represents 90 percent of Consumers’ 19,863 million kWh baseload supply, the capacity used to serve a constant level of customer demand. These plants burned 9.4 million tons of coal in 2007. On December 31, 2007, Consumers had on hand a 50-day supply of coal.

Consumers has entered into coal supply contracts with various suppliers and associated rail transportation contracts for its coal-fired 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 2010 and total an estimated $376 million. Its coal transportation contracts expire through 2009 and total an estimated $263 million. Long-term coal supply contracts have accounted for approximately 60 to 90 percent of Consumers’ annual coal requirements over the last 10 years. Consumers believes that it is within the historical 60 to 90 percent range.

At December 31, 2007, 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 2008 through 2030 total an

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estimated $21.025 billion. 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.

Consumers Gas Utility

  Gas Utility Operations

Consumers’ gas utility operating revenue was $2.621 billion in 2007, $2.374 billion in 2006, and $2.483 billion in 2005. Consumers’ gas utility operations purchase, transport, store, distribute and sell natural gas. Consumers is authorized to provide service in 46 of the 68 counties in Michigan’s Lower Peninsula. Principal cities served include Bay City, Flint, Jackson, Kalamazoo, Lansing, Pontiac and Saginaw, as well as the suburban Detroit area, where nearly 900,000 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 such 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 2007, deliveries of natural gas sold through Consumers’ pipeline and distribution network totaled 347 bcf.

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

•  26,404 miles of distribution mains;

•  1,669 miles of transmission lines;

•  7 compressor stations with a total of 162,000 installed horsepower; and

•  15 gas storage fields with an aggregate storage capacity of 308 bcf and a working storage capacity of 143 bcf.

Gas Supply: In 2007, Consumers purchased 67 percent of the gas it delivered from United States producers and 25 percent from Canadian producers. Authorized suppliers in the gas customer choice program supplied the remaining 8 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 ninety percent of Consumers’ total gas supply requirements. As of December 31, 2007, 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		290,000		October	2008
Trunkline Gas Company (starting 11/01/08)		240,000		October	2012
Panhandle Eastern Pipe Line Company		50,000		October	2008
Panhandle Eastern Pipe Line Company (starting 4/01/08)		50,000		October	2008
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 11/01/08)		50,000		October	2013
Panhandle Eastern Pipe Line Company (starting 4/01/13)		50,000		October	2013
Vector Pipeline		50,000		March	2012

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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 such 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.

Enterprises

Enterprises, through various subsidiaries and certain equity investments, is engaged primarily in domestic independent power production. Enterprises’ operating revenue included in Continuing Operations in our consolidated financial statements was $383 million in 2007, $438 million in 2006, and $693 million in 2005. Operating revenue included in Discontinued Operations in our consolidated financial statements was $235 million in 2007, $684 million in 2006, and $409 million in 2005.

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.

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. The independent power production business segment’s operating revenue included in Continuing Operations in our consolidated financial statements was $41 million in 2007, $103 million in 2006, and $104 million in 2005. Operating revenue included in Discontinued Operations in our consolidated financial statements was $124 million in 2007, $437 million in 2006, and $211 million in 2005. 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 2. ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES — ASSET SALES.

Independent Power Production Properties: At December 31, 2007, 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, 2007:

						Percentage of
						Gross Capacity
						Under Long-Term
		Ownership Interest		Gross Capacity		Contract
Location	Fuel Type	(%)		(MW)		(%)
California	Wood		37.8		36		100
Connecticut	Scrap tire		100		31		0
Michigan	Coal		50		70		100
Michigan	Natural gas		100		710		61
Michigan	Natural gas		100		224		0
Michigan	Wood		50		40		100
Michigan	Wood		50		38		100
North Carolina	Wood		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.

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Natural Gas Transmission

CMS Gas Transmission was formed in 1988 and owned, developed and managed domestic and international natural gas facilities. CMS Gas Transmission’s operating revenue included in Continuing Operations in our consolidated financial statements was less than $1 million in 2007, $1 million in 2006, and less than $1 million in 2005. Operating revenue included in Discontinued Operations in our consolidated financial statements was $3 million in 2007, $17 million in 2006, and $18 million in 2005.

In 2003, CMS Gas Transmission sold Panhandle to Southern Union Panhandle Corp. Also in 2003, CMS Gas Transmission sold CMS Field Services to Cantera Natural Gas, Inc. In 2004, CMS Gas Transmission sold its interest in Goldfields and its Parmelia business to APT.

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. For more information on these asset sales, see ITEM 8. CMS ENERGY’S FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — NOTE 2. ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES — ASSET SALES.

Natural Gas Transmission Properties: At December 31, 2007, CMS Gas Transmission had a 23.5 percent ownership interest in 3,362 miles of pipelines in Argentina which remain subject to a potential sale to the government of Argentina or other form of disposition.

Energy Resource Management

In 2004, CMS ERM changed its name from CMS Marketing, Services and Trading Company to CMS Energy Resource Management Company. Also, in 2004, CMS ERM discontinued its natural gas retail program as customer contracts expired.

CMS ERM purchases and sells energy commodities in support of CMS Energy’s generating facilities. In 2007, CMS ERM marketed approximately 38 bcf of natural gas and 2,687 GWh of electricity. Its operating revenue was $342 million in 2007, $334 million in 2006, and $589 million in 2005.

International Energy Distribution

The international energy distribution business segment’s operating revenue, all of which was reflected in Discontinued Operations in our consolidated financial statements, was $108 million in 2007, $230 million in 2006, and $180 million in 2005. 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 2. ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES — ASSET SALES.

CMS ENERGY AND CONSUMERS REGULATION

CMS Energy is a public utility holding company that was previously exempt from registration under the PUHCA of 1935. The PUHCA of 1935 was repealed and replaced by the Energy Policy Act of 2005, effective February 8, 2006. 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 intervene in MPSC proceedings concerning Consumers and appeal most significant MPSC orders. Certain appeals of the MPSC orders are pending in the Court of Appeals.

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Rate Proceedings: In 2005, the MPSC issued an order that established the electric authorized rate of return on common equity at 11.15 percent. During 2007, we filed an electric rate case with the MPSC requesting an 11.25 percent authorized rate of return, which is still pending. In August 2007, the MPSC approved a partial settlement agreement for our 2007 gas rate case, which established the gas authorized rate of return on common equity at 10.75 percent. This proceeding is still pending with the MPSC. In February 2008, we filed a gas rate case with the MPSC requesting an 11 percent authorized rate of return.

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 3 OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) — CONSUMERS’ ELECRIC UTILITY RATE MATTERS and CONSUMERS’ GAS UTILITY RATE MATTERS and ITEM 8. CONSUMERS’ FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 3 OF CONSUMERS’ NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) — ELECTRIC RATE MATTERS and GAS RATE MATTERS.

MPSC Regulation and Michigan Legislation: Effective January 2002, the Customer Choice Act provided that all electric customers have the choice to buy generation service from an alternative electric supplier. The Customer Choice Act also imposed rate reductions, rate freezes and rate caps, which expired at the end of 2005. The Michigan legislature introduced several bills in December 2007 that would significantly reform the Customer Choice Act. For additional information regarding the Customer Choice Act, see ITEM 7. CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC UTILITY BUSINESS UNCERTAINTIES — ELECTRIC ROA and ITEM 7. CONSUMERS’ MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC BUSINESS UNCERTAINTIES — ELECTRIC ROA.

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 that began in April 2003, 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 in which Enterprises has ownership interests, as well as over CMS ERM and DIG. Among other things, FERC has jurisdiction over acquisitions, operation and disposal of certain assets and facilities, services provided and rates charged, and limited jurisdiction over other holding company matters with respect to CMS Energy. 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 FERC accounting rules, wholesale rates, operation of licensed hydro-electric generating plants, transfers of certain facilities, and corporate mergers and issuance of securities.

The Energy Policy Act of 2005 modified the FERC’s responsibilities, which affects both Consumers and Enterprises. The new law repeals the PUHCA of 1935, streamlines electric transmission siting rules, promotes wholesale competition and investment, and requires mandatory electric supply reliability planning. In addition, the 2005 Act gave the FERC the authority to require a wide range of activities to improve the bulk power system’s reliability. During 2007, more than ninety new regulations in this area went into effect.

The FERC is currently in the process of establishing standards for ensuring a more reliable system of providing electricity throughout North America through increased regulation of generation owners and operators, load serving entities, and others.

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.

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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.

CMS Energy has a recorded a significant liability for its obligations associated with Bay Harbor. For additional information, see ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTE 3 (CONTINGENCIES) OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS and ITEM 1A. RISK FACTORS.

Consumers has installed and is currently installing modern emission controls at its electric generating plants and has converted and is converting electric generating units to burn cleaner fuels. Consumers expects that the cost of future environmental compliance, especially compliance with clean air laws, will be significant because of EPA regulations and proposed regulations regarding nitrogen oxide, particulate-related emissions, and mercury. Consumers will spend $835 million through 2015 to comply with the Clean Air Interstate Rule and will spend $480 million through 2015 to comply with the State of Michigan’s proposed mercury plan.

Consumers completed the closure of an ash landfill at one plant in 2007 and is awaiting MDEQ certification of that closure. Consumers is also in the process of closing some older areas at an ash landfill at another plant. 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 significantly reduce 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 such 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 announced its intention to develop new nationwide standards for ash disposal areas. Consumers intends to work through industry groups to help ensure that any such regulations require only the minimum cost necessary to adhere to standards that are consistent with protection of the environment.

Consumers’ electric generating plants must comply with rules that significantly reduce the number of fish killed by plant cooling water intake systems. Consumers is studying options to determine the most cost-effective solutions for compliance.

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 the Ludington Pumped Storage facility. Consumers removed and replaced part of the PCB material with non-PCB material. Consumers has proposed a plan to the EPA to deal with the remaining materials and is waiting for a response from the EPA.

Certain environmental regulations affecting CMS Energy and Consumers include, but are not limited to, the Clean Air Act Amendments of 1990 and Superfund. Superfund can require any individual or entity that may have owned or operated a disposal site, as well as transporters or generators of hazardous substances that were sent to such a site, to share in remediation costs for the site.

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.

For additional information concerning environmental matters, including estimated capital expenditures to reduce nitrogen oxide related emissions, see ITEM 7. CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC UTILITY BUSINESS UNCERTAINTIES — ELECTRIC ENVIRONMENTAL ESTIMATES and ITEM 7. CONSUMERS’ MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC BUSINESS UNCERTAINTIES — ELECTRIC ENVIRONMENTAL ESTIMATES.

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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.

Michigan’s Customer Choice Act gives all electric customers the right to buy generation service from an alternative electric supplier. In January 2006, the MPSC approved cost-based ROA distribution tariffs. A significant decrease in retail electric competition occurred in 2005 due to changes in market conditions, including increased uncertainty and volatility in fuel commodity prices. Energy market volatility continued into 2006. At December 31, 2007, alternative electric suppliers were providing 315 MW of generation service to ROA customers. This amount represents an increase of 5 percent compared to December 31, 2006, and is 4 percent of Consumers’ total distribution load. It is difficult to predict future ROA customer trends.

In addition to retail electric customer choice, Consumers 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 MPSC and 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. 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 at lower prices on the wholesale market.

For additional information concerning electric competition, see ITEM 7. CMS ENERGY’S MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC UTILITY BUSINESS UNCERTAINTIES and ITEM 7. CONSUMERS’ MANAGEMENT’S DISCUSSION AND ANALYSIS — OUTLOOK — ELECTRIC BUSINESS UNCERTAINTIES.

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, 2007, CMS Energy and its wholly owned subsidiaries, including Consumers, had 7,898 full-time equivalent employees. Included in the total are 3,475 employees who are covered by union contracts.

Consumers

At December 31, 2007, Consumers and its subsidiaries had 7,614 full-time equivalent employees. Included in the total are 3,147 full-time operating, maintenance and construction employees and 322 full-time and part-time call center employees who are represented by the Utility Workers Union of America.

CMS ENERGY EXECUTIVE OFFICERS (as of February 1, 2008)

Name	Age	Position	Period
David W. Joos	54	President and CEO of CMS Energy	2004-Present
		CEO of Consumers	2004-Present
		Chairman of the Board, CEO of Enterprises	2003-Present
		President, Chief Operating Officer of CMS Energy	2001-2004
		President, Chief Operating Officer of Consumers	2001-2004
		President, Chief Operating Officer of Enterprises	2001-2003
		Director of CMS Energy	2001-Present
		Director of Consumers	2001-Present
		Director of Enterprises	2000-Present
Thomas J. Webb	55	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
		Executive Vice President, CFO of CMS Generation	2006-5/2007
		Director of Enterprises	2002-Present
		Director of CMS Generation	2003-5/2007
James E. Brunner*	55	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
		Senior Vice President of Enterprises	2006-11/2007
		Senior Vice President of CMS Generation	2006-5/2007
		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	2004
		Director of Enterprises	2006-Present

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Name	Age	Position	Period
John M. Butler **	43	Senior Vice President of CMS Energy	2006-Present
		Senior Vice President of Consumers	2006-Present
		Senior Vice President of Enterprises	2006-Present
		Senior Vice President of CMS Generation	2006-5/2007
David G. Mengebier	50	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
Thomas W. Elward	59	President, Chief Operating Officer of Enterprises	2003-Present
		President, CEO of CMS Generation	2002-5/2007
		Senior Vice President of Enterprises	2002-2003
		Director of Enterprises	2003-Present
		Director of CMS Generation	2002-5/2007
John G. Russell	50	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	42	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
		Vice President and Controller of Consumers	2002-2003

*	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 16, 2008).

CONSUMERS EXECUTIVE OFFICERS (as of February 1, 2008)

Name	Age	Position	Period
David W. Joos	54	President and CEO of CMS Energy	2004-Present
		CEO of Consumers	2004-Present
		Chairman of the Board, CEO of Enterprises	2003-Present
		President, Chief Operating Officer of CMS Energy	2001-2004
		President, Chief Operating Officer of Consumers	2001-2004
		President, Chief Operating Officer of Enterprises	2001-2003
		Director of CMS Energy	2001-Present
		Director of Consumers	2001-Present
		Director of Enterprises	2000-Present

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Name	Age	Position	Period
Thomas J. Webb	55	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
		Executive Vice President, CFO of CMS Generation	2006-5/2007
		Director of Enterprises	2002-Present
		Director of CMS Generation	2003-5/2007
James E. Brunner*	55	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
		Senior Vice President of Enterprises	2006-11/2007
		Senior Vice President of CMS Generation	2006-5/2007
		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	2004
		Director of Enterprises	2006-Present
John M. Butler **	43	Senior Vice President of CMS Energy	2006-Present
		Senior Vice President of Consumers	2006-Present
		Senior Vice President of Enterprises	2006-Present
		Senior Vice President of CMS Generation	2006-5/2007
David G. Mengebier	50	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	50	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	59	Senior Vice President of Consumers	2005-Present
		Vice President of Consumers	1999-2005
Frank Johnson	59	Senior Vice President of Consumers	2001-Present
Paul N. Preketes	58	Senior Vice President of Consumers	1999-Present

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Name	Age	Position	Period
Glenn P. Barba	42	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
		Vice President and Controller of Consumers	2002-2003

*	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.

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 16, 2008).

AVAILABLE INFORMATION

CMS Energy’s internet address is www.cmsenergy.com. 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. Such 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 consolidated Consumers could differ materially from historical results and the forward-looking statements contained in this report. Factors that might cause or contribute to such 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 carefully considered before making an investment in securities of CMS Energy and Consumers. Risk factors of Consumers are also risk factors for CMS Energy.

Risks Related to 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 obligations. Restrictions contained in Consumers’ preferred stock provisions and other legal restrictions, such as certain terms in its articles of incorporation, limit Consumers’ ability to pay dividends or acquire its own stock from CMS Energy. At December 31, 2007, Consumers had $269 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, 2007, CMS Energy had $1.891 billion aggregate principal amount of indebtedness, including $178 million of subordinated indebtedness relating to its convertible preferred securities. $4.374 billion of subsidiary debt is not included in the preceding total. In April 2007, CMS Energy entered into the Seventh Amended and Restated Credit Agreement providing revolving credit and commitments in the amount of $300 million, which was increased to $550 million in January 2008. As of December 31, 2007, there were $278 million of letters of credit outstanding under the Seventh Amended and Restated 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; and

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

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 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 or other litigation in which substantial monetary claims are involved.

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 September 2004, the MDEQ issued a notice of noncompliance after finding high-pH leachate in Lake Michigan adjacent to the property. The MDEQ also alleged higher than acceptable levels of heavy metals, including mercury, in the leachate flow.

In 2005, the EPA along with CMS Land and CMS Capital executed an AOC and approved a Removal Action Work Plan to address problems at Bay Harbor. Among other things, the plan called for the installation of collection trenches to capture high-pH leachate flow to the lake. Collection systems required under the plan have been installed and shoreline monitoring is ongoing. CMS Land and CMS Capital are required to address observed exceedances in pH, including required enhancements of the collection system. In May 2006, the EPA approved a pilot carbon dioxide enhancement plan to improve pH results in a specific area of the collection system. The enhanced system was installed in June 2006. CMS Land and CMS Capital also engaged in other enhancements of the installed collection systems.

In November 2007, the EPA sent CMS Land and CMS Capital a letter identifying three separate areas representing approximately 700 feet of shoreline in which the EPA claimed pH levels were unacceptable. The letter also took the position that CMS Land and CMS Capital are required to remedy the claimed noncompliance. CMS Land and CMS Capital submitted a formal objection to the EPA’s conclusions. In their objections, CMS Land and CMS Capital noted that the AOC did not require perfection and that over 97 percent of the measured pH levels were in the correct range. Further, the limited number of exceedances were not much above the pH nine level set by the AOC and posed no threat to the public health and safety. In addition, CMS Land and CMS Capital noted in their objection that the actions they had already taken fully complied with the terms of the AOC. In January 2008, the EPA advised CMS Land and CMS Capital that it had rejected their objections, and that CMS Land and CMS Capital were obligated to submit a plan to augment measures to collect high pH leachate under the terms of the November 2007 EPA letter as modified in the January 2008 letter. CMS Land and CMS Capital submitted a proposed augmentation plan in February 2008.

In February 2006, CMS Land and CMS Capital submitted to the EPA a proposed Remedial Investigation and Feasibility Study (RIFS) for one of the CKD piles known as the East Park CKD pile. A similar RIFS is planned to be submitted for the remaining CKD piles in 2008. The EPA approved a schedule for near-term activities, which includes consolidating certain CKD materials and installing collection trenches in the East Park leachate release area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan and Final Engineering Design for Consolidation. However, the EPA has not approved the RIFS for the East Park.

As a result of the installation of collection systems at the Bay Harbor sites, CMS Land and CMS Capital are collecting and treating 135,000 gallons of liquid per day and shipping it by truck for disposal at a nearby well and at a municipal wastewater treatment plant located in Traverse City, Michigan. To address both short term and longer-term disposal of liquid, CMS Land has filed two permit applications with the MDEQ and the EPA, the first to treat the collected leachate at the Bay Harbor sites before releasing the water to Lake Michigan and the second to dispose of it in a deep injection well in Alba, Michigan, that CMS Land or its affiliate would own and operate. In February 2008, the MDEQ and the EPA granted permits for CMS Land or its affiliate to construct and operate a deep injection well near Alba, Michigan in eastern Antrim County. Certain environmental groups and a local township have indicated they may challenge these permits before the agencies or the courts.

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CMS Land and CMS Capital, the MDEQ, and the EPA have ongoing discussions concerning the long-term remedy for the Bay Harbor sites. These negotiations are addressing, among other things, issues relating to the disposal of leachate, 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 CMS Land and CMS Capital may be obliged to undertake. Negotiations have been ongoing for over a year, but CMS Land and CMS Capital have not been able to resolve these issues with the regulators and they remain pending.

CMS Land has entered into various access, purchase and settlement agreements with several of the affected landowners at Bay Harbor, and entered into a confidential settlement with one landowner to resolve a lawsuit filed by that landowner. We have received demands for indemnification relating to claims made by a property owner at Bay Harbor. CMS Land has purchased five unimproved lots and two lots with houses.

CMS Energy has recorded a cumulative charge of $140 million, which includes accretion expense, for its obligations. An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy’s financial condition and liquidity and could negatively impact CMS Energy’s results of operations. CMS Energy cannot predict the financial impact or outcome of this matter.

CMS Energy retains contingent liabilities in connection with its asset sales.

The agreements CMS Energy enters into for the sale of assets customarily include provisions whereby it is required to:

•  retain specified preexisting liabilities such as for taxes, pensions, or environmental conditions;

•  indemnify the buyers against specified risks, including the inaccuracy of representations and warranties it makes; and

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

Many of these contingent liabilities can remain open for extended periods of time after the sales are closed. Depending on the extent to which the buyers may ultimately seek to enforce their rights under these contractual provisions, and the resolution of any disputes CMS Energy may have concerning them, these liabilities could have a material adverse effect on its financial condition, liquidity and future results of operations.

Risks Related to CMS Energy and Consumers

CMS Energy and Consumers have financing needs and they may be unable to obtain bank financing or access the capital markets.

CMS Energy and Consumers may be subject to liquidity demands pursuant to commercial commitments under guarantees, indemnities and letters of credit.

CMS Energy continues to explore financing opportunities to supplement its financial plan. These potential opportunities include: entering into leasing arrangements and refinancing and/or issuing new capital markets debt, preferred stock and/or common equity. 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 upon its financial condition, liquidity or results of operations. Similarly, Consumers currently plans to seek funds through the capital markets and commercial lenders. 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 upon its liquidity and operations.

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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 may have to post collateral or make prepayments to certain of its suppliers pursuant to existing contracts with them. In addition, certain bonds of Consumers are supported by municipal bond insurance policies, and the interest rates on those bonds have been affected by ratings downgrades of bond insurers. 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.

Regulatory changes and other developments have resulted and could continue to result in increased competition in the domestic energy business. Generally, increased competition threatens market share in certain segments of CMS Energy’s business and can reduce its and Consumers’ profitability.

As of January 1, 2002, the Customer Choice Act allows all electric customers in Michigan the choice of buying electric generation service from Consumers or an alternative electric supplier. Consumers had experienced, and could experience in the future, a significant increase in competition for generation services due to ROA. At December 31, 2007, alternative electric suppliers were providing 315 MW of generation service to ROA customers. This amount represents 4 percent of Consumers’ total distribution load, which is down from a high of 12 percent in 2004. Consumers cannot predict the total amount of electric supply load that may be lost to competitor suppliers in the future.

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 adversely affect CMS Energy’s and Consumers’ business, financial condition and profitability.

There are multiple proceedings pending before the FERC involving transmission rates, regional transmission organizations and electric bulk power markets and transmission. FERC is also reviewing the standards under which electric utilities are allowed to participate in wholesale power markets without price restrictions. CMS Energy and Consumers cannot predict the impact of these electric industry restructuring proceedings on their financial condition, liquidity or results of operations.

CMS Energy and Consumers could incur significant capital expenditures 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.

In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. Consumers plans to meet the nitrogen oxides requirements by installing equipment that reduces nitrogen oxides emissions and purchasing emissions allowances. Consumers also will meet the sulfur dioxide requirements by injecting a chemical that reduces sulfur dioxide emissions, installing scrubbers and purchasing emission allowances. Consumers plans to spend an additional $835 million for equipment installation through 2015.

In March 2005, the EPA issued the CAMR, which requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010 and further reductions by 2018. Certain portions of the CAMR were appealed to the U.S. Court of Appeals for the District of Columbia by a number of states and other entities. The U.S. Court of Appeals for the District of Columbia decided the case on February 8, 2008, and determined that the

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rules developed by the EPA were not consistent with the Clean Air Act. CMS Energy and Consumers continue to monitor the development of federal regulations in this area.

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ on the details of this plan; however, we have developed preliminary cost estimates and a mercury emissions reduction scenario based on our best knowledge of control technology options and initially proposed requirements. We estimate that costs associated with Phase I of the state’s mercury plan will be approximately $220 million by 2010 and an additional $200 million by 2015.

The EPA has alleged that some utilities have incorrectly classified plant modifications as “routine maintenance” rather than seeking permits from the EPA to modify their plants. 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 “routine maintenance.” If the EPA finds that its interpretation is incorrect, Consumers could be required to install additional pollution controls at some or all of its coal-fired electric generating plants and pay fines. Additionally, Consumers would need to assess the viability of continuing operations at certain plants.

Several legislative proposals have been introduced in the United States Congress that would require reductions in emissions of greenhouse gases, including carbon dioxide. These laws, or similar state laws or rules, if enacted, could require Consumers to replace equipment, install additional equipment for pollution controls, purchase allowances, curtail operations, or take other steps.

CMS Energy and Consumers expect to collect fully from its customers, through the ratemaking process, these and other required environmental expenditures. However, if these expenditures are not recovered from customers in Consumers’ rates, CMS Energy and/or Consumers may be required to seek significant additional financing to fund these expenditures, which could strain their cash resources. We can give no assurances that CMS Energy and/or Consumers will have access to bank financing or capital markets to fund any such 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 pension and postretirement benefit plans. CMS Energy has significant obligations in this area and holds significant assets in these trusts. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below CMS Energy’s forecasted return rates. A decline in the market value of the assets may increase the funding requirements of these obligations. Also, changes in demographics, including increased number of retirements or changes in life expectancy assumptions may also increase the funding requirements of the obligations related to the pension and postretirement benefit plans. If CMS Energy is unable to successfully manage its pension and postretirement plan assets, its results of operations and financial position could be affected negatively.

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, they 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 and Consumers may be adversely affected by regulatory investigations regarding “round-trip” trading by CMS MST as well as civil lawsuits regarding pricing information that CMS MST and CMS Field Services provided to market publications.

As a result of round-trip trading transactions (simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price) at CMS MST, CMS Energy is under

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investigation by the DOJ. CMS Energy received subpoenas in 2002 and 2003 from U.S. Attorneys’ Offices regarding investigations of those trades. CMS Energy responded to those subpoenas in 2003 and 2004.

In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy relating to round-trip trading. The order did not assess a fine and CMS Energy neither admitted nor denied the order’s findings.

CMS Energy and Consumers cannot predict the outcome of the investigations. It is possible that the outcome in one or more of the investigations could, affect adversely CMS Energy’s and Consumers’ financial condition, liquidity or results of operations.

CMS Energy and Consumers 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 has 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.

CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a result of alleged false 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 Colorado, Kansas, Missouri, Tennessee, and Wyoming.

CMS Energy and Consumers cannot predict the outcome of the investigations. It is possible that the outcome in one or more of the investigations could affect adversely CMS Energy’s and Consumers’ financial condition, liquidity or results of operations.

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 adversely impact their results of operations, financial condition and cash flows. 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 impact their results of operations and financial condition in unpredictable ways. These actions could also result in disruptions of power and fuel markets. In addition, their natural gas distribution system and pipelines could be directly or indirectly harmed by future terrorist activity.

Consumers may not prevail in the exercise of its regulatory-out rights under the MCV PPA.

The MCV Partnership, which leases and operates the MCV Facility, contracted to sell electricity to Consumers for a 35-year period beginning in 1990. The cost that Consumers incurred under the MCV PPA exceeded the recovery amount allowed by the MPSC, including $39 million in 2007, until it exercised the regulatory-out provision in the MCV PPA in September 2007. This action limited its capacity and fixed energy payments to the MCV Partnership to the amounts that it collects from its customers. However, it uses the direct savings from the RCP, after allocating a portion to customers, to offset a portion of its capacity and fixed energy underrecoveries expense. The MCV Partnership has notified Consumers that it disputes its right to exercise the regulatory-out provision. Consumers believes that the provision is valid and fully effective, but cannot assure that it will prevail in the event of a proceeding on this issue.

As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA. If the MCV Partnership terminates the MCV PPA or reduces the amount of capacity sold under the MCV PPA, Consumers would seek to replace the lost capacity to maintain an adequate electric Reserve Margin. This could involve entering

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into a new power purchase agreement or entering into electric capacity contracts on the open market. Consumers cannot predict its ability to enter into such contracts at a reasonable price. Consumers also is unable to predict regulatory approval of the terms and conditions of such contracts, or that the MPSC would allow full recovery of its incurred costs.

CMS Energy and Consumers cannot predict the financial impact or outcome of these matters.

Consumers’ energy risk management strategies may not be effective in managing fuel and electricity pricing risks, which could result in unanticipated liabilities to Consumers 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 offset its positions, such as hedging exposure to the risks of demand, market effects of weather and changes in commodity prices associated with its gas distribution business. These positions are taken in conjunction with the GCR mechanism, which allows 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 open positions than preferred at a given time. To the extent that open positions exist, fluctuating commodity prices can improve or worsen CMS Energy’s and Consumers’ financial condition or results of operations.

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 IRS and/or other taxing authorities. Unfavorable settlements of any of the issues related to these reserves at CMS Energy or Consumers Energy could adversely affect their financial condition or 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 cycles of the customers it serves. In its service territories in Michigan, the economy has been sluggish and hampered by negative developments in the manufacturing industry and limited growth in non-manufacturing sectors of the state’s economy. 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 impact its collections of accounts receivable and its financial results.

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

Consumers’ electric and gas utility businesses are generally seasonal businesses. 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, its overall results in the future may fluctuate substantially on a seasonal

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basis. Mild temperatures during the summer cooling season and winter heating season will negatively impact CMS Energy’s and Consumers’ results of operations and cash flows.

Unplanned power plant outages may be costly for Consumers.

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

Failure to implement successfully 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 are in the midst of 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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;

•  BUSINESS — BUSINESS SEGMENTS — Independent Power Production — Independent Power Production Properties; and

•  BUSINESS — BUSINESS SEGMENTS — Natural Gas Transmission — Natural Gas Transmission 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

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Consumers’ ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA — NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

CMS Energy

SEC REQUEST

On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy voluntarily produce documents and data relating to the SEC’s inquiry into payments made to officials or relatives of officials of the government of Equatorial Guinea. On August 17, 2004, CMS Energy submitted its response, advising the SEC of the information and documentation it had available. On March 8, 2005, CMS Energy received a request from the SEC that CMS Energy voluntarily produce certain of such documents. The SEC subsequently issued a formal order of private investigation on this matter on August 1, 2005. CMS Energy and several other companies that have conducted business in Equatorial Guinea, received subpoenas from the SEC to provide documents regarding payments made to officials or relatives of officials of the government of Equatorial Guinea. CMS Energy is cooperating and will continue to produce documents responsive to the subpoena.

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. These complaints make allegations similar to those in the Texas-Ohio case regarding price reporting. The court issued an order granting the defendants’ motion to dismiss on April 8, 2005 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 others 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 the ruling of the trial judge in the Texas-Ohio case and held that the “filed rate doctrine” is not applicable to the claims. The Ninth Circuit Court of Appeals then 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.

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

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

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of personal jurisdiction. CMS MST remains a defendant in all of these actions. 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.

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 August 10, 2005, certain defendants, including CMS MST, filed a motion to dismiss and CMS Energy and CMS Field Services filed a motion to dismiss for lack of personal jurisdiction. Defendants attempted to remove the case to federal court, but it was remanded to state court by a federal judge. 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.

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. A motion to remand the case back to Kansas state court was denied on April 21, 2006. The court issued an order granting the motion to dismiss on December 18, 2006, but later reversed the ruling on reconsideration and has now denied the defendants’ motion to dismiss. On September 7, 2007, the CMS Energy defendants filed an answer to the complaint.

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 that month a motion was filed to transfer the case to the MDL proceeding. On January 6, 2006, plaintiffs filed a motion to remand the case to Kansas state court. On January 23, 2006, a conditional transfer order transferring the case to the MDL proceeding was issued. On February 7, 2006, plaintiffs filed an opposition to the conditional transfer order, and on June 20, 2006, the MDL Panel issued an order transferring the case to the MDL proceeding. The court issued an order dated August 3, 2006 denying the motion to remand the case to Kansas state court. Defendants filed a motion to dismiss, which was denied on July 27, 2007. On September 7, 2007, the CMS Energy defendants filed an answer to the complaint.

Breckenridge Brewery of Colorado, LLC and BBD Acquisition Co. v. Oneok, Inc., et al., a class action complaint brought on behalf of retail direct purchasers of natural gas in Colorado, was filed in Colorado state court in May 2006. Defendants, including CMS Energy, CMS Field Services, and CMS MST, are alleged to have violated the Colorado Antitrust Act of 1992 in connection with their natural gas price reporting activities. Plaintiffs are seeking full refund damages. The case was removed to the United States District Court for the District of Colorado on June 12, 2006, a conditional transfer order transferring the case to the MDL proceeding was entered on June 27, 2006, and an order transferring the case to the MDL proceeding was entered on October 17, 2006. The court issued an order dated December 4, 2006 denying the motion to remand the case back to Colorado state court. Defendants have filed a motion to dismiss. On August 21, 2007, the court granted the motion to dismiss by CMS Energy on the basis of a lack of jurisdiction. The other defendants remain in the case, and they filed an answer to the complaint on

34

September 7, 2007. The remaining CMS Energy defendants also filed a summary judgment motion which remains pending.

On October 30, 2006, CMS Energy and CMS MST were each served with a summons and complaint which named CMS Energy, CMS MST and CMS Field Services as defendants in an action filed in Missouri state court, titled Missouri Public Service Commission v. Oneok, Inc. The Missouri Public Service Commission purportedly is acting as an assignee of six local distribution companies, and it alleges that from at least January 2000 through at least October 2002, defendants knowingly reported false natural gas prices to publications that compile and publish indices of natural gas prices, and engaged in wash sales. The complaint contains claims for violation of the Missouri Anti-Trust Law, fraud and unjust enrichment. Defendants removed the case to Missouri federal court and then transferred it to the Nevada MDL proceeding. On October 30, 2007, the court granted the plaintiff’s motion to remand the case to state court in Missouri. The CMS Energy defendants will be filing an answer. A second action, Heartland Regional Medical Center, et al. v. Oneok Inc. et al., was filed in Missouri state court in March 2007 alleging violations of Missouri anti-trust laws. The second action is denoted as a class action. Defendants also removed this case to Missouri federal court, and it has been conditionally transferred to the Nevada MDL proceeding. Plaintiffs also filed a motion to remand this case back to state court but that motion has not yet been decided.

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 CMS Energy entered a special appearance for purpose of filing a motion to dismiss all the CMS Energy defendants due to lack of personal jurisdiction. That motion was filed on September 10, 2007. The court has not yet ruled on the motion. The court denied plaintiffs’ motion to remand the case back to Wisconsin state court, and the case has been transferred to the Nevada MDL proceeding.

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

ROUND-TRIP TRADING INVESTIGATIONS

From May 2000 through January 2002, CMS MST engaged in simultaneous, prearranged commodity trading transactions in which energy commodities were sold and repurchased at the same price. These transactions, referred to as round-trip trades, had no impact on previously reported consolidated net income, EPS or cash flows, but had the effect of increasing operating revenues and operating expenses by equal amounts.

CMS Energy is cooperating with an investigation by the DOJ concerning round-trip trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict the outcome of this matter and what effect, if any, this investigation will have on its business. In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order’s findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies. The two individuals filed a motion to dismiss the SEC action, which was denied.

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 Sale and Purchase of natural gas, pursuant to which Quicksilver agreed to sell, and CMS MST agreed to buy, natural gas. Quicksilver contended that a special provision in the contract requires CMS MST to pay Quicksilver 50 percent of the difference between $2.47/MMBtu and the index price each month. CMS MST disagrees with Quicksilver’s interpretation of the special provision and contends that it

35

has paid all monies owed for delivery of gas according to the contract. Quicksilver was seeking damages of approximately $126 million, plus prejudgment interest and attorneys’ fees, which in CMS Energy’s judgment was unsupported by the facts.

The trial commenced on March 19, 2007. The jury verdict awarded Quicksilver zero compensatory damages but $10 million in punitive damages. The jury found that CMS MST breached the contract and committed fraud but found no actual damage related to such a claim.

On May 15, 2007, the trial court vacated the jury award of punitive damages but held that the contract should be rescinded prospectively. The judicial rescission of the contract caused CMS Energy to record a charge in the second quarter of 2007 of approximately $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.

Consumers

In February 2008, Consumers received a data request relating to an investigation FERC is conducting into possible violations of the FERC’s posting and competitive bidding regulations for pre-arranged released firm capacity on natural gas pipelines. Consumers will cooperate with the FERC in responding to the request. Consumers cannot predict the outcome of this matter.

CMS Energy and Consumers

SECURITIES CLASS ACTION SETTLEMENT

Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the United States District Court for the Eastern District of Michigan. The cases were consolidated into a single lawsuit (the “Shareholder Action”), which generally sought unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy’s business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the court conditionally certified a class consisting of “all persons who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17, 2002 and who were damaged thereby.” The court excluded purchasers of CMS Energy’s 8.75 percent Adjustable Convertible Trust Securities (“ACTS”) from the class and, in response, a new class action lawsuit was filed on behalf of ACTS purchasers (the “ACTS Action”) against the same defendants named in the Shareholder Action. The settlement described in the following paragraph has resolved both the Shareholder and ACTS actions.

On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the “MOU”), 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 of CMS Energy. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. Under the terms of the MOU, the litigation was settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy made a payment of approximately $123 million plus interest on the settlement amount on September 20, 2007. CMS Energy’s insurers paid $77 million, the balance of the settlement amount. In entering into the MOU, CMS Energy made no admission of liability under the Shareholder Action and the ACTS Action. The parties executed a Stipulation and Agreement of Settlement dated May 22, 2007 (“Stipulation”) incorporating the terms of the MOU. In accordance with the Stipulation, CMS Energy has paid approximately $1 million of the settlement amount to fund administrative expenses. On September 6, 2007, the court issued a final order approving the settlement. The remaining settlement amount was paid following the September 6, 2007 hearing.

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On October 5, 2007, two former officers of Consumers filed an appeal of the order approving the settlement of the shareholder litigation. Their principal complaint was with the exclusion of all present and former officers and their immediate families from participation in the settlement. The two former officers have resolved their objections to the terms of the settlement order. On December 12, 2007, their appeal was dismissed by the court.

ENVIRONMENTAL MATTERS

CMS Energy and Consumers, as well as their subsidiaries and affiliates, are subject to various federal, state and local laws and regulations relating to the environment. Several of these companies have been named parties to various actions involving environmental issues. Based on their present knowledge and subject to future legal and factual developments, they believe it is unlikely that these actions, individually or in total, will have a material adverse effect on their financial condition or future results of operations. For additional information, see both CMS Energy’s and Consumers’ 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 2007, CMS Energy did not submit any matters to a vote of security holders.

Consumers

During the fourth quarter of 2007, 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

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 17 OF CMS ENERGY’S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED) which is incorporated by reference herein. At February 19, 2008, the number of registered holders of CMS Energy Common Stock totaled 47,647, based upon the number of record holders. In January 2003, CMS Energy suspended dividends on its common stock. On January 26, 2007, CMS Energy’s Board of Directors reinstated a quarterly dividend on CMS Energy Common Stock of $0.05 per share. On January 25, 2008, CMS Energy’s Board of Directors increased the quarterly dividend on CMS Energy Common Stock to $0.09 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.

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 $94 million in February 2007, $41 million in May 2007, $41 million in August 2007, and $75 million in November 2007. Consumers paid cash dividends on its common stock of $40 million in February 2006, $31 million in August 2006, and $76 million in November 2006.

Issuer Repurchases of Equity Securities

The table below shows our repurchases of equity securities for the three months ended December 31, 2007:

					Total Number of		Maximum Number of
					Shares Purchased		Shares That May Yet
	Total Number				as Part of Publicly		Be Purchased Under
	of Shares		Average Price		Announced		Publicly Announced
Period	Purchased*		Paid per Share		Plans or Programs		Plans or Programs
October 1, 2007 to October 31, 2007		—		—		—		—
November 1, 2007 to November 30, 2007		1,062	$	16.97		—		—
December 1, 2007 to December 31, 2007		1,233	$	17.09		—		—

* We repurchase certain restricted shares upon vesting under the Performance Incentive Stock Plan (“Plan”) from participants in the Plan, equal to our minimum statutory income tax withholding obligation. Shares repurchased have a value based on the market price on the vesting date.

ITEM 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 — ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, 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 Forward-Looking Statements and Information	CMS - 3
Executive Overview	CMS - 4
Results of Operations	CMS - 6
Critical Accounting Policies	CMS - 15
Capital Resources and Liquidity	CMS - 21
Outlook	CMS - 25
Implementation of New Accounting Standards	CMS - 32
New Accounting Standards Not Yet Effective	CMS - 33
Consolidated Financial Statements
Consolidated Statements of Income (Loss)	CMS - 35
Consolidated Statements of Cash Flows	CMS - 37
Consolidated Balance Sheets	CMS - 39
Consolidated Statements of Common Stockholders’ Equity	CMS - 41
Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies	CMS - 44
2. Asset Sales, Discontinued Operations and Impairment Charges	CMS - 51
3. Contingencies	CMS - 56
4. Financings and Capitalization	CMS - 68
5. Earnings Per Share	CMS - 72
6. Financial and Derivative Instruments	CMS - 73
7. Retirement Benefits	CMS - 77
8. Asset Retirement Obligations	CMS - 83
9. Income Taxes	CMS - 85
10. Stock Based Compensation	CMS - 88
11. Leases	CMS - 90
12. Property, Plant, and Equipment	CMS - 92
13. Equity Method Investments	CMS - 93
14. Jointly Owned Regulated Utility Facilities	CMS - 96
15. Reportable Segments	CMS - 96
16. Consolidation of Variable Interest Entities	CMS - 99
17. Quarterly Financial and Common Stock Information (Unaudited)	CMS - 99
Reports of Independent Registered Public Accounting Firms	CMS - 101

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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 - 4
Results of Operations	CE - 6
Critical Accounting Policies	CE - 12
Capital Resources and Liquidity	CE - 16
Outlook	CE - 20
Implementation of New Accounting Standards	CE - 26
New Accounting Standards Not Yet Effective	CE - 27
Consolidated Financial Statements
Consolidated Statements of Income (Loss)	CE - 29
Consolidated Statements of Cash Flows	CE - 30
Consolidated Balance Sheets	CE - 32
Consolidated Statements of Common Stockholder’s Equity	CE - 34
Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies	CE - 37
2. Asset Sales and Impairment Charges	CE - 43
3. Contingencies	CE - 45
4. Financings and Capitalization	CE - 53
5. Financial and Derivative Instruments	CE - 55
6. Retirement Benefits	CE - 57
7. Asset Retirement Obligations	CE - 63
8. Income Taxes	CE - 65
9. Stock Based Compensation	CE - 68
10. Leases	CE - 70
11. Property, Plant, and Equipment	CE - 72
12. Jointly Owned Regulated Utility Facilities	CE - 73
13. Reportable Segments	CE - 73
14. Quarterly Financial and Common Stock Information (Unaudited)	CE - 75
Reports of Independent Registered Public Accounting Firms	CE - 76

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2007 Consolidated Financial Statements

CMS-1

CMS Energy Corporation

SELECTED FINANCIAL INFORMATION

				2007			2006			2005			2004			2003
Operating revenue (in millions)	($		)		6,464			6,126			5,879			5,154			5,232
Earnings from equity method investees (in millions)	($		)		40			89			125			115			164
Income (loss) from continuing operations (in millions)	($		)		(126	)		(133	)		(141	)		112			—
Cumulative effect of change in accounting (in millions)	($		)		—			—			—			(2	)		(24	)
Income (loss) from discontinued operations (in millions)(a)	($		)		(89	)		54			57			11			(19	)
Net income (loss) (in millions)	($		)		(215	)		(79	)		(84	)		121			(43	)
Net income (loss) available to common stockholders (in millions)	($		)		(227	)		(90	)		(94	)		110			(44	)
Average common shares outstanding (in thousands)					222,644			219,857			211,819			168,553			150,434
Net income (loss) from continuing operations per average common share
CMS Energy — Basic	($		)		(0.62	)		(0.66	)		(0.71	)		0.59			(0.01	)
— Diluted	($		)		(0.62	)		(0.66	)		(0.71	)		0.58			(0.01	)
Cumulative effect of change in accounting per average common share
CMS Energy — Basic	($		)		—			—			—			(0.01	)		(0.16	)
— Diluted	($		)		—			—			—			(0.01	)		(0.16	)
Net income (loss) per average common share
CMS Energy — Basic	($		)		(1.02	)		(0.41	)		(0.44	)		0.65			(0.30	)
— Diluted	($		)		(1.02	)		(0.41	)		(0.44	)		0.64			(0.30	)
Cash provided by (used in) operations (in millions)	($		)		27			686			598			353			(250	)
Capital expenditures, excluding acquisitions and capital lease additions (in millions)	($		)		1,263			670			593			525			535
Total assets (in millions)(b)	($		)		14,196			15,371			16,041			15,872			13,838
Long-term debt, excluding current portion (in millions)(b)	($		)		5,385			6,200			6,778			6,414			5,981
Long-term debt-related parties, excluding current portion (in millions)	($		)		178			178			178			504			684
Non-current portion of capital leases and finance lease obligations (in millions)	($		)		225			42			308			315			58
Total preferred stock (in millions)	($		)		294			305			305			305			305
Cash dividends declared per common share	($		)		0.20			—			—			—			—
Market price of common stock at year-end	($		)		17.38			16.70			14.51			10.45			8.52
Book value per common share at year-end	($		)		9.46			10.03			10.53			10.62			9.84
Number of employees at year-end (full-time equivalents)					7,898			8,640			8,713			8,660			8,411
Electric Utility Statistics
Sales (billions of kWh)					39			38			39			38			38
Customers (in thousands)					1,799			1,797			1,789			1,772			1,754
Average sales rate per kWh		(c	)		8.65			8.46			6.73			6.88			6.91
Gas Utility Statistics
Sales and transportation deliveries (bcf)					340			309			350			385			380
Customers (in thousands)(c)					1,710			1,714			1,708			1,691			1,671
Average sales rate per mcf	($		)		10.66			10.44			9.61			8.04			6.72

(a)	Prior year amounts have been reclassified to discontinued operations.
(b)	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.
(c)	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. Such factors include our inability to predict or control:

•  the price of CMS Energy Common Stock, capital and financial market conditions, and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets, including availability of financing to CMS Energy, Consumers, or any of their affiliates, and the energy industry,

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

•  factors affecting utility and diversified energy operations, such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints,

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

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

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

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

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

•  recovery of power supply and natural gas supply costs when fuel prices are fluctuating,

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

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

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

•  recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers,

•  recovery of Palisades plant sale-related costs,

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

•  approval of the Balanced Energy Initiative, and

•  authorization of a new clean coal plant,

CMS-3

•  the effects on our ability to purchase capacity to serve our customers and fully recover the cost of these purchases, if the owners of the MCV Facility exercise their right to terminate the MCV PPA,

•  the ability of Consumers to prevail in the exercise of its regulatory out rights under the MCV PPA,

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

•  the ability of Consumers to recover Big Rock decommissioning funding shortfalls and nuclear fuel storage costs due to the DOE’s failure to accept spent nuclear fuel on schedule, including the outcome of pending litigation with the DOE,

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

•  our ability to collect accounts receivable from our customers,

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

•  the effect on our utility and utility revenues of the direct and indirect impacts of the continued economic downturn in Michigan,

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

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

•  achievement of capital expenditure and operating expense goals,

•  changes in financial or regulatory accounting principles or policies,

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

•  changes in federal or state regulations or laws that could have an impact on our business,

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

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

•  credit ratings of CMS Energy or Consumers, and

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

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

EXECUTIVE OVERVIEW

CMS Energy is an energy company operating primarily in Michigan. We are the parent holding company of Consumers and Enterprises. Consumers is a combination electric and gas utility company serving in Michigan’s Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged primarily in

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domestic independent power production. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises.

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

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

•  economic conditions, primarily in Michigan,

•  regulation and regulatory issues that affect our electric and gas utility operations,

•  energy commodity prices,

•  interest rates, and

•  our debt credit rating.

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

We completed the sale of our international Enterprises assets in 2007, resulting in gross cash proceeds of $1.491 billion. We used the proceeds to retire debt and to invest in our utility business.

We also made important progress at Consumers to reduce business risk and to meet the future needs of our customers. We sold Palisades to Entergy in April 2007 for $380 million, and received $363 million after various closing adjustments. The sale improved our cash flow, reduced our nuclear operating and decommissioning risk, and increased our financial flexibility to support other utility investments.

In September 2007, we exercised the regulatory-out provision in the MCV PPA, thus limiting the amount we pay the MCV Partnership for capacity and fixed energy to the amount recoverable from our customers. The MCV Partnership may, under certain circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA, which could affect our need to build or purchase additional generating capacity. The MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision.

In May 2007, we filed with the MPSC our Balanced Energy Initiative, which is a comprehensive plan to meet customer energy needs over the next 20 years. The plan is designed to meet the growing customer demand for electricity with energy efficiency, demand management, expanded use of renewable energy, and development of new power plants to complement existing generating sources. In September 2007, we filed with the MPSC the second phase of our Balanced Energy Initiative, which contains our plan for construction of a new 800 MW clean coal plant at an existing site located near Bay City, Michigan.

In December 2007, we purchased a 935 MW natural gas-fired power plant located in Zeeland, Michigan from Broadway Gen Funding LLC, an affiliate of LS Power Group, for $519 million. This plant fits in with our Balanced Energy Initiative as it will help provide the capacity we need to meet the growing needs of our customers.

We took an important step in our business plan in 2007 by reinstating a quarterly dividend of $0.05 per share on our common stock, after a four-year suspension. We paid $45 million in common stock dividends in 2007. In January 2008, we increased the quarterly dividend on our common stock to $0.09 per share.

In September 2007, we also resolved a long-outstanding litigation issue by settling two class action lawsuits related to round-trip trading by CMS MST. We believe that eliminating this business uncertainty was in the best interests of our shareholders.

We also restructured our investment in DIG. In November 2007, we negotiated the termination of certain electricity sales agreements in order to eliminate future losses under those agreements. We recorded a liability and recognized a loss of $279 million in 2007, representing the cost to terminate the agreements. In February 2008, we closed the transaction and paid $275 million. Resolving the issues associated with the unfavorable supply contracts allows us to maximize future benefits from our DIG investment.

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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.

As we execute our strategy, we will need to overcome a sluggish Michigan economy that has been hampered by negative developments in Michigan’s automotive industry and limited growth in the non-manufaturing sectors of the state’s economy. While the recent sub-prime mortgage market weakness has disrupted financial markets and the U.S. economy, it has not impacted materially our financial condition. We will continue to monitor developments for potential impacts on our business.

RESULTS OF OPERATIONS

CMS Energy Consolidated Results of Operations

Years Ended December 31	2007			2006			2005
	In Millions (Except for Per Share Amounts)
Net Loss Available to Common Stockholders	$	(227	)	$	(90	)	$	(94	)
Basic Loss Per Share	$	(1.02	)	$	(0.41	)	$	(0.44	)
Diluted Loss Per Share	$	(1.02	)	$	(0.41	)	$	(0.44	)

Years Ended December 31	2007			2006			Change			2006			2005			Change
	In Millions
Electric Utility	$	196		$	199		$	(3	)	$	199		$	153		$	46
Gas Utility		87			37			50			37			48			(11	)
Enterprises		(391	)		(227	)		(164	)		(227	)		(217	)		(10	)
Corporate Interest and Other		(30	)		(153	)		123			(153	)		(135	)		(18	)
Discontinued Operations		(89	)		54			(143	)		54			57			(3	)
Net Loss Available to Common Stockholders	$	(227	)	$	(90	)	$	(137	)	$	(90	)	$	(94	)	$	4

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 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 additional Bay Harbor environmental remediation expenses. The increase in losses was partially offset by increased earnings at our utility primarily due to the positive effects of rate orders and increased sales. Further reducing the year-over-year change were the absence of the shareholder settlement liability recorded in 2006 and the absence of activities related to our former interest in the MCV Partnership.

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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	)
• additional environmental remediation expenses 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 activities,		60
• earnings from non-MCV-related mark-to-market activity 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 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	)

For 2006, our net loss was $90 million compared with a net loss of $94 million for 2005. The improvement is primarily due to increased net income at our electric utility, as the positive effects of regulatory actions, the return of open access customers, and favorable tax adjustments more than offset the negative impacts of increased operating expenses and milder summer weather. The improvements at the electric utility were essentially negated by earnings reductions or increased losses at our other segments. At our Enterprises segment, the negative impacts of mark-to-market valuation losses and the net loss on the sale of our investment in the MCV Partnership more than offset the reduction in asset impairment charges. At our gas utility, net income decreased as the benefits derived from lower operating costs and a gas rate increase authorized by the MPSC in November 2006 were more than offset by lower, weather-driven sales. At our corporate interest and other segment, the cost of our agreement to settle the shareholder class action lawsuits more than offset reduced corporate expenditures.

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Specific changes to net loss available to common stockholders for 2006 versus 2005 are:

		In Millions
•	decrease in asset impairment charges as the $385 million impairment related to the MCV Partnership recorded in 2005 exceeded the $169 million impairment related to GasAtacama recorded in 2006,	$	216
•	increase from Enterprises due to favorable arbitration and property tax awards,		48
•	increase in earnings from our electric utility primarily due to an increase in revenue from an electric rate order, the return to full service-rates of customers previously using alternative energy suppliers, and the expiration of rate caps in December 2005 partially offset by higher operating expense and lower deliveries due to milder weather,		46
•	decrease in Enterprise and corporate interest and other expenses primarily due to an insurance reimbursement received for previously incurred legal expenses, and a reduction in debt retirement charges and other expenses,		26
•	lower incremental environmental remediation expenses recorded in 2006 related to our involvement in Bay Harbor,		20
•	decrease in earnings from mark-to-market valuation adjustments primarily at the MCV Partnership and CMS ERM as losses recorded in 2006 replaced gains recorded in 2005,		(203	)
•	net charge resulting from our agreement to settle shareholder class action lawsuits,		(80	)
•	net loss on the sale of our investment in the MCV Partnership including the negative impact of the associated impairment charge recorded in 2006 and the positive impact of the recognition of certain derivative instruments,		(41	)
•	decrease in various corporate and Enterprises tax benefits as the absence of tax benefits recorded in 2005 related to the American Jobs Creation Act more than offset benefits recorded in 2006, primarily related to the restoration and utilization of income tax credits due to the resolution of an IRS income tax audit,		(14	)
•	decrease in earnings from our gas utility primarily due to a reduction in deliveries resulting from increased customer conservation efforts and warmer weather in 2006 partially offset by other gas revenue associated with pipeline capacity optimization and a reduction in operation and maintenance expenses, and		(11	)
•	reduced earnings from discontinued operations as the positive impact of an arbitration award and a reduction of contingent liabilities recorded in 2005 exceeded income recorded in 2006 from the favorable resolution of certain accrued liabilities.		(3	)
Total change		$	4

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Electric Utility Results of Operations

Years Ended December 31	2007		2006		Change			2006		2005		Change
	In Millions
Net income	$	196	$	199	$	(3	)	$	199	$	153	$	46
Reasons for the change:
Electric deliveries					$	18						$	193
Surcharge revenue						6							61
Palisades revenue to PSCR						(136	)						—
Power supply costs and related revenue						(17	)						57
Other operating expenses, other income, and non-commodity revenue						159							(236	)
Regulatory return on capital expenditures						5							22
General taxes						(15	)						(7	)
Interest charges						(18	)						(34	)
Income taxes						(5	)						(10	)
Total change					$	(3	)					$	46

Electric deliveries: For 2007, electric delivery revenues increased $18 million versus 2006, 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, which resulted in an increase in electric delivery revenues of $14 million. The increase also reflects $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.

For 2006, electric delivery revenues increased by $193 million over 2005 despite the fact that electric deliveries to end-use customers were 38.5 billion kWh, a decrease of 0.4 billion kWh or 1.2 percent versus 2005. The decrease in deliveries was primarily due to milder summer weather compared with 2005, which resulted in a decrease in revenue of $16 million. However, despite these lower electric deliveries, electric delivery revenues increased $160 million due to an approved electric rate order in December 2005 and $49 million related to the return of additional former ROA customers.

Surcharge Revenue: For 2007, the $6 million increase in surcharge revenue was primarily due to a surcharge that we started collecting in the first quarter of 2006 that the MPSC authorized under Section 10d(4) of the Customer Choice Act. The surcharge factors increased in January 2007 pursuant to an MPSC order. This surcharge increased electric delivery revenue by $13 million in 2007 versus 2006. Partially offsetting this increase was a decrease in the collection of Customer Choice Act transition costs, due to the expiration of the surcharge period for our large commercial and industrial customers. The absence of this surcharge decreased electric delivery revenue by $7 million in 2007 versus 2006.

In the first quarter of 2006, we started collecting the surcharge that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This surcharge increased electric delivery revenue by $51 million in 2006 versus 2005. In addition, in the first quarter of 2006, we started collecting customer choice transition costs from our residential customers that increased electric delivery revenue by $12 million in 2006 versus 2005. Reductions in other surcharges decreased electric delivery revenue by $2 million in 2006 versus 2005.

Palisades Revenue to PSCR: Consistent with the MPSC order related to the April 2007 sale of Palisades, $136 million of revenue related to Palisades was designated toward recovery of PSCR costs.

Power Supply Costs and Related Revenue: 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.

For 2006, PSCR revenue increased $57 million versus 2005. The increase was due to the absence, in 2006, of rate caps which allowed us to record power supply revenue to offset fully our power supply costs. Our ability to recover these power supply costs resulted in an $82 million increase in electric revenue in 2006 versus 2005. Additionally, electric revenue increased $9 million in 2006 versus 2005 primarily due to the return of former

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special-contract customers to full-service rates in 2006. Partially offsetting these increases was the absence, in 2006, of deferrals of transmission and nitrogen oxides allowance expenditures related to our capped customers recorded in 2005. These costs were not fully recoverable due to the application of rate caps, so we deferred them for recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the MPSC approved the recovery of these costs. For 2005, deferrals of these costs were $34 million.

Other Operating Expenses, Other Income, and Non-Commodity Revenue: For 2007, other operating expenses decreased $150 million, other income increased $21 million, and non-commodity revenue decreased $12 million versus 2006.

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

Other income increased in 2007 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. Non-commodity revenue decreased in 2007 versus 2006 primarily due to lower transmission services revenue.

For 2006, other operating expenses increased $236 million versus 2005. The increase in other operating expenses reflects higher operating and maintenance, customer service, depreciation and amortization, and pension and benefit expenses. Operating and maintenance expense increased primarily due to costs related to a planned refueling outage at Palisades, and higher tree trimming and storm restoration costs.

Regulatory Return on Capital Expenditures: For 2007, the return on capital expenditures in excess of our depreciation base increased income by $5 million versus 2006. The increase reflects the equity return on the regulatory asset authorized by the MPSC’s December 2005 order which provided for the recovery of $333 million of Section 10d(4) costs over five years.

For 2006, the return on capital expenditures in excess of our depreciation base increased income by $22 million versus 2005.

General Taxes: For 2007, the $15 million increase in general taxes versus 2006 was primarily due to higher property tax expense, reflecting higher millage rates and lower property tax refunds versus 2006.

For 2006, the $7 million increase in general taxes versus 2005 reflects higher MSBT expense, partially offset by property tax refunds.

Interest Charges: 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.

For 2006, interest charges increased $34 million versus 2005 primarily due to lower capitalized interest and interest expense related to an IRS income tax audit settlement. In 2005, we capitalized $33 million of interest in connection with the MPSC’s December 2005 order in our Section 10d(4) Regulatory Asset case. The IRS income tax settlement in 2006 recognized that our taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years.

Income Taxes: 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.

For 2006, income taxes increased $10 million versus 2005 primarily due to higher earnings by the electric utility, partially offset by the resolution of an IRS income tax audit, which resulted in a $4 million income tax benefit caused by the restoration and utilization of income tax credits. Further reducing the increase in income taxes was $5 million of income tax benefits, primarily reflecting the tax treatment of items related to property, plant and equipment as required by past MPSC orders.

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Gas Utility Results of Operations

Years Ended December 31	2007		2006		Change			2006		2005		Change
	In Millions
Net income	$	87	$	37	$	50		$	37	$	48	$	(11	)
Reasons for the change:
Gas deliveries					$	10						$	(61	)
Gas rate increase						81							14
Gas wholesale and retail services, other gas revenues, and other income						14							24
Other operating expenses						(19	)						7
General taxes and depreciation						(11	)						(10	)
Interest charges						4							(6	)
Income taxes						(29	)						21
Total change					$	50						$	(11	)

Gas Deliveries: For 2007, gas delivery revenues increased by $10 million versus 2006 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 lower system efficiency.

In 2006, gas delivery revenues decreased by $61 million versus 2005 as gas deliveries, including miscellaneous transportation to end-use customers, were 282 bcf, a decrease of 36 bcf or 11.3 percent. The decrease in gas deliveries was primarily due to warmer weather in 2006 versus 2005 and increased customer conservation efforts in response to higher gas prices.

Gas Rate Increase: In November 2006, the MPSC issued an order authorizing an annual rate increase of $81 million. In August 2007, the MPSC issued an order authorizing an annual rate increase of $50 million. As a result of these orders, gas revenues increased $81 million for 2007 versus 2006.

In May 2006, the MPSC issued an interim gas rate order authorizing an $18 million annual rate increase. In November 2006, the MPSC issued an order authorizing an annual increase of $81 million. As a result of these orders, gas revenues increased $14 million for 2006 versus 2005.

Gas Wholesale and Retail Services, Other Gas Revenues, and Other Income: For 2007, the $14 million increase in gas wholesale and retail services, other gas revenue and other income primarily reflects higher interest income on short-term cash investments. The increase in short-term cash investments was primarily due to proceeds from the Palisades sale.

For 2006, the $24 million increase in gas wholesale and retail services, other gas revenues, and other income primarily reflects higher pipeline revenues and higher pipeline capacity optimization in 2006 versus 2005.

Other Operating Expenses: 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.

For 2006, other operating expenses decreased $7 million versus 2005 primarily due to lower operating expenses, partially offset by higher customer service and pension and benefit expenses.

General Taxes and Depreciation: 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.

For 2006, general taxes and depreciation expense increased $10 million versus 2005. The increase in depreciation expense was primarily due to higher plant in service. The increase in general taxes reflects higher MSBT expense, partially offset by lower property tax expense.

Interest Charges: For 2007, interest charges decreased $4 million reflecting lower average debt levels and a lower average interest rate versus 2006.

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For 2006, interest charges increased $6 million primarily due to higher interest expense on our GCR overrecovery balance and an IRS income tax audit settlement. The settlement recognized that Consumers’ taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years.

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

For 2006, income taxes decreased $21 million versus 2005 primarily due to lower earnings by the gas utility. Also contributing to the decrease was the absence, in 2006, of the write-off of general business credits of $2 million that expired in 2005, and the resolution, in 2006, of an IRS income tax audit, which resulted in a $3 million income tax benefit caused by the restoration and utilization of income tax credits. Further reducing the increase in income taxes was $5 million of income tax benefits, primarily reflecting the tax treatment of items related to property, plant and equipment as required by past MPSC orders.

Enterprises Results of Operations

Years Ended December 31	2007			2006			Change			2006			2005			Change
	In Millions
Net loss	$	(391	)	$	(227	)	$	(164	)	$	(227	)	$	(217	)	$	(10	)
Reasons for the change:
Operating revenues							$	(9	)							$	(253	)
Cost of gas and purchased power								36									128
Earnings from equity method investees								(48	)								(37	)
Gain (loss) on sale of assets, net								21									(6	)
Operation and maintenance								(7	)								19
Electric sales contract termination								(279	)								—
General taxes, depreciation, and other income, net								20									7
Asset impairment charges, net of insurance reimbursement								29									(216	)
Environmental remediation								(35	)								31
Fixed charges								14									(9	)
Minority interest								(7	)								(2	)
Income taxes								41									103
The MCV Partnership								60									225
Total change							$	(164	)							$	(10	)

Operating Revenues: For 2007, operating revenues decreased $9 million versus 2006 primarily due to decreased third-party gas sales of $52 million, the write-off of $40 million of derivative assets associated with the Quicksilver contract that was voided by the trial judge in May 2007, $18 million in mark-to-market losses related to the amendment of an electricity sales agreement, and the absence of third-party financial settlements of $16 million in 2007 all at CMS ERM. Also contributing to the decrease in operating revenues was the absence of third-party tolling revenue of $17 million at DIG in 2007. These decreases were partially offset by an increase in mark-to-market gains of $89 million on power and gas contracts versus 2006 and increased power sales of $45 million at CMS ERM.

For 2006, operating revenues decreased $253 million versus 2005 primarily due to lower revenue of $102 million at CMS ERM related to mark-to-market losses on power and gas contracts, compared with gains on such items in 2005. In addition, CMS ERM had lower third-party power sales of $53 million, decreased sales to MISO of $22 million, and decreased financial revenue of $76 million resulting from the termination of prepaid gas contracts.

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Cost of Gas and Purchased Power: For 2007, cost of gas and purchased power decreased $36 million versus 2006. The decrease was primarily due to lower power purchases from MISO of $26 million at CMS ERM and a decrease in the cost of gas sold of $10 million due to lower gas prices.

For 2006, cost of gas and purchased power decreased by $128 million versus 2005. The decrease was primarily due to decreases in the cost of gas sold of $93 million resulting from lower gas prices partially offset by increased usage, and decreases in third-party wholesale purchased power of $61 million resulting from the implementation of the MISO market all at CMS ERM, and a decrease in transmission costs of $3 million at DIG. These decreases were partially offset by power purchases from MISO of $29 million at CMS ERM.

Earnings from Equity Method Investees: For 2007, equity earnings decreased $48 million versus 2006. The decrease was due to the absence of $61 million of earnings associated with our investments in Africa, the Middle East and India that were sold in May 2007 and $6 million of earnings associated with our investments in Argentina and Chile that were sold in March and August 2007. Also contributing to the decrease was a $5 million reduction in earnings from our former investment in GasAtacama due to the shortage of gas from Argentina. These decreases were partially offset by the absence, in 2007, of a $20 million provision for higher foreign taxes in Argentina and an increase of $4 million in earnings from our remaining assets in Argentina.

For 2006, equity earnings decreased $37 million versus 2005. The decrease was primarily due to the establishment of tax reserves totaling $23 million related to foreign investments, higher tax expense primarily at Jorf Lasfar of $5 million due to lower tax relief and lower earnings at Shuweihat of $1 million due to higher operating and maintenance costs.

Gain (Loss) on Sale of Assets, Net: For 2007, the net gain on asset sales was $21 million. The net gain consisted of a $34 million gain on the sale of our equity investment in El Chocon to Endesa S.A., and $5 million in gains on the sale of other assets, partially offset by a $13 million net loss on the sale of our equity investments in Africa, the Middle East and India to TAQA and a $5 million net loss on the sale of our Argentine and Michigan assets to Lucid Energy.

For 2006, there were no gains or losses on asset sales. In 2005, we had gains on the sale of GVK and SLAP totaling $6 million.

For a discussion of the 2006 sale of our interest in the MCV Partnership, see “The MCV Partnership” in this section. For additional information, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Operation and Maintenance: For 2007, operation and maintenance expenses increased $7 million versus 2006 due to the absence of a favorable 2006 arbitration settlement related to DIG of $20 million and increased maintenance expense of $2 million, partially offset by the reduction of $6 million in expenses associated with assets sold during 2007, the reimbursement of $3 million in arbitration costs at CMS Gas Transmission in 2007 and the absence of $6 million in losses on the termination of prepaid gas contracts in 2006.

For 2006, operation and maintenance expenses decreased $19 million versus 2005 due to a favorable arbitration settlement related to DIG of $20 million and a $3 million reduction in losses on the termination of prepaid gas contracts. These decreases were partially offset by increased expenditures related to prospecting initiatives in North America of $4 million.

Electric Sales Contract Termination: For 2007, CMS ERM recorded a charge of $279 million related to the termination of electricity sales agreements. For additional information, see the Enterprises Outlook section included in this MD&A.

General Taxes, Depreciation, and Other Income, Net: For 2007, the net of general tax expense, depreciation and other income contributed to a $20 million increase in operating income versus 2006. Other income increased due to gains of $8 million recognized on the rebalancing of SERP investments and the absence, in 2007, of $4 million of accretion expense related to prepaid gas contracts at CMS ERM recorded in 2006, and general tax expense and depreciation decreased $8 million due to the sale of assets in 2007.

For 2006, the net of general tax expense, depreciation, and other income contributed to a $7 million increase in operating income versus 2005. Other income increased due to a decrease in accretion expense of $13 million related

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to the prepaid gas contracts at CMS ERM, partially offset by an increase of $4 million in general tax expense and depreciation and the absence, in 2006, of a $2 million favorable settlement recorded at CMS Gas Transmission in 2005.

Asset Impairment Charges, Net of Insurance Reimbursement: For 2007, asset impairment charges decreased $29 million versus 2006. For 2007, we recorded net impairment charges of $187 million that included $262 million for the reduction in fair value of our investments in TGN, Jamaica, GasAtacama and PowerSmith, and a $75 million credit to recognize a prior insurance award associated with our ownership interest in TGN. For 2006, we recorded a $214 million charge for the reduction in the fair value of our former equity investment in GasAtacama and related notes receivable and other impairment charges of $2 million at Enterprises. For additional information, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

For 2006, asset impairment charges increased $216 million versus 2005 primarily due to 2006 charges of $214 million recorded for the impairment of our former equity investment in GasAtacama and related notes receivable, and $2 million of other impairment charges.

For a discussion of asset impairment charges related to our former interest in the MCV Partnership, see “The MCV Partnership” in this section.

Environmental Remediation: Our environmental remediation charges relate to our projections of future costs associated with Bay Harbor. These charges were $44 million in 2007, $9 million in 2006, and $40 million in 2005. Total remediation charges including accretion expense were $140 million. For additional information, see Note 3, Contingencies.

Fixed Charges: For 2007, fixed charges decreased $14 million versus 2006 due to lower interest expense on subsidiary debt of $12 million resulting from asset sales in 2007. Also contributing to the decrease was the absence, in 2007, of $2 million of interest expense at DIG related to an arbitration settlement recorded in 2006.

For 2006, fixed charges increased $9 million versus 2005 due to higher interest expense of $7 million resulting from an increase in subsidiary debt and $2 million in higher interest expense at DIG related to an arbitration settlement.

Minority Interest: The allocation of profits to minority owners decreases our net income, and the allocation of losses to minority owners increases our net income. For 2007, minority owners shared in a portion of increased earnings at our subsidiaries versus 2006. This was primarily due to increased earnings and gains due to asset sales.

For 2006, minority owners shared in a portion of increased earnings at our subsidiaries versus 2005. This was primarily due to increased earnings, partially offset by losses from asset impairments.

Income Taxes: For 2007, income tax expense decreased $41 million versus 2006. The decrease reflects $93 million in lower tax expenses resulting from higher net losses in 2007 versus 2006 and $27 million of tax benefits primarily related to lower tax reserves in 2007. These benefits were partially offset by $79 million of tax expense on earnings associated with the recognition of previously deferred foreign earnings of subsidiaries.

For 2006, income tax expense decreased $103 million versus 2005. The decrease reflects $119 million in lower tax expenses resulting from higher net losses in 2006 versus 2005 and $23 million of tax benefit related to higher deferred foreign earnings of subsidiaries and resolution of an IRS income tax audit of $8 million, primarily for the restoration and utilization of income tax credits. These benefits were partially offset by the absence of $30 million of income tax benefit related to the American Jobs Creation Act recorded in 2005 and $17 million of tax expense primarily related to higher tax reserves in 2006.

The MCV Partnership: We sold our ownership interests in the MCV Partnership in November 2006. As a result, we have condensed its consolidated results of operations for the years 2005, 2006 and 2007 for discussion purposes.

In 2006, our share of the MCV Partnership’s loss was $60 million, net of tax and minority interest. This was primarily due 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. For additional information, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

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For 2006 versus 2005, our share of the MCV Partnership’s earnings increased by $225 million, net of tax, primarily due to the absence of a 2005 impairment charge to property, plant and equipment at the MCV Partnership. This increase was partially offset by the recognition of mark-to-market losses in 2006 versus mark-to-market gains in 2005.

Corporate Interest and Other Net Expenses

Years Ended December 31	2007			2006			Change		2006			2005			Change
	In Millions
Net loss	$	(30	)	$	(153	)	$	123	$	(153	)	$	(135	)	$	(18	)

For 2007, corporate interest and other net expenses were $30 million, a decrease of $123 million versus 2006. The $123 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 of tax expense in 2007 related to the sale of our international operations. Partially offsetting the decrease is the absence, in 2007, of a tax benefit due to the resolution of an IRS income tax audit.

For 2006, corporate interest and other net expenses were $153 million, an increase of $18 million versus 2005. The increase reflects an $80 million after tax net charge recorded in 2006 as a result of our agreement to settle shareholder class action lawsuits. Also contributing to the increase was the recognition of a portion of the reduction in fair value in our investment in GasAtacama. Partially offsetting the increase was the 2006 resolution of an IRS income tax audit, which resulted in an income tax benefit primarily for the restoration and utilization of income tax credits. Further offsetting the increase were lower early debt retirement premiums, and the receipt of insurance proceeds for previously incurred legal expenses.

Discontinued Operations: For 2007, the net loss from discontinued operations was $89 million versus $54 million of net income in 2006. The $143 million change is primarily due to the net loss on the disposal of international businesses in 2007, which replaced earnings recorded for these businesses in 2006.

For 2006, we recorded $54 million in net income versus $57 million in net income in 2005. The $3 million reduction in net income is primarily due to the absence of income from the favorable resolution of certain accrued contingent liabilities in 2006 associated with previously disposed businesses.

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, 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.

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

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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. On January 1, 2007, we adopted FIN 48, the FASB’s interpretation on the recognition and measurement of uncertain tax positions. For additional details, see the “Implementation of New Accounting Standards” section included in this MD&A.

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 $14.196 billion at December 31, 2007, 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.”

Discontinued Operations

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

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 such expenses will be recovered 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 they will require that such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. At December 31, 2007, we had $2.059 billion recorded as regulatory assets and $2.137 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, 2007, we had $45 million recorded as regulatory assets for underrecoveries of power supply costs and $19 million recorded as regulatory liabilities for overrecoveries of gas costs.

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

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

Financial Instruments: Debt and equity securities classified as available-for-sale are reported at fair value determined from quoted market prices. Unrealized gains 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, it is recorded 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 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. These models 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 results that we estimate using models. If necessary, our calculations of fair value include reserves to reflect the credit risk of our counterparties.

The types of contracts we typically classify as derivatives are interest rate swaps, forward contracts for electricity and gas, option contracts for electricity and gas, gas futures, and electric swaps. Most of our commodity purchase and sale contracts are not subject to derivative accounting under SFAS No. 133 because:

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

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

•  there is not an active market for the commodity.

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

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

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

CMS ERM Contracts: In order to support CMS Energy’s ongoing operations, CMS ERM enters into contracts to purchase and sell electricity and natural gas in the future. These forward contracts will result in physical delivery of the commodity at a contracted price. These contracts are generally long-term in nature and are classified as non-trading contracts.

To manage commodity price risks associated with these forward purchase and sale contracts, CMS ERM uses various financial instruments, such as swaps, options, and futures. CMS ERM also uses these types of instruments

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to manage commodity price risks associated with generation assets owned by CMS Energy and its subsidiaries. These financial contracts are classified as trading contracts.

Certain of CMS ERM’s non-trading and trading contracts qualify as derivatives. We include the fair value of these derivatives in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The following tables provide a summary of these contracts at December 31, 2007:

	Non-
	Trading			Trading			Total
	In Millions
Fair value of contracts outstanding at December 31, 2006	$	31		$	(68	)	$	(37	)
Fair value of new contracts when entered into during the period(a)		—			(1	)		(1	)
Contracts realized or otherwise settled during the period(b)		(6	)		74			68
Other changes in fair value(c)		(43	)		(10	)		(53	)
Fair value of contracts outstanding at December 31, 2007	$	(18	)	$	(5	)	$	(23	)

(a)	Reflects premiums paid (received) for new contracts.
(b)	CMS ERM terminated certain trading gas contracts during 2007. CMS ERM had recorded derivative liabilities, representing cumulative unrealized mark-to-market losses, associated with these contracts. Therefore, upon the termination of those contracts, the fair value of CMS ERM’s trading contracts increased significantly.
(c)	Reflects changes in the fair value of contracts over the period, as well as increases or decreases to credit reserves. The fair value of CMS ERM’s non-trading electric and gas contracts decreased significantly during 2007 for two reasons. First, a natural gas contract with Quicksilver was prospectively rescinded by court action. CMS ERM had recorded a derivative asset for this contract, representing cumulative unrealized mark-to-market gains. See Note 3, Contingencies, “Other Contingencies — Quicksilver Resources, Inc.” for additional details. In addition, CMS ERM recorded a derivative liability of $18 million related to the amendment of an electricity sales agreement. For additional details of this amendment, see the “Outlook” section included in this MD&A.

				Fair Value of Non-Trading Contracts at December 31, 2007
	Total			Maturity (in years)
Source of Fair Value	Fair Value			Less than 1			1 to 3			4 to 5			Greater than 5
	In Millions
Prices actively quoted	$	—		$	—		$	—		$	—		$	—
Prices obtained from external sources or based on models and other valuation methods		(18	)		(2	)		(6	)		(5	)		(5	)
Total	$	(18	)	$	(2	)	$	(6	)	$	(5	)	$	(5	)

				Fair Value of Trading Contracts at
				December 31, 2007
	Total			Maturity (in years)
Source of Fair Value	Fair Value			Less than 1			1 to 3		4 to 5		Greater than 5
	In Millions
Prices actively quoted	$	1		$	—		$	1	$	—	$	—
Prices obtained from external sources or based on models and other valuation methods		(6	)		(6	)		—		—		—
Total	$	(5	)	$	(6	)	$	1	$	—	$	—

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

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risks, including swaps, options, futures, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of two different committees: 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 through established credit policies, 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 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	2007		2006
	In Millions
Variable-rate financing — before-tax annual earnings exposure	$	2	$	4
Fixed-rate financing — potential reduction in fair value(a)		172		193

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

At December 31, 2007, Consumers had $131 million in variable auction rate tax exempt bonds, insured by monoline insurers, that are subject to rate reset every 35 days. The subprime mortgage problems have put monoline insurers’ credit ratings at risk of downgrade by rating agencies. This risk of downgrade could cause the interest rates on these bonds to rise. Consumers does not expect its interest rate risk exposure regarding these bonds to be material. Consumers is continuing to monitor the situation and its alternatives.

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 enter into non-trading derivative contracts, such as forward purchase and sale contracts for electricity and natural gas. We also enter into trading derivative contracts, including options and swaps for electricity and gas. For additional details on these contracts, see Note 6, Financial and Derivative Instruments.

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

December 31	2007		2006
	In Millions
Potential reduction in fair value:
Trading contracts
Electricity-related contracts		4		2
Gas-related 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	2007		2006
	In Millions
Potential reduction in fair value of available-for-sale equity securities (primarily SERP investments):	$	6	$	6

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

Pension and OPEB

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 5 percent of base pay to the existing Employees’ Savings 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 resumed the employer’s match in CMS Energy Common Stock in our 401(k) savings plan on January 1, 2005. On September 1, 2005, we increased the employer match from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee’s wages.

Beginning May 1, 2007, the CMS Energy Common Stock Fund was no longer an investment option available for investments in the 401(k) savings plan and the employer match was no longer in CMS Energy Common Stock. Participants had an opportunity to reallocate investments in the CMS Energy Common Stock Fund to other plan investment alternatives prior to November 1, 2007. In November 2007, the remaining shares in the CMS Energy Common Stock Fund were sold and the sale proceeds were reallocated to other plan investment options.

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,

•  present-value 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 Costs	Pension Cost		OPEB Cost		Contributions
	In Millions
2008	$	106	$	27	$	49
2009		112		25		49
2010		116		24		133

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 2008 by $3 million. Lowering the discount rate by 0.25 percent (from 6.40 percent to 6.15 percent) would increase estimated pension cost for 2008 by $1 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. No market risk premium was included in our ARO fair value estimate 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.

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,

•  working capital needs, and

•  collateral requirements.

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

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

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

•  our current level of cash and revolving credit facilities,

•  our anticipated cash flows from operating and investing activities, and

•  our ability to access secured and unsecured borrowing capacity in the capital markets, if necessary.

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

Cash Position, Investing, and Financing

Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2007, we had $382 million of consolidated cash, which includes $34 million of restricted cash and $7 million from entities consolidated pursuant to FIN 46(R).

Our primary ongoing source of cash is dividends and other distributions from our subsidiaries. For the year ended December 31, 2007, Consumers paid $251 million in common stock dividends to CMS Energy. For details on dividend restrictions, see Note 4, Financings and Capitalization.

Our cash flow statements include amounts related to discontinued operations through the date of disposal. The sale of our discontinued operations and their related cash flows will have no material adverse effect on our liquidity, as we used the proceeds of these sales to invest in our utility business and to reduce debt. For additional details on discontinued operations, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Summary of Consolidated Statements of Cash Flows:

	2007			2006			2005
	In Millions
Net cash provided by (used in):
Operating activities	$	27		$	686		$	598
Investing activities		658			(749	)		(493	)
Net cash provided by (used in) operating and investing activities		685			(63	)		105
Financing activities		(690	)		(434	)		74
Effect of exchange rates on cash		2			1			(1	)
Net Increase (Decrease) in Cash and Cash Equivalents	$	(3	)	$	(496	)	$	178

Operating Activities:

2007: Net cash provided by operating activities was $27 million, a decrease of $659 million versus 2006. In addition to a decrease in earnings, cash provided by operating activities decreased primarily as result of the following:

•  absence, in 2007, of the sale of accounts receivable,

•  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 and other timing differences.

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, and

•  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.

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For additional details on excess Palisades decommissioning funds, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

2006: Net cash provided by operating activities was $686 million, an increase of $88 million versus 2005. Cash provided by operating activities increased primarily as result of the following:

•  decreases in accounts receivable primarily due to the collection of receivables in 2006 reflecting higher gas prices billed during the latter part of 2005 and reduced billings in the latter part of 2006 due to milder weather,

•  reduced inventory purchases,

•  cash proceeds from the sale of excess sulfur dioxide allowances, and

•  a return of funds formerly held as collateral under certain gas hedging arrangements.

These increases were partially offset by decreases in the MCV Partnership gas supplier funds on deposit as a result of refunds to suppliers from decreased exposure due to declining gas prices in 2006.

Investing Activities:

2007: Net cash provided by investing activities was $658 million, an increase of $1.407 billion versus 2006. This increase was primarily due to proceeds from asset sales and the related 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.

2006: Net cash used in investing activities was $749 million, an increase of $256 million versus 2005. This was primarily due to cash relinquished from the sale of assets, the absence of short-term investment proceeds, an increase in capital expenditures and cost to retire property, and an increase in non-current notes receivable. This activity was offset by the release of restricted cash in February 2006, which we used to extinguish long-term debt - related parties.

For additional details on asset sales, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

Financing Activities:

2007: Net cash used in financing activities was $690 million, an increase of $256 million versus 2006. This was primarily due to an increase in net debt retirements and the payment of common stock dividends.

2006: Net cash used in financing activities was $434 million, an increase of $508 million versus 2005. This was due to an increase in net retirement of long-term debt of $269 million combined with a decrease in proceeds from common stock issuances of $287 million.

For additional details on long-term debt activity, see Note 4, Financings and Capitalization.

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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, 2007	Total		One Year		Three Years		Five Years		Five Years
	In Millions
Long-term debt(a)	$	6,077	$	542	$	1,078	$	1,146	$	3,311
Long-term debt — related parties(a)		178		—		—		—		178
Interest payments on long-term debt(b)		2,736		330		593		457		1,356
Capital and finance leases(c)		255		30		48		44		133
Interest payments on capital and finance leases(d)		139		14		27		24		74
Operating leases(e)		207		26		45		42		94
Purchase obligations(f)		21,286		2,502		2,897		2,275		13,612
Total contractual obligations	$	30,878	$	3,444	$	4,688	$	3,988	$	18,758

(a)	Principal amounts due on outstanding debt obligations, current and long-term, at December 31, 2007. For additional details on long-term debt, see Note 4, 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, 2007.
(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.

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 $58 million per month during 2008. 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 3, Contingencies, “Consumers’ Electric Utility Rate Matters — Power Supply Costs.”

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

Off-Balance Sheet Arrangements: CMS Energy and certain of its subsidiaries enter into various arrangements in the normal course of business to facilitate commercial transactions with third parties. These arrangements include indemnifications, 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 amount of potential payments we would be required to make under a

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number of these indemnities is not estimable. At December 31, 2007, we have an $88 million liability in connection with indemnities related to the sale of certain subsidiaries reflected on our Consolidated Balance Sheets.

We provide guarantees and surety bonds on behalf of certain non-consolidated entities, improving their ability to transact business. In addition, we have provided financial guarantees to certain property owners in connection with the Bay Harbor remediation effort. We monitor these obligations and believe it is unlikely that we will incur any material losses associated with these guarantees. For additional details on these and other guarantee arrangements, see Note 3, Contingencies, “Other Contingencies — Guarantees and Indemnifications.”

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers may sell up to $325 million of certain accounts receivable. This program provides less expensive funding that unsecured debt. For additional details, see Note 4, Financings and Capitalization.

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 2008 through 2010:

Years Ending December 31	2008		2009		2010
	In Millions
Electric utility operations(a)(b)	$	684	$	717	$	783
Gas utility operations(b)		234		263		232
Enterprises		28		55		26
Total	$	946	$	1,035	$	1,041

(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.

OUTLOOK

Corporate Outlook

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

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

ELECTRIC UTILITY BUSINESS OUTLOOK

Growth: In 2007, electric deliveries grew about one percent over 2006 levels. In 2008, we project electric deliveries to decline one-quarter of a percent compared to 2007 levels. This outlook assumes a small decline in industrial economic activity, the cancellation of one wholesale customer contract, and normal weather conditions throughout the year.

We expect electric deliveries to grow one percent annually over the next five years. This outlook assumes a modestly growing customer base and a stabilizing Michigan economy after 2008. This growth rate, which reflects a long-range expected trend includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. Growth from year to year may vary from this trend due to customer response to the following:

•  energy conservation measures,

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•  fluctuations in weather conditions, and

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

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

Electric Reserve Margin: To reduce the risk of high power supply costs during peak demand periods and to achieve our Reserve Margin target, we purchase electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser extent in the winter months. We have purchased capacity and energy contracts covering a portion of our Reserve Margin requirements for 2008 through 2010. We are currently planning for a Reserve Margin of 13.7 percent for summer 2008, or supply resources equal to 113.7 percent of projected firm summer peak load. Of the 2008 supply resources target, we expect 93 percent to come from our electric generating plants and long-term power purchase contracts, with other contractual arrangements making up the remainder. We expect capacity costs for these electric capacity and energy contracts to be $21 million for 2008.

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

Electric Transmission Expenses: In 2008, we expect transmission rates charged to us to increase by $42 million due primarily to a 33 percent increase in METC transmission rates. This increase was included in our 2008 PSCR plan filed with the MPSC in September 2007.

In September 2007, the FERC approved a proposal to include 100 percent of the costs of network upgrades associated with new generator interconnections in the rates of certain MISO transmission owners, including METC. Previously, those transmission owners shared interconnection network upgrade costs with generators. Consumers, Detroit Edison, the MPSC, and other parties filed a request for rehearing of the FERC order.

21st Century Electric Energy Plan: In January 2007, the then chairman of the MPSC proposed initiatives to the governor of Michigan for the use of more renewable energy resources by all load-serving entities such as Consumers, the creation of an energy efficiency program, and a procedure for reviewing proposals to construct new generation facilities. The January proposal indicated that Michigan will need new base-load capacity by 2015. The proposed initiatives will require changes to current legislation.

Balanced Energy Initiative: In response to the 21st Century Electric Energy Plan, we filed with the MPSC a “Balanced Energy Initiative” that provides a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements. The filing requests the MPSC to rule that the Balanced Energy Initiative represents a reasonable and prudent plan for the acquisition of necessary electric utility resources. Implementation of the Balanced Energy Initiative will require legislative repeal or significant reform of the Customer Choice Act.

In September 2007, we filed with the MPSC an updated Balanced Energy Initiative, which includes our plan to build an 800 MW advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan. We expect to use 500 MW of the plant’s output to serve Consumers’ customers and to commit the remaining 300 MW to others. We expect the plant to begin operating in 2015. We estimate our share of the cost at $1.6 billion including financing costs. Construction of the proposed new clean coal plant is contingent upon obtaining environmental permits and MPSC approval.

The Michigan Attorney General filed a motion with the MPSC to dismiss the Balanced Energy Initiative case, claiming that the MPSC lacks jurisdiction over the matter, which the ALJ denied. The Michigan Attorney General and another intervenor have filed an appeal of that decision with the MPSC.

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Proposed Energy Legislation: There are various bills introduced and being considered in the U.S. Congress and the Michigan legislature relating to mandatory renewable energy standards. If enacted, these bills generally would require electric utilities either to acquire a certain percentage of their power from renewable sources or pay fees, or purchase allowances in lieu of having the resources. Also in December 2007, several bills were introduced in the Michigan legislature that would reform the Customer Choice Act, introduce energy efficiency programs, modify the timing of rate increase requests, amend customer rate design and provide for other regulatory changes. We cannot predict whether any of these bills will be enacted or what form the final legislation might take.

Power Plant Purchase: In December 2007, we purchased a 935 MW gas-fired power plant located in Zeeland, Michigan for $519 million from Broadway Gen Funding LLC, an affiliate of LS Power Group. The power plant will help meet the growing energy needs of our customers.

ELECTRIC UTILITY BUSINESS UNCERTAINTIES

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

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

Clean Air Act: Compliance with the federal Clean Air Act and resulting state and federal regulations continues to be a major focus for us. The State of Michigan’s Nitrogen Oxides Implementation Plan requires significant reductions in nitrogen oxides emissions. From 1998 to present, we have incurred $786 million in capital expenditures to comply with this plan, including installing selective catalytic reduction control technology on three of our coal-fired electric generating units. We have also installed low nitrogen oxides burners on a number of our coal-fired electric generating units.

Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. We plan to meet the nitrogen oxides requirements by:

•  operating our selective catalytic reduction control technology units throughout the year,

•  completing the installation of a fourth selective catalytic reduction control unit,

•  installing low nitrogen oxides burners, and

•  purchasing emission allowances.

We plan to meet the sulfur dioxide requirements by injecting a chemical that reduces sulfur dioxide emissions, installing scrubbers and purchasing emission allowances. We plan to spend an additional $835 million for equipment installation through 2015, which we expect to recover in customer rates. The key assumptions in the capital expenditure estimate include:

•  construction commodity prices, especially construction material and labor,

•  project completion schedules and spending plans,

•  cost escalation factor used to estimate future years’ costs of 3.2 percent, and

•  an AFUDC capitalization rate of 7.9 percent.

We will need to purchase additional nitrogen oxides emission allowances through 2011 at an estimated cost of $3 million per year. We will also need to purchase additional sulfur dioxide emission allowances in 2012 and 2013 at an estimated cost of $10 million per year. We expect to recover emissions allowance costs from our customers through the PSCR process.

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The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of Columbia by a number of utilities and other companies. A decision is expected in 2008. We cannot predict the outcome of these appeals.

State and Federal Mercury Air Rules: In March 2005, the EPA issued the CAMR, which requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010 and further reductions by 2018. Certain portions of the CAMR were appealed to the U.S. Court of Appeals for the District of Columbia by a number of states and other entities. The U.S. Court of Appeals for the District of Columbia decided the case on February 8, 2008, and determined that the rates developed by the EPA were not consistent with the Clean Air Act. We continue to monitor the development of federal regulation in this area.

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ on the details of this plan; however, we have developed preliminary cost estimates and a mercury emissions reduction scenario based on our best knowledge of control technology options and initially proposed requirements. We estimate that costs associated with Phase I of the state’s mercury plan will be approximately $280 million by 2010 and an additional $200 million by 2015. The key assumptions in the capital expenditure estimate are the same as those stated for the Clean Air Interstate Rule.

The following table outlines the proposed state mercury plan:

	Phase I	Phase II
Proposed State Mercury Rule	30% reduction by 2010	90% reduction by 2015

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

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

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

Water: In March 2004, the EPA issued rules that govern electric generating plant cooling water intake systems. The rules require significant reduction in the number of fish harmed by operating equipment. EPA compliance options in the rule were challenged in court. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The court’s ruling is expected to increase significantly the cost of complying with this rule. However, the cost to comply will not be known until the EPA’s reconsideration is complete. At this time, the EPA is developing rules to implement the court’s decision. The rules are expected to be released for public comment in late 2008.

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

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Electric ROA: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2007, alternative electric suppliers were providing 315 MW of generation service to ROA customers. This is 4 percent of our total distribution load and represents an increase of 5 percent of ROA load compared to December 31, 2006.

In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred in 2002 and 2003 through a surcharge applied to ROA customers. Since the MPSC order, we have experienced a downward trend in ROA customers. If this trend continues, it may require legislative or regulatory assistance to recover fully our 2002 and 2003 Stranded Costs.

Electric Rate Case: During 2007, we filed applications with the MPSC seeking an 11.25 percent authorized return on equity and an annual increase in revenues of $269 million. The filings sought recovery of the costs associated with increased plant investment, including the purchase of the Zeeland power plant, increased equity investment, higher operation and maintenance expenses, recovery of transaction costs from the sale of Palisades, and the approval of an energy efficiency program.

In December 2007, the MPSC approved a rate increase of $70 million related to the purchase of the Zeeland power plant. For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, “Consumers’ Electric Utility Rate Matters.”

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

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

To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a determination as to whether it wished to reconsider the amount of the MCV PPA payments that we recover from customers. In May 2007, the MCV Partnership also filed an application with the MPSC seeking approval to increase our recovery of costs incurred under the MCV PPA. We cannot predict the financial impact or outcome of these matters. For additional details on the MCV PPA, see Note 3, Contingencies, “Other Consumers’ Electric Utility Contingencies - The MCV PPA.”

Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million and received $363 million after various closing adjustments. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. In addition, we paid the NMC, the former operator of Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC. The MPSC order approving the Palisades transaction allowed us to recover the book value of Palisades. As a result, we are crediting proceeds in excess of book value of $66 million to our customers through the end of 2008. After closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were $77 million. Recovery of our transaction costs of $28 million, which includes the NMC exit fees and investment forfeiture, is presently under review by the MPSC in our current electric rate case.

Entergy assumed responsibility for the future decommissioning of Palisades and for storage and disposal of spent nuclear fuel at Palisades and the Big Rock ISFSI sites. We transferred $252 million in trust fund assets to Entergy. We are crediting excess decommissioning funds of $189 million to our retail customers through the end of

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2008. Modification to the terms of the transaction allowed us immediate access to additional excess decommissioning trust funds of $123 million. The distribution of these funds is currently under review by the

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MPSC in our electric rate case filing. For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.

As part of the transaction, we entered into a 15-year power purchase agreement under which Entergy sells us all of the plant’s output up to its current annual average capacity of 798 MW. 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 for accounting purposes and not a sale. For additional details on the Palisades financing, see Note 11, Leases.

GAS UTILITY BUSINESS OUTLOOK

Growth: In 2008, we project that gas deliveries will remain flat, on a weather-adjusted basis, relative to 2007 levels due to continuing conservation and overall economic conditions in Michigan. We expect gas deliveries to decline by less than one-half of one percent annually over the next five years. Actual gas deliveries in future periods may be affected by:

•  fluctuations in weather conditions,

•  use by independent power producers,

•  availability of renewable energy sources,

•  changes in gas commodity prices,

•  Michigan economic conditions,

•  the price of competing energy sources or fuels,

•  gas consumption per customer, and

•  improvements in gas appliance efficiency.

GAS UTILITY BUSINESS UNCERTAINTIES

Several gas business trends 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 3, Contingencies, “Consumers’ Gas Utility Contingencies — Gas Environmental Matters.”

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

Gas Depreciation: In June 2007, the MPSC issued its final order in a generic ARO accounting case and modified the filing requirement for our next gas depreciation case. The original filing requirement date was changed from 90 days after the issuance of that order to no later than August 1, 2008. Additionally, we have been ordered to use 2007 data and prepare a cost-of-removal depreciation study with five alternatives using the MPSC’s prescribed methods. We cannot predict the outcome of the analysis.

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

2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity as part of an $88 million annual increase in our gas delivery and transportation rates. In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate increase of $50 million, including an authorized return on equity of 10.75 percent. On September 25, 2007, the MPSC reopened the record in the case to allow all interested parties to be heard concerning the approval of an energy efficiency program, which

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we proposed in our original filing. Hearings on this matter were held in February 2008. We expect the MPSC to issue a final order in the second quarter of 2008. If approved in total, this would result in an additional rate increase of $9 million for implementation of the energy efficiency program.

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million and an 11 percent authorized return on equity.

ENTERPRISES OUTLOOK

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

In connection with the sale of our Argentine and Michigan assets to Lucid Energy in March 2007, we entered into agreements that grant Lucid Energy:

•  an option to buy CMS Gas Transmission’s ownership interest in TGN, subject to the rights of other third parties,

•  the rights to certain proceeds that may be awarded and received by CMS Gas Transmission in connection with certain legal proceedings, including an ICSID arbitration award, and

•  the rights to proceeds that Enterprises will receive if it sells its interest in CMS Generation San Nicolas Company.

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

For details on the ICSID arbitration award, see Note 3, Contingencies.

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

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

•  the outcome of certain legal proceedings,

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

CMS ERM Electricity Sales Agreements: CMS ERM was a party to three electricity sales agreements, under which it provided up to 300 MW of electricity at fixed prices. CMS ERM satisfied its obligations under these agreements by using electricity generated by DIG or by purchasing electricity from the market. Because the price of natural gas has increased substantially in recent years, the prices that were charged under these agreements did not reflect DIG’s cost to generate or CMS ERM’s cost to purchase electricity from the market. Therefore, these agreements negatively impacted DIG’s and CMS ERM’s financial performance.

In November 2007, CMS ERM, DIG, and CMS Energy reached an agreement to terminate two of these electricity sales agreements in order to eliminate future losses under those contracts. As consideration for agreeing to terminate the agreements, CMS ERM paid the customers $275 million upon closing the transaction in February 2008. We recorded a liability for the future payment and other termination costs and recognized a loss of $279 million in 2007, representing the cost to terminate the agreements. As a result of terminating these agreements, CMS ERM and DIG have reduced their long-term electric capacity supply obligations by 260 MW. CMS ERM will market the capacity and energy that was previously committed under these agreements into the merchant market either through third party agreements or directly with the MISO.

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Also in November 2007, CMS ERM executed an amendment of the remaining electricity sales agreement, which was effective upon the closing of the transaction. The purpose of the amendment is to optimize production planning and ensure optimal use of available resources. The amendment establishes a minimum amount of contract capacity to be provided under the agreement, and adds a minimum and maximum amount of electricity to be delivered to the customer. As amended, this electricity sales agreement is a derivative instrument. Upon signing the amendment in 2007, we recorded our minimum obligation under the contract on our Consolidated Balance Sheets at its fair value and recognized the resulting mark-to-market loss of $18 million in earnings. For additional details on accounting for this derivative, see Note 6, Financial and Derivative Instruments.

OTHER OUTLOOK

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

Software Implementation: We are implementing an integrated business software system for finance, purchasing/supply chain, customer billing, human resources and payroll, and utility asset construction and maintenance work management. We expect the new business software, scheduled to be in production in the first half of 2008, to improve customer service, reduce risk, and increase flexibility. Including work done to date, we expect to incur $175 million in operating expenses and capital expenditures for the initial implementation.

Michigan Public Service Commission: During the third quarter of 2007, the Michigan governor appointed a new MPSC chairperson and a new MPSC commissioner. We have several significant cases pending MPSC review and approval. For additional detail on these cases, see Note 3, Contingencies, “Consumers’ Electric Utility Rate Matters” and “Consumers’ Gas Utility Rate Matters.”

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

Michigan Tax Legislation: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan Business Tax Act, which imposed a business income tax of 4.95 percent and a modified gross receipts tax of 0.8 percent. The bill provided for a number of tax credits and incentives geared toward those companies investing and employing in Michigan. The Michigan Business Tax, which was effective January 1, 2008, replaced the state’s Single Business Tax that expired on December 31, 2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional deductions in future years against the business income portion of the tax. These future deductions are phased in over a 15-year period, beginning in 2015. As a result, our consolidated net deferred tax liability of $122 million, recorded due to the Michigan Business Tax enactment, was offset by a net deferred tax asset of $122 million. In December 2007, the Michigan governor signed House Bill 5408, replacing the expanded sales tax for certain services with a 21.99 percent surcharge on the business income tax and the modified gross receipts tax. Therefore, the total tax rates imposed under the Michigan Business Tax are 6.04 percent for the business income tax and 0.98 percent for the modified gross receipts tax. We expect to recover the taxes that we pay from our customers, but we cannot predict the timeliness of such recovery.

IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS No. 158. Phase one of this standard, implemented in December 2006, required us to recognize the funded

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status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. Phase two requires that we change our plan measurement date from November 30 to December 31, effective for the year ending December 31, 2008. The implementation of phase two of this standard will not have a material effect on our consolidated financial statements.

FIN 48, Accounting for Uncertainty in Income Taxes: This interpretation, which we adopted on January 1, 2007, provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management’s best judgment, it is greater than 50 percent likely that we will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return.

CMS Energy and its subsidiaries file a consolidated U.S. federal income tax return as well as unitary and combined income tax returns in several states. CMS Energy and its subsidiaries also file separate company income tax returns in several states. The only significant state tax paid by CMS Energy is in Michigan. However, since the Michigan Single Business Tax was not an income tax, it was not part of the FIN 48 analysis. For the U.S. federal income tax return, CMS Energy completed examinations by federal taxing authorities for its taxable years prior to 2002. The federal income tax returns for the years 2002 through 2006 are open under the statute of limitations, with 2002 through 2005 currently under examination.

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. As of December 31, 2007, remaining uncertain tax benefits that would reduce our effective tax rate in future years are $8 million. We are not expecting any other material changes to our uncertain tax positions over the next twelve months.

We have reflected a net interest liability of $2 million related to our uncertain income tax positions on our Consolidated Balance Sheets as of December 31, 2007. We have not accrued any penalties with respect to uncertain tax benefits. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us on January 1, 2008. The standard provides a revised definition of fair value and establishes a framework for measuring fair value. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value, but it requires new disclosures about the impact and reliability of fair value measurements. The standard will also eliminate the existing prohibition against recognizing “day one” gains and losses on derivative instruments. We currently do not hold any derivatives that would involve day one gains or losses. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we currently hold. We do not believe that the implementation of this standard will have a material effect on our consolidated financial statements.

In February 2008, the FASB issued a one-year deferral of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recorded or disclosed at fair value on a recurring basis. Under this partial deferral, SFAS No. 157 will not be effective until January 1, 2009 for fair value measurements in the following areas:

•  AROs,

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

•  fair value measurements performed in conjunction with impairment analyses.

CMS-33

SFAS No. 157 remains effective January 1, 2008 for our derivative instruments, available-for-sale investment securities, and long-term debt fair value disclosures.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us on January 1, 2008. This standard gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We do not expect to elect the fair value option for any financial instruments or other items.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. Any changes in our ownership interests while control is retained will be treated as equity transactions. In addition, this standard requires presentation and disclosure of the allocation between controlling and noncontrolling interests’ income from continuing operations, discontinued operations, and comprehensive income and a reconciliation of changes in the consolidated statement of equity during the reporting period. The presentation and disclosure requirements of the standard will be applied retrospectively for all periods presented. All other requirements will be applied prospectively. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39: In April 2007, the FASB issued FSP FIN 39-1, effective for us on January 1, 2008. This standard will permit us to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. We have elected to offset our derivative fair values under master netting arrangements, but we currently record cash collateral amounts separately. As a result of offsetting the collateral amounts under this standard, we expect that both our total assets and total liabilities will be reduced by an immaterial amount. There will be no impact on earnings from adopting this standard. The standard is to be applied retrospectively for all periods presented in our consolidated financial statements.

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

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CMS Energy Corporation

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

	Years Ended December 31
	2007			2006			2005
	In Millions
Operating Revenue	$	6,464		$	6,126		$	5,879
Earnings from Equity Method Investees		40			89			125
Operating Expenses
Fuel for electric generation		422			711			644
Fuel costs mark-to-market at the MCV Partnership		—			204			(200	)
Purchased and interchange power		1,407			709			441
Cost of gas sold		2,273			2,131			2,296
Electric sales contract termination		279			—			—
Other operating expenses		976			1,136			1,030
Maintenance		201			297			230
Depreciation and amortization		540			550			504
General taxes		222			151			226
Asset impairment charges, net of insurance recoveries		204			459			1,184
Gain on asset sales, net		(21	)		(79	)		(6	)
		6,503			6,269			6,349
Operating Income (Loss)		1			(54	)		(345	)
Other Income (Deductions)
Interest and dividends		96			76			60
Regulatory return on capital expenditures		31			26			4
Foreign currency gain (loss), net		1			—			(5	)
Other income		40			31			33
Other expense		(39	)		(21	)		(45	)
		129			112			47
Fixed Charges
Interest on long-term debt		382			448			458
Interest on long-term debt — related parties		14			15			29
Other interest		48			27			14
Capitalized interest		(6	)		(10	)		(38	)
Preferred dividends of subsidiaries		2			5			5
		440			485			468
Loss Before Income Taxes		(310	)		(427	)		(766	)
Income Tax Benefit		(195	)		(188	)		(180	)
Loss Before Minority Interests (Obligations), Net		(115	)		(239	)		(586	)
Minority Interests (Obligations), Net		11			(106	)		(445	)
Loss From Continuing Operations		(126	)		(133	)		(141	)
Income (Loss) From Discontinued Operations, Net of Tax (Tax Benefit) of $(1), $32, and $20		(89	)		54			57
Net Loss		(215	)		(79	)		(84	)
Preferred Dividends		11			11			10
Redemption Premium on Preferred Stock		1			—			—
Net Loss Available to Common Stockholders	$	(227	)	$	(90	)	$	(94	)

CMS-35

	Years Ended December 31
	2007			2006			2005
	In Millions, Except Per
	Share Amounts
CMS Energy
Net Loss
Net Loss Available to Common Stockholders	$	(227	)	$	(90	)	$	(94	)
Basic Earnings (Loss) Per Average Common Share
Loss from Continuing Operations	$	(0.62	)	$	(0.66	)	$	(0.71	)
Gain (Loss) from Discontinued Operations		(0.40	)		0.25			0.27
Net Loss Attributable to Common Stock	$	(1.02	)	$	(0.41	)	$	(0.44	)
Diluted Earnings (Loss) Per Average Common Share
Loss from Continuing Operations	$	(0.62	)	$	(0.66	)	$	(0.71	)
Gain (Loss) from Discontinued Operations		(0.40	)		0.25			0.27
Net Loss Attributable to Common Stock	$	(1.02	)	$	(0.41	)	$	(0.44	)
Dividends Declared Per Common Share	$	0.20		$	—		$	—

The accompanying notes are an integral part of these statements.

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CMS Energy Corporation

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31
	2007			2006			2005
	In Millions
Cash Flows from Operating Activities
Net loss	$	(215	)	$	(79	)	$	(84	)
Adjustments to reconcile net loss to net cash provided by operating activities Depreciation and amortization, net of nuclear decommissioning of $4, $6,  and $6		545			576			525
Deferred income taxes and investment tax credit		(221	)		(271	)		(199	)
Minority obligations, net		(10	)		(100	)		(440	)
Asset impairment charges, net of insurance recoveries		204			459			1,184
Postretirement benefits expense		131			131			112
Electric sales contract termination		279			—			—
Shareholder class action settlement expense		—			125			—
Fuel costs mark-to-market at the MCV Partnership		—			204			(200	)
Regulatory return on capital expenditures		(31	)		(26	)		(4	)
Capital lease and other amortization		55			44			40
Bad debt expense		37			28			23
Loss (gain) on the sale of assets		112			(79	)		(20	)
Earnings from equity method investees		(40	)		(89	)		(125	)
Cash distributions from equity method investees		18			75			108
Postretirement benefits contributions		(184	)		(69	)		(63	)
Shareholder class action settlement payment		(125	)		—			—
Changes in other assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenues		(451	)		75			(246	)
Decrease (increase) in accrued power supply and gas revenue		99			(91	)		(65	)
Increase in inventories		(10	)		(105	)		(245	)
Increase (decrease) in accounts payable		(45	)		(43	)		170
Increase (decrease) in accrued expenses		(31	)		39			8
Increase (decrease) in the MCV Partnership gas supplier funds on deposit		—			(147	)		173
Decrease (increase) in other current and non-current assets		41			56			(38	)
Increase (decrease) in other current and non-current liabilities		(131	)		(27	)		(16	)
Net cash provided by operating activities		27			686			598
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)		(1,263	)		(670	)		(593	)
Cost to retire property		(28	)		(78	)		(27	)
Restricted cash and restricted short-term investments		49			124			(151	)
Investments in nuclear decommissioning trust funds		(1	)		(21	)		(6	)
Proceeds from nuclear decommissioning trust funds		333			22			39
Purchases of available-for-sale SERP investments		(68	)		(4	)		(2	)
Proceeds from available-for-sale SERP investments		64			6			3
Proceeds from short-term investments		—			—			295
Purchase of short-term investments		—			—			(186	)
Maturity of the MCV Partnership restricted investment securities held-to-maturity		—			130			318
Purchase of the MCV Partnership restricted investment securities held-to-maturity		—			(131	)		(270	)
Proceeds from sale of assets		1,717			69			61
Cash relinquished from sale of assets		(113	)		(148	)		—
Decrease (increase) in non-current notes receivable		(32	)		(50	)		1
Other investing		—			2			25
Net cash provided by (used in) investing activities		658			(749	)		(493	)

CMS-37

	Years Ended December 31
	2007			2006			2005
	In Millions
Cash Flows from Financing Activities
Proceeds from notes, bonds, and other long-term debt	$	515		$	100		$	1,385
Issuance of common stock		15			8			295
Retirement of bonds and other long-term debt		(1,095	)		(493	)		(1,509	)
Redemption of preferred stock		(32	)		—			—
Payment of common stock dividends		(45	)		—			—
Payment of preferred stock dividends		(11	)		(11	)		(11	)
Payment of capital lease and financial lease obligations		(20	)		(26	)		(29	)
Debt issuance costs, financing fees, and other		(17	)		(12	)		(57	)
Net cash provided by (used in) financing activities		(690	)		(434	)		74
Effect of Exchange Rates on Cash		2			1			(1	)
Net Increase (Decrease) in Cash and Cash Equivalents		(3	)		(496	)		178
Cash and Cash Equivalents, Beginning of Period		351			847			669
Cash and Cash Equivalents, End of Period	$	348		$	351		$	847
Other cash flow activities and non-cash investing and financing activities were:
Cash transactions
Interest paid (net of amounts capitalized)	$	432		$	487		$	454
Income taxes paid (net of refunds of $- , $2, and $11)		14			98			3
Non-cash transactions
Other assets placed under capital lease	$	229		$	7		$	12

The accompanying notes are an integral part of these statements.

CMS-38

CMS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

	December 31
	2007		2006
	In Millions
ASSETS
Plant and Property (At cost)
Electric utility	$	8,555	$	8,504
Gas utility		3,467		3,273
Enterprises		391		453
Other		34		33
		12,447		12,263
Less accumulated depreciation, depletion and amortization		4,166		5,194
		8,281		7,069
Construction work-in-progress		447		639
		8,728		7,708
Investments
Enterprises		6		556
Other		5		10
		11		566
Current Assets
Cash and cash equivalents at cost, which approximates market		348		249
Restricted cash at cost, which approximates market		34		71
Accounts receivable and accrued revenue, less allowances of $21 in 2007 and $25 in 2006		837		502
Notes receivable		68		48
Accrued power supply and gas revenue		45		156
Accounts receivable and notes receivable — related parties		2		62
Inventories at average cost
Gas in underground storage		1,123		1,129
Materials and supplies		86		87
Generating plant fuel stock		125		126
Regulatory assets — postretirement benefits		19		19
Deferred income taxes		—		155
Deferred property taxes		158		150
Assets held for sale		—		239
Price risk management assets		1		45
Prepayments and other		38		105
		2,884		3,143
Non-current Assets
Regulatory Assets
Securitized costs		466		514
Postretirement benefits		921		1,131
Customer Choice Act		149		190
Other		504		497
Nuclear decommissioning trust funds		—		602
Deferred income taxes		99		—
Notes receivable, less allowances of $31 in 2007 and $50 in 2006		170		137
Notes receivable — related parties, less allowance of $50 in 2006		—		125
Assets held for sale		—		412
Price risk management assets		1		19
Other		263		327
		2,573		3,954
Total Assets	$	14,196	$	15,371

CMS-39

	December 31
	2007			2006
	In Millions
STOCKHOLDERS’ INVESTMENT AND LIABILITIES
Capitalization
Common stockholders’ equity
Common stock, authorized 350.0 shares; outstanding 225.1 shares and 222.8 shares, respectively	$	2		$	2
Other paid-in capital		4,480			4,468
Accumulated other comprehensive loss		(144	)		(318	)
Retained deficit		(2,208	)		(1,918	)
		2,130			2,234
Preferred stock of subsidiary		44			44
Preferred stock		250			261
Long-term debt		5,385			6,200
Long-term debt — related parties		178			178
Non-current portion of capital and finance lease obligations		225			42
		8,212			8,959
Minority Interests		53			52
Current Liabilities
Current portion of long-term debt, capital and finance lease obligations		722			563
Notes payable		1			2
Accounts payable		432			481
Accrued rate refunds		19			37
Accounts payable — related parties		1			2
Accrued interest		103			126
Accrued taxes		308			301
Regulatory liabilities		164			—
Deferred income taxes		41			—
Electric sales contract termination liability		279			—
Argentine currency impairment reserve		197			—
Legal settlement liability		—			200
Liabilities held for sale		—			144
Price risk management liabilities		9			70
Other		201			230
		2,477			2,156
Non-current Liabilities
Regulatory Liabilities
Regulatory liabilities for cost of removal		1,127			1,166
Income taxes, net		533			539
Other regulatory liabilities		313			249
Postretirement benefits		858			1,066
Deferred income taxes		—			123
Deferred investment tax credit		58			62
Asset retirement obligation		198			498
Liabilities held for sale		—			59
Price risk management liabilities		16			31
Other		351			411
		3,454			4,204
Commitments and Contingencies (Notes 3, 4, 6, 9 and 11)
Total Stockholders’ Investment and Liabilities	$	14,196		$	15,371

The accompanying notes are an integral part of these statements.

CMS-40

CMS Energy Corporation

Consolidated Statements of Common Stockholders’ Equity

	Years Ended December 31
	2007			2006			2005			2007			2006			2005
	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		222,783			220,497			194,997			4,468			4,436			4,140
Common stock repurchased		(318	)		(98	)		(88	)		(5	)		(2	)		(1	)
Common stock reacquired		(19	)		(59	)		—			—			—			—
Common stock issued		2,339			2,375			25,493			30			33			296
Common stock reissued		361			68			95			6			1			1
Redemption of preferred stock		—			—			—			(19	)		—			—
At end of period		225,146			222,783			220,497			4,480			4,468			4,436
Accumulated Other Comprehensive Loss
Retirement benefits liability
At beginning of period											(23	)		(19	)		(17	)
Retirement benefits liability adjustments(a)											—			3			(2	)
Net gain arising during the period(a)											7			—			—
Amortization of net actuarial loss(a)											1			—			—
Adjustment to initially apply FASB Statement No. 158											—			(7	)		—
At end of period											(15	)		(23	)		(19	)
Investments
At beginning of period											14			9			9
Unrealized gain on investments(a)											1			5			—
Reclassification adjustments included in net loss(a)											(15	)		—			—
At end of period											—			14			9
Derivative instruments
At beginning of period											(12	)		35			(9	)
Unrealized gain (loss) on derivative instruments(a)											(3	)		(15	)		51
Reclassification adjustments included in net loss(a)											14			(32	)		(7	)
At end of period											(1	)		(12	)		35
Foreign currency translation
At beginning of period											(297	)		(313	)		(319	)
Sale of Argentine assets(a)											128			—			—
Sale of Brazilian assets(a)											36			—			—
Other foreign currency translations(a)											5			16			6
At end of period											(128	)		(297	)		(313	)
At end of period											(144	)		(318	)		(288	)
Retained Deficit
At beginning of period											(1,918	)		(1,828	)		(1,734	)
Adjustment to initially apply FIN 48											(18	)		—			—
Net loss(a)											(215	)		(79	)		(84	)
Preferred stock dividends declared											(11	)		(11	)		(10	)
Common stock dividends declared											(45	)		—			—
Redemption of preferred stock(a)											(1	)		—			—
At end of period											(2,208	)		(1,918	)		(1,828	)
Total Common Stockholders’ Equity										$	2,130		$	2,234		$	2,322

CMS-41

	Years Ended December 31
	2007			2006			2005
	In Millions
(a) Disclosure of Comprehensive Loss:
Net loss	$	(215	)	$	(79	)	$	(84	)
Retirement benefits liability:
Retirement benefits liability adjustments, net of tax (tax benefit) of $1 in 2006 and $(1) in 2005		—			3			(2	)
Net gain arising during the period, net of tax of $5		7			—			—
Amortization of net actuarial loss, net of tax of $-		1			—			—
Investments:
Unrealized gain on investments, net of tax of $- in 2007 and $2 in 2006		1			5			—
Reclassification adjustments included in net loss, net of tax benefit of $(7)		(15	)		—			—
Derivative instruments:
Unrealized gain (loss) on derivative instruments, net of tax (tax benefit)
of $2 in 2007, $(11) in 2006, and $29 in 2005		(3	)		(15	)		51
Reclassification adjustments included in net loss, net of tax (tax benefit) of $7 in 2007, $(19) in 2006, and $(9) in 2005		14			(32	)		(7	)
Foreign currency translation:
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 $2 in 2007, $9 in 2006, and $- in 2005		5			16			6
Redemption of preferred stock, net of tax benefit of $1		(1	)		—			—
Total Comprehensive Loss	$	(42	)	$	(102	)	$	(36	)

The accompanying notes are an integral part of these statements.

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CMS-43

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 Consumers and Enterprises. Consumers is a combination electric and gas utility company serving in Michigan’s Lower Peninsula. Enterprises, through various subsidiaries and equity investments, is engaged primarily in domestic independent power production. We manage our businesses by the nature of services each provides and operate principally in three business segments: electric utility, gas utility, and enterprises.

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

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

We record estimated liabilities for contingencies in our consolidated financial statements when it is probable that a liability has been incurred, and when the amount of loss can be reasonably estimated. For additional details, see Note 3, 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. We record sales tax on a net basis and exclude it from revenues. We recognize revenues on sales of marketed electricity, natural gas, and other energy products at delivery. For trading and non-trading energy contracts that qualify as derivatives, we recognize changes in the fair value of those contracts (mark-to-market gains and losses) in earnings as the changes occur.

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; such 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 Equivalents and Restricted Cash: Cash equivalents are all liquid investments with an original maturity of three months or less.

At December 31, 2007, our restricted cash on hand was $34 million. We classify restricted cash dedicated for repayment of Securitization bonds as a current asset, as the related payments occur within one year.

Collective Bargaining Agreements: At December 31, 2007, the Utility Workers of America Union represented 46 percent of Consumers’ employees. The Union represents Consumers’ operating, maintenance, construction, and call center employees.

CMS-44

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Determination of Pension 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 use the MRV in the calculation of net pension cost.

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 5, 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. We reflected unrealized gains and losses on our nuclear decommissioning investments as regulatory liabilities on our Consolidated Balance Sheets.

In accordance with SFAS No. 133, if a contract is a derivative and does not qualify for the normal purchases and sales exception, it is recorded 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.

Goodwill: Goodwill is the excess of the purchase price over the fair value of the net assets of acquired companies. We test goodwill annually for impairment. We eliminated our goodwill in 2007 with the sale of several Enterprises businesses.

The changes in the carrying amount of goodwill at the Enterprises segment for the years ended December 31, 2006 and 2007 are included in the following table:

	In Millions
Balance at January 1, 2006	$	27
Currency translation adjustment		(1	)
Balance at December 31, 2006	$	26
Currency translation adjustment		2
Sale of CMS Energy Brasil S.A.		(28	)
Balance at December 31, 2007	$	—

Impairment of Long-Lived Assets and Equity Method Investments: 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.

A long-lived asset held-in-use is evaluated 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

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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 2, Asset Sales, Discontinued Operations and Impairment Charges.

International Operations and Foreign Currency: Our subsidiaries and affiliates whose functional currency is not the U.S. dollar translate their assets and liabilities into U.S. dollars at the exchange rates in effect at the end of the fiscal period. We translate revenue and expense accounts of such subsidiaries and affiliates into U.S. dollars at the average exchange rates that prevailed during the period. We show these foreign currency translation adjustments in the stockholders’ equity 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.

We completed the sale of our international assets in 2007. For additional details, see Note 2, 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 the emission allowances are used 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	2007			2006			2005
Electric utility property		3.0	%		3.1	%		3.1%
Gas utility property		3.6	%		3.6	%		3.6%
Other property		8.7	%		8.2	%		7.6%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Other Income and Other Expense: The following tables show the items we report in Other income and Other expense:

Years Ended December 31	2007		2006		2005
	In Millions
Other income
Interest and dividends — related parties	$	—	$	8	$	9
Gain on SERP investment		22		—		—
Return on stranded and security costs		6		5		6
MCV Partnership emmission allowance sales		—		8		2
Electric restructuring return		2		4		6
Gain on investment		7		1		—
Settlement of contingent liability		—		—		3
Refund of surety bond premium		—		1		—
All other		3		4		7
Total other income	$	40	$	31	$	33

Years Ended December 31	2007			2006			2005
	In Millions
Other expense
Accretion expense	$	—		$	(4	)	$	(18	)
Loss on SERP investment		—			—			(2	)
Loss on reacquired and extinguished debt		(22	)		(5	)		(16	)
Abandoned Midland project		(8	)		—			—
Derivative loss on debt tender offer		(3	)		—			—
Civic and political expenditures		(2	)		(2	)		(2	)
Donations		—			(9	)		—
All other		(4	)		(1	)		(7	)
Total other expense	$	(39	)	$	(21	)	$	(45	)

Property, Plant, and Equipment: We record property, plant, and equipment at original cost when placed into service. When regulated assets are 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. 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 of AFUDC capitalized 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 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	2007			2006			2005
Composite AFUDC capitalization rate		7.4	%		7.5	%		7.6%

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Reclassifications: We have reclassified certain prior-period amounts on our Consolidated Financial Statements to conform to the presentation for the current period. These reclassifications did not affect consolidated net loss or cash flows for the periods presented. The most significant of these reclassifications is related to certain subsidiaries reclassified as “held for sale” on our Consolidated Balance Sheets and activities of those subsidiaries as Income (Loss) From Discontinued Operations in our Consolidated Statements of Income (Loss). For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges, “Discontinued Operations.”

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. Unbilled receivables were $490 million in 2007 and $355 million in 2006. 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.

Unamortized Debt Premium, Discount, and Expense: We capitalize premiums, discounts, and 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 expenses and amortize them over the terms of the newly issued debt.

Utility Regulation: Consumers is subject to the actions of the MPSC and FERC and prepare 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 such expenses will be recovered 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 they will require that such revenues be refunded to customers.

We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets at December 31, 2007.

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December 31	End of Recovery Period	2007		2006
	In Millions
Assets Earning a Return:
Customer Choice Act	2010	$	149	$	190
Unamortized debt costs	2035		74		86
Stranded Costs	See Note 3		68		65
Electric restructuring implementation plan	2008		14		40
Manufactured gas plant sites (Note 3)	2016		33		15
Abandoned Midland project	n/a		—		9
Other(a)	various		50		21
Assets Not Earning a Return:
SFAS No. 158 transition adjustment (Note 7)	various		851		1,038
Securitized costs (Note 4)	2015		466		514
Postretirement benefits (Note 7)	2011		89		112
ARO (Note 8)	n/a		85		177
Big Rock nuclear decommissioning and	n/a		129		35
related costs (Note 3)
Manufactured gas plant sites (Note 3)	n/a		17		41
Palisades sales transaction costs (Note 2)	n/a		28		—
Other(a)	2011		6		8
Total regulatory assets(b)		$	2,059	$	2,351
Palisades refund — Current (Note 2)(c)		$	164	$	—
Cost of removal (Note 8)			1,127		1,166
Income taxes, net (Note 9)			533		539
ARO (Note 8)			141		180
Palisades refund — Noncurrent (Note 2)(c)			140		—
Other(a)			32		69
Total regulatory liabilities(b)		$	2,137	$	1,954

(a)	At December 31, 2007 and 2006, other regulatory assets include a gas inventory regulatory asset and OPEB and pension expense incurred in excess of the MPSC-approved amount. Consumers will recover these regulatory assets from its 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, 2007, we classified $19 million of regulatory assets as current regulatory assets and $2.040 billion of regulatory assets as non-current regulatory assets. At December 31, 2006, we classified $19 million of regulatory assets as current regulatory assets and $2.332 billion of regulatory assets as non-current regulatory assets. At December 31, 2007, we classified $164 million of regulatory liabilities as current regulatory liabilities and $1.973 billion of regulatory liabilities as non-current regulatory liabilities. At December 31, 2006, all of our regulatory liabilities represented non-current regulatory liabilities.
(c)	The MPSC order approving the Palisades and Big Rock ISFSI transaction requires that Consumers credits $255 million of excess proceeds and decommissioning amounts to its retail customers beginning in June 2007 through December 2008. 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

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decommissioning fund balances above the amount in the MPSC order. The non-current portion of regulatory liabilities for Palisades refunds represents this obligation, plus interest. For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales, Discountinued Operations, and Impairment Charges.

The PSCR and GCR cost recovery mechanisms also represent probable future revenues that will be recovered from or 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 3, Contingencies, “Consumers’ Electric Utility Rate Matters — Power Supply Costs” and for additional details on GCR, see Note 3, 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	2007		2006
	In Millions
Regulatory Assets for PSCR and GCR
Underrecoveries of power supply costs	$	45	$	156
Regulatory Liabilities for PSCR and GCR
Overrecoveries of gas	$	19	$	37

New Accounting Standards Not Yet Effective: SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us on January 1, 2008. The standard provides a revised definition of fair value and establishes a framework for measuring fair value. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value, but it requires new disclosures about the impact and reliability of fair value measurements. The standard will also eliminate the existing prohibition against recognizing “day one” gains and losses on derivative instruments. We currently do not hold any derivatives that would involve day one gains or losses. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we currently hold. We do not believe that the implementation of this standard will have a material effect on our consolidated financial statements.

In February 2008, the FASB issued a one-year deferral of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recorded or disclosed at fair value on a recurring basis. Under this partial deferral, SFAS No. 157 will not be effective until January 1, 2009 for fair value measurements in the following areas:

•  AROs,

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

•  fair value measurements performed in conjunction with impairment analyses.

SFAS No. 157 remains effective January 1, 2008 for our derivative instruments, available-for-sale investment securities, and long-term debt fair value disclosures.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us on January 1, 2008. This standard gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We do not expect to elect the fair value option for any financial instruments or other items.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Ownership interests in

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subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. Any changes in our ownership interests while control is retained will be treated as equity transactions. In addition, this standard requires presentation and disclosure of the allocation between controlling and noncontrolling interests’ income from continuing operations, discontinued operations, and comprehensive income and a reconciliation of changes in the consolidated statement of equity during the reporting period. The presentation and disclosure requirements of the standard will be applied retrospectively for all periods presented. All other requirements will be applied prospectively. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

FSP FIN 39-1, Amendment of FASB Interpretation No. 39: In April 2007, the FASB issued FSP FIN 39-1, effective for us on January 1, 2008. This standard will permit us to offset the fair value of derivative instruments with cash collateral received or paid for those derivative instruments executed with the same counterparty under a master netting arrangement. The decision to offset derivative positions under master netting arrangements remains an accounting policy choice. We have elected to offset our derivative fair values under master netting arrangements, but we currently record cash collateral amounts separately. As a result of offsetting the collateral amounts under this standard, we expect that both our total assets and total liabilities will be reduced by an immaterial amount. There will be no impact on earnings from adopting this standard. The standard is to be applied retrospectively for all periods presented in our consolidated financial statements.

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

2: 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).

The following table summarizes our 2007 asset sales:

							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	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(a)	We sold our interest in El Chocon to Endesa, S.A.
(b)	We completed the sale of a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy. We also entered into agreements that grant Lucid Energy:

•  an option to buy CMS Gas Transmission’s ownership interest in TGN, subject to the rights of other third parties,

•  the rights to certain proceeds that may be awarded and received by CMS Gas Transmission in connection with certain legal proceedings, including an ICSID arbitration award, and

•  the rights to proceeds that Enterprises will receive if it sells its interest in CMS Generation San Nicolas Company.

	Under these agreements, we have assigned our rights to certain awards or proceeds that we may receive in the future. Of the total consideration received in the sale, we allocated $32 million to these agreements and recorded this amount as a deferred credit on our Consolidated Balance Sheets. Due to the settlement of certain legal proceedings in 2007, a portion of CMS Gas Transmission’s obligations under these agreements has been satisfied. Accordingly, we recognized $17 million of the deferred credit as a gain.
	For details on the ICSID arbitration award, see Note 3, Contingencies.
(c)	In April 2007, we sold Palisades to Entergy for $380 million, and received $363 million after various closing adjustments such as working capital and capital expenditure adjustments and nuclear fuel usage and inventory 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. At closing, we transferred $252 million in decommissioning trust fund balances to Entergy. We are presently crediting excess decommissioning funds, which totaled $189 million to our retail customers through the end of 2008. Modification to the terms of the transaction allowed us immediate access to additional excess decommissioning trust funds of $123 million. The distribution of these funds is currently under review by the MPSC in our electric rate case filing. We have recorded this obligation, plus interest, as a regulatory liability on our Consolidated Balance Sheets.
	The MPSC order approving the Palisades transaction allows us to recover the book value of Palisades. As a result, we are presently crediting proceeds in excess of book value of $66 million to our retail customers through the end of 2008. After closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were $77 million. We recorded the excess proceeds as a regulatory liability on our Consolidated Balance Sheets. Recovery of our transaction costs of $28 million, which includes the NMC exit fees and investment forfeiture, is presently under review by the MPSC in our current electric rate case. We recorded these costs as a regulatory asset on our Consolidated Balance Sheets as recovery is probable.
	We accounted for the disposal of Palisades as a financing for accounting purposes and thus we recognized no gain on the Consolidated Statements of Income (Loss). We accounted for the remaining non-real estate assets and liabilities associated with the transaction as a sale. For additional details on the Palisades finance obligation, see Note 11, Leases.
(d)	We sold our ownership interest in SENECA and certain associated generating equipment to PDVSA, which is owned by the Bolivarian Republic of Venezuela.
(e)	We sold our ownership interest in businesses in the Middle East, Africa, and India to TAQA. Gross proceeds from the sale included $792 million in cash proceeds and TAQA’s assumption of $108 million in debt. Businesses included in the sale were Takoradi, Taweelah, Shuweihat, Jorf Lasfar, Jubail, and Neyveli.
(f)	We sold CMS Energy Brasil S.A. to CPFL Energia S.A., a Brazilian utility. Gross proceeds included $201 million in cash proceeds and CPFL Energia S.A.’s assumption of a $10 million tax liability.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(g)	We sold our investment in GasAtacama to Endesa S.A.
(h)	We sold our investment in Jamaica to AEI.

For the year ended December 31, 2006, we sold the following assets:

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

(a)	We sold 36 parcels of land near Ludington, Michigan. Consumers held a majority share of the land, which we co-owned with DTE Energy.
(b)	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. SFAS No. 98 specifies the accounting required for a seller’s sale and simultaneous leaseback involving real estate. 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 of $61 million (excluding $3 million of selling expenses) 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.

For the year ended December 31, 2005, we sold the following assets:

				Continuing
				Operations
		Gross Cash		Pretax
Month sold	Business/Project	Proceeds		Gain
		In Millions
February	GVK	$	21	$	4
April	SLAP		23		2
April	Gas turbine and auxiliary equipment		15		—
Various	Other		2		—
	Total	$	61	$	6

Discontinued Operations

In accordance with SFAS No. 144, our consolidated financial statements have been reclassified for all periods presented to reflect the operations, assets and liabilities of our consolidated subsidiaries that meet the criteria of

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discontinued operations. The assets and liabilities of these subsidiaries have been classified as “Assets held for sale” and “Liabilities held for sale” on our December 31, 2006 Consolidated Balance Sheets. Subsidiaries classified as “held for sale” at December 31, 2006 include our Argentine businesses, a majority of our Michigan non-utility gas businesses, CMS Energy Brasil S.A., SENECA, Takoradi, and certain associated holding companies. At December 31, 2007, there were no subsidiaries classified as “held for sale” due to the completion of these sales in the first and second quarters of 2007.

The major classes of assets and liabilities “held for sale” on our December 31, 2006 Consolidated Balance Sheet are as follows:

	In Millions
Assets
Cash	$	102
Accounts receivable, net		105
Notes receivable		110
Goodwill		25
Investments		33
Property, plant and equipment, net		233
Other		43
Total assets	$	651
Liabilities
Accounts payable	$	82
Accrued taxes		30
Minority interest		40
Other		51
Total liabilities	$	203

Our discontinued operations contain the activities of the subsidiaries classified as “held for sale” as well as those disposed of for the year ended December 31, 2007 and are a component of our Enterprises business segment. We reflect the following amounts in the Income (Loss) From Discontinued Operations line in our Consolidated Statements of Income (Loss):

Years Ended December 31	2007			2006		2005
	In Millions
Revenues	$	235		$	684	$	409
Discontinued operations:
Pretax income (loss) from discontinued operations	$	(90	)	$	86	$	77
Income tax expense (benefit)		(1	)		32		20
Income (Loss) From Discontinued Operations	$	(89	)(a)	$	54	$	57

(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 interest 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).

Income (Loss) From Discontinued Operations includes a provision for anticipated closing costs and a portion of CMS Energy’s parent company interest expense. Interest expense of $7 million for 2007, $17 million for 2006, and $16 million for 2005 has been allocated based on the net book value of the asset to be sold divided by CMS Energy’s total capitalization of each discontinued operation multiplied by CMS Energy’s interest expense.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Impairment Charges

The table below summarizes our asset impairments:

Years Ended December 31	2007		2006		2005
	In Millions
Asset impairments:
Enterprises:
TGN(a)	$	140	$	—	$	—
GasAtacama(b)		35		239		—
Jamaica(c)		22		—		—
PowerSmith(d)		5		—		—
Prairie State(e)		2		—		—
MCV Partnership(f)		—		218		1,184
Other		—		2		—
Total asset impairments	$	204	$	459	$	1,184

(a)	In the first quarter of 2007, 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 approximately $197 million.
	In December 2005, certain insurance underwriters paid $75 million to CMS Gas Transmission in respect of their insurance obligations resulting from the non-payment of the ICSID award. We recorded this payment as a deferred credit on our Consolidated Balance Sheets because of a contingent obligation to refund the proceeds if the arbitration decision was annulled. In September 2007, the contingent repayment obligation was eliminated by agreement and a separate arbitration panel ruling on the annulment issue upheld the prior ICSID award. As a result, we recognized the $75 million deferred credit in Asset impairment charges, net of insurance recoveries on our Consolidated Statements of Income (Loss). For additional details on this settlement, see Note 3, Contingencies, “Other Contingencies — Argentina.”
(b)	In August 2006, a major gas supplier notified GasAtacama that it would no longer deliver gas to GasAtacama due to the Argentine government’s decision to increase the cost of its gas exports using a special tax. 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. As a result, our consolidated net income was reduced by $169 million, net of tax and minority interest.
	In the second quarter of 2007, we recorded a further impairment charge to reflect expected proceeds from the pending sale of our investment in GasAtacama.
(c)	In the first quarter of 2007, 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)	In the first quarter of 2007, we recorded an impairment charge to reflect the fair value of our investment in PowerSmith as determined in sale negotiations.
(e)	In the second quarter of 2007, we recorded an impairment charge to reflect our withdrawal from the co-development of Prairie State with Peabody Energy because it did not meet our investment criteria.
(f)	In November 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.
	In the third quarter of 2005, based on forecasts for higher natural gas prices, the MCV Partnership determined an impairment analysis considering revised forward natural gas price assumptions was required. The MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows. The carrying value of the MCV Partnership’s fixed assets exceeded the estimated

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fair value resulting in impairment charges of $1.159 billion to recognize the reduction in fair value of the MCV Facility’s fixed assets and $25 million of interest capitalized during the construction of the MCV Facility. Our 2005 consolidated net income was reduced by $385 million, after considering tax effects and minority interest.

We report our interests in the MCV Partnership as a component of our “Enterprises” business segment.

3: CONTINGENCIES

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

SEC Investigation and Settlement: In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order’s findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies. The two individuals filed a motion to dismiss the SEC action, which was denied.

Securities Class Action Settlement: Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the United States District Court for the Eastern District of Michigan. The cases were consolidated into a single lawsuit (the “Shareholder Action”), which generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy’s business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the court conditionally certified a class consisting of “all persons who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17, 2002 and who were damaged thereby.” The court excluded purchasers of CMS Energy’s 8.75 percent Adjustable Convertible Trust Securities (“ACTS”) from the class and, in response, a new class action lawsuit was filed on behalf of ACTS purchasers (the “ACTS Action”) against the same defendants named in the Shareholder Action. The settlement described in the following paragraph has resolved both the Shareholder and ACTS Actions.

On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the “MOU”), 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 was settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy made a payment of approximately $123 million plus interest on the settlement amount on September 20, 2007. CMS Energy’s insurers paid $77 million, the balance of the settlement amount. In entering into the MOU, CMS Energy made no admission of liability under the Shareholder Action and the ACTS Action. The parties executed a Stipulation and Agreement of Settlement dated May 22, 2007 (“Stipulation”) incorporating the terms of the MOU. In accordance with the Stipulation, CMS Energy paid approximately $1 million of the settlement amount to fund administrative expenses. On September 6, 2007, the court issued a final order approving the settlement. The remaining settlement amount was paid following the September 6, 2007 hearing.

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Gas Index Price Reporting Investigation: 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 cooperated with an investigation by the DOJ regarding this matter. Although CMS Energy has not received any formal notification that the DOJ has completed its investigation, the DOJ’s last request for information occurred in November 2003, and CMS Energy completed its response to this request in May 2004. CMS Energy is unable to predict the outcome of the DOJ investigation and what effect, if any, the investigation will have on its business. The CFTC filed a civil injunctive action against two former CMS Field Services employees in Oklahoma federal district court on February 1, 2005. The action alleged the two engaged in reporting false natural gas trade information, and sought to prohibit these acts, compel compliance with the Commodities Exchange Act, and impose monetary penalties. The court entered separate consent orders with respect to each of the two individuals, one dated April 18, 2007 and one dated June 25, 2007, resolving this litigation. The consent orders prohibit each of the individuals from engaging in certain activities and further provide civil monetary penalties in the amount of $100,000 for one individual and $25,000 for the other individual. Pursuant to agreements with each of the individuals, CMS Energy has paid $95,000 of the $100,000 amount and $22,000 of the $25,000 amount, with the remaining amounts paid by the individuals themselves.

Gas Index Price Reporting Litigation: CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and Cantera Gas Company are named as defendants in various lawsuits arising as a result of claimed 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. CMS MST has settled a master class action suit in California state court for $7 million. The CMS Energy defendants have also settled four class action suits originally filed in California federal court. The other cases in several state jurisdictions remain pending. We cannot predict the financial impact or outcome of these matters.

Katz Technology Litigation: In June 2007, RAKTL filed a lawsuit in the United States District Court for the Eastern District of Michigan against CMS Energy and Consumers alleging patent infringement. RAKTL claimed that automated customer service, bill payment services and gas leak reporting offered to our customers and accessed through toll free numbers infringe on patents held by RAKTL. On January 15, 2008, Consumers and CMS Energy reached an agreement in principle with RAKTL to settle the litigation. We expect to finalize the terms of the settlement and license by late February 2008. We believe any settlement with RAKTL will be immaterial.

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 September 2004, the MDEQ issued a notice of noncompliance after finding high-pH leachate in Lake Michigan adjacent to the property. The MDEQ also alleged higher than acceptable levels of heavy metals, including mercury, in the leachate flow.

In 2005, the EPA along with CMS Land and CMS Capital executed an AOC and approved a Removal Action Work Plan to address problems at Bay Harbor. Among other things, the plan called for the installation of collection trenches to capture high-pH leachate flow to the lake. Collection systems required under the plan have been installed and shoreline monitoring is ongoing. CMS Land and CMS Capital are required to address observed exceedances in pH, including required enhancements of the collection system. In May 2006, the EPA approved a pilot carbon dioxide enhancement plan to improve pH results in a specific area of the collection system. The

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enhanced system was installed in June 2006. CMS Land and CMS Capital also engaged in other enhancements of the installed collection systems.

In November 2007, the EPA sent CMS Land and CMS Capital a letter identifying three separate areas representing approximately 700 feet of shoreline in which the EPA claimed pH levels were unacceptable. The letter also took the position that CMS Land and CMS Capital are required to remedy the claimed noncompliance. CMS Land and CMS Capital submitted a formal objection to the EPA’s conclusions. In their objections, CMS Land and CMS Capital noted that the AOC did not require perfection and that over 97 percent of the measured pH levels were in the correct range. Further, the limited number of exceedances were not much above the pH nine level set by the AOC and posed no threat to the public health and safety. In addition, CMS Land and CMS Capital noted in their objection that the actions they had already taken fully complied with the terms of the AOC. In January 2008, the EPA advised CMS Land and CMS Capital that it had rejected their objections, and that CMS Land and CMS Capital were obligated to submit a plan to augment measures to collect high pH leachate under the terms of the November 2007 EPA letter as modified in the January 2008 letter. CMS Land and CMS Capital submitted a proposed augmentation plan in February 2008.

In February 2006, CMS Land and CMS Capital submitted to the EPA a proposed Remedial Investigation and Feasibility Study (RIFS) for one of the CKD piles known as the East Park CKD pile. A similar RIFS is planned to be submitted for the remaining CKD piles in 2008. The EPA approved a schedule for near-term activities, which includes consolidating certain CKD materials and installing collection trenches in the East Park leachate release area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan and Final Engineering Design for Consolidation. However, the EPA has not approved the RIFS for the East Park.

As a result of the installation of collection systems at the Bay Harbor sites, CMS Land and CMS Capital are collecting and treating 135,000 gallons of liquid per day and shipping it by truck for disposal at a nearby well and at a municipal wastewater treatment plant located in Traverse City, Michigan. To address both short term and longer-term disposal of liquid, CMS Land has filed two permit applications with the MDEQ and the EPA, the first to treat the collected leachate at the Bay Harbor sites before releasing the water to Lake Michigan and the second to dispose of it in a deep injection well in Alba, Michigan, that CMS Land or its affiliate would own and operate. In February 2008, the MDEQ and the EPA granted permits for CMS Land or its affiliate to construct and operate a deep injection well near Alba, Michigan in eastern Antrim County. Certain environmental groups and a local township have indicated they may challenge these permits before the agencies or the courts.

CMS Land and CMS Capital, the MDEQ, and the EPA have ongoing discussions concerning the long-term remedy for the Bay Harbor sites. These negotiations are addressing, among other things, issues relating to the disposal of leachate, 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 CMS Land and CMS Capital may be obliged to undertake. Negotiations have been ongoing for over a year, but CMS Land and CMS Capital have not been able to resolve these issues with the regulators and they remain pending.

CMS Land has entered into various access, purchase and settlement agreements with several of the affected landowners at Bay Harbor, and entered into a confidential settlement with one landowner to resolve a lawsuit filed by that landowner. We have received demands for indemnification relating to claims made by a property owner at Bay Harbor. CMS Land has purchased five unimproved lots and two lots with houses.

CMS Energy has recorded cumulative charges, including accretion expense, related to this matter of $140 million ($44 million of which was recorded in 2007). Several factors contributed to the need to revise remediation cost estimates in 2007. One of the major components of the revised remediation cost related to the disposal of collected liquid as discussed in preceding paragraphs. There has been a delay in the receipt of the Alba well permits from the schedule originally anticipated by CMS Land and CMS Capital, who also received an unfavorable response from the regulators concerning the plan to treat and release the leachate to Lake Michigan.

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Also, CMS Energy is recognizing a higher cost for operating and maintaining the existing collection system. In addition, CMS Land and CMS Capital have been unable to reach an agreement with the MDEQ and the EPA over the scope of necessary remedial work. Furthermore, the EPA’s issuance in November 2007 of its order requiring augmentation and accelerated actions regarding the high pH leachate recovery system caused CMS Land and CMS Capital to reconsider and modify their plans regarding the scope and schedule of the leachate collection systems and related shoreline work.

At December 31, 2007, CMS Energy has a recorded liability of $80 million for its remaining obligations. We calculated this liability based on discounted projected costs, using a discount rate of 4.45 percent and an inflation rate of 1 percent on annual operating and maintenance costs. We used the interest rate for 30-year U.S. Treasury securities for the discount rate. The undiscounted amount of the remaining obligation is $94 million. We expect to pay $18 million in 2008, $16 million in 2009, $9 million in 2010 and in 2011, and the remaining expenditures as part of long-term liquid disposal and operating and maintenance costs. Any significant change in circumstances or assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, continued inability to reach agreement with the MDEQ or 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, additional or new legal or regulatory requirements, or new or different landowner claims, could impact our estimate of remedial action costs and the timing of the expenditures. An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy’s financial condition and liquidity and could negatively impact CMS Energy’s financial results. CMS Energy cannot predict the financial impact or outcome of this matter.

Consumers’ Electric Utility Contingencies

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

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 $1 million and $10 million. At December 31, 2007, we have recorded a liability for the minimum amount of our estimated probable Superfund liability in accordance with FIN 14.

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

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

Electric Utility Plant Air Permit Issues: In April 2007, we received a Notice of Violation (NOV) /Finding of Violation (FOV) from the EPA alleging that fourteen of our utility boilers exceeded visible emission limits in their associated air permits. The utility boilers are located at the D.E. Karn/J.C. Weadock Generating Complex, J.H.

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Campbell Plant, B.C. Cobb Electric Generating Station and J.R. Whiting Plant, which are all located in Michigan. We have formally responded 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.

Litigation: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs) filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made under power purchase agreements. The judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The plaintiffs have an appeal of the MPSC order pending with the Court of Appeals. We believe we have been performing the calculation in the manner prescribed by the power purchase agreements and have not recorded any reserves. We cannot predict the financial impact or outcome of this matter.

Consumers’ Electric Utility Rate Matters

Electric ROA: The Customer Choice Act allows electric utilities to recover their net Stranded Costs. In November 2004, the MPSC approved recovery of our Stranded Costs incurred from 2002 through 2003 plus interest through the period of collection. At December 31, 2007, we had a regulatory asset for Stranded Costs of $68 million. We collect these Stranded Costs through a surcharge on ROA customers. At December 31, 2007, alternative electric suppliers were providing 315 MW of generation service to ROA customers, which represents an increase of 5 percent of ROA load compared to December 31, 2006. However, since the MPSC order, we have experienced a downward trend in ROA customers. This trend has affected negatively our ability to recover these Stranded Costs in a timely manner. If this trend continues, it may require legislative or regulatory assistance to recover fully our 2002 and 2003 Stranded Costs.

Power Supply Costs: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudency in annual plan proceedings and in plan reconciliation proceedings. The following table summarizes our PSCR reconciliation filings with the MPSC:

Power Supply Cost Recovery Reconciliation
			Net Under-	PSCR Cost
PSCR Year	Date Filed	Order Date	recovery	of Power Sold	Description of Net Underrecovery
2005 Reconciliation	March 2006	July 2007	$36 million	$1.081 billion	MPSC approved the recovery of our $36 million underrecovery, including interest, related to our commercial and industrial customers.
2006 Reconciliation	March 2007	Pending	$105 million(a)	$1.490 billion	Underrecovery relates to our increased METC costs and coal supply costs, certain increased sales, and other cost increases beyond those included in the 2006 PSCR plan filings.

(a) $99 million as recommended by a February 2008 ALJ Proposal for Decision. In a separate matter, this ALJ also recommended that we refund $62 million in proceeds from the sale of excess sulfur dioxide allowances. In accordance with FERC regulations, we previously reserved these proceeds as a regulatory liability pending final direction on disposition of the proceeds from the MPSC.

2007 PSCR Plan: In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as filed. The order also allowed us to include prior year underrecoveries and overrecoveries in future PSCR plans. In September 2007, the ALJ recommended in his Proposal for Decision that we reduce our underrecoveries to reflect the refund of all proceeds from the sale of sulfur dioxide allowances,

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which totaled $62 million. Our PSCR plan proposed to refund 50 percent of proceeds to customers. We reserved all proceeds, excluding interest, as a regulatory liability as discussed in the preceding paragraph.

2008 PSCR Plan: In September 2007, we submitted our 2008 PSCR plan filing to the MPSC. The plan proposed recovery of estimated 2007 PSCR underrecoveries of $84 million. We self-implemented a 2008 PSCR charge in January 2008.

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

Electric Rate Case: In 2007, we filed applications with the MPSC seeking an 11.25 percent authorized return on equity and an annual increase in revenues of $269 million. We presently have an authorized return on equity of 11.15 percent. In July 2007, we filed an amended application for rate relief, which seeks the following:

•  recovery of the purchase of the Zeeland power plant,

•  approval to remove the costs associated with Palisades,

•  approval of a plan for the distribution of additional excess proceeds from the sale of Palisades to customers, effectively offsetting the partial and immediate rate relief for up to nine months, and

•  partial and immediate rate relief associated with 2007 capital investments, a $400 million equity infusion into Consumers, and increased distribution system operation and maintenance costs including employee pension and health care costs.

In December 2007, the MPSC approved a rate increase of $70 million related to the purchase of the Zeeland power plant. The MPSC also stated that our interim request that sought the removal of costs associated with Palisades and the approval of a plan to distribute excess proceeds from the sale of Palisades to customers should be addressed in the final electric rate case order. Furthermore, the MPSC denied our request for the approval of partial and immediate rate relief associated with capital investments, changes in the capital structure, and increased operation and maintenance expenses.

When we are unable to include increased costs and investments in rates in a timely manner, there is a negative impact on our cash flows from electric utility operations. We cannot predict the financial impact or the outcome of this proceeding.

Other Consumers’ Electric Utility Contingencies

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-year power purchase agreement that began in 1990. We estimate that capacity and energy payments under the MCV PPA, excluding RCP savings, will range from $650 million to $750 million annually, assuming successful exercise of the regulatory-out provision in the MCV PPA. We purchased capacity and energy, net of the MCV RCP replacement energy and benefits, under the MCV PPA of $464 million in 2007, $411 million in 2006, and $352 million in 2005.

Regulatory-out Provision in the MCV PPA: Until we exercised the regulatory-out provision in the MCV PPA in September 2007, the cost that we incurred under the MCV PPA exceeded the recovery amount allowed by the MPSC. The regulatory-out provision limits our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. Cash underrecoveries of our capacity and fixed energy payments were $39 million in 2007. Savings from the RCP, after allocation of a portion to customers, offset some of our capacity and fixed energy underrecoveries expense.

As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain circumstances, have the right to terminate the MCV PPA, or reduce the amount of capacity sold under the

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MCV PPA from 1,240 MW to 806 MW, which could affect our electric Reserve Margin. The MCV Partnership has until February 25, 2008 to notify us of its intention to terminate the MCV PPA, at which time the MCV Partnership must specify the termination date. We have not yet received any notification of termination; however, the MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision. We believe that the provision is valid and fully effective and have not recorded any reserves, but we cannot predict whether we would prevail in the event of litigation on this issue.

We expect the MPSC to review our exercise of the regulatory-out provision and the likely consequences of such action. It is possible that in the event that the MCV Partnership terminates performance under the MCV PPA, prior orders could limit recovery of replacement power costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the cost of replacement power, this could result in our costs exceeding the recovery amount allowed by the MPSC. We cannot predict the financial impact or outcome of these matters.

To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a determination as to whether it wished to reconsider the amount of the MCV PPA payments that we recover from customers. The MCV Partnership also filed an application with the MPSC requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed energy charges that we are allowed to recover from our customers. We cannot predict the financial impact or outcome of these matters.

Nuclear Matters: Big Rock Decommissioning: The MPSC and the FERC regulate the recovery of costs to decommission Big Rock. In December 2000, funding of the Big Rock trust fund stopped 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 $45 million of corporate contributions for decommissioning costs. This amount excludes 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 $54 million, due to the DOE’s failure to accept spent nuclear fuel on schedule. We plan to seek recovery from the MPSC for decommissioning and other related expenditures and we have a $129 million regulatory asset recorded on our Consolidated Balance Sheets.

Nuclear Fuel Disposal Cost: We deferred payment for disposal of spent nuclear fuel burned before April 7, 1983. Our DOE liability is $159 million at December 31, 2007. This amount includes interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. We recovered, through electric rates, the amount of this liability, excluding a portion of interest. In conjunction with the sale of Palisades and the Big Rock ISFSI, we retained this obligation and provided a $155 million letter of credit to Entergy as security for this obligation.

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.

Consumers’ Gas Utility Contingencies

Gas Environmental Matters: We expect to incur investigation and remediation costs at a number of sites under the Michigan Natural Resources and Environmental Protection Act, a Michigan statute that covers environmental activities including remediation. These sites include 23 former manufactured gas plant facilities.

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We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In December 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represented a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through proceeds from insurance settlements and MPSC-approved rates.

From January 1, 2006 to December 31, 2007, we spent a total of $12 million for MGP response activities. At December 31, 2007, we have a liability of $17 million and a regulatory asset of $50 million, which includes $33 million of deferred MGP expenditures. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. Annual response activity costs are expected to range between $4 million and $6 million per year over the next five years. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of response activity costs and the timing of our payments.

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

FERC Investigation: In February 2008, Consumers 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. Consumers will cooperate with the FERC in responding to the request. Consumers cannot predict the financial impact or 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 prudency in annual plan and reconciliation proceedings.

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

Gas Cost Recovery Reconciliation
			Net Over-	GCR Cost
GCR Year	Date Filed	Order Date	recovery	of Gas Sold	Description of Net Overrecovery
2005-2006	June 2006	April 2007	$3 million	$1.8 billion	The net overrecovery includes $1 million interest income through March 2006, which resulted from a net underrecovery position during most of the GCR period.
2006-2007	June 2007	Pending	$5 million	$1.7 billion	The total overrecovery amount reflects an overrecovery of $1 million plus $4 million in accrued interest owed to customers.

GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan year. The order approved a settlement agreement and established a fixed price cap of $10.10 per mcf for December 2005 through March 2006. We were able to maintain our GCR billing factor below the authorized level for that period. The order was appealed to the Michigan Court of Appeals by one intervenor. In January 2008, the Michigan Court of Appeals affirmed the MPSC’s order for our 2005-2006 GCR Plan year.

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GCR plan for year 2006-2007: In August 2006, the MPSC issued an order for our 2006-2007 GCR Plan year. The order approved a settlement agreement that allowed a base GCR ceiling factor of $9.48 per mcf for April 2006 through March 2007. We were able to maintain our GCR billing factor below the authorized level for that period.

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

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 February 2008 is $7.69 per mcf.

GCR plan for year 2008-2009: In December 2007, we filed an application with the MPSC seeking approval of a GCR plan for our 2008-2009 GCR Plan year. Our request proposed the use of a GCR factor consisting of:

•  a base GCR ceiling factor of $8.17 per mcf, plus

•  a quarterly GCR ceiling price adjustment contingent upon future events.

2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity as part of an $88 million annual increase in our gas delivery and transportation rates. In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate increase of $50 million, including an authorized return on equity of 10.75 percent. In September  2007, the MPSC reopened the record in the case to allow all interested parties to be heard concerning the approval of an energy efficiency program, which we proposed in our original filing. Hearings on this matter were held in February 2008. We expect the MPSC to issue a final order in the second quarter of 2008. If approved in total, this would result in an additional rate increase of $9 million for implementation of the energy efficiency program.

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million and an 11 percent authorized return on equity.

Other Contingencies

Argentina: As part of its energy privatization incentives, the Republic of Argentina (Argentina) directed CMS Gas Transmission to calculate tariffs in U.S. dollars, then convert them to pesos at the prevailing exchange rate, and to adjust tariffs every six months to reflect changes in inflation. Starting in early 2000, Argentina suspended the inflation adjustments.

In January 2002, the Republic of Argentina enacted the Public Emergency and Foreign Exchange System Reform Act. This law repealed the fixed exchange rate of one U.S. dollar to one Argentine peso, converted all dollar-denominated utility tariffs and energy contract obligations into pesos at the same one-to-one exchange rate, and directed the Government of Argentina to renegotiate such tariffs.

CMS Gas Transmission began arbitration proceedings against Argentina under the auspices of the ICSID in mid-2001, citing breaches by Argentina of the Argentine-U.S. Bilateral Investment Treaty. In May 2005, an ICSID tribunal concluded, among other things, that Argentina’s economic emergency did not excuse Argentina from liability for violations of the BIT. The ICSID tribunal found in favor of CMS Gas Transmission, and awarded damages of U.S. $133 million, plus interest.

The ICSID Convention provides that either party may seek annulment of the award based upon five possible grounds specified in the ICSID Convention. ICSID formally registered Argentina’s Application for Annulment in September 2005. In December 2005, certain insurance underwriters paid $75 million to CMS Gas Transmission in respect of their insurance obligations resulting from non-payment of the ICSID arbitration award. We recorded this payment as a deferred credit on our Consolidated Balance Sheets because of a contingent obligation to refund the proceeds if the arbitration decision was annulled. In March 2007, we sold our Argentine businesses and the rights to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

receive any proceeds from the ICSID award and certain claims against political risk insurance to Lucid Energy for $130 million. Under the sale, we retained the rights to $75 million in proceeds previously received from political risk insurance insurers.

In September 2007, the contingent repayment obligation was eliminated by agreement. Later that month, a separate arbitration panel ruling on the annulment issue upheld the prior ICSID award. As a result, we recognized the $75 million deferred credit in Asset impairment charges, net of insurance recoveries on our Consolidated Statements of Income (Loss). For more information on the sale of our Argentine assets to Lucid Energy, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges, “Asset Sales.”

Quicksilver Resources, Inc.: Quicksilver sued CMS MST for breach of contract in connection with a base contract for 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 was seeking damages of up to approximately $126 million, plus prejudgment interest and attorney fees.

The trial commenced on March 19, 2007. The jury verdict awarded Quicksilver zero compensatory damages but $10 million in punitive damages. The jury found that CMS MST breached the contract and committed fraud but found no actual damage related to such a claim.

On May 15, 2007, the trial court vacated the jury award of punitive damages but held that the contract should be rescinded prospectively. The judicial rescission of the contract caused CMS Energy to record a charge in the second quarter of 2007 of approximately $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.

Star Energy: In 2000, a Michigan trial judge granted Star Energy, Inc. and White Pine Enterprises, LLC a judgment in an action filed in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas subsidiary, violated an oil and gas lease and other arrangements by failing to drill wells it had committed to drill. A jury then awarded the plaintiffs an $8 million award. The Court of Appeals reversed the damages award and granted Terra Energy Ltd. a new trial on damages only. The trial was set for August 2007, but the parties reached a settlement before trial. As a result, CMS Energy recorded a charge in the second quarter of 2007 of $3 million, net of tax.

T.E.S. Filer City Air Permit Issue: In January 2007, we received a Notice of Violation from the EPA alleging that T.E.S. Filer City, a generating facility in which we have a 50 percent partnership interest, exceeded certain air permit limits. The EPA recently issued a notice levying a penalty of $0.1 million. We cannot predict the financial impact or outcome of this issue.

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 it $142 million in taxes in connection with that sale. CMS Energy and its tax advisors 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 Equatorial Guinea government still intends to pursue its claim. We cannot predict the financial impact or outcome of this matter.

Moroccan Tax Claim: In February 2007, CMS Energy sold its interest in Jorf Lasfar. As part of the sale, CMS Energy agreed to indemnify the purchaser for any tax assessments attributable to tax years prior to the sale. In December 2007, the Moroccan government concluded its audit of JLEC for tax years 2002 through 2005 for which the government has presented its preliminary findings but not yet issued an assessment. CMS Energy is participating in discussions with the Moroccan tax authorities but at this time cannot predict the financial impact or outcome of this matter.

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CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

CMS ERM Electricity Sales Agreements: CMS ERM was a party to three electricity sales agreements, under which it provided up to 300 MW of electricity at fixed prices. CMS ERM satisfied its obligations under these agreements by using electricity generated by DIG or by purchasing electricity from the market. Because the price of natural gas has increased substantially in recent years, the prices that were charged under these agreements did not reflect DIG’s cost to generate or CMS ERM’s cost to purchase electricity from the market. Therefore, these agreements negatively impacted DIG’s and CMS ERM’s financial performance.

In November 2007, CMS ERM, DIG, and CMS Energy reached an agreement to terminate two of these electricity sales agreements in order to eliminate future losses under those contracts. As consideration for agreeing to terminate the agreements, CMS ERM paid the customers $275 million upon closing the transaction in February 2008. We recorded a liability for the future payment and other termination costs and recognized a loss of $279 million in 2007, representing the cost to terminate the agreements. As a result of terminating these agreements, CMS ERM and DIG have reduced their long-term electric capacity supply obligations by 260 MW. CMS ERM will market the capacity and energy that was previously committed under these agreements into the merchant market either through third party agreements or directly with the MISO.

Also in November 2007, CMS ERM executed an amendment of the remaining electricity sales agreement, which was effective upon the closing of the transaction. The purpose of the amendment is to optimize production planning and ensure optimal use of available resources. The amendment establishes a minimum amount of contract capacity to be provided under the agreement, and adds a minimum and maximum amount of electricity to be delivered to the customer. As amended, this electricity sales agreement is a derivative instrument. Upon signing the amendment in 2007, we recorded our minimum obligation under the contract on our consolidated balance sheet at its fair value and recognized the resulting mark-to-market loss of $18 million in earnings. For additional details on accounting for this derivative, see Note 6, Financial and Derivative Instruments.

Guarantees and Indemnifications: FIN 45 requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee.

The following table describes our guarantees at December 31, 2007:

						FIN 45
			Maximum			Carrying
Guarantee Description	Issue Date	Expiration Date	Obligation			Amount
	In Millions
Indemnifications from asset sales and other agreements	Various	Indefinite	$	1,446	(a)	$	88	(a)
Surety bonds and other indemnifications	Various	Indefinite		24			—
Guarantees and put options	Various	Various through September 2027		99	(b)		1

(a)

The majority of this amount arises from provisions in stock and asset sales agreements under which we indemnify the purchaser for losses resulting from claims related to tax disputes, claims related to power purchase agreements and the failure of title to the assets or stock sold by us to the purchaser. As of December 31, 2007, we have an $88 million liability in connection with indemnities related to the sale of certain subsidiaries. We believe the likelihood of loss for the remaining indemnifications to be remote.

(b)

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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, 2007, certain contracts contained provisions allowing us to recover, from third parties, amounts paid under the guarantees. For example, if we are required to purchase a property under a put option agreement, we may sell the property to recover the amount paid under the option.

In addition to the indemnities and guarantees discussed in the preceding tables where we have identified a maximum potential obligation amount or carrying amount, we also enter into various agreements containing tax and other indemnification provisions for which we are unable to estimate the maximum potential obligation. We consider the likelihood that we would be required to perform or incur significant losses related to these indemnities to be remote.

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

We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or future results of operations.

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CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

4: FINANCINGS AND CAPITALIZATION

Long-term debt at December 31 follows:

	Interest Rate (%)			Maturity	2007			2006
					In Millions
CMS Energy Corporation
Senior notes		9.875		2007	$	—		$	289
		8.900		2008		—			260
		7.500		2009		—			409
		7.750		2010		300			300
		8.500		2011		300			300
		6.300		2012		150			150
		Variable	(a)	2013		150			—
		6.875		2015		125			125
		6.550		2017		250			—
		3.375	(b)	2023		150			150
		2.875	(b)	2024		288			288
						1,713			2,271
Other						—			1
Total — CMS Energy Corporation						1,713			2,272
Consumers Energy Company
First mortgage bonds		4.250		2008		250			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		2020		300			300
		5.650		2035		145			147
		5.800		2035		175			175
						3,170			3,172
Senior notes		6.375		2008		159			159
		6.875		2018		180			180
Securitization bonds		5.442	(c)	2008-2015		309			340
Nuclear fuel disposal liability				(d)		159			152
Tax-exempt pollution control revenue bonds		Various		2010-2035		161			161
Total — Consumers Energy Company						4,138			4,164
Other Subsidiaries						236			328
Total principal amount outstanding						6,087			6,764
Current amounts						(692	)		(550	)
Net unamortized discount						(10	)		(14	)
Total long-term debt					$	5,385		$	6,200

(a) The variable rate senior notes bear interest at three-month LIBOR plus 95 basis points (6.1925 percent at December 31, 2007).

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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)	Represents the weighted average interest rate at December 31, 2007 (5.384 percent at December 31, 2006).
(d)	The maturity date is uncertain.

Financings: The following is a summary of significant long-term debt transactions during 2007:

	Principal
	(In millions)		Interest Rate (%)			Issue/Retirement Date	Maturity Date
Debt Issuances
CMS Energy
Senior notes	$	250		6.55	%	July 2007	July 2017
Senior notes		150		Variable		July 2007	January 2013
Total	$	400
Debt Retirements:
CMS Energy
Senior notes	$	260		8.90	%	June 2007	July 2008
Senior notes		409		7.50	%	July and August 2007	January 2009
Senior notes		289		9.875	%	October 2007	October 2007
Enterprises
CMS Generation
Investment Co. IV
Bank Loan		108		Variable		May 2007	December 2008
Total	$	1,066

First Mortgage Bonds: Consumers secures its FMBs by a mortgage and lien on substantially all of its property. Its ability to issue FMBs 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.

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 its affiliates. Securitization surcharges totaled $48 million in 2007 and $50 million in 2006.

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		2007		2006
					In Millions
Convertible subordinated debentures, CMS Energy Trust I		7.75		2027	$	178	$	178

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CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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.

Debt Maturities: At December 31, 2007, the aggregate annual contractual maturities for long-term debt and long-term debt — related parties for the next five years are:

	Payments Due
	2008		2009		2010		2011		2012
	In Millions
Long-term debt and long-term debt — related parties	$	542	$	414	$	664	$	642	$	504

Regulatory Authorization for Financings: The FERC has authorized Consumers to issue up to $1.0 billion of secured and unsecured short-term securities for general corporate purposes. The remaining availability is $500 million at December 31, 2007.

The FERC has also authorized Consumers to issue up to $2.5 billion of secured and unsecured long-term securities for the following:

•  up to $1.5 billion of new issuance for general corporate purposes and

•  up to $1.0 billion for purposes of refinancing or refunding existing long-term debt.

All of the new issuance availability remains ($1.5 billion) and the refinancing availability remaining is $500 million at December 31, 2007.

The authorizations are for the period ending June 30, 2008. Any long-term issuances during the authorization period are exempt from FERC’s competitive bidding and negotiated placement requirements.

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at December 31, 2007:

						Outstanding
		Amount of		Amount		Letters of		Amount
Company	Expiration Date	Facility		Borrowed		Credit		Available
	In Millions
CMS Energy(a)	April 2, 2012	$	300	$	—	$	278	$	22
Consumers(b)	March 30, 2012		500		—		203		297
Consumers(c)	November 28, 2008		200		NA		185		15

(a)	In January 2008, the lenders increased the commitments for CMS Energy’s credit facility from $300 million to $550 million.
(b)	In January 2008, $185 million of letters of credit were cancelled, resulting in the amount of credit available of $482 million under this facility.
(c)	Secured revolving letter of credit facility.

Dividend Restrictions: Under provisions of our senior notes indenture, at December 31, 2007, payment of common stock dividends was limited to $363 million.

Under the provisions of its articles of incorporation, at December 31, 2007, Consumers had $269 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 Consumers’ retained earnings. For the year ended December 31, 2007, CMS Energy received $251 million of common stock dividends from Consumers.

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CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we sell certain 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 $325 million of the receivables. The special purpose entity sold no receivables at December 31, 2007 and $325 million at December 31, 2006. 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 interest in the receivables sold. We continue to service the receivables sold to the special purpose entity. We have not recorded a servicing asset in connection with our accounts receivable sales program. The following table summarizes certain cash flows under our accounts receivable sales program:

Years Ended December 31	2007			2006
	In Millions
Net cash flow as a result of accounts receivable financing	$	(325	)	$	—
Collections from customers	$	5,881		$	5,684

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.

Preferred Stock: Details about our outstanding preferred stock follow:

	Number of Shares
December 31	2007		2006		2007		2006
					In Millions
Preferred stock
4.50% convertible,
Authorized 10,000,000 shares(a)		5,000,000		5,000,000	$	250	$	250
Preferred subsidiary interest(b)						—		11
Total preferred stock					$	250	$	261

(a)	See the “Contingently Convertible Securities” section in this Note for further discussion of the convertible preferred stock.
(b)	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 retained deficit.

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

			Optional
			Redemption		Number of Shares
December 31	Series		Price		2007		2006		2007		2006
									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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Contingently Convertible Securities: At December 31, 2007, 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		—	$	250	$	9.78	$	11.73
3.375% senior notes		2023	$	150	$	10.55	$	12.66
2.875% senior notes		2024	$	288	$	14.58	$	17.49

On or after December 5, 2008, we will have the right to cause the 4.50 percent preferred stock to be converted if the closing price of our common stock remains at or above $12.71 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, 2008, 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 2007, the trigger price contingency was met for our 4.50 percent preferred stock and our 3.375 percent senior notes. As a result, these securities are convertible at the option of the security holders during the three months ended March 31, 2008. In December 2007, one security holder notified us of its intention to convert 2,000 shares of 4.50 percent preferred stock. As of February 2008, no other security holders have notified us of their intention to convert these securities.

The 3.375 percent senior notes are convertible on demand and are classified as current liabilities.

5: EARNINGS PER SHARE

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

Years Ended December 31	2007			2006			2005
	In Millions, Except
	per Share Amounts
Loss Available to Common Stockholders
Loss from Continuing Operations	$	(126	)	$	(133	)	$	(141	)
Less Preferred Dividends and Redemption Premiums		(12	)		(11	)		(10	)
Loss from Continuing Operations Available to Common Stockholders — Basic and Diluted		(138	)		(144	)		(151	)
Average Common Shares Outstanding Applicable to Basic and Diluted EPS
Weighted Average Shares — Basic and Diluted		222.6			219.9			211.8
Loss Per Average Common Share Available to Common Stockholders
Basic	$	(0.62	)	$	(0.66	)	$	(0.71	)
Diluted	$	(0.62	)	$	(0.66	)	$	(0.71	)

Contingently Convertible Securities: There was no impact on diluted EPS from our contingently convertible securities for the years ended December 31, 2007, 2006 and 2005. When we have positive income from continuing

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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, 11.3 million shares for 2006, and 10.9 million shares for 2005. For additional details on our contingently convertible securities, see Note 4, Financings and Capitalization.

Stock Options, Warrants and Restricted Stock: For the year ended December 31, 2007, there was no impact on diluted EPS from 1.1 million shares of unvested restricted stock awards or from options and warrants to purchase 0.3 million shares of common stock. Since the exercise price was greater than the average market price of our common stock, there was no impact to diluted EPS from additional options and warrants to purchase 0.7 million shares of common stock. These stock options have the potential to dilute EPS in the future.

Convertible Debentures: For the years ended December 31, 2007, 2006, and 2005, 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.

6: FINANCIAL AND DERIVATIVE INSTRUMENTS

Financial Instruments: The carrying amounts of cash, 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:

	2007				2006
December 31	Book Value		Fair Value		Book Value		Fair Value
	In Millions
Long-term debt(a)	$	6,077	$	6,287	$	6,750	$	6,946
Long-term debt — related parties		178		173		178		155

(a) Includes current maturities of $692 million at December 31, 2007 and $550 million at December 31, 2006. Settlement of long-term debt is generally not expected until maturity.

A summary of our available-for-sale investment securities follows:

	2007								2006
			Unrealized		Unrealized		Fair				Unrealized		Unrealized			Fair
December 31	Cost		Gains		Losses		Value		Cost		Gains		Losses			Value
	In Millions
Nuclear decommissioning investments:
Equity securities	$	—	$	—	$	—	$	—	$	140	$	150	$	(4	)	$	286
Debt securities		—		—		—		—		307		4		(2	)		309
SERP:
Equity securities		62		—		—		62		36		21		—			57
Debt securities		13		—		—		13		13		—		—			13

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CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The fair value of available-for-sale debt securities by contractual maturity at December 31, 2007 is as follows:

	In Millions
Due after one year through five years	$	5
Due after five years through ten years		7
Due after ten years		1
Total	$	13

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. Net gains of $15 million, net of tax of $7 million, were reclassified from AOCL and included in net loss. The proceeds from sales of SERP securities were $6 million during 2006 and $3 million during 2005. Gross gains and losses were immaterial in 2006 and 2005.

Derivative Instruments: In order to limit our exposure to certain market risks, we may enter into various risk management contracts, such as swaps, options, futures, and forward contracts. These contracts, used primarily to limit our exposure to changes in interest rates and commodity prices, are classified as either non-trading or trading. We enter into these contracts using established policies and procedures, under the direction of two different committees: 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 and hedge 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, it is recorded 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. If a derivative qualifies for cash flow hedge accounting treatment, we report changes in its fair value (gains or losses) in AOCL; otherwise, we report the gains and losses in earnings.

For a derivative instrument to qualify for cash flow hedge accounting:

•  the relationship between the derivative instrument and the forecasted transaction being hedged must be formally documented at inception,

•  the derivative instrument must be highly effective in offsetting the hedged transaction’s cash flows, and

•  the forecasted transaction being hedged must be probable.

If a derivative qualifies for cash flow hedge accounting treatment and gains or losses are recorded in AOCL, those gains or losses will be reclassified into earnings in the same period or periods the hedged forecasted transaction affects earnings. If a cash flow hedge is terminated early because it is determined that the forecasted transaction will not occur, any gain or loss recorded in AOCL at that date is recognized immediately in earnings. If a cash flow hedge is terminated early for other economic reasons, any gain or loss as of the termination date is deferred and then reclassified to earnings when the forecasted transaction affects earnings. The ineffective portion, if any, of all hedges is recognized in earnings.

To determine the fair value of our derivatives, we 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. These models use various inputs and assumptions, including commodity market prices and volatilities, as well as interest rates and contract maturity dates. The cash returns we actually realize on these contracts may be different from the results that we estimate using models. If necessary, our calculations of fair value include reserves to reflect the credit risk of our counterparties.

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

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

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

•  there is not an active market for the commodity.

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

The following table summarizes our derivative instruments:

December 31	2007								2006
			Fair			Unrealized						Fair			Unrealized
Derivative Instruments	Cost		Value			Loss			Cost			Value			Gain (Loss)
	In Millions
CMS ERM derivative contracts:
Non-trading electric/gas contracts(a)	$	—	$	(18	)	$	(18	)	$	—		$	31		$	31
Trading electric/gas contracts(b)		—		(5	)		(5	)		(11	)		(68	)		(57	)
Derivative contracts associated with equity investments in:
Shuweihat(c)		—		—			—			—			(14	)		(14	)
Taweelah(c)		—		—			—			(35	)		(11	)		24
Jorf Lasfar(c)		—		—			—			—			(5	)		(5	)
Other		—		—			—			—			1			1

(a)	The fair value of CMS ERM’s non-trading electric and gas contracts decreased significantly during 2007 for two reasons. First, a natural gas contract with Quicksilver was prospectively rescinded by court action. CMS ERM had recorded a derivative asset for this contract, representing cumulative unrealized mark-to-market gains. See Note 3, Contingencies, “Other Contingencies — Quicksilver Resources, Inc.” for additional details. In addition, CMS ERM recorded a derivative liability of $18 million related to the amendment of an electricity sales agreement. See Note 3, Contingencies, “Other Contingencies — CMS ERM Electricity Sales Agreements” for additional details.
(b)	The fair value of CMS ERM’s trading electric and gas contracts increased significantly during 2007 due to the termination of certain gas contracts. CMS ERM had recorded derivative liabilities, representing cumulative unrealized mark-to-market losses, associated with these contracts.
(c)	We sold our equity investments in Shuweihat, Taweelah, and Jorf Lasfar in May 2007. Therefore, we no longer reflect our share of the fair value of the derivatives contracts held by these businesses in our consolidated financial statements.

We record the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. At December 31, 2006, the fair value of derivative contracts associated with our equity investments was included in Investments — Enterprises on our Consolidated Balance Sheets.

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CMS ERM Contracts: In order to support CMS Energy’s ongoing operations, CMS ERM enters into contracts to purchase and sell electricity and natural gas in the future. These forward contracts will result in physical delivery of the commodity at a contracted price. These contracts are generally long-term in nature and are classified as non-trading contracts.

To manage commodity price risks associated with these forward purchase and sale contracts, CMS ERM uses various financial instruments, such as swaps, options, and futures. CMS ERM also uses these types of instruments to manage commodity price risk associated with generation assets owned by CMS Energy and its subsidiaries. These financial contracts are classified as trading contracts.

Changes in the fair value of CMS ERM’s non-trading and trading contracts are recorded in earnings as a component of Operating Revenue. For trading contracts, these gains and losses are recorded net in accordance with EITF Issue 02-03.

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

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

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 established credit policies. For each counterparty, we assess credit quality by considering credit ratings, financial condition, and other available information. We then 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, if necessary.

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 these counterparties are affected by similar changes in economic conditions, the weather, or other conditions. 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, 2007, 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 for the normal purchases and sales exception under SFAS No. 133, or other contracts that are not accounted 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.

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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.

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.

In April 2007, we sold Palisades to Entergy. Employees transferred to Entergy as a result of the sale no longer participate in our retirement benefit plans. We recorded a net decrease of $16 million in pension SFAS No. 158 regulatory assets with a corresponding reduction of $16 million in pension liabilities on our Consolidated Balance Sheets. We also recorded a net decrease of $15 million in OPEB regulatory SFAS No. 158 assets with a corresponding reduction of $15 million in OPEB liabilities. The following table shows the net adjustment:

	Pension		OPEB
Plan liability transferred to Entergy	$	38	$	20
Trust assets transferred to Entergy		22		5
Net adjustment	$	16	$	15

On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of 5 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. 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. The DCCP expense was $2 million for each of the years ended December 31, 2007 and December 31, 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 $95 million at December 31, 2007 and $71 million at December 31, 2006. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $83 million at December 31, 2007 and $78 million at December 31, 2006. 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

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placed in a grantor trust. Trust assets were less than $1 million at December 31, 2007 and 2006. 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, 2007 and 2006.

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

Beginning May 1, 2007, the CMS Energy Common Stock Fund was no longer an investment option available for investments in the 401(k) savings plan and the employer match was no longer in CMS Energy Common Stock. Participants had an opportunity to reallocate investments in the CMS Energy Common Stock Fund to other plan investment alternatives prior to November 1, 2007. In November 2007, the remaining shares in the CMS Energy Common Stock Fund were sold and the sale proceeds were reallocated to other plan investment options.

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 $1 million for each of the years ended December 31, 2007 and 2006. The ABO for the EISP was $4 million at December 31, 2007 and $5 million at December 31, 2006.

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. Starting in 2007, we used two health care trend rates: one for retirees under 65 and the other for retirees 65 and over. The two health care trend rates recognize that prescription drug costs are increasing at a faster pace than other medical claim costs and that prescription drug costs make up a larger portion of expenses for retirees age 65 and over. Retiree health care costs were based on the assumption that costs would increase 9.0 percent for those under 65 and 10.5 percent for those over 65 in 2007. The 2008 rate of increase for OPEB health costs for those under 65 is expected to be 8.0 percent and for those over 65 is expected to be 9.5 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2011 and for those over 65 by 2013 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	$	21	$	(17	)
Effect on postretirement benefit obligation	$	208	$	(176	)

Upon adoption of SFAS No. 106, at the beginning of 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 requires 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 requires us to recognize changes in the funded status of our plans in the year in which the changes occur. In addition, the standard requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe

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that implementation of this provision of the standard will have a material effect on our consolidated financial statements.

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	2007		2006		2005		2007		2006		2005
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%

Weighted average for net periodic benefit cost:

	Pension & SERP						OPEB
Years Ended December 31	2007		2006		2005		2007		2006		2005
Discount rate(a)		5.65%		5.75%		5.75%		5.65%		5.75%		5.75%
Expected long-term rate of return on plan assets(b)		8.25%		8.50%		8.75%		7.75%		8.00%		8.25%
Mortality table(c)		2000		2000		2000		2000		2000		2000
Rate of compensation increase:
Pension		4.00%		4.00%		3.50%
SERP		5.50%		5.50%		5.50%

(a)	The discount rate represents the market rate for high-quality AA-rated corporate bonds with durations corresponding to the expected durations of the benefit obligations and is used to calculate the present value of the expected future cash flows for benefit obligations under our pension plans.
(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)	We utilize the Combined Healthy RP-2000 Table from the 2000 Group Annuity Mortality Tables.

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CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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	2007			2006			2005
	In Millions
Net periodic pension cost
Service cost	$	50		$	51		$	44
Interest expense		91			88			83
Expected return on plan assets		(79	)		(85	)		(97	)
Amortization of:
Net loss		46			43			35
Prior service cost		7			7			6
Net periodic pension cost		115			104			71
Regulatory adjustment(a)		(22	)		(11	)		—
Net periodic pension cost after regulatory adjustment	$	93		$	93		$	71

	OPEB
Years Ended December 31	2007			2006			2005
	In Millions
Net periodic OPEB cost
Service cost	$	25		$	23		$	23
Interest expense		69			64			61
Expected return on plan assets		(62	)		(57	)		(54	)
Amortization of:
Net loss		22			20			20
Prior service credit		(10	)		(10	)		(9	)
Net periodic OPEB cost		44			40			41
Regulatory adjustment(a)		(6	)		(2	)		—
Net periodic OPEB cost after regulatory adjustment		38			38		$	41

(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. These adjustments are deferred as a regulatory asset and will be included in future rate cases. The pension regulatory asset had a balance of $33 million at December 31, 2007 and $11 million at December 31, 2006. The OPEB regulatory asset had a balance of $8 million at December 31, 2007 and $2 million at December 31, 2006.

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 $43 million and from AOCL is $2 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 zero 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 13 years for pension and 14 years for OPEB. Prior service cost amortization is established in the years in which they first occur, and are based on the same amortization period in all future years until fully recognized. The estimated time of amortization of new prior service costs is 13 years for pension and 11 years for OPEB.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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	2007			2006			2007			2006			2007			2006
	In Millions
Benefit obligation at beginning of period	$	1,576		$	1,510		$	92		$	91		$	1,243		$	1,136
Service cost		49			49			1			2			25			23
Interest cost		86			83			5			5			69			64
Actuarial loss (gain)		30			51			1			(2	)		(128	)		70
Palisades sale		(38	)		—			—			—			(20	)		—
Benefits paid		(138	)		(117	)		(4	)		(4	)		(53	)		(50	)
Benefit obligation at end of period(a)		1,565			1,576			95			92			1,136			1,243
Plan assets at fair value at beginning of period		1,040			1,018			—			—			798			714
Actual return on plan assets		89			126			—			—			55			73
Company contribution		109			13			4			4			52			58
Palisades sale		(22	)		—			—			—			(5	)		—
Actual benefits paid(b)		(138	)		(117	)		(4	)		(4	)		(48	)		(47	)
Plan assets at fair value at end of period		1,078			1,040			—			—			852			798
Funded status at end of measurement period		(487	)		(536	)		(95	)		(92	)		(284	)		(445	)
Additional VEBA Contributions or Non-Trust Benefit Payments		—			—			—			—			12			14
Funded status at December 31(c)	$	(487	)	$	(536	)	$	(95	)	$	(92	)	$	(272	)	$	(431	)

(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 $28 million for 2007 and 2006. The reduction includes $7 million for the years ended December 31, 2007 and December 31, 2006 in capitalized OPEB costs.
(b)	We received $4 million in 2007 and $3 million in 2006 for Medicare Part D Subsidy payments.
(c)	Liabilities for retirement benefits are $850 million non-current and $4 million current for year ended December 31, 2007 and $1.055 billion non-current and $4 million current for year ended December 31, 2006.

The following table provides pension ABO in excess of plan assets:

Years Ended December 31	2007		2006
	In Millions
Pension ABO	$	1,231	$	1,240
Fair value of pension plan assets		1,078		1,040
Pension ABO in excess of Pension Plan assets	$	153	$	200

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

SFAS No. 158 Recognized: 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	2007		2006		2007			2006
	In Millions
Regulatory assets
Net loss	$	636	$	676	$	265		$	416
Prior service cost (credit)		39		45		(89	)		(99	)
AOCI
Net loss (gain)		46		46		(22	)		(11	)
Prior service cost (credit)		3		4		(3	)		(4	)
Total amounts recognized in regulatory assets and AOCL	$	724	$	771	$	151		$	302

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

	Pension						OPEB
November 30	2007			2006			2007			2006
Asset Category:
Fixed Income		30	%		28	%		34	%		37	%
Equity Securities		60	%		62	%		66	%		63	%
Alternative Strategy		10	%		10	%		—			—

We contributed $50 million to our OPEB plan in 2007 and we plan to contribute $49 million to our OPEB plan in 2008. Of the $50 million OPEB contribution during 2007, $25 million was contributed to the 401(h) component of the qualified pension plan and the remaining $25 million was contributed to the VEBA trust accounts. We contributed $109 million to our Pension Plan in 2007 and we do not plan to contribute to our Pension Plan in 2008.

We established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments 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 Mid Cap and Small Cap 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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
2008	$	64	$	4	$	57
2009		71		4		60
2010		78		4		62
2011		88		4		65
2012		101		4		66
2013-2017		664		22		364

(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 2008 and 2009, $7 million for 2010, $8 million for 2011 and 2012 and $50 million combined for 2013 through 2017.

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, 2007 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 life and that we have an ARO liability recorded:

	In Service
ARO Description	Date	Long-Lived Assets
December 31, 2007
JHCampbell intake/discharge water line	1980	Plant intake/discharge water line
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-fired 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	12/31/05		Incurred		Settled(a)			Accretion		Revisions		12/31/06
	In Millions
Palisades-decommission	$	375	$	—	$	—		$	26	$	—	$	401
Big Rock-decommission		27		—		(28	)		3		—		2
JHCampbell intake line		—		—		—			—		—		—
Coal ash disposal areas		54		—		(2	)		5		—		57
Wells at gas storage fields		1		—		—			—		—		1
Indoor gas services relocations		1		—		—			—		—		1
Asbestos abatement		36		—		(3	)		2		—		35
Gas distribution cut, purge, cap		—		—		—			—		—		—
Natural gas-fired power plant		1		—		—			—		—		1
Close gas treating plant and gas wells		1		—		—			1		—		2
Total	$	496	$	—	$	(33	)	$	37	$	—	$	500	(b)

	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		—		—
JHCampbell intake line		—			—		—			—		—		—
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-fired power plant		1			—		(1	)		—		—		—
Close gas treating plant and gas wells		2			—		(2	)		—		—		—
Total	$	500	(b)	$	101	$	(421	)	$	16	$	2	$	198

(a) Cash payments of $5 million in 2007 and $33 million in 2006 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.

(b)

We reclassified $2 million in ARO liabilities to Noncurrent liabilities held for sale on our Consolidated Balance Sheets at December 31, 2006. These AROs were subsequently settled as a result of the sale of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy.

9: INCOME TAXES

CMS Energy and its subsidiaries file a consolidated federal 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, 2007, we had AMT credit carryforwards of $267 million that do not expire, and tax loss carryforwards of $995 million that expire from 2023 through 2026, including SRLY tax loss carryforwards of $15 million that expire from 2018 through 2020. We do not believe that a valuation allowance is required, as we expect to use the loss carryforwards prior to their expiration. In addition, we had general business credit carryforwards of $17 million that expire from 2008 through 2027, and capital loss carryforwards of $18 million that expire in 2011. We have provided $9 million of valuation allowances for these items. It is reasonably possible that further adjustments will be made to the valuation allowance within one year. We recorded a benefit of $188 million for a future Michigan deduction, granted as part of the Michigan Business Tax legislation of 2007, offset by a federal tax benefit of $66 million, for a net benefit of $122 million, as discussed within this Note.

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

Years Ended December 31	2007			2006			2005
	(In Millions)
Current income taxes:
Federal	$	229		$	133		$	82
Federal income tax benefit of operating loss carryforwards		(209	)		(31	)		(70	)
State and local		1			—			(3	)
Foreign		—			(2	)		—
	$	21		$	100		$	9
Deferred income taxes:
Federal	$	(212	)	$	(281	)	$	(149	)
Federal tax benefit of American Jobs Creation Act of 2004		—			—			(30	)
State		—			—			—
Foreign		—			(3	)		3
	$	(212	)	$	(284	)	$	(176	)
Deferred ITC, net		(4	)		(4	)		(13	)
Tax benefit	$	(195	)	$	(188	)	$	(180	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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 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, 2007 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	2007			2006
	(In Millions)
Current Assets and (Liabilities):
Tax loss and credit carryforwards	$	—		$	150
Deferred charges		107			44
Employee benefits		8			10
Other		48			—
Current Assets	$	163		$	204
Gas inventory		(204	)		—
Other		—			(49	)
Current Liabilities	$	(204	)	$	(49	)
Net Current Asset/(Liability)	$	(41	)	$	155
Noncurrent Assets and (Liabilities):
Tax loss and credit carryforwards	$	761		$	717
SFAS No. 109 regulatory liability		207			189
Reserves and accruals		92			—
Currency translation adjustment		77			159
Foreign investments inflation indexing		23			42
Nuclear decommissioning (including unrecovered costs)		—			57
Employee benefits		64			28
Other		—			—
Noncurrent Assets	$	1,224		$	1,192
Valuation allowance		(32	)		(72	)
Net Noncurrent Asset	$	1,192		$	1,120
Property	$	(840	)	$	(790	)
Securitized costs		(180	)		(177	)
Gas inventory		—			(168	)
Nuclear decommisioning (including unrecovered costs)		(18	)		—
Other		(55	)		(108	)
Noncurrent Liabilities	$	(1,093	)	$	(1,243	)
Net Noncurrent Asset/(Liability)	$	99		$	(123	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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	2007			2006			2005
	(In Millions)
Income (loss) from continuing operations before income taxes
Domestic	$	(124	)	$	(118	)	$	(451	)
Foreign		(197	)		(203	)		130
Total		(321	)		(321	)		(321	)
Statutory federal income tax rate		x 35	%		x 35	%		x 35	%
Expected income tax expense (benefit)		(112	)		(112	)		(112	)
Increase (decrease) in taxes from:
Property differences		9			13			18
Income tax effect of foreign investments		47			(29	)		(32	)
AJCA foreign dividends benefit		—			—			(30	)
ITC amortization		(4	)		(4	)		(4	)
State and local income taxes, net of federal benefit		—			—			(2	)
Medicare Part D exempt income		(10	)		(10	)		(6	)
Tax exempt income		(1	)		(3	)		(3	)
Tax contingency reserves		—			(15	)		(5	)
Valuation allowance		(121	)		23			—
IRS Settlement/Credit Restoration		—			(49	)		—
Other, net		(3	)		(2	)		(4	)
Recorded income tax benefit	$	(195	)	$	(188	)	$	(180	)
Effective tax rate		60.7	%		58.6	%		56.1	%

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.

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 2006 are currently open under the statute of limitations and 2002 through 2005 are currently under audit by the IRS.

The American Jobs Creation Act (AJCA) of 2004 created a one-time opportunity to receive a tax benefit for U.S. corporations that reinvest, in the U.S., dividends received in a year (2005 for CMS Energy) from controlled foreign corporations. During 2005, we repatriated $370 million of foreign earnings that qualified for the tax benefit. The repatriated earnings provided net tax benefits of $45 million in 2005, with $30 million of this amount reflected in income from continuing operations and $15 million in discontinued operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

On January 1, 2007 we adopted the provisions of FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. 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.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	(In Millions)
Balance at January 1, 2007	$	151
Reductions for prior year tax positions		(101	)
Additions for prior year tax positions		1
Additions for current year tax positions		—
Statute lapses		—
Settlements		—
Balance at December 31, 2007	$	51

Included in the balance at December 31, 2007, are $43 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, 2007, remaining uncertain tax benefits that would reduce our effective tax rate in future years are $8 million. We are not expecting any other material changes to our uncertain tax positions over the next twelve months.

We have reflected a net interest liability of $2 million related to our uncertain income tax positions on our Consolidated Balance Sheets as of December 31, 2007. We have not accrued any penalties with respect to uncertain tax benefits. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

Michigan Business Tax Act: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan Business Tax Act, which imposed a business income tax of 4.95 percent and a modified gross receipts tax of 0.8 percent. The bill provided for a number of tax credits and incentives geared toward those companies investing and employing in Michigan. The Michigan Business Tax, which was effective January 1, 2008, replaced the state’s Single Business Tax that expired on December 31, 2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional deductions in future years against the business income portion of the tax. These future deductions are phased in over a 15-year period, beginning in 2015. As a result, our consolidated net deferred tax liability of $122 million, recorded due to the Michigan Business Tax enactment, was offset by a net deferred tax asset of $122 million. In December 2007, the Michigan governor signed House Bill 5408, replacing the expanded sales tax for certain services with a 21.99 percent surcharge on the business income tax and the modified gross receipts tax. Therefore, the total tax rates imposed under the Michigan Business Tax are 6.04 percent for the business income tax and 0.98 percent for the modified gross receipts tax.

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.

All grants under the Plan for 2007, 2006, and 2005 were in the form of total shareholder return (TSR) restricted stock and time-lapse restricted stock. Restricted stock recipients receive shares of CMS Energy’s 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

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levels of total shareholder return over a three-year period and half is based on a comparison of our total shareholder return 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 0 percent 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 and 2005 were entirely TSR restricted stock. Awards granted to officers in 2007 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 or disability and vest fully if control of CMS Energy changes, 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 2007, 2006, or 2005.

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 3,677,930 shares of common stock under the Plan at December 31, 2007. 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
	Number of			Grant Date
Restricted Stock	Shares			Fair Value
Nonvested at December 31, 2006		1,902,438		$	12.10
Granted(a)		721,870		$	14.18
Vested(a)		(923,329	)	$	16.21
Forfeited		(19,525	)	$	13.41
Nonvested at December 31, 2007		1,681,454		$	13.52

(a) During 2007, we granted 411,600 TSR shares and 105,020 time-lapse shares of restricted stock. In addition, we granted 205,250 shares that immediately vested as a result of achieving 150 percent of the market conditions on our 2004 TSR restricted stock grant. The fair value at the date of grant in 2004 was $9.73. We excluded the impact of these shares from the weighted-average grant date fair value for the 2007 shares granted.

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. The fair value of TSR restricted stock awards was calculated on the award grant date using a Monte Carlo simulation. Expected volatilities were based 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:

	2007			2006			2005
Expected Volatility		19.11	%		20.51	%		48.70	%
Expected Dividend Yield		1.20	%		0.00	%		0.00	%
Risk-free rate		4.59	%		4.82	%		4.14	%

The total fair value of shares vested was $15 million in 2007, $4 million in 2006, and $4 million in 2005. Compensation expense related to restricted stock was $10 million in 2007, $9 million in 2006, and $4 million in

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2005. The total related income tax benefit recognized in income was $3 million in 2007, $3 million in 2006, and $2 million in 2005. At December 31, 2007, 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 1.4 years.

The following table summarizes stock option activity under the Plan:

	Options
	Outstanding,
	Fully Vested,					Weighted-Average		Aggregate
	and			Weighted-Average		Remaining		Intrinsic
Stock Options	Exercisable			Exercise Price		Contractual Term		Value
								(In millions)
Outstanding at December 31, 2006		2,913,270		$	20.29		4.7 years	$	(10	)
Granted		—			—
Exercised		(900,400	)	$	8.14
Cancelled or Expired		(798,965	)	$	32.14
Outstanding at December 31, 2007		1,213,905		$	21.51		3.8 years	$	(5	)

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 $9 million in 2007, $1 million in 2006, and $2 million in 2005. Cash received from exercise of these stock options was $7 million in 2007.

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, 2007, we have $15 million of unrealized excess tax benefits.

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

Years Ended December 31	2007		2006		2005
Weighted average grant date fair value
Restricted stock granted	$	14.18	$	13.84	$	15.61
Stock options granted(a)		—		—		—

(a) No stock options were granted in 2007, 2006, or 2005.

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 this Statement 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.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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 5 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	2007			2006			2005
	(In Millions)
Capital lease expense	$	34		$	15		$	14
Operating lease expense		23			19			18
Income from subleases		(2	)		(2	)		(2	)

Minimum annual rental commitments under our non-cancelable leases at December 31, 2007 are:

	Capital		Finance
	Leases		Lease(b)		Operating
	(In Millions)
2008	$	21	$	13	$	26
2009		16		13		24
2010		15		13		21
2011		13		13		21
2012		14		13		21
2013 and thereafter		53		122		94
Total minimum lease payments(a)		132		187	$	207
Less imputed interest		64		—
Present value of net minimum lease payments		68		187
Less current portion		17		13
Non-current portion	$	51	$	174

(a)

Minimum payments have not been reduced by minimum sublease rentals of $3 million due in the future under noncancelable subleases.

(b)

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 $300 million annually. Our total purchases of capacity and energy under the Palisades power purchase agreement were $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 and 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.

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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 charges under the financing were $10 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		2007		2006
			(In Millions)
Electric:
Generation		13-85	$	3,328	$	3,573
Distribution		12-75		4,496		4,425
Other		7-40		438		421
Capital and finance leases(a)				293		85
Gas:
Underground storage facilities(b)		30-65		267		263
Transmission		15-75		570		465
Distribution		40-75		2,286		2,216
Other		7-50		320		300
Capital leases(a)				24		29
Enterprises:
IPP		3-40		378		415
CMS Gas Transmission		3-40		—		25
CMS Electric and Gas		2-30		2		2
Other		4-25		11		11
Other:		7-71		34		33
Construction work-in-progress				447		639
Less accumulated depreciation, depletion, and amortization(c)				4,166		5,194
Net property, plant, and equipment(d)			$	8,728	$	7,708

(a)	Capital and finance leases presented in this table are gross amounts. Accumulated amortization of capital and finance leases was $62 million at December 31, 2007 and $59 million at December 31, 2006. 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. Additions were $7 million and Retirements and adjustments were $6 million during 2006.
(b)	Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2007 and December 31, 2006, which is not subject to depreciation.
(c)	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. At December 31, 2006, accumulated depreciation, depletion, and amortization included $5.017 billion from our utility plant assets and $177 million from other plant assets.

CMS-92

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(d) 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. At December 31, 2006, utility plant additions were $470 million and utility plant retirements, including other plant adjustments, were $82 million.

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

	Amortization		2007				2006
December 31	Life in				Accumulated				Accumulated
Description	years		Gross Cost		Amortization		Gross Cost		Amortization
			In Millions
Software development		7-15	$	207	$	170	$	204	$	153
Rights of way		50-75		116		32		114		31
Leasehold improvements		various		19		16		19		15
Franchises and consents		various		14		5		19		10
Other intangibles		various		20		14		23		14
Total			$	376	$	237	$	379	$	223

Pretax amortization expense related to these intangible assets was $21 million for the year ended December 31, 2007, $23 million for the year ended December 31, 2006 and $21 million for the year ended December 31, 2005. Amortization of intangible assets is forecasted to range between $12 million and $22 million per year over the next five years.

Asset Acquisition: In December 2007, we purchased a 935 MW gas-fired power 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.

13: EQUITY METHOD INVESTMENTS

We account for certain investments in other companies, partnerships, and joint ventures 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 was $40 million in 2007, $89 million in 2006, and $125 million in 2005. The amount of consolidated retained earnings that represents undistributed earnings from these equity method investments was $22 million as of December 31, 2007, $14 million as of December 31, 2006, and $17 million as of December 31, 2005.

If assets or income from continuing operations associated with any of our equity method investments exceeds 10 percent of our consolidated assets or income, then summarized financial data of that subsidiary must be presented in our notes. If assets or income from continuing operations associated with any of our equity method investments exceeds 20 percent of our consolidated assets or income, then separate audited financial statements must be presented as an exhibit to our Form 10-K.

At December 31, 2007, no equity method investments exceeded the 10 percent threshold. At December 31, 2006, and December 31, 2005, Jorf Lasfar exceeded the 10 percent threshold and no equity method investments exceeded the 20 percent threshold.

CMS-93

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Summarized financial information for these equity method investments is as follows:

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

	Year Ended
	December 31, 2005
	Jorf
	Lasfar(a)		Total(b)
	(In Millions)
Operating revenue	$	508	$	2,058
Operating expenses		340		1,530
Operating income		168		528
Other expense, net		56		243
Net income	$	112	$	285

CMS-94

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

	December 31, 2006
	Jorf
	Lasfar(a)		Total(b)
Assets
Current assets	$	239	$	794
Property, plant and equipment, net		15		2,946
Other assets		1,047		1,527
	$	1,301	$	5,267
Liabilities
Current liabilities	$	272	$	818
Long-term debt and other non-current liabilities		403		3,124
Equity		626		1,325
	$	1,301	$	5,267

(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, $54 million for the year ended December 31, 2006, and $56 million for the year ended December 31, 2005.
(b)	Amounts include financial data from our international equity method investments through the date of sale.

CMS-95

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

14: JOINTLY OWNED REGULATED UTILITY FACILITIES

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

	Ownership						Accumulated				Construction
	Share		Net Investment(a)				Depreciation				Work in Progress
December 31	(%)		2007		2006		2007		2006		2007		2006
	(In Millions)
Campbell Unit 3		93.3	$	664	$	262	$	337	$	370	$	44	$	353
Ludington		51.0		65		68		104		95		1		1
Distribution		Various		89		98		44		47		5		4

(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.

15: 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 the summary of significant 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 and 2005 to include CMS Capital results in the Other segment.

CMS-96

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following tables provide financial information by reportable segment:

Years Ended December 31	2007			2006			2005
	(In Millions)
Operating Revenues
Electric utility	$	3,443		$	3,302		$	2,695
Gas utility		2,621			2,373			2,483
Enterprises		383			438			693
Other		17			13			8
	$	6,464		$	6,126		$	5,879
Earnings from Equity Method Investees
Enterprises	$	39		$	87		$	124
Other		1			2			1
	$	40		$	89		$	125
Depreciation, Depletion, and Amortization
Electric utility	$	397		$	380		$	292
Gas utility		127			122			117
Enterprises		12			44			93
Other		4			4			2
	$	540		$	550		$	504
Interest Charges
Electric utility	$	192		$	164		$	132
Gas utility		69			73			68
Enterprises		9			66			69
Other		168			177			194
	$	438		$	480		$	463
Income Tax Expense (Benefit)
Electric utility	$	100		$	95		$	85
Gas utility		47			18			39
Enterprises		(183	)		(145	)		(203	)
Other		(159	)		(156	)		(101	)
	$	(195	)	$	(188	)	$	(180	)
Net Income (Loss) Available to Common Stockholders
Electric utility	$	196		$	199		$	153
Gas utility		87			37			48
Enterprises		(391	)		(227	)		(217	)
Discontinued operations(a)		(89	)		54			57
Other		(30	)		(153	)		(135	)
	$	(227	)	$	(90	)	$	(94	)

CMS-97

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Years Ended December 31	2007		2006		2005
	(In Millions)
Investments in equity method investees
Enterprises	$	6	$	556	$	698
Other		5		10		13
	$	11	$	566	$	711
Total Assets
Electric utility(b)	$	8,492	$	8,516	$	7,755
Gas utility(b)		4,102		3,950		3,609
Enterprises		986		1,947		3,616
Other		616		958		1,061
	$	14,196	$	15,371	$	16,041
Capital Expenditures(c)
Electric utility	$	1,319	$	462	$	384
Gas utility		168		172		168
Enterprises		5		42		50
Other		—		1		3
	$	1,492	$	677	$	605

Geographic Areas(d)

	2007			2006			2005
	(In Millions)
United States
Operating revenue	$	6,462		$	6,123		$	5,877
Operating income (loss)		151			85			(468	)
Total Assets	$	14,191		$	14,123		$	14,675
International
Operating revenue	$	2		$	3		$	2
Operating income (loss)		(150	)		(139	)		123
Total Assets	$	5		$	1,248		$	1,366

(a)	Amounts include an income tax benefit of $1 million for December 31, 2007, and income tax expense of $32 million for December 31, 2006 and $20 million for December 31, 2005.
(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-98

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

16: CONSOLIDATION OF VARIABLE INTEREST ENTITIES

We are the primary beneficiary of three variable interest entities through our 50 percent ownership interests in the following partnerships:

•  T.E.S. Filer City Station Limited Partnership,

•  Grayling Generating Station Limited Partnership, and

•  Genesee Power Station Limited Partnership.

Additionally, 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. Collectively, these interests make us the primary beneficiary of these entities, and we consolidated them for all periods presented. The partnerships have third-party obligations totaling $83 million at December 31, 2007 and $97 million at December 31, 2006. Property, plant, and equipment serving as collateral for these obligations have a carrying value of $180 million at December 31, 2007 and $157 million at December 31, 2006. 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.

17: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)

	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

CMS-99

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

	2006
Quarters Ended	March 31			June 30		Sept. 30			Dec. 31(e)
	(In Millions, Except Per Share Amounts)
Operating revenue	$	1,897		$	1,219	$	1,288		$	1,722
Operating income (loss)		(21	)		69		(27	)		(75	)
Income (loss) from continuing operations		(33	)		63		(112	)		(51	)
Income from discontinued operations(a)		9			12		11			22
Net income (loss)		(24	)		75		(101	)		(29	)
Preferred dividends		3			3		2			3
Net income (loss) available to common stockholders		(27	)		72		(103	)		(32	)
Income (loss) from continuing operations per average common share — basic		(0.16	)		0.27		(0.52	)		(0.25	)
Income (loss) from continuing operations per average common share — diluted		(0.16	)		0.26		(0.52	)		(0.25	)
Basic earnings (loss) per average common share(b)		(0.12	)		0.33		(0.47	)		(0.15	)
Diluted earnings (loss) per average common share(b)		(0.12	)		0.31		(0.47	)		(0.15	)
Common stock prices(c)
High		15.22			13.66		14.79			16.95
Low		12.95			12.46		12.92			14.55

(a)	Net of tax.
(b)	Sum of the quarters may not equal the annual 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. For additional details, see Note 3, Contingencies — “Other Contingencies.”
(e)	The quarter ended December 31, 2006 includes a $41 million net loss on the sale of our investment in the MCV Partnership, including the associated asset impairment charge. The quarter also includes an $80 million net after-tax charge resulting from our agreement to settle shareholder class action lawsuits. For additional details, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges and Note 3, Contingencies.

CMS-100

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders

In our opinion, the accompanying consolidated balance sheet 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, 2007, and the results of their operations and their cash flows for the year ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index at Item 15(a)2 presents 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, 2007, 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 schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audit. 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides 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 20, 2008

CMS-101

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 balance sheets and the related statements of operations, of partners’ equity (deficit) and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and December 31, 2005, and the results of its operations and its cash flows for the period ended November 21, 2006 and the year ended December 31, 2005 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-102

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of CMS Energy Corporation

We have audited the accompanying consolidated balance sheets of CMS Energy Corporation (a Michigan Corporation) as of December 31, 2006, and the related consolidated statements of income (loss), common stockholders’ equity, and cash flows for each of the two years in the period ended December 31, 2006. Our audits also included the financial statement schedules as it relates to 2006 and 2005 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 audits. 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 2), which statements reflect total revenues constituting 8.9% in 2006 and 10.1% in 2005 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 periods indicated above for Midland Cogeneration Venture Limited Partnership is based solely on the report of the other auditors.

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 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 audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CMS Energy Corporation at December 31, 2006, and the consolidated results of their operations and their cash flows for each of the two years in the period 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 7 to the consolidated financial statements, in 2006, the Company adopted 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).” As discussed in Note 10 to the consolidated financial statements, in 2006, the Company adopted FASB Statement of Financial Accounting Standards No. 123(R) “Share-Based Payment.”

/s/ Ernst & Young LLP

Detroit, Michigan

February 21, 2007, except for “Discontinued

Operations” in Note 2 as to which the date

is February 20, 2008

CMS-103

2007 CONSOLIDATED FINANCIAL STATEMENTS

CE-1

CONSUMERS ENERGY COMPANY

SELECTED FINANCIAL INFORMATION

				2007		2006		2005			2004			2003
Operating revenue (in millions)	($		)		6,064		5,721		5,232			4,711			4,435
Earnings from equity method investees (in millions)	($		)		—		1		1			1			42
												—
Income (loss) before cumulative effect of change in accounting principle (in millions)	($		)		312		186		(96	)		280			196
Cumulative effect of change in accounting (in millions)	($		)		—		—		—			(1	)		—
Net income (loss) (in millions)	($		)		312		186		(96	)		279			196
Net income (loss) available to common stockholder (in millions)	($		)		310		184		(98	)		277			194
Cash provided by operations (in millions)	($		)		442		473		639			595			5
Capital expenditures, excluding capital lease additions (in millions)	($		)		1,258		646		572			508			486
Total assets (in millions)(a)	($		)		13,401		12,845		13,178			12,811			10,745
Long-term debt, excluding current portion (in millions)(a)	($		)		3,692		4,127		4,303			4,000			3,583
Long-term debt — related parties, excluding current portion (in millions)	($		)		—		—		—			326			506
Non-current portion of capital and finance lease obligations (in millions)	($		)		225		42		308			315			58
Total preferred stock (in millions)	($		)		44		44		44			44			44
Number of preferred shareholders at year-end					1,641		1,728		1,823			1,931			2,032
Book value per common share at year-end	($		)		43.37		35.17		33.03			28.68			24.51
Number of full-time equivalent employees at year-end					7,614		8,026		8,114			8,050			7,947
Electric statistics
Sales (billions of kWh)					39		38		39			38			38
Customers (in thousands)					1,799		1,797		1,789			1,772			1,754
Average sales rate per kWh		(c	)		8.65		8.46		6.73			6.88			6.91
Gas Utility Statistics
Sales and transportation deliveries (bcf)					340		309		350			385			380
Customers (in thousands)(b)					1,710		1,714		1,708			1,691			1,671
Average sales rate per mcf	($		)		10.66		10.44		9.61			8.04			6.72

(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

In this MD&A, Consumers Energy, which includes Consumers Energy Company and all of its subsidiaries, is at times referred to in the first person as “we,” “our” or “us.”

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. Such factors include our inability to predict and (or) control:

•  the price of CMS Energy Common Stock, capital and financial market conditions, and the effect of such market conditions on the Pension Plan, interest rates, and access to the capital markets, including availability of financing to Consumers, CMS Energy, or any of their affiliates, and the energy industry,

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

•  factors affecting utility and diversified energy operations, such as unusual weather conditions, catastrophic weather-related damage, unscheduled generation outages, maintenance or repairs, environmental incidents, or electric transmission or gas pipeline system constraints,

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

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

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

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

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

•  recovery of power supply and natural gas supply costs,

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

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

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

•  recovery of Stranded Costs incurred due to customers choosing alternative energy suppliers,

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

•  recovery of Palisades sale related costs,

•  approval of the Balanced Energy Initiative, and

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•  authorization of a new clean coal plant.

•  the effects on our ability to purchase capacity to serve our customers and fully recover the cost of these purchases, if the owners of the MCV Facility exercise their right to terminate the MCV PPA,

•  our ability to prevail in the exercise of our regulatory out rights under the MCV PPA,

•  our ability to recover Big Rock decommissioning funding shortfalls and nuclear fuel storage costs due to the DOE’s failure to accept spent nuclear fuel on schedule, including the outcome of pending litigation with the DOE,

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

•  our ability to collect accounts receivable from our customers,

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

•  the effect on our utility and utility revenues of the direct and indirect impacts of the continued economic downturn in Michigan,

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

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

•  achievement of capital expenditure and operating expense goals,

•  changes in financial or regulatory accounting principles or policies,

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

•  changes in federal or state regulations or laws that could have an impact on our business,

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

•  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,

•  credit ratings of Consumers or CMS Energy, and

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

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

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We manage our business by the nature of services each provides 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.

We sold Palisades to Entergy in April 2007 for $380 million, and received $363 million after various closing adjustments. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. We entered into a 15-year power purchase agreement with Entergy for 100 percent of the plant’s current electric output. The sale improved our cash flow, reduced our nuclear operating and decommissioning risk, and increased our financial flexibility to support other utility investments. The MPSC order approving the transaction requires that we credit $255 million of excess proceeds and decommissioning amounts to our retail customers by December 2008. There are additional excess sales proceeds and decommissioning fund balances of $134 million above the amount in the MPSC order. The distribution of these additional amounts has not yet been addressed by the MPSC.

In September 2007, we exercised the regulatory-out provision in the MCV PPA, thus limiting the amount we pay the MCV Partnership for capacity and fixed energy to the amount recoverable from our customers. The MCV Partnership may, under certain circumstances, have the right to terminate or reduce the amount of capacity sold under the MCV PPA, which could affect our need to build or purchase additional generating capacity. The MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision.

In May 2007, we filed with the MPSC our Balanced Energy Initiative, which is a comprehensive plan to meet customer energy needs over the next 20 years. The plan is designed to meet the growing customer demand for electricity with energy efficiency, demand management, expanded use of renewable energy, and development of new power plants to complement existing generating sources. In September 2007, we filed with the MPSC the second phase of our Balanced Energy Initiative, which contains our plan for construction of a new 800 MW clean coal plant at an existing site located near Bay City, Michigan.

In December 2007, we purchased a 935 MW natural gas-fired power plant located in Zeeland, Michigan from Broadway Gen Funding LLC, an affiliate of LS Power Group, for $519 million. This plant fits in with our Balanced Energy Initiative as it will help provide the capacity we need to meet the growing needs of our customers.

In the future, we will continue to focus on:

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

•  growing earnings while controlling operating and fuel costs,

•  managing cash flow issues, and

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•  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 sluggish Michigan economy that has been hampered by negative developments in Michigan’s automotive industry and limited growth in the non-manufacturing sectors of the state’s economy. While the recent sub-prime mortgage market weakness has disrupted financial markets and the U.S. economy, it has not impacted materially our financial condition. We will continue to monitor developments for potential impacts on our business.

RESULTS OF OPERATIONS

Net Income (Loss) Available to Common Stockholder

Years Ended December 31	2007		2006			Change			2006			2005			Change
	In Millions
Electric	$	196	$	199		$	(3	)	$	199		$	153			46
Gas		87		37			50			37			48			(11	)
Other (Includes The MCV Partnership interest)		27		(52	)		79			(52	)		(299	)		247
Net Income (Loss) Available to Common Stockholder	$	310	$	184		$	126		$	184		$	(98	)	$	282

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 are no longer experiencing 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.

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

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For 2006, our net income available to our common stockholder was $184 million, compared to a net loss available to our common stockholder of $98 million for 2005. The increase was primarily due to the absence of a 2005 impairment charge to property, plant, and equipment at the MCV Partnership partially offset by charges related to the sale of the MCV Partnership recorded in 2006. For additional details on the impairment and sale of the MCV Facility, see Note 2, Asset Sales and Impairment Charges. The increase also reflects higher net income from our electric utility, primarily due to increased revenue resulting from an electric rate order, the expiration of rate caps on our residential customers, and the return of former ROA customers to full-service rates. Partially offsetting these increases were higher operating and maintenance costs at our electric utility, and a reduction in net income from our gas utility. Lower, weather-driven sales at our gas utility exceeded the benefits from lower operating costs and a gas rate increase authorized by the MPSC in November of 2006.

Specific changes to net income available to our common stockholder for 2006 versus 2005 are:

		In Millions
•	the net impact of activities associated with the MCV Partnership as the absence of a 2005 impairment charge and improved operations in 2006 more than offset the negative effects of mark-to-market activity and charges related to the sale of our interest in the MCV Partnership,	$	225
•	increase in electric delivery revenue primarily due to a December 2005 electric rate order,		165
•	increase in earnings due to the expiration of rate caps that, in 2005, would not allow us to recover fully our power supply costs from our residential customers,		37
•	increase in gas wholesale and retail services and other gas revenue associated with pipeline capacity optimization,		16
•	increase in return on electric utility capital expenditures in excess of depreciation base as allowed by the Customer Choice Act,		14
•	decrease in income taxes primarily due to an IRS audit settlement,		14
•	increase in operating expenses primarily due to higher depreciation and amortization expense, higher electric maintenance expense, and higher customer service expense,		(101	)
•	decrease in gas delivery revenue primarily due to lower, weather-driven sales,		(31	)
•	increase in operating expenses primarily due to costs related to a planned refueling outage at our Palisades nuclear plant,		(29	)
•	increase in interest charges, and		(20	)
•	increase in general tax expense, primarily due to higher property tax expense.		(8	)
Total change		$	282

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Electric Utility Results of Operations

Years Ended December 31	2007		2006		Change			2006		2005		Change
					In Millions
Net income	$	196	$	199	$	(3	)	$	199	$	153	$	46
Reasons for the change:
Electric deliveries					$	18						$	193
Surcharge revenue						6							61
Palisades revenue to PSCR						(136	)						—
Power supply costs and related revenue						(17	)						57
Other operating expenses, other income, and non-commodity revenue						159							(236	)
Regulatory return on capital expenditures						5							22
General taxes						(15	)						(7	)
Interest charges						(18	)						(34	)
Income taxes						(5	)						(10	)
Total change					$	(3	)					$	46

Electric deliveries: For 2007, electric delivery revenues increased $18 million versus 2006, 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, which resulted in an increase in electric delivery revenues of $14 million. The increase also reflects $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.

For 2006, electric delivery revenues increased by $193 million over 2005 despite the fact that electric deliveries to end-use customers were 38.5 billion kWh, a decrease of 0.4 billion kWh or 1.2 percent versus 2005. The decrease in deliveries was primarily due to milder summer weather compared with 2005, which resulted in a decrease in revenue of $16 million. However, despite these lower electric deliveries, electric delivery revenues increased $160 million due to an approved electric rate order in December 2005 and $49 million related to the return of additional former ROA customers.

Surcharge revenue: For 2007, the $6 million increase in surcharge revenue was primarily due to a surcharge that we started collecting in the first quarter of 2006 that the MPSC authorized under Section 10d(4) of the Customer Choice Act. The surcharge factors increased in January 2007 pursuant to an MPSC order. This surcharge increased electric delivery revenue by $13 million in 2007 versus 2006. Partially offsetting this increase was a decrease in the collection of Customer Choice Act transition costs, due to the expiration of the surcharge period for our large commercial and industrial customers. The absence of this surcharge decreased electric delivery revenue by $7 million in 2007 versus 2006.

In the first quarter of 2006, we started collecting the surcharge that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This surcharge increased electric delivery revenue by $51 million in 2006 versus 2005. In addition, in the first quarter of 2006, we started collecting customer choice transition costs from our residential customers that increased electric delivery revenue by $12 million in 2006 versus 2005. Reductions in other surcharges decreased electric delivery revenue by $2 million in 2006 versus 2005.

Palisades revenue to PSCR: Consistent with the MPSC order related to the April 2007 sale of Palisades, $136 million of revenue related to Palisades was designated toward recovery of PSCR costs.

Power supply costs and related revenue: 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

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decrease also reflects the absence, in 2007, of an increase in Power Supply Revenue associated with the 2005 PSCR reconciliation case.

For 2006, PSCR revenue increased $57 million versus 2005. The increase was due to the absence, in 2006, of rate caps which allowed us to record power supply revenue to offset fully our power supply costs. Our ability to recover these power supply costs resulted in an $82 million increase in electric revenue in 2006 versus 2005. Additionally, electric revenue increased $9 million in 2006 versus 2005 primarily due to the return of former special-contract customers to full-service rates in 2006. Partially offsetting these increases was the absence, in 2006, of deferrals of transmission and nitrogen oxides allowance expenditures related to our capped customers recorded in 2005. These costs were not fully recoverable due to the application of rate caps, so we deferred them for recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the MPSC approved the recovery of these costs. For 2005, deferrals of these costs were $34 million.

Other operating expenses, other income, and non-commodity revenue: For 2007, other operating expenses decreased $150 million, other income increased $21 million, and non-commodity revenue decreased $12 million versus 2006.

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

Other income increased in 2007 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. Non-commodity revenue decreased in 2007 versus 2006 primarily due to lower transmission services revenue.

For 2006, other operating expenses increased $236 million versus 2005. The increase in other operating expenses reflects higher operating and maintenance, customer service, depreciation and amortization, and pension and benefit expenses. Operating and maintenance expense increased primarily due to costs related to a planned refueling outage at Palisades, and higher tree trimming and storm restoration costs.

Regulatory return on capital expenditures: For 2007, the return on capital expenditures in excess of our depreciation base increased income by $5 million versus 2006. The increase reflects the equity return on the regulatory asset authorized by the MPSC’s December 2005 order which provided for the recovery of $333 million of Section 10d(4) costs over five years.

For 2006, the return on capital expenditures in excess of our depreciation base increased income by $22 million versus 2005.

General taxes: For 2007, the $15 million increase in general taxes versus 2006 was primarily due to higher property tax expense, reflecting higher millage rates and lower property tax refunds versus 2006.

For 2006, the $7 million increase in general taxes versus 2005 reflects higher MSBT expense, partially offset by property tax refunds.

Interest charges: 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.

For 2006, interest charges increased $34 million versus 2005 primarily due to lower capitalized interest and interest expense related to an IRS income tax audit settlement. In 2005, we capitalized $33 million of interest in connection with the MPSC’s December 2005 order in our Section 10d(4) Regulatory Asset case. The IRS income tax settlement in 2006 recognized that our taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years.

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Income taxes: 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.

For 2006, income taxes increased $10 million versus 2005 primarily due to higher earnings by the electric utility, partially offset by the resolution of an IRS income tax audit, which resulted in a $4 million income tax benefit caused by the restoration and utilization of income tax credits. Further reducing the increase in income taxes was $5 million of income tax benefits, primarily reflecting the tax treatment of items related to property, plant and equipment as required by past MPSC orders.

Gas Utility Results of Operations

Years Ended December 31	2007		2006		Change			2006		2005		Change
					In Millions
Net income	$	87	$	37	$	50		$	37	$	48	$	(11	)
Reasons for the change:
Gas deliveries					$	10						$	(61	)
Gas rate increase						81							14
Gas wholesale and retail services, other gas revenues, and other income						14							24
Other operating expenses						(19	)						7
General taxes and depreciation						(11	)						(10	)
Interest charges						4							(6	)
Income taxes						(29	)						21
Total change					$	50						$	(11	)

Gas deliveries: For 2007, gas delivery revenues increased by $10 million versus 2006 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 lower system efficiency.

In 2006, gas delivery revenues decreased by $61 million versus 2005 as gas deliveries, including miscellaneous transportation to end-use customers, were 282 bcf, a decrease of 36 bcf or 11.3 percent. The decrease in gas deliveries was primarily due to warmer weather in 2006 versus 2005 and increased customer conservation efforts in response to higher gas prices.

Gas rate increase: In November 2006, the MPSC issued an order authorizing an annual rate increase of $81 million. In August 2007, the MPSC issued an order authorizing an annual rate increase of $50 million. As a result of these orders, gas revenues increased $81 million for 2007 versus 2006.

In May 2006, the MPSC issued an interim gas rate order authorizing an $18 million annual rate increase. In November 2006, the MPSC issued an order authorizing an annual increase of $81 million. As a result of these orders, gas revenues increased $14 million for 2006 versus 2005.

Gas wholesale and retail services, other gas revenues, and other income: For 2007, the $14 million increase in gas wholesale and retail services, other gas revenue and other income primarily reflects 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.

For 2006, the $24 million increase in gas wholesale and retail services, other gas revenues, and other income primarily reflects higher pipeline revenues and higher pipeline capacity optimization in 2006 versus 2005.

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Other operating expenses: 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.

For 2006, other operating expenses decreased $7 million versus 2005 primarily due to lower operating expenses, partially offset by higher customer service and pension and benefit expenses.

General taxes and depreciation: 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.

For 2006, general taxes and depreciation expense increased $10 million versus 2005. The increase in depreciation expense was primarily due to higher plant in service. The increase in general taxes reflects higher MSBT expense, partially offset by lower property tax expense.

Interest charges: For 2007, interest charges decreased $4 million reflecting lower average debt levels and a lower average interest rate versus 2006.

For 2006, interest charges increased $6 million primarily due to higher interest expense on our GCR overrecovery balance and an IRS income tax audit settlement. The settlement recognized that Consumers’ taxable income for prior years was higher than originally filed, resulting in interest on the tax liability for these prior years.

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

For 2006, income taxes decreased $21 million versus 2005 primarily due to lower earnings by the gas utility. Also contributing to the decrease was the absence, in 2006, of the write-off of general business credits of $2 million that expired in 2005, and the resolution, in 2006, of an IRS income tax audit, which resulted in a $3 million income tax benefit caused by the restoration and utilization of income tax credits. Further reducing the increase in income taxes was $5 million of income tax benefits, primarily reflecting the tax treatment of items related to property, plant and equipment as required by past MPSC orders.

Other Nonutility Results of Operations

Years Ended December 31	2007		2006			Change		2006			2005			Change
	In Millions
Net income (loss)	$	27	$	(52	)	$	79	$	(52	)	$	(299	)	$	247

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 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 8, Income Taxes, for further details.

For 2006, other nonutility operations were a net loss of $52 million, an increase of $247 million versus 2005. The change is primarily due to a $225 million increase in earnings related to our ownership interest in the MCV Partnership, primarily due to the absence of a 2005 impairment charge to property, plant, and equipment at the MCV Partnership. Partially offsetting this increase were charges related to the sale of the MCV Partnership recorded in 2006 and mark-to-market losses on the MCV Partnership’s long-term gas contracts and associated hedges (which partially reduced gains recorded in 2005).

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CRITICAL ACCOUNTING POLICIES

The following accounting policies and related information are important to an understanding of our results of operations and financial condition and should be considered an integral part of our MD&A. 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.

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 $13.401 billion at December 31, 2007, 64 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 such expenses will be recovered 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 they will require that such revenues be refunded to customers. Judgment is required to determine the recoverability of items recorded as regulatory assets and liabilities. At December 31, 2007, we had $2.059 billion recorded as regulatory assets and $2.137 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, 2007, we had $45 million recorded as regulatory assets for underrecoveries of power supply costs and $19 million recorded as regulatory liabilities for overrecoveries of gas costs.

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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 AOCI. 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, it is recorded 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 5, Financial and Derivative Instruments.

To determine the fair value of our derivatives, we 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. These models 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 results that we estimate using models. If necessary, our calculations of fair value include reserves to reflect the credit risk of our counterparties.

The types of contracts we typically classify as derivatives are interest rate swaps and gas supply options. 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.

Market Risk Information: We are exposed to market risks including, but not limited to, changes in interest rates, commodity prices, and equity security prices. We may use various contracts to limit our exposure to these risks, including swaps, options, and forward contracts. We enter into these risk management contracts using established policies and procedures, under the direction of two different committees: 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 through established credit policies, 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

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prices of 10 percent. Potential losses could exceed the amounts shown in the sensitivity analyses if changes in market rates or prices 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	2007		2006
	In Millions
Variable-rate financing — before tax annual earnings exposure	$	1	$	3
Fixed-rate financing — potential reduction in fair value(a)		116		134

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

At December 31, 2007, we had $131 million in variable auction rate tax exempt bonds, insured by monoline insurers, that are subject to rate reset every 35 days. The subprime mortgage problems have put monoline insurers’ credit ratings at risk of downgrade by rating agencies. This risk of downgrade could cause the interest rates on these bonds to rise. We do not expect our interest rate risk exposure regarding these bonds to be material. We are continuing to monitor the situation and our alternatives

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 gas supply call and put options. As of December 31, 2007, we did not hold any such contracts.

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	2007		2006
	In Millions
Potential reduction in fair value of available-for-sale equity securities (SERP investments and investment in CMS Energy common stock)	$	7	$	6

For additional details on market risk and derivative activities, see Note 5, Financial and Derivative Instruments.

Pension and OPEB

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 5 percent of base pay to the existing Employees’ Savings 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 resumed the employer’s match in CMS Energy Common Stock in our 401(k) savings plan on January 1, 2005. On September 1, 2005, we increased the employer match from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee’s wages.

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Beginning May 1, 2007, the CMS Energy Common Stock Fund was no longer an investment option available for investments in the 401(k) savings plan and the employer match was no longer in CMS Energy Common Stock. Participants had an opportunity to reallocate investments in the CMS Energy Common Stock Fund to other plan investment alternatives prior to November 1, 2007. In November 2007, the remaining shares in the CMS Energy Common Stock Fund were sold and the sale proceeds were reallocated to other plan investment options.

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,

•  present-value 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 Costs	Pension Cost		OPEB Cost		Contributions
	In Millions
2008	$	103	$	29	$	48
2009		109		28		48
2010		112		26		129

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 2008 by $3 million. Lowering the discount rate by 0.25 percent (from 6.40 percent to 6.15 percent) would increase estimated pension cost for 2008 by $1 million.

For additional details on postretirement benefits, see Note 6, 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. No market risk premium was included in our ARO fair value estimate 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

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for assets that have insignificant cumulative disposal costs, such as substation batteries. For additional details, see Note 7, 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.

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,

•  credit ratings,

•  working capital needs, and

•  collateral requirements.

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

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

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

•  our current level of cash and revolving credit facilities,

•  our anticipated cash flows from operating and investing activities, and

•  our ability to access secured and unsecured borrowing capacity in the capital markets, if necessary.

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

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Cash Position, Investing, and Financing

Our operating, investing, and financing activities meet consolidated cash needs. At December 31, 2007, we had $220 million of consolidated cash, which includes $25 million of restricted cash.

Summary of Cash Flows:

	2007			2006			2005
	In Millions
Net cash provided by (used in):
Operating activities	$	442		$	473		$	639
Investing activities		(585	)		(672	)		(661	)
Net cash used in operating and investing activities		(143	)		(199	)		(22	)
Financing activities		301			(180	)		267
Net Increase (Decrease) in Cash and Cash Equivalents	$	158		$	(379	)	$	245

Operating Activities:

2007: Net cash provided by operating activities was $442 million, a decrease of $31 million versus 2006. This decrease was driven by the following:

•  the absence, in 2007, of the sale of accounts receivable,

•  a payment to fund our Pension Plan,

•  refunds to customers of excess Palisades decommissioning funds, and

•  other timing differences.

These decreases were partially offset by increased earnings and:

•  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, and

•  a decrease in expenditures for gas inventory as the milder winter in 2006 allowed us to accumulate more gas in our storage facilities.

For additional details on the excess Palisades decommissioning funds, see Note 2, Asset Sales and Impairment Charges.

2006: Net cash provided by operating activities was $473 million, a decrease of $166 million versus 2005. This decrease was driven by the following:

•  decreases in the MCV Partnership gas supplier funds on deposit resulting in refunds to suppliers from decreased exposure to declining gas prices in 2006,

•  income tax payments to the parent related to the 2006 IRS income tax audit, and

•  decreases in accounts payable mainly due to payments for higher-priced gas that were accrued at December 31, 2005.

These decreases were partially offset by:

•  a decrease in accounts receivable due to the collection of receivables in 2006 reflecting higher gas prices billed during the latter part of 2005 and reduced billings in the latter part of 2006 due to milder weather, and

•  reduced inventory purchases.

Investing Activities:

2007: Net cash used in investing activities was $585 million, a decrease of $87 million versus 2006. This decrease was primarily due to proceeds from the sale of Palisades and the related dissolution of our nuclear

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decommissioning trust funds. This decrease was partially offset by an increase in capital expenditures primarily due to the purchase of the Zeeland power plant.

2006: Net cash used in investing activities was $672 million, an increase of $11 million versus 2005. This increase was due to cash relinquished from the sale of assets, an increase in capital expenditures and cost to retire property and a decrease in net proceeds from investments. These changes were partially offset by a decrease in restricted cash and restricted short-term investments. Cash restricted in 2005 was released in February 2006, which we used to extinguish long-term debt — related parties.

Financing Activities:

2007: Net cash provided by financing activities was $301 million, an increase of $481 million versus 2006. This increase was primarily due to an increase of $450 million 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 of $104 million.

2006: Net cash used in financing activities was $180 million, an increase of $447 million versus 2005. This increase was due to a decrease of $500 million in contributions from the parent and an increase in net retirement of long-term debt. These changes were partially offset by a decrease in common stock dividend payments of $130 million.

For additional details on long-term debt activity, see Note 4, 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, 2007	Total		One Year		Three Years		Five Years		Five Years
	In Millions
Long-term debt(a)	$	4,132	$	440	$	727	$	376	$	2,589
Interest payments on long-term debt(b)		1,712		198		342		298		874
Capital and finance leases(c)		255		30		48		44		133
Interest payments on capital and finance leases(d)		139		14		27		24		74
Operating leases(e)		204		25		44		42		93
Purchase obligations(f)		21,286		2,502		2,897		2,275		13,612
Purchase obligations — related parties(f)		1,492		78		154		154		1,106
Total contractual obligations	$	29,220	$	3,287	$	4,239	$	3,213	$	18,481

(a)	Principal amounts due on outstanding debt obligations, current and long-term, at December 31, 2007. For additional details on long-term debt, see Note 4, 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, 2007.
(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 $62 million per month during 2008. 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 3, Contingencies, “Electric Rate Matters — Power Supply Costs.”

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

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

Off-Balance Sheet Arrangements: 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 amount of potential payments we would be required to make under a number of these indemnities is not estimable. We provide guarantees on behalf of certain non-consolidated entities, improving their ability to transact business. We monitor these obligations and believe it is unlikely that we will incur any material losses associated with these guarantees. For additional details on these arrangements, see Note 3, Contingencies, “Other Contingencies — Guarantees and Indemnifications.”

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we may sell up to $325 million of certain accounts receivable. This program provides a lower cost source of funding compared with unsecured debt. For additional details, see Note 4, Financings and Capitalization.

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 2008 through 2010:

Years Ending December 31	2008		2009		2010
	In Millions
Construction	$	523	$	589	$	575
Clean Air(a)		112		135		94
Cost of Removal		44		56		48
New Customers		83		84		116
Other(b)		156		116		182
Total	$	918	$	980	$	1,015
Electric utility operations(a)(b)	$	684	$	717	$	783
Gas utility operations(b)		234		263		232
Total	$	918	$	980	$	1,015

(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.

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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 increasing environmental performance standards, and to maintain adequate supply and capacity.

ELECTRIC BUSINESS OUTLOOK

Growth: In 2007, electric deliveries grew about one percent over 2006 levels. In 2008, we project electric deliveries to decline one-quarter of a percent compared to 2007 levels. This outlook assumes a small decline in industrial economic activity, the cancellation of one wholesale customer contract, and normal weather conditions throughout the year.

We expect electric deliveries to grow one percent annually over the next five years. This outlook assumes a modestly growing customer base and a stabilizing Michigan economy after 2008. This growth rate, which reflects a long-range expected trend includes both full-service sales and delivery service to customers who choose to buy generation service from an alternative electric supplier, but excludes transactions with other wholesale market participants and other electric utilities. Growth from year to year may vary from this trend due to customer response to the following:

•  energy conservation measures,

•  fluctuations in weather conditions, and

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

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

Electric Reserve Margin: To reduce the risk of high power supply costs during peak demand periods and to achieve our Reserve Margin target, we purchase electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser extent in the winter months. We have purchased capacity and energy contracts covering a portion of our Reserve Margin requirements for 2008 through 2010. We are currently planning for a Reserve Margin of 13.7 percent for summer 2008, or supply resources equal to 113.7 percent of projected firm summer peak load. Of the 2008 supply resources target, we expect 93 percent to come from our electric generating plants and long-term power purchase contracts, with other contractual arrangements making up the remainder. We expect capacity costs for these electric capacity and energy contracts to be $21 million for 2008.

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

Electric Transmission Expenses: In 2008, we expect transmission rates charged to us to increase by $42 million due primarily to a 33 percent increase in METC transmission rates. This increase was included in our 2008 PSCR plan filed with the MPSC in September 2007.

In September 2007, the FERC approved a proposal to include 100 percent of the costs of network upgrades associated with new generator interconnections in the rates of certain MISO transmission owners, including METC.

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Previously, those transmission owners shared interconnection network upgrade costs with generators. Consumers, Detroit Edison, the MPSC, and other parties filed a request for rehearing of the FERC order.

21st Century Electric Energy Plan: In January 2007, the then chairman of the MPSC proposed initiatives to the governor of Michigan for the use of more renewable energy resources by all load-serving entities such as Consumers, the creation of an energy efficiency program, and a procedure for reviewing proposals to construct new generation facilities. The January proposal indicated that Michigan will need new base-load capacity by 2015. The proposed initiatives will require changes to current legislation.

Balanced Energy Initiative: In response to the 21st Century Electric Energy Plan, we filed with the MPSC a “Balanced Energy Initiative” that provides a comprehensive energy resource plan to meet our projected short-term and long-term electric power requirements. The filing requests the MPSC to rule that the Balanced Energy Initiative represents a reasonable and prudent plan for the acquisition of necessary electric utility resources. Implementation of the Balanced Energy Initiative will require legislative repeal or significant reform of the Customer Choice Act.

In September 2007, we filed with the MPSC an updated Balanced Energy Initiative, which includes our plan to build an 800 MW advanced clean coal plant at our Karn/Weadock Generating complex near Bay City, Michigan. We expect to use 500 MW of the plant’s output to serve Consumers’ customers and to commit the remaining 300 MW to others. We expect the plant to begin operating in 2015. We estimate our share of the cost at $1.6 billion including financing costs. Construction of the proposed new clean coal plant is contingent upon obtaining environmental permits and MPSC approval.

The Michigan Attorney General filed a motion with the MPSC to dismiss the Balanced Energy Initiative case, claiming that the MPSC lacks jurisdiction over the matter, which the ALJ denied. The Michigan Attorney General and another intervenor have filed an appeal of that decision with the MPSC.

Proposed Energy Legislation: There are various bills introduced and being considered in the U.S. Congress and the Michigan legislature relating to mandatory renewable energy standards. If enacted, these bills generally would require electric utilities either to acquire a certain percentage of their power from renewable sources or pay fees, or purchase allowances in lieu of having the resources. Also in December 2007, several bills were introduced in the Michigan legislature that would reform the Customer Choice Act, introduce energy efficiency programs, modify the timing of rate increase requests, amend customer rate design and provide for other regulatory changes. We cannot predict whether any of these bills will be enacted or what form the final legislation might take.

Power Plant Purchase: In December 2007, we purchased a 935 MW gas-fired power plant located in Zeeland, Michigan for $519 million from Broadway Gen Funding LLC, an affiliate of LS Power Group. The power plant will help meet the growing energy needs of our customers.

ELECTRIC BUSINESS UNCERTAINTIES

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

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

Clean Air Act: Compliance with the federal Clean Air Act and resulting state and federal regulations continues to be a major focus for us. The State of Michigan’s Nitrogen Oxides Implementation Plan requires significant reductions in nitrogen oxides emissions. From 1998 to present, we have incurred $786 million in capital expenditures to comply with this plan, including installing selective catalytic reduction control technology on three of our coal-fired electric generating units. We have also installed low nitrogen oxides burners on a number of our coal-fired electric generating units.

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Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air Interstate Rule that requires additional coal-fired electric generating plant emission controls for nitrogen oxides and sulfur dioxide. We plan to meet the nitrogen oxides requirements by:

•  operating our selective catalytic reduction control technology units throughout the year,

•  completing the installation of a fourth selective catalytic reduction control unit,

•  installing low nitrogen oxides burners, and

•  purchasing emission allowances.

We plan to meet the sulfur dioxide requirements by injecting a chemical that reduces sulfur dioxide emissions, installing scrubbers and purchasing emission allowances. We plan to spend an additional $835 million for equipment installation through 2015, which we expect to recover in customer rates. The key assumptions in the capital expenditure estimate include:

•  construction commodity prices, especially construction material and labor,

•  project completion schedules and spending plans,

•  cost escalation factor used to estimate future years’ costs of 3.2 percent, and

•  an AFUDC capitalization rate of 7.9 percent.

We will need to purchase additional nitrogen oxides emission allowances through 2011 at an estimated cost of $3 million per year. We will also need to purchase additional sulfur dioxide emission allowances in 2012 and 2013 at an estimated cost of $10 million per year. We expect to recover emissions allowance costs from our customers through the PSCR process.

The Clean Air Interstate Rule was appealed to the U.S. Court of Appeals for the District of Columbia by a number of utilities and other companies. A decision is expected in 2008. We cannot predict the outcome of these appeals.

State and Federal Mercury Air Rules: In March 2005, the EPA issued the CAMR, which requires initial reductions of mercury emissions from coal-fired electric generating plants by 2010 and further reductions by 2018. Certain portions of the CAMR were appealed to the U.S. Court of Appeals for the District of Columbia by a number of states and other entities. The U.S. Court of Appeals for the District of Columbia decided the case on February 8, 2008, and determined that the rules developed by the EPA were not consistent with the Clean Air Act. We continue to monitor the development of federal regulations in this area.

In April 2006, Michigan’s governor proposed a plan that would result in mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ on the details of this plan; however, we have developed preliminary cost estimates and a mercury emissions reduction scenario based on our best knowledge of control technology options and initially proposed requirements. We estimate that costs associated with Phase I of the state’s mercury plan will be approximately $280 million by 2010 and an additional $200 million by 2015. The key assumptions in the capital expenditure estimate are the same as those stated for the Clean Air Interstate Rule.

The following table outlines the proposed state mercury plan:

	Phase I	Phase II
Proposed State Mercury Rule	30% reduction by 2010	90% reduction by 2015

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

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

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

Water: In March 2004, the EPA issued rules that govern electric generating plant cooling water intake systems. The rules require significant reduction in the number of fish harmed by operating equipment. EPA compliance options in the rule were challenged in court. In January 2007, the court rejected many of the compliance options favored by industry and remanded the bulk of the rule back to the EPA for reconsideration. The court’s ruling is expected to increase significantly the cost of complying with this rule. However, the cost to comply will not be known until the EPA’s reconsideration is complete. At this time, the EPA is developing rules to implement the court’s decision. The rules are expected to be released for public comment in late 2008.

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

Electric ROA: The Customer Choice Act allows all of our electric customers to buy electric generation service from us or from an alternative electric supplier. At December 31, 2007, alternative electric suppliers were providing 315 MW of generation service to ROA customers. This is 4 percent of our total distribution load and represents an increase of 5 percent of ROA load compared to December 31, 2006.

In November 2004, the MPSC issued an order allowing us to recover Stranded Costs incurred in 2002 and 2003 through a surcharge applied to ROA customers. Since the MPSC order, we have experienced a downward trend in ROA customers. If this trend continues, it may require legislative or regulatory assistance to recover fully our 2002 and 2003 Stranded Costs.

Electric Rate Case: During 2007, we filed applications with the MPSC seeking an 11.25 percent authorized return on equity and an annual increase in revenues of $269 million. The filings sought recovery of the costs associated with increased plant investment, including the purchase of the Zeeland power plant, increased equity investment, higher operation and maintenance expenses, recovery of transaction costs from the sale of Palisades, and the approval of an energy efficiency program.

In December 2007, the MPSC approved a rate increase of $70 million related to the purchase of the Zeeland power plant. For additional details and material changes relating to the restructuring of the electric utility industry and electric rate matters, see Note 3, Contingencies, “Electric Rate Matters.”

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

As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain circumstances, have the right to terminate the MCV PPA or reduce the amount of capacity sold under the MCV PPA. If the MCV Partnership terminates or reduces the amount of capacity sold under the MCV PPA, we will

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seek to replace the lost capacity to maintain an adequate electric Reserve Margin. This could involve entering into a new power purchase agreement and (or) entering into electric capacity contracts on the open market. We cannot predict whether we could enter into such contracts at a reasonable price. We are also unable to predict whether we would receive regulatory approval of the terms and conditions of such contracts, or whether the MPSC would allow full recovery of our incurred costs.

To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a determination as to whether it wished to reconsider the amount of the MCV PPA payments that we recover from customers. In May 2007, the MCV Partnership also filed an application with the MPSC seeking approval to increase our recovery of costs incurred under the MCV PPA. We cannot predict the financial impact or outcome of these matters. For additional details on the MCV PPA, see Note 3, Contingencies, “Other Electric Contingencies — The MCV PPA.”

Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million and received $363 million after various closing adjustments. We also paid Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI. In addition, we paid the NMC, the former operator of Palisades, $7 million in exit fees and forfeited our $5 million investment in the NMC. The MPSC order approving the Palisades transaction allowed us to recover the book value of Palisades. As a result, we are crediting proceeds in excess of book value of $66 million to our customers through the end of 2008. After closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were $77 million. Recovery of our transaction costs of $28 million, which includes the NMC exit fees and investment forfeiture, is presently under review by the MPSC in our current electric rate case.

Entergy assumed responsibility for the future decommissioning of Palisades and for storage and disposal of spent nuclear fuel at Palisades and the Big Rock ISFSI sites. We transferred $252 million in trust fund assets to Entergy. We are crediting excess decommissioning funds of $189 million to our retail customers through the end of 2008. Modification to the terms of the transaction allowed us immediate access to additional excess decommissioning trust funds of $123 million. The distribution of these funds is currently under review by the MPSC in our electric rate case filing. For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales and Impairment Charges.

As part of the transaction, we entered into a 15-year power purchase agreement under which Entergy sells us all of the plant’s output up to its current annual average capacity of 798 MW. 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 for accounting purposes and not a sale. For additional details on the Palisades financing, see Note 10, Leases.

GAS BUSINESS OUTLOOK

Growth: In 2008, we project that gas deliveries will remain flat, on a weather-adjusted basis, relative to 2007 levels due to continuing conservation and overall economic conditions in Michigan. We expect gas deliveries to decline by less than one-half of one percent annually over the next five years. Actual gas deliveries in future periods may be affected by:

•  fluctuations in weather conditions,

•  use by independent power producers,

•  availability of renewable energy sources,

•  changes in gas commodity prices,

•  Michigan economic conditions,

•  the price of competing energy sources or fuels,

•  gas consumption per customer, and

•  improvements in gas appliance efficiency.

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Consumers Energy Company

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 3, 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 prudency in annual plan and reconciliation proceedings. For additional details on GCR, see Note 3, Contingencies, “Gas Rate Matters — Gas Cost Recovery.”

Gas Depreciation: In June 2007, the MPSC issued its final order in a generic ARO accounting case and modified the filing requirement for our next gas depreciation case. The original filing requirement date was changed from 90 days after the issuance of that order to no later than August 1, 2008. Additionally, we have been ordered to use 2007 data and prepare a cost-of-removal depreciation study with five alternatives using the MPSC’s prescribed methods. We cannot predict the outcome of the analysis.

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

2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity as part of an $88 million annual increase in our gas delivery and transportation rates. In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate increase of $50 million, including an authorized return on equity of 10.75 percent. On September 25, 2007, the MPSC reopened the record in the case to allow all interested parties to be heard concerning the approval of an energy efficiency program, which we proposed in our original filing. Hearings on this matter were held in February 2008. We expect the MPSC to issue a final order in the second quarter of 2008. If approved in total, this would result in an additional rate increase of $9 million for implementation of the energy efficiency program.

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million and an 11 percent authorized return on equity.

OTHER OUTLOOK

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

Software Implementation: We are implementing an integrated business software system for finance, purchasing/supply chain, customer billing, human resources and payroll, and utility asset construction and maintenance work management. We expect the new business software, scheduled to be in production in the first half of 2008, to improve customer service, reduce risk, and increase flexibility. Including work done to date, we expect to incur $175 million in operating expenses and capital expenditures for the initial implementation.

Michigan Public Service Commission: During the third quarter of 2007, the Michigan governor appointed a new MPSC chairperson and a new MPSC commissioner. We have several significant cases pending MPSC review and approval. For additional detail on these cases, see Note 3, Contingencies, “Electric Rate Matters” and “Gas Rate Matters.”

CE-25

Consumers Energy Company

Litigation and Regulatory Investigation: CMS Energy is the subject of various investigations resulting from round-trip trading transactions by CMS MST, including an investigation by the DOJ. For additional details regarding this investigation and litigation, see Note 3, Contingencies.

Michigan Tax Legislation: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan Business Tax Act, which imposed a business income tax of 4.95 percent and a modified gross receipts tax of 0.8 percent. The bill provided for a number of tax credits and incentives geared toward those companies investing and employing in Michigan. The Michigan Business Tax, which was effective January 1, 2008, replaced the state’s Single Business Tax that expired on December 31, 2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional deductions in future years against the business income portion of the tax. These future deductions are phased in over a 15-year period, beginning in 2015. As a result, our net deferred tax liability of $165 million, recorded due to the Michigan Business Tax enactment, was offset by a net deferred tax asset of $165 million. In December 2007, the Michigan governor signed House Bill 5408, replacing the expanded sales tax for certain services with a 21.99 percent surcharge on the business income tax and the modified gross receipts tax. Therefore, the total tax rates imposed under the Michigan Business Tax are 6.04 percent for the business income tax and 0.98 percent for the modified gross receipts tax. We expect to recover the taxes that we pay from our customers, but we cannot predict the timeliness of such recovery.

Implementation of New Accounting Standards

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS No. 158. Phase one of this standard, 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 requires that we change our plan measurement date from November 30 to December 31, effective for the year ending December 31, 2008. The implementation of phase two of this standard will not have a material effect on our consolidated financial statements.

FIN 48, Accounting for Uncertainty in Income Taxes: This interpretation, which we adopted on January 1, 2007, provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management’s best judgment, it is greater than 50 percent likely that we will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return.

Consumers joins in the filing of a consolidated U.S. federal income tax return as well as unitary and combined income tax returns in several states. Consumers and its subsidiaries also file separate company income tax returns in several states. The only significant state tax paid by Consumers or any of its subsidiaries is in Michigan. However, since the Michigan Single Business Tax was not an income tax, it was not part of the FIN 48 analysis. The IRS has completed its audits for all the consolidated federal returns, of which Consumers is a member, for years through 2001. The federal income tax returns for the years 2002 through 2006 are open under the statute of limitations, with 2002 through 2005 currently under examination.

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. Since all our remaining uncertain tax benefits relate only to timing issues, at December 31, 2007, there are no uncertain benefits that would reduce our effective tax rate in future years. We are not expecting any other material changes to our uncertain tax positions over the next twelve months.

CE-26

Consumers Energy Company

Due to the consolidated net operating loss position, we have reflected no interest related to our uncertain income tax positions on our Balance Sheet as of December 31, 2007, nor have we accrued any penalties. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us on January 1, 2008. The standard provides a revised definition of fair value and establishes a framework for measuring fair value. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value, but it requires new disclosures about the impact and reliability of fair value measurements. The standard will also eliminate the existing prohibition against recognizing “day one” gains and losses on derivative instruments. We currently do not hold any derivatives that would involve day one gains or losses. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we currently hold. We do not believe that the implementation of this standard will have a material effect on our consolidated financial statements.

In February 2008, the FASB issued a one-year deferral of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recorded or disclosed at fair value on a recurring basis. Under this partial deferral, SFAS No. 157 will not be effective until January 1, 2009 for fair value measurements in the following areas:

•  AROs,

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

•  fair value measurements performed in conjunction with impairment analyses.

SFAS No. 157 remains effective January 1, 2008 for our derivative instruments, available-for-sale investment securities, and long-term debt fair value disclosures.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us on January 1, 2008. This standard gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We do not expect to elect the fair value option for any financial instruments or other items.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. Any changes in our ownership interests while control is retained will be treated as equity transactions. In addition, this standard requires presentation and disclosure of the allocation between controlling and noncontrolling interests’ income from continuing operations, discontinued operations, and comprehensive income and a reconciliation of changes in the consolidated statement of equity during the reporting period. The presentation and disclosure requirements of the standard will be applied retrospectively for all periods presented. All other requirements will be applied prospectively. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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

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Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

	Years Ended December 31
	2007			2006			2005
	In Millions
Operating Revenue	$	6,064		$	5,721		$	5,232
Earnings from Equity Method Investees		—			1			1
Operating Expenses
Fuel for electric generation		385			672			605
Fuel costs mark-to-market at the MCV
Partnership		—			204			(200	)
Purchased and interchange power		1,370			647			347
Purchased power — related parties		79			74			68
Cost of gas sold		1,918			1,770			1,844
Other operating expenses		808			895			841
Maintenance		183			284			218
Depreciation and amortization		524			527			484
General taxes		217			150			214
Asset impairment charges		—			218			1,184
Gain on asset sales, net		(2	)		(79	)		—
		5,482			5,362			5,605
Operating Income (Loss)		582			360			(372	)
Other Income (Deductions)
Interest and dividends		69			62			45
Interest and dividends — related parties		1			—			—
Regulatory return on capital expenditures		31			26			4
Other income		32			20			20
Other expense		(14	)		(12	)		(15	)
		119			96			54
Interest Charges
Interest on long-term debt		234			281			289
Interest on long-term debt — related parties		2			5			16
Other interest		34			13			5
Capitalized interest		(6	)		(10	)		(38	)
		264			289			272
Income (Loss) Before Income Taxes		437			167			(590	)
Income Tax Expense (Benefit)		125			91			(47	)
Income (Loss) Before Minority Obligations, Net		312			76			(543	)
Minority Obligations, Net		—			(110	)		(447	)
Net Income (Loss)		312			186			(96	)
Preferred Stock Dividends		2			2			2
Net Income (Loss) Available to Common Stockholder	$	310		$	184		$	(98	)

The accompanying notes are an integral part of these statements.

CE-29

Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Years Ended December 31
	2007			2006			2005
	In Millions
Cash Flows from Operating Activities
Net income (loss)	$	312		$	186		$	(96	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation and amortization (includes nuclear decommissioning of $4, $6 and $6)		524			527			484
Deferred income taxes and investment tax credit		55			(113	)		(225	)
Regulatory return on capital expenditures		(31	)		(26	)		(4	)
Minority obligations, net		—			(110	)		(447	)
Fuel costs mark-to-market at the MCV Partnership		—			204			(200	)
Asset impairment charges		—			218			1,184
Postretirement benefits expense		124			122			107
Capital lease and other amortization		44			37			34
Bad debt expense		33			30			24
Gain on sale of assets		(2	)		(79	)		—
Earnings from equity method investees		—			(1	)		(1	)
Postretirement benefits contributions		(173	)		(68	)		(62	)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable, notes receivable and accrued revenue		(442	)		24			(229	)
Decrease (increase) in accrued power supply and gas revenue		99			(91	)		(65	)
Increase in inventories		(5	)		(114	)		(235	)
Increase (decrease) in accounts payable		(23	)		(32	)		154
Increase (decrease) in accrued expenses		(15	)		35			(13	)
Increase (decrease) in accrued taxes		80			(101	)		146
Increase (decrease) in the MCV Partnership gas supplier funds on deposit		—			(147	)		173
Increase in other current and non-current assets		(5	)		(51	)		(20	)
Increase (decrease) in other current and non-current liabilities		(133	)		23			(70	)
Net cash provided by operating activities		442			473			639
Cash Flows from Investing Activities
Capital expenditures (excludes assets placed under capital lease)		(1,258	)		(646	)		(572	)
Cost to retire property		(28	)		(78	)		(27	)
Restricted cash and restricted short-term investments		32			126			(162	)
Investments in nuclear decommissioning trust funds		(1	)		(21	)		(6	)
Proceeds from nuclear decommissioning trust funds		333			22			39
Purchases of available-for-sale SERP investments		(31	)		(2	)		(1	)
Proceeds from available-for-sale SERP investments		29			3			2
Proceeds from short-term investments		—			—			145
Purchase of short-term investments		—			—			(141	)
Maturity of the MCV Partnership restricted investment securities held-to-maturity		—			130			318
Purchase of the MCV Partnership restricted investment securities held-to-maturity		—			(131	)		(270	)
Cash proceeds from sale of assets		337			69			2
Cash relinquished from sale of assets		—			(148	)		—
Other investing		2			4			12
Net cash used in investing activities		(585	)		(672	)		(661	)

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Consumers Energy Company

	Years Ended December 31
	2007			2006			2005
	In Millions
Cash Flows from Financing Activities
Proceeds from issuance of long term debt		—			—			910
Retirement of long-term debt		(34	)		(217	)		(1,028	)
Payment of common stock dividends		(251	)		(147	)		(277	)
Payment of capital and finance lease obligations		(20	)		(26	)		(29	)
Stockholder’s contribution, net		650			200			700
Payment of preferred stock dividends		(1	)		(2	)		(2	)
Increase (decrease) in notes payable		(42	)		15			27
Debt issuance and financing costs		(1	)		(3	)		(34	)
Net cash provided by (used in) financing activities		301			(180	)		267
Net Increase (Decrease) in Cash and Cash Equivalents		158			(379	)		245
Cash and Cash Equivalents, Beginning of Period		37			416			171
Cash and Cash Equivalents, End of Period	$	195		$	37		$	416
Other cash flow activities and non-cash investing and financing activities were:
Cash transactions
Interest paid (net of amounts capitalized)	$	242		$	279		$	250
Income taxes paid (net of refunds, $98, $39, and $8)		—			306			35
Non-cash transactions
Other assets placed under capital lease	$	229		$	7		$	12

The accompanying notes are an integral part of these statements.

CE-31

Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

	December 31
	2007		2006
	In Millions
ASSETS
Plant and Property (at cost)
Electric	$	8,555	$	8,504
Gas		3,467		3,273
Other		15		15
		12,037		11,792
Less accumulated depreciation, depletion, and amortization		3,993		5,018
		8,044		6,774
Construction work-in-progress		447		639
		8,491		7,413
Investments
Stock of affiliates		32		36
Other		—		5
		32		41
Current Assets
Cash and cash equivalents at cost, which approximates market		195		37
Restricted cash at cost, which approximates market		25		57
Accounts receivable and accrued revenue, less allowances of $16 in 2007 and $14 in 2006		810		389
Notes receivable		67		46
Accrued power supply and gas revenue		45		156
Accounts receivable — related parties		4		5
Inventories at average cost
Gas in underground storage		1,123		1,129
Materials and supplies		79		81
Generating plant fuel stock		100		105
Deferred property taxes		158		150
Regulatory assets — postretirement benefits		19		19
Prepayments and other		28		50
		2,653		2,224
Non-current Assets
Regulatory assets
Securitized costs		466		514
Postretirement benefits		921		1,131
Customer Choice Act		149		190
Other		504		497
Nuclear decommissioning trust funds		—		602
Other		185		233
		2,225		3,167
Total Assets	$	13,401	$	12,845

The accompanying notes are an integral part of these statements.

CE-32

Consumers Energy Company

	December 31
	2007		2006
	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		1,832
Accumulated other comprehensive income		—		15
Retained earnings		324		270
		3,647		2,958
Preferred stock		44		44
Long-term debt		3,692		4,127
Non-current portion of capital and finance lease obligations		225		42
		7,608		7,171
Current Liabilities
Current portion of long-term debt, capital and finance lease obligations		470		44
Notes payable — related parties		—		42
Accounts payable		403		421
Accrued rate refunds		19		37
Accounts payable — related parties		13		18
Accrued interest		65		62
Accrued taxes		353		295
Deferred income taxes		151		11
Regulatory liabilities		164		—
Other		150		184
		1,788		1,114
Non-current Liabilities
Deferred income taxes		713		847
Regulatory liabilities
Regulatory liabilities for cost of removal		1,127		1,166
Income taxes, net		533		539
Other regulatory liabilities		313		249
Postretirement benefits		813		993
Asset retirement obligations		198		497
Deferred investment tax credit		58		62
Other		250		207
		4,005		4,560
Commitments and Contingencies (Notes 3, 4, 5, 8, and 10)
Total Stockholder’s Investment and Liabilities	$	13,401	$	12,845

CE-33

Consumers Energy Company

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY

	Years Ended December 31
	2007			2006			2005
	In Millions
Common Stock
At beginning and end of period(a)	$	841		$	841		$	841
Other Paid-in Capital
At beginning of period		1,832			1,632			932
Stockholder’s contribution		650			200			700
At end of period		2,482			1,832			1,632
Accumulated Other Comprehensive Income
Retirement benefits liability
At beginning of period		(8	)		(2	)		(1	)
Retirement benefits liability adjustments(b)		—			—			(1	)
Net loss arising during the period(b)		(7	)		—			—
Adjustment to initially apply FASB Statement No. 158, net of tax		—			(6	)		—
At end of period		(15	)		(8	)		(2	)
Investments
At beginning of period		23			18			12
Unrealized gain (loss) on investments(b)		(1	)		5			6
Reclassification adjustments included in net income (loss)(b)		(7	)		—			—
At end of period		15			23			18
Derivative instruments
At beginning of period		—			56			20
Unrealized gain (loss) on derivative instruments(b)		—			(21	)		53
Reclassification adjustments included in net income (loss)(b)		—			(35	)		(17	)
At end of period		—			—			56
Total Accumulated Other Comprehensive Income		—			15			72
Retained Earnings
At beginning of period		270			233			608
Adjustment to initially apply FIN 48		(5	)		—			—
Net income (loss)(b)		312			186			(96	)
Cash dividends declared — Common Stock		(251	)		(147	)		(277	)
Cash dividends declared — Preferred Stock		(2	)		(2	)		(2	)
At end of period		324			270			233
Total Common Stockholder’s Equity	$	3,647		$	2,958		$	2,778

The accompanying notes are an integral part of these statements.

CE-34

Consumers Energy Company

	Years Ended December 31
	2007			2006			2005
	In Millions
(a) Number of shares of common stock outstanding was 84,108,789 for all periods presented.
(b) Disclosure of Comprehensive Income (Loss):
Net income (loss)	$	312		$	186		$	(96	)
Retirement benefits liability
Retirement benefits liability adjustment, net of tax benefit of $—		—			—			(1	)
Net loss arising during the period, net of tax benefit of $(4)		(7	)		—			—
Investments
Unrealized gain (loss) on investments, net of tax (tax benefit) of $(1) in 2007, $2 in 2006, and $3 in 2005		(1	)		5			6
Reclassification adjustments included in net income (loss), net of tax benefit of $(3)		(7	)		—			—
Derivative instruments
Unrealized gain (loss) on derivative instruments, net of tax (tax benefit) of $(11) in 2006, and $28 in 2005		—			(21	)		53
Reclassification adjustments included in net income (loss), net of tax benefit of $(19) in 2006, and $(10) in 2005		—			(35	)		(17	)
Total Comprehensive Income (Loss)	$	297		$	135		$	(55	)

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CE-36

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 services each provides and operate principally in two business segments: electric utility and gas utility.

Principles of Consolidation: The consolidated financial statements include 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 U.S. GAAP. We are required to make estimates using assumptions that may affect the reported amounts and disclosures. Actual results could differ from those estimates.

We record estimated liabilities for contingencies in our consolidated financial statements when it is probable that a liability was incurred and when the amount of loss can be reasonably estimated. For additional details, see Note 3, 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. 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; such 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 (Loss). 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 Equivalents and Restricted Cash: Cash equivalents are all liquid investments with an original maturity of three months or less.

At December 31, 2007, our restricted cash on hand was $25 million. We classify restricted cash dedicated for repayment of Securitization bonds as a current asset, as the related payments occur within one year.

Collective Bargaining Agreements: At December 31, 2007, the Utility Workers of America Union represented approximately 46 percent of our employees. The Union represents Consumers’ operating, maintenance, and construction employees and our call center employees.

Determination of Pension 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

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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 use the MRV in the calculation of net pension cost.

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 AOCI. We exclude unrealized losses from earnings unless the related changes in fair value are determined to be other than temporary. We reflected unrealized gains and losses on our nuclear decommissioning investments as regulatory liabilities on our Consolidated Balance Sheets.

In accordance with SFAS No. 133, if a contract is a derivative and does not qualify for the normal purchases and sales exception, it is recorded 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 AOCI; otherwise, we report the changes in earnings.

For additional details regarding financial and derivative instruments, see Note 5, Financial and Derivative Instruments.

Impairment of Investments and Long-Lived Assets: 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.

A long-lived asset held-in-use is evaluated 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 2, 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 the emission allowances are used 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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perform depreciation studies periodically to determine appropriate group lives. The composite depreciation rates for our properties are as follows:

Years Ended December 31	2007		2006		2005
Electric utility property		3.0%		3.1%		3.1%
Gas utility property		3.6%		3.6%		3.6%
Other property		8.7%		8.2%		7.6%

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

Years Ended December 31	2007		2006		2005
	In Millions
Other income
Electric restructuring return	$	2	$	4	$	6
Return on stranded and security costs		6		5		6
MCV Partnership emmission allowance sales		—		8		2
Gain on SERP investment		10		—		—
Gain on investment		7		—		—
Gain on stock		4		1		1
All other		3		2		5
Total other income	$	32	$	20	$	20

Years Ended December 31	2007			2006			2005
	In Millions
Other expense
Loss on reacquired debt	$	—		$	—		$	(6	)
Civic and political expenditures		(2	)		(2	)		(2	)
Donations		—			(9	)		—
Abandoned Midland Project		(8	)		—			—
Loss on SERP investment		—			—			(1	)
All other		(4	)		(1	)		(6	)
Total other expense	$	(14	)	$	(12	)	$	(15	)

Property, Plant, and Equipment: We record property, plant, and equipment at original cost when placed into service. When regulated assets are 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. For additional details, see Note 7, Asset Retirement Obligations and Note 11, 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 of AFUDC capitalized 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 property is placed in service, we depreciate and recover the capitalized AFUDC from our

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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	2007			2006			2005
AFUDC capitalization rate		7.4	%		7.5	%		7.6	%

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	2007			2006			2005
		In Millions
Type of Income:
Income from our investments in related party trusts	Consumers’ affiliated Trust Preferred Securities Companies	$	—		$	—		$	1
Dividend Income	CMS Energy		1			—			—
Type of Expense:
Electric generating capacity and energy	Affiliates of Enterprises		(79	)		(74	)		(68	)
Interest expense on long-term debt	Consumers’ affiliated Trust Preferred Securities Companies		—			(1	)		(15	)
Interest expense on note payable	CMS Energy		(2	)		(4	)		(1	)
Overhead expense(a)	CMS Energy		(1	)		(1	)		(1	)
Gas transportation(b)	CMS Bay Area Pipeline, L.L.C.		(1	)		(4	)		(4	)

(a)	We base our related party transactions on regulated prices, market prices, or competitive bidding. We pay overhead costs to CMS Energy based on an industry allocation methodology, such as the Massachusetts Formula.
(b)	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 $32 million at December 31, 2007. For additional details on our investment in CMS Energy Common Stock, see Note 5, Financial and Derivative Instruments.

Trade Receivables: Accounts receivable is primarily composed of trade receivables and unbilled receivables. We record our accounts receivable at cost which approximates fair value. Unbilled receivables were $490 million in 2007 and $355 million in 2006. 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 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 expenses 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 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 such expenses will be recovered 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 they will require that such revenues be refunded to customers.

We reflect the following regulatory assets and liabilities, which include both current and non-current amounts, on our Consolidated Balance Sheets at December 31, 2007.

	End of
	Recovery
December 31	Period	2007		2006
	In Millions
Assets Earning a Return:
Customer Choice Act	2010	$	149	$	190
Unamortized debt costs	2035		74		86
Stranded Costs	See Note 3		68		65
Electric restructuring implementation plan	2008		14		40
Manufactured gas plant sites (Note 3)	2016		33		15
Abandoned Midland project	n/a		—		9
Other(a)	various		50		21
Assets Not Earning a Return:
SFAS No. 158 transition adjustment (Note 6)	various		851		1,038
Securitized costs (Note 4)	2015		466		514
Postretirement benefits (Note 6)	2011		89		112
ARO (Note 7)	n/a		85		177
Big Rock nuclear decommissioning and related costs (Note 3)	n/a		129		35
Manufactured gas plant sites (Note 3)	n/a		17		41
Palisades sales transaction costs (Note 2)	n/a		28		—
Other(a)	2011		6		8
Total regulatory assets(b)		$	2,059	$	2,351
Palisades refund — Current (Note 2)(c)		$	164	$	—
Cost of removal (Note 7)			1,127		1,166
Income taxes, net (Note 8)			533		539
ARO (Note 7)			141		180
Palisades refund — Noncurrent (Note 2)(c)			140		—
Other(a)			32		69
Total regulatory liabilities(b)		$	2,137	$	1,954

(a) At December 31, 2007 and 2006, 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, 2007, we classified $19 million of regulatory assets as current regulatory assets and $2.040 billion of regulatory assets as non-current regulatory assets. At December 31, 2006, we classified $19 million of regulatory assets as current regulatory assets and $2.332 billion of regulatory assets as non-current regulatory assets. At December 31, 2007, we classified $164 million of regulatory liabilities as current regulatory liabilities and $1.973 billion of regulatory liabilities as non-current regulatory liabilities. At December 31, 2006, all of our regulatory liabilities represented non-current regulatory liabilities.

(c)

The MPSC order approving the Palisades and Big Rock ISFSI transaction requires that we credit $255 million of excess proceeds and decommissioning amounts to our retail customers beginning in June 2007 through December 2008. 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. The non-current portion of regulatory liabilities for Palisades refunds represents this obligation, plus interest. For additional details on the sale of Palisades and the Big Rock ISFSI, see Note 2, Asset Sales and Impairment Charges.

Our PSCR and GCR cost recovery mechanisms also represent probable future revenues that will be recovered from or 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 3, Contingencies, “Electric Rate Matters — Power Supply Costs” and for additional details on GCR, see Note 3, 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	2007		2006
	In Millions
Regulatory Assets for PSCR and GCR
Underrecoveries of power supply costs	$	45	$	156
Regulatory Liabilities for PSCR and GCR
Overrecoveries of gas costs	$	19	$	37

New Accounting Standards Not Yet Effective: SFAS No. 157, Fair Value Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us on January 1, 2008. The standard provides a revised definition of fair value and establishes a framework for measuring fair value. Under the standard, fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly exchange between market participants. The standard does not expand the use of fair value, but it requires new disclosures about the impact and reliability of fair value measurements. The standard will also eliminate the existing prohibition against recognizing “day one” gains and losses on derivative instruments. We currently do not hold any derivatives that would involve day one gains or losses. The standard is to be applied prospectively, except that limited retrospective application is required for three types of financial instruments, none of which we currently hold. We do not believe that the implementation of this standard will have a material effect on our consolidated financial statements.

In February 2008, the FASB issued a one-year deferral of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recorded or disclosed at fair value on a recurring basis. Under this partial deferral, SFAS No. 157 will not be effective until January 1, 2009 for fair value measurements in the following areas:

•  AROs,

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

•  fair value measurements performed in conjunction with impairment analyses.

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SFAS No. 157 remains effective January 1, 2008 for our derivative instruments, available-for-sale investment securities, and long-term debt fair value disclosures.

SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities, Including an amendment to FASB Statement No. 115: In February 2007, the FASB issued SFAS No. 159, effective for us on January 1, 2008. This standard gives us the option to measure certain financial instruments and other items at fair value, with changes in fair value recognized in earnings. We do not expect to elect the fair value option for any financial instruments or other items.

SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, an Amendment of ARB No. 51: In December 2007, the FASB issued SFAS No. 160, effective for us January 1, 2009. Ownership interests in subsidiaries held by third parties, which are currently referred to as minority interests, will be presented as noncontrolling interests and shown separately on our Consolidated Balance Sheets within equity. Any changes in our ownership interests while control is retained will be treated as equity transactions. In addition, this standard requires presentation and disclosure of the allocation between controlling and noncontrolling interests’ income from continuing operations, discontinued operations, and comprehensive income and a reconciliation of changes in the consolidated statement of equity during the reporting period. The presentation and disclosure requirements of the standard will be applied retrospectively for all periods presented. All other requirements will be applied prospectively. We are evaluating the impact SFAS No. 160 will have on our consolidated financial statements.

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

2:  ASSET SALES AND IMPAIRMENT CHARGES

Asset Sales

Gross cash proceeds from the sale of assets totaled $337 million in 2007 and $69 million in 2006. The impacts of our asset sales are included in Gain on asset sales, net in our Consolidated Statements of Income (Loss).

For the year ended December 31, 2007, we sold the following assets:

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

(a) Sale of Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million, and received $363 million after various closing adjustments such as working capital and capital expenditure adjustments and nuclear fuel usage and inventory 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. At closing, we transferred $252 million in decommissioning trust fund balances to Entergy. We are presently crediting excess decommissioning funds,

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which totaled $189 million to our retail customers through the end of 2008. Modification to the terms of the transaction allowed us immediate access to additional excess decommissioning trust funds of $123 million. The distribution of these funds is currently under review by the MPSC in our electric rate case filing. We have recorded this obligation, plus interest, as a regulatory liability on our Consolidated Balance Sheets.

The MPSC order approving the Palisades transaction allows us to recover the book value of Palisades. As a result, we are presently crediting proceeds in excess of book value of $66 million to our retail customers through the end of 2008. After closing adjustments, which are subject to MPSC review, proceeds in excess of the book value were $77 million. We recorded the excess proceeds as a regulatory liability on our Consolidated Balance Sheets. Recovery of our transaction costs of $28 million, which includes the NMC exit fees and investment forfeiture, is presently under review by the MPSC in our current electric rate case. We recorded these costs as a regulatory asset on our Consolidated Balance Sheets as recovery is probable.

We accounted for the disposal of Palisades as a financing for accounting purposes and thus we recognized no gain on the Consolidated Statements of Income (Loss). We accounted for the remaining non-real estate assets and liabilities associated with the transaction as a sale. For additional details on the Palisades finance obligation, see Note 10, Leases.

For the year ended December 31, 2006, we sold the following assets:

		Pretax		After-tax
Month sold	Business/Project	Gain		Gain
		In Millions
October	Land in Ludington, Michigan(a)	$	2	$	2
November	MCV GP II(b)		77		38
	Total gain on asset sales	$	79	$	40

(a)	We sold 36 parcels of land near Ludington, Michigan. We held a majority share of the land, which we co-owned with DTE Energy. Our portion of the proceeds was $6 million.
(b)	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. SFAS No. 98 specifies the accounting required for a seller’s sale and simultaneous leaseback involving real estate. 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 of $61 million (excluding $3 million of selling expenses) 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

In November 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.

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In the third quarter of 2005, based on forecasts for higher natural gas prices, the MCV Partnership determined an impairment analysis considering revised forward natural gas price assumptions was required. The MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows. The carrying value of the MCV Partnership’s fixed assets exceeded the estimated fair value resulting in impairment charges of $1.159 billion to recognize the reduction in fair value of the MCV Facility’s fixed assets and $25 million of interest capitalized during the construction of the MCV Facility. Our 2005 consolidated net income was reduced by $385 million, after considering tax effects and minority interest.

We report our interests in the MCV Partnership as a component of our “other” business segment.

3:  CONTINGENCIES

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

SEC Investigation and Settlement: In March 2004, the SEC approved a cease-and-desist order settling an administrative action against CMS Energy related to round-trip trading. The order did not assess a fine and CMS Energy neither admitted to nor denied the order’s findings. The settlement resolved the SEC investigation involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action against three former employees related to round-trip trading at CMS MST. One of the individuals has settled with the SEC. CMS Energy is currently advancing legal defense costs for the remaining two individuals in accordance with existing indemnification policies. The two individuals filed a motion to dismiss the SEC action, which was denied.

Securities Class Action Settlement: Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the United States District Court for the Eastern District of Michigan. The cases were consolidated into a single lawsuit (the “Shareholder Action”), which generally seeks unspecified damages based on allegations that the defendants violated United States securities laws and regulations by making allegedly false and misleading statements about CMS Energy’s business and financial condition, particularly with respect to revenues and expenses recorded in connection with round-trip trading by CMS MST. In January 2005, the court granted a motion to dismiss Consumers and three of the individual defendants, but denied the motions to dismiss CMS Energy and the 13 remaining individual defendants. In March 2006, the court conditionally certified a class consisting of “all persons who purchased CMS Common Stock during the period of October 25, 2000 through and including May 17, 2002 and who were damaged thereby.” The court excluded purchasers of CMS Energy’s 8.75 percent Adjustable Convertible Trust Securities (“ACTS”) from the class and, in response, a new class action lawsuit was filed on behalf of ACTS purchasers (the “ACTS Action”) against the same defendants named in the Shareholder Action. The settlement described in the following paragraph has resolved both the Shareholder and ACTS Actions.

On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the “MOU”), 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 was settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy made a payment of approximately $123 million plus interest on the settlement amount on September 20, 2007. CMS Energy’s insurers paid $77 million, the balance of the settlement amount. In entering into the MOU, CMS Energy made no admission of liability under the Shareholder Action and the ACTS Action. The

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parties executed a Stipulation and Agreement of Settlement dated May 22, 2007 (“Stipulation”) incorporating the terms of the MOU. In accordance with the Stipulation, CMS Energy paid approximately $1 million of the settlement amount to fund administrative expenses. On September 6, 2007, the court issued a final order approving the settlement. The remaining settlement amount was paid following the September 6, 2007 hearing.

Katz Technology Litigation: In June 2007, RAKTL filed a lawsuit in the United States District Court for the Eastern District of Michigan against CMS Energy and Consumers alleging patent infringement. RAKTL claimed that automated customer service, bill payment services and gas leak reporting offered to our customers and accessed through toll free numbers infringe on patents held by RAKTL. On January 15, 2008, Consumers and CMS Energy reached an agreement in principle with RAKTL to settle the litigation. We expect to finalize the terms of the settlement and license by late February 2008. We believe any settlement with RAKTL will be immaterial.

Electric Contingencies

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

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 $1 million and $10 million. At December 31, 2007, we have recorded a liability for the minimum amount of our estimated probable Superfund liability in accordance with FIN 14.

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

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

Electric Utility Plant Air Permit Issues: In April 2007, we received a Notice of Violation (NOV) /Finding of Violation (FOV) from the EPA alleging that fourteen of our utility boilers exceeded visible emission limits in their associated air permits. The utility boilers are located at the D.E. Karn/J.C. Weadock Generating Complex, J.H. Campbell Plant, B.C. Cobb Electric Generating Station and J.R. Whiting Plant, which are all located in Michigan. We have formally responded 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.

Litigation: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs) filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made under power purchase agreements. The judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding

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that we have been correctly administering the energy charge calculation methodology. The plaintiffs have an appeal of the MPSC order pending with the Court of Appeals. We believe we have been performing the calculation in the manner prescribed by the power purchase agreements and have not recorded any reserves. We cannot predict the financial impact or outcome of this matter.

Electric Rate Matters

Electric ROA: The Customer Choice Act allows electric utilities to recover their net Stranded Costs. In November 2004, the MPSC approved recovery of our Stranded Costs incurred from 2002 through 2003 plus interest through the period of collection. At December 31, 2007, we had a regulatory asset for Stranded Costs of $68 million. We collect these Stranded Costs through a surcharge on ROA customers. At December 31, 2007, alternative electric suppliers were providing 315 MW of generation service to ROA customers, which represents an increase of 5 percent of ROA load compared to December 31, 2006. However, since the MPSC order, we have experienced a downward trend in ROA customers. This trend has affected negatively our ability to recover these Stranded Costs in a timely manner. If this trend continues, it may require legislative or regulatory assistance to recover fully our 2002 and 2003 Stranded Costs.

Power Supply Costs: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudency in annual plan proceedings and in plan reconciliation proceedings. The following table summarizes our PSCR reconciliation filings with the MPSC:

Power Supply Cost Recovery Reconciliation

			Net Under-	PSCR Cost
PSCR Year	Date Filed	Order Date	recovery	of Power Sold	Description of Net Underrecovery
2005 Reconciliation	March 2006	July 2007	$36 million	$1.081 billion	MPSC approved the recovery of our $36 million underrecovery, including interest, related to our commercial and industrial customers.
2006 Reconciliation	March 2007	Pending	$105 million(a)	$1.490 billion	Underrecovery relates to our increased METC costs and coal supply costs, certain increased sales, and other cost increases beyond those included in the 2006 PSCR plan filings.

(a) $99 million as recommended by a February 2008 ALJ Proposal for Decision. In a separate matter, this ALJ also recommended that we refund $62 million in proceeds from the sale of excess sulfur dioxide allowances. In accordance with FERC regulations, we previously reserved these proceeds as a regulatory liability pending final direction on disposition of the proceeds from the MPSC.

2007 PSCR Plan: In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as filed. The order also allowed us to include prior year underrecoveries and overrecoveries in future PSCR plans. In September 2007, the ALJ recommended in his Proposal for Decision that we reduce our underrecoveries to reflect the refund of all proceeds from the sale of sulfur dioxide allowances,

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which totaled $62 million. Our PSCR plan proposed to refund 50 percent of proceeds to customers. We reserved all proceeds, excluding interest, as a regulatory liability as discussed in the preceding paragraph.

2008 PSCR Plan: In September 2007, we submitted our 2008 PSCR plan filing to the MPSC. The plan proposed recovery of estimated 2007 PSCR underrecoveries of $84 million. We self-implemented a 2008 PSCR charge in January 2008.

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

Electric Rate Case: In 2007, we filed applications with the MPSC seeking an 11.25 percent authorized return on equity and an annual increase in revenues of $269 million. We presently have an authorized return on equity of 11.15 percent. In July 2007, we filed an amended application for rate relief, which seeks the following:

•  recovery of the purchase of the Zeeland power plant,

•  approval to remove the costs associated with Palisades,

•  approval of a plan for the distribution of additional excess proceeds from the sale of Palisades to customers, effectively offsetting the partial and immediate rate relief for up to nine months, and

•  partial and immediate rate relief associated with 2007 capital investments, a $400 million equity infusion into Consumers, and increased distribution system operation and maintenance costs including employee pension and health care costs.

In December 2007, the MPSC approved a rate increase of $70 million related to the purchase of the Zeeland power plant. The MPSC also stated that our interim request that sought the removal of costs associated with Palisades and the approval of a plan to distribute excess proceeds from the sale of Palisades to customers should be addressed in the final electric rate case order. Furthermore, the MPSC denied our request for the approval of partial and immediate rate relief associated with capital investments, changes in the capital structure, and increased operation and maintenance expenses.

When we are unable to include increased costs and investments in rates in a timely manner, there is a negative impact on our cash flows from electric utility operations. We cannot predict the financial impact or the outcome of this proceeding.

Other Electric Contingencies

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-year power purchase agreement that began in 1990. We estimate that capacity and energy payments under the MCV PPA, excluding RCP savings, will range from $650 million to $750 million annually, assuming successful exercise of the regulatory-out provision in the MCV PPA. We purchased capacity and energy, net of the MCV RCP replacement energy and benefits, under the MCV PPA of $464 million in 2007, $411 million in 2006, and $352 million in 2005.

Regulatory-out Provision in the MCV PPA: Until we exercised the regulatory-out provision in the MCV PPA in September 2007, the cost that we incurred under the MCV PPA exceeded the recovery amount allowed by the MPSC. The regulatory-out provision limits our capacity and fixed energy payments to the MCV Partnership to the amounts that we collect from our customers. Cash underrecoveries of our capacity and fixed energy payments were $39 million in 2007. Savings from the RCP, after allocation of a portion to customers, offset some of our capacity and fixed energy underrecoveries expense.

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As a result of our exercise of the regulatory-out provision, the MCV Partnership may, under certain circumstances, have the right to terminate the MCV PPA, or reduce the amount of capacity sold under the MCV PPA from 1,240 MW to 806 MW, which could affect our electric Reserve Margin. The MCV Partnership has until February 25, 2008 to notify us of its intention to terminate the MCV PPA, at which time the MCV Partnership must specify the termination date. We have not yet received any notification of termination; however, the MCV Partnership has notified us that it disputes our right to exercise the regulatory-out provision. We believe that the provision is valid and fully effective and have not recorded any reserves, but we cannot predict whether we would prevail in the event of litigation on this issue.

We expect the MPSC to review our exercise of the regulatory-out provision and the likely consequences of such action. It is possible that in the event that the MCV Partnership terminates performance under the MCV PPA, prior orders could limit recovery of replacement power costs to the amounts that the MPSC authorized for recovery under the MCV PPA. Depending on the cost of replacement power, this could result in our costs exceeding the recovery amount allowed by the MPSC. We cannot predict the financial impact or outcome of these matters.

To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC requesting a determination as to whether it wished to reconsider the amount of the MCV PPA payments that we recover from customers. The MCV Partnership also filed an application with the MPSC requesting the elimination of the 88.7 percent availability cap on the amount of capacity and fixed energy charges that we are allowed to recover from our customers. We cannot predict the financial impact or outcome of these matters.

Nuclear Matters: Big Rock Decommissioning: The MPSC and the FERC regulate the recovery of costs to decommission Big Rock. In December 2000, funding of the Big Rock trust fund stopped 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 $45 million of corporate contributions for decommissioning costs. This amount excludes 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 $54 million, due to the DOE’s failure to accept spent nuclear fuel on schedule. We plan to seek recovery from the MPSC for decommissioning and other related expenditures and we have a $129 million regulatory asset recorded on our Consolidated Balance Sheets.

Nuclear Fuel Disposal Cost: We deferred payment for disposal of spent nuclear fuel burned before April 7, 1983. Our DOE liability is $159 million at December 31, 2007. This amount includes interest, which is payable upon the first delivery of spent nuclear fuel to the DOE. We recovered, through electric rates, the amount of this liability, excluding a portion of interest. In conjunction with the sale of Palisades and the Big Rock ISFSI, we retained this obligation and provided a $155 million letter of credit to Entergy as security for this obligation.

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

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

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Gas Contingencies

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

From January 1, 2006 to December 31, 2007, we spent a total of $12 million for MGP response activities. At December 31, 2007, we have a liability of $17 million and a regulatory asset of $50 million, which includes $33 million of deferred MGP expenditures. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. Annual response activity costs are expected to range between $4 million and $6 million per year over the next five years. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of response activity costs and the timing of our payments.

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

FERC Investigation: In February 2008, Consumers 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. Consumers will cooperate with the FERC in responding to the request. Consumers cannot predict the financial impact or 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 prudency in annual plan and reconciliation proceedings.

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

Gas Cost Recovery Reconciliation

			Net Over-	GCR Cost
GCR Year	Date Filed	Order Date	recovery	of Gas Sold	Description of Net Overrecovery
2005-2006	June 2006	April 2007	$3 million	$1.8 billion	The net overrecovery includes $1 million interest income through March 2006, which resulted from a net underrecovery position during most of the GCR period.
2006-2007	June 2007	Pending	$5 million	$1.7 billion	The total overrecovery amount reflects an overrecovery of $1 million plus $4 million in accrued interest owed to customers.

GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan year. The order approved a settlement agreement and established a fixed price cap of $10.10 per mcf for December

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2005 through March 2006. We were able to maintain our GCR billing factor below the authorized level for that period. The order was appealed to the Michigan Court of Appeals by one intervenor. In January 2008, the Michigan Court of Appeals affirmed the MPSC’s order for our 2005-2006 GCR Plan year.

GCR plan for year 2006-2007: In August 2006, the MPSC issued an order for our 2006-2007 GCR Plan year. The order approved a settlement agreement that allowed a base GCR ceiling factor of $9.48 per mcf for April 2006 through March 2007. We were able to maintain our GCR billing factor below the authorized level for that period.

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

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 February 2008 is $7.69 per mcf.

GCR plan for year 2008-2009: In December 2007, we filed an application with the MPSC seeking approval of a GCR plan for our 2008-2009 GCR Plan year. Our request proposed the use of a GCR factor consisting of:

•  a base GCR ceiling factor of $8.17 per mcf, plus

•  a quarterly GCR ceiling price adjustment contingent upon future events.

2007 Gas Rate Case: In February 2007, we filed an application with the MPSC seeking an 11.25 percent authorized return on equity as part of an $88 million annual increase in our gas delivery and transportation rates. In August 2007, the MPSC approved a partial settlement agreement authorizing an annual rate increase of $50 million, including an authorized return on equity of 10.75 percent. In September  2007, the MPSC reopened the record in the case to allow all interested parties to be heard concerning the approval of an energy efficiency program, which we proposed in our original filing. Hearings on this matter were held in February 2008. We expect the MPSC to issue a final order in the second quarter of 2008. If approved in total, this would result in an additional rate increase of $9 million for implementation of the energy efficiency program.

2008 Gas Rate Case: In February 2008, we filed an application with the MPSC for an annual gas rate increase of $91 million and an 11 percent authorized return on equity.

Other Contingencies

Guarantees and Indemnifications: FIN 45 requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee.

The following table describes our guarantees at December 31, 2007:

		Expiration	Maximum
Guarantee Description	Issue Date	Date	Obligation
		In Millions
Surety bonds and other indemnifications	Various	Various	$	1	(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.
(b)	At December 31, 2007, only our guarantee to provide power and steam to Dow contained provisions reimbursing us for payments made under the guarantee. The purchaser of our interest in the MCV Partnership and FMLP, an affiliate of GSO Capital Partners and Rockland Capital Energy Investments,

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agreed to pay us $85 million, subject to certain reimbursement rights, if Dow terminates the 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. At December 31, 2007, the guarantee liability recorded for surety bonds and indemnities and for the guarantee to provide power and steam to Dow was immaterial.

We enter into various agreements containing tax and other indemnification provisions in connection with a variety of transactions. While we are unable to estimate the maximum potential obligation related to these indemnities, we consider the likelihood that we would be required to perform or incur significant losses related to these indemnities and the guarantees listed in the preceding tables 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.

We have accrued estimated losses for certain contingencies discussed within this Note. Resolution of these contingencies is not expected to have a material adverse impact on our financial position, liquidity, or future results of operations.

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4:  FINANCINGS AND CAPITALIZATION

Long-term debt at December 31 follows:

	Interest Rate (%)			Maturity	2007			2006
					(In Millions)
First mortgage bonds		4.250		2008	$	250		$	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		2020		300			300
		5.650		2035		145			147
		5.800		2035		175			175
						3,170			3,172
Senior notes		6.375		2008		159			159
		6.875		2018		180			180
Securitization bonds		5.442	(a)	2008-2015		309			340
Nuclear fuel disposal liability				(b)		159			152
Tax-exempt pollution control revenue bonds		Various		2010-2035		161			161
Total principal amount outstanding						4,138			4,164
Current amounts						(440	)		(31	)
Net unamortized discount						(6	)		(6	)
Total long-term debt					$	3,692		$	4,127

(a)	Represents the weighted average interest rate at December 31, 2007 (5.384 percent at December 31, 2006).
(b)	The maturity date is uncertain.

First Mortgage Bonds: We secure our FMBs by a mortgage and lien on substantially all of our property. Our ability to issue FMBs 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.

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 $48 million in 2007 and $50 million in 2006.

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Debt Maturities: At December 31, 2007, the aggregate annual contractual maturities for long-term debt for the next five years are:

	Payments Due
	2008		2009		2010		2011		2012
	(In Millions)
Long-term debt	$	440	$	384	$	343	$	37	$	339

Regulatory Authorization for Financings: The FERC has authorized us to issue up to $1.0 billion of secured and unsecured short-term securities for general corporate purposes. The remaining availability is $500 million at December 31, 2007.

The FERC has also authorized us to issue up to $2.5 billion of secured and unsecured long-term securities for the following:

•  up to $1.5 billion of new issuance for general corporate purposes and

•  up to $1.0 billion for purposes of refinancing or refunding existing long-term debt.

All of the new issuance availability remains ($1.5 billion) and the refinancing availability remaining is $500 million at December 31, 2007.

The authorizations are for the period ending June 30, 2008. Any long-term issuances during the authorization period are exempt from FERC’s competitive bidding and negotiated placement requirements.

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at December 31, 2007:

							Outstanding
			Amount of		Amount		Letters of		Amount
Company	Expiration Date		Facility		Borrowed		Credit		Available
			(In Millions)
Consumers(a)		March 30, 2012	$	500	$	—	$	203	$	297
Consumers(b)		November 28, 2008		200		NA		185		15

(a)	In January 2008, $185 million of letters of credit were cancelled, resulting in the amount of credit available of $482 million under this facility.
(b)	Secured revolving letter of credit facility.

Dividend Restrictions: Under the provisions of our articles of incorporation, at December 31, 2007, we had $269 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. During 2007, we paid $251 million in common stock dividends to CMS Energy.

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, we sell certain 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 $325 million of the receivables. The special purpose entity sold no receivables at December 31, 2007 and $325 million at December 31, 2006. 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. We have not recorded a servicing asset in connection with our accounts receivable sales program.

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Certain cash flows under our accounts receivable sales program are shown in the following table:

Years Ended December 31	2007			2006
	(In Millions)
Net cash flow as a result of accounts receivable financing	$	(325	)	$	—
Collections from customers	$	5,881		$	5,684

Preferred Stock: Details about our outstanding preferred stock follow:

			Optional
			Redemption		Number of Shares
December 31	Series		Price		2007		2006		2007		2006
									(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

5: FINANCIAL AND DERIVATIVE INSTRUMENTS

Financial Instruments: The carrying amounts of cash, 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:

	2007				2006
	Book		Fair		Book		Fair
December 31	Value		Value		Value		Value
	In Millions
Long-term debt(a)	$	4,132	$	4,099	$	4,158	$	4,111

(a) Includes current maturities of $440 million at December 31, 2007 and $31 million at December 31, 2006. Settlement of long-term debt is generally not expected until maturity.

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The summary of our available-for-sale investment securities follows:

	2007								2006
			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	$	24	$	—	$	32	$	10	$	26	$	—		$	36
Nuclear decommissioning investments:
Equity securities		—		—		—		—		140		150		(4	)		286
Debt securities		—		—		—		—		307		4		(2	)		309
SERP:
Equity securities		35		—		—		35		17		9		—			26
Debt securities		7		—		—		7		6		—		—			6

(a) At December 31, 2007, we held 1.8 million shares, and at December 31, 2006, we held 2.2 million shares of CMS Energy Common Stock.

The fair value of available-for-sale debt securities by contractual maturity at December 31, 2007 is as follows:

	(In Millions)
Due after one year through five years	$	3
Due after five years through ten years		4
Total	$	7

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. Net gains of $7 million, net of tax of $3 million, were reclassified from AOCI and included in net income. The proceeds from sales of SERP securities were $3 million during 2006 and $2 million during 2005. Gross gains and losses were immaterial in 2006 and 2005.

Derivative Instruments: In order to limit our exposure to certain market risks, we may enter into various risk management contracts, such as swaps, options, and forward contracts. These contracts, used primarily to limit our exposure to changes in interest rates and commodity prices, are entered into for non-trading purposes. We enter into these contracts using established policies and procedures, under the direction of two different committees: 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 and hedge 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, it is recorded 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. If a derivative qualifies for cash flow hedge accounting treatment, we report changes in its fair value (gains or losses) in AOCI; otherwise, we report the gains and losses in earnings.

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

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

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

•  there is not an active market for the commodity.

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

At December 31, 2007, the fair value of our derivative contracts was immaterial.

6: 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.

In April 2007, we sold Palisades to Entergy. Employees transferred to Entergy as a result of the sale no longer participate in our retirement benefit plans. We recorded a net decrease of $16 million in pension SFAS No. 158 regulatory assets with a corresponding reduction of $16 million in pension liabilities on our Consolidated Balance Sheets. We also recorded a net decrease of $15 million in OPEB regulatory SFAS No. 158 assets with a corresponding reduction of $15 million in OPEB liabilities. The following table shows the net adjustment:

	Pension		OPEB
Plan liability transferred to Entergy	$	38	$	20
Trust assets transferred to Entergy		22		5
Net adjustment	$	16	$	15

On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of 5 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. 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. The DCCP expense was $2 million for each of the years ended December 31, 2007 and December 31, 2006.

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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 $53 million at December 31, 2007 and $32 million at December 31, 2006. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $48 million at December 31, 2007 and $37 million at December 31, 2006. 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, 2007 and 2006. 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, 2007 and 2006.

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

Beginning May 1, 2007, the CMS Energy Common Stock Fund was no longer an investment option available for investments in the 401(k) savings plan and the employer match was no longer in CMS Energy Common Stock. Participants had an opportunity to reallocate investments in the CMS Energy Common Stock Fund to other plan investment alternatives prior to November 1, 2007. In November 2007, the remaining shares in the CMS Energy Common Stock Fund were sold and the sale proceeds were reallocated to other plan investment options.

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 each of the years ended December 31, 2007 and 2006. The ABO for the EISP was $1 million at December 31, 2007 and less than $1 million at December 31, 2006.

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. Starting in 2007, we used two health care trend rates: one for retirees under 65 and the other for retirees 65 and over. The two health care trend rates recognize that prescription drug costs are increasing at a faster pace than other medical claim costs and that prescription drug costs make up a larger portion of expenses for retirees age 65 and over. Retiree health care costs were based on the assumption that costs would increase 9.0 percent for those under 65 and 10.5 percent for those over 65 in 2007. The 2008 rate of increase for OPEB health costs for those under 65 is expected to be 8.0 percent and for those over 65 is expected to be 9.5 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2011 and for those over 65 by 2013 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
	One Percentage		Percentage
	Point Increase		Point Decrease
	(In Millions)
Effect on total service and interest cost component	$	20	$	(16	)
Effect on postretirement benefit obligation	$	201	$	(169	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Upon adoption of SFAS No. 106, at the beginning of 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 requires 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 requires us to recognize changes in the funded status of our plans in the year in which the changes occur. In addition, the standard requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of this provision of the standard will have a material effect on our consolidated financial statements.

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	2007		2006		2005		2007		2006		2005
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%

Weighted average for net periodic benefit cost:

	Pension & SERP						OPEB
Years Ended December 31	2007		2006		2005		2007		2006		2005
Discount rate(a)		5.65%		5.75%		5.75%		5.65%		5.75%		5.75%
Expected long-term rate of return on plan assets(b)		8.25%		8.50%		8.75%		7.75%		8.00%		8.25%
Mortality table(c)		2000		2000		2000		2000		2000		2000
Rate of compensation increase:
Pension		4.00%		4.00%		3.50%
SERP		5.50%		5.50%		5.50%

(a)	The discount rate represents the market rate for high-quality AA-rated corporate bonds with durations corresponding to the expected durations of the benefit obligations and is used to calculate the present value of the expected future cash flows for benefit obligations under our pension plans.
(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

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	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)	We utilize the Combined Healthy RP-2000 Table from the 2000 Group Annuity Mortality Tables.

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	2007			2006			2005
	(In Millions)
Net periodic pension cost
Service cost	$	47		$	47		$	41
Interest expense		84			81			76
Expected return on plan assets		(75	)		(80	)		(89	)
Amortization of:
Net loss		44			41			33
Prior service cost		7			7			5
Net periodic pension cost		107			96			66
Regulatory adjustment(a)		(22	)		(11	)		—
Net periodic pension cost after regulatory adjustment	$	85		$	85		$	66

	OPEB
Years Ended December 31	2007			2006			2005
	(In Millions)
Net periodic OPEB cost
Service cost	$	24		$	22		$	21
Interest expense		65			60			58
Expected return on plan assets		(57	)		(53	)		(49	)
Amortization of:
Net loss		23			20			20
Prior service credit		(10	)		(10	)		(9	)
Net periodic OPEB cost		45			39			41
Regulatory adjustment(a)		(6	)		(2	)		—
Net periodic OPEB cost after regulatory adjustment	$	39		$	37		$	41

(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. These adjustments are deferred as a regulatory asset and will be included in future rate cases. The pension regulatory asset had a balance of $33 million at December 31, 2007 and $11 million at December 31, 2006. The OPEB regulatory asset had a balance of $8 million at December 31, 2007 and $2 million at December 31, 2006.

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 $43 million. The estimated net loss and

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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 zero.

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 13 years for pension and 14 years for OPEB. Prior service cost amortization is established in the years in which they first occur, and are based on the same amortization period in all future years until fully recognized. The estimated time of amortization of new prior service costs is 13 years for pension and 11 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	2007			2006			2007			2006			2007			2006
	(In Millions)
Benefit obligation at beginning of period	$	1,576		$	1,510		$	47		$	46		$	1,179		$	1,065
Service cost		49			49			1			1			24			22
Interest cost		86			83			3			3			65			60
Actuarial loss (gain)		30			51			12			(1	)		(115	)		79
Palisades sale		(38	)		—			—			—			(20	)		—
Benefits paid		(138	)		(117	)		(2	)		(2	)		(51	)		(47	)
Benefit obligation at end of period(a)		1,565			1,576			61			47			1,082			1,179
Plan assets at fair value at beginning of period		1,040			1,018			—			—			734			655
Actual return on plan assets		89			126			—			—			51			67
Company contribution		109			13			2			2			51			57
Palisades sale		(22	)		—			—			—			(5	)		—
Actual benefits paid(b)		(138	)		(117	)		(2	)		(2	)		(46	)		(45	)
Plan assets at fair value at end of period		1,078			1,040			—			—			785			734
Funded status at end of measurement period		(487	)		(536	)		(61	)		(47	)		(297	)		(445	)
Additional VEBA Contributions or Non-Trust Benefit Payments		—			—			—			—			12			14
Funded status at December 31(c)(d)	$	(487	)	$	(536	)	$	(61	)	$	(47	)	$	(285	)	$	(431	)

(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 $27 million for 2007 and 2006. The reduction includes $7 million for the years ended December 31, 2007 and December 31, 2006 in capitalized OPEB costs.
(b)	We received $4 million in 2007 and $3 million in 2006 for Medicare Part D Subsidy payments.
(c)	Liabilities for retirement benefits are $805 million non-current and $2 million current for year ended December 31, 2007 and $983 million non-current and $2 million current for year ended December 31, 2006.
(d)	Of the $487 million funded status of Pension Plan at December 31, 2007, $461 million is attributable to Consumers; and of the $536 million funded status of the Pension Plan at December 31, 2006, $507 million is attributable to Consumers, based on allocation of expenses.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table provides pension ABO in excess of plan assets:

Years Ended December 31	2007		2006
	(In Millions)
Pension ABO	$	1,231	$	1,240
Fair value of Pension Plan assets		1,078		1,040
Pension ABO in excess of Pension Plan assets	$	153	$	200

SFAS No. 158 Recognized: The following table recaps the amounts recognized in SFAS No. 158 regulatory assets and AOCI 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	2007		2006		2007			2006
	(In Millions)
Regulatory assets
Net loss	$	636	$	676	$	265		$	416
Prior service cost (credit)		39		45		(89	)		(99	)
AOCI
Net loss (gain)		18		7		—			—
Prior service cost (credit)		1		1		—			—
Total amounts recognized in regulatory assets and AOCI	$	694	$	729	$	176		$	317

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

	Pension						OPEB
November 30	2007			2006			2007			2006
Asset Category:
Fixed Income		30	%		28	%		34	%		37	%
Equity Securities		60	%		62	%		66	%		63	%
Alternative Strategy		10	%		10	%		—			—

We contributed $49 million to our OPEB plan in 2007 and we plan to contribute $48 million to our OPEB plan in 2008. Of the $49 million OPEB contribution during 2007, $24 million was contributed to the 401(h) component of the qualified pension plan and the remaining $25 million was contributed to the VEBA trust accounts. We contributed $103 million to our Pension Plan in 2007 and we do not plan to contribute to our Pension Plan in 2008.

We established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments 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 Mid Cap and Small Cap 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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)
2008	$	64	$	2	$	53
2009		71		2		56
2010		78		2		58
2011		88		2		60
2012		101		2		61
2013-2017		664		10		339

(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 2008, $6 million for 2009 and 2010, $7 million for 2011, $8 million for 2012 and $47 million combined for 2013 through 2017.

7: 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, 2007 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 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

	In Service
ARO Description	Date		Long-Lived Assets
December 31, 2007
JHCampbell intake/discharge water line		1980	Plant intake/discharge water line
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	12/31/05		Incurred		Settled(a)			Accretion		Revisions		12/31/06
					(In Millions)
Palisades-decommission	$	375	$	—	$	—		$	26	$	—	$	401
Big Rock-decommission		27		—		(28	)		3		—		2
JHCampbell intake line		—		—		—			—		—		—
Coal ash disposal areas		54		—		(2	)		5		—		57
Wells at gas storage fields		1		—		—			—		—		1
Indoor gas services relocations		1		—		—			—		—		1
Asbestos abatement		36		—		(3	)		2		—		35
Gas distribution cut, purge, cap		—		—		—			—		—		—
Total	$	494	$	—	$	(33	)	$	36	$	—	$	497

	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		—		—
JHCampbell intake line		—		—		—			—		—		—
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

(a) Cash payments of $5 million in 2007 and $33 million in 2006 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 April 2007, we sold Palisades to Entergy and paid Entergy to assume ownership and responsibility for the Big

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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.

8: INCOME TAXES

We join in the filing of a consolidated federal 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 $154 million in 2007 and $31 million in 2006.

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.

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, 2007, we had AMT credit carryforwards of $13 million that do not expire and tax loss carryforwards of $196 million that expire from 2023 through 2025. In addition, we had a capital loss carryforward of $6 million that expires in 2011. We do not believe that valuation allowances are required, as we expect to fully utilize the loss carryforwards prior to their expiration. In addition, we recorded a benefit of $253 million for a future Michigan deduction, offset by a federal tax benefit of $88 million, for a net benefit of $165 million. This future deduction was granted as part of the Michigan Business Tax legislation of 2007, discussed within this Note.

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

Years Ended December 31	2007			2006			2005
	(In Millions)
Current federal income taxes	$	114		$	212		$	176
Current federal income tax benefit of operating loss carryforwards		(44	)		(8	)		(9	)
Deferred federal income taxes		59			(109	)		(201	)
Deferred ITC, net		(4	)		(4	)		(13	)
Income tax expense (benefit)	$	125		$	91		$	(47	)

Current tax expense reflects the settlement of income tax audits for prior years, as well as the provision for current year’s income taxes prior to the use of loss carryforwards. 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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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

December 31	2007			2006
	(In Millions)
Current Assets and (Liabilities):
Tax loss and credit carryforwards	$	—		$	32
Employee benefits		5			6
Other		48			—
Current Assets	$	53		$	38
Gas inventory		(204	)		—
Other		—			(49	)
Current Liabilities	$	(204	)	$	(49	)
Net Current Asset/(Liability)	$	(151	)	$	(11	)
Noncurrent Assets and (Liabilities):
Tax loss and credit carryforwards	$	249		$	177
SFAS No. 109 regulatory liability		207			189
Nuclear decommissioning (including unrecovered costs)		—			57
Employee benefits		39			30
Noncurrent Assets	$	495		$	453
Valuation Allowance		—			(15	)
Net Noncurrent Assets	$	495		$	438
Property	$	(919	)	$	(814	)
Securitized costs		(180	)		(177	)
Gas inventory		—			(168	)
Nuclear decommisioning (including unrecovered costs)		(18	)		—
Other		(91	)		(126	)
Noncurrent Liabilities	$	(1,208	)	$	(1,285	)
Net Noncurrent Asset/(Liability)	$	(713	)	$	(847	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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	2007			2006			2005
	(In Millions)
Net Income (Loss)	$	312		$	186		$	(96	)
Income tax expense (benefit)		125			91			(47	)
Income (loss) before income taxes		437			277			(143	)
Statutory federal income tax rate		x 35	%		x 35	%		x 35	%
Expected income tax expense (benefit)		153			97			(50	)
Increase (decrease) in taxes from:
Property differences		9			13			18
IRS Settlement/Credit Restoration		—			(19	)		—
Medicare Part D exempt income		(9	)		(10	)		(6	)
ITC amortization		(3	)		(4	)		(4	)
Expiration of general business credits		—			—			6
Valuation allowance		(23	)		15			(9	)
Other, net		(2	)		(1	)		(2	)
Recorded income tax expense (benefit)	$	125		$	91		$	(47	)
Effective tax rate		28.6	%		32.9	%		32.9	%

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, 2007 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 2006 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 FASB Interpretation No. 48, Accounting for Uncertainty in Income Taxes. 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.

CE-67

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

	(In Millions)
Balance at January 1, 2007	$	51
Reductions for prior year tax positions		(11	)
Additions for prior year tax positions		1
Additions for current year tax positions		—
Statute lapses		—
Settlements		—
Balance at December 31, 2007	$	41

The balance of $41 million is 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, 2007, there are no uncertain benefits that would reduce our effective tax rate in future years. We are not expecting any other material changes to our uncertain tax positions over the next twelve months.

Due to the consolidated net operating loss position, we have reflected no interest related to our uncertain income tax positions on our Consolidated Balance Sheets as of December 31, 2007, nor have we accrued any penalties. We recognize accrued interest and penalties, where applicable, related to uncertain tax benefits as part of income tax expense.

Michigan Business Tax Act: In July 2007, the Michigan governor signed Senate Bill 94, the Michigan Business Tax Act, which imposed a business income tax of 4.95 percent and a modified gross receipts tax of 0.8 percent. The bill provided for a number of tax credits and incentives geared toward those companies investing and employing in Michigan. The Michigan Business Tax, which was effective January 1, 2008, replaced the state’s Single Business Tax that expired on December 31, 2007. In September 2007, the Michigan governor signed House Bill 5104, allowing additional deductions in future years against the business income portion of the tax. These future deductions are phased in over a 15-year period, beginning in 2015. As a result, our net deferred tax liability of $165 million, recorded due to the Michigan Business Tax enactment, was offset by a net deferred tax asset of $165 million. In December 2007, the Michigan governor signed House Bill 5408, replacing the expanded sales tax for certain services with a 21.99 percent surcharge on the business income tax and the modified gross receipts tax. Therefore, the total tax rates imposed under the Michigan Business Tax are 6.04 percent for the business income tax and 0.98 percent for the modified gross receipts tax.

9: 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 2007, 2006, and 2005 were in the form of total shareholder return (TSR) restricted stock and time-lapse restricted stock. Restricted stock recipients receive shares of CMS Energy’s 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 total shareholder return over a three-year period and half is based on a comparison of our total shareholder return 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 0 percent 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

CE-68

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

three years for awards granted in 2004 and thereafter. Restricted stock awards granted to officers in 2006 and 2005 were entirely TSR restricted stock. Awards granted to officers in 2007 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 or disability and vest fully if control of CMS Energy changes, 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 2007, 2006, or 2005.

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 3,677,930 shares of common stock under the Plan at December 31, 2007. 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
Restricted Stock	Number of Shares			Grant Date Fair Value
Nonvested at December 31, 2006		1,422,000		$	12.26
Granted(a)		606,083		$	14.12
Vested(a)		(641,004	)	$	16.09
Forfeited		(12,000	)	$	13.95
Nonvested at December 31, 2007		1,375,079		$	13.54

(a) During 2007, we granted 369,150 TSR shares and 83,020 time-lapse shares of restricted stock. In addition, we granted 153,913 shares that immediately vested as a result of achieving 150 percent of the market conditions on our 2004 TSR restricted stock grant. The fair value at the date of grant in 2004 was $9.73. We excluded the impact of these shares from the weighted-average grant date fair value for the 2007 shares granted.

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. The fair value of TSR restricted stock awards was calculated on the award grant date using a Monte Carlo simulation. Expected volatilities were based 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:

	2007			2006			2005
Expected Volatility		19.11	%		20.51	%		48.70	%
Expected Dividend Yield		1.20	%		0.00	%		0.00	%
Risk-free rate		4.59	%		4.82	%		4.14	%

The total fair value of shares vested was $10 million in 2007, $2 million in 2006, and $2 million in 2005. Compensation expense related to restricted stock was $7 million in 2007, $7 million in 2006, and $3 million in 2005. The total related income tax benefit recognized in income was $2 million in 2007, $2 million in 2006, and $1 million in 2005. At December 31, 2007, 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 1.4 years.

CE-69

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table summarizes stock option activity under the Plan:

						Weighted-
	Options			Weighted-		Average
	Outstanding,			Average		Remaining		Aggregate
	Fully Vested,			Exercise		Contractual		Intrinsic
Stock Options	and Exercisable			Price		Term		Value
								(In Millions)
Outstanding at December 31, 2006		1,601,784		$	18.16		5.0 years	$	(2	)
Granted		—			—
Exercised		(631,565	)		7.54
Cancelled or Expired		(283,993	)		32.90
Outstanding at December 31, 2007		686,226		$	21.83		3.6 years	$	(3	)

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 $6 million in 2007 and $1 million in 2006 and 2005. Cash received from exercise of these stock options was $5 million in 2007.

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

Years Ended December 31	2007		2006		2005
Weighted average grant date fair value
Restricted stock granted	$	14.12	$	13.82	$	15.60
Stock options granted(a)		—		—		—

(a) No stock options were granted in 2007, 2006, or 2005.

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 this Statement 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.

10: 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 5 and 22 years. Most of our power purchase agreements contain provisions at the end of the initial contract term to renew the agreement annually.

CE-70

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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	2007		2006		2005
	(In Millions)
Capital lease expense	$	34	$	15	$	14
Operating lease expense		23		19		17

Minimum annual rental commitments under our non-cancelable leases at December 31, 2007 are:

	Capital		Finance		Operating
	Leases		Lease(a)		Leases
	(In Millions)
2008	$	21	$	13	$	25
2009		16		13		23
2010		15		13		21
2011		13		13		21
2012		14		13		21
2013 and thereafter		53		122		93
Total minimum lease payments		132		187	$	204
Less imputed interest		64		—
Present value of net minimum lease payments		68		187
Less current portion		17		13
Non-current portion	$	51	$	174

(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 $300 million annually. Our total purchases of capacity and energy under the Palisades power purchase agreement were $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 and 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 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 charges under the financing were $10 million in 2007.

CE-71

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

11: PROPERTY, PLANT, AND EQUIPMENT

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

	Estimated
	Depreciable
December 31	Life in Years		2007		2006
			(In Millions)
Electric:
Generation		13-85	$	3,328	$	3,573
Distribution		12-75		4,496		4,425
Other		7-40		438		421
Capital and finance leases(a)				293		85
Gas:
Underground storage facilities(b)		30-65		267		263
Transmission		15-75		570		465
Distribution		40-75		2,286		2,216
Other		7-50		320		300
Capital leases(a)				24		29
Other:
Non-utility property		7-71		15		15
Construction work-in-progress				447		639
Less accumulated depreciation, depletion, and amortization(c)				3,993		5,018
Net property, plant, and equipment(d)			$	8,491	$	7,413

(a)	Capital and finance leases presented in this table are gross amounts. Accumulated amortization of capital and finance leases was $62 million at December 31, 2007 and $59 million at December 31, 2006. 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. Additions were $7 million and Retirements and adjustments were $6 million during 2006.
(b)	Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2007 and December 31, 2006, which is not subject to depreciation.
(c)	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. At December 31, 2006, accumulated depreciation, depletion, and amortization included $5.017 billion from our utility plant and $1 million related to our non-utility plant assets.
(d)	At December 31, 2007, utility plant additions were $1.303 billion and utility plant retirements, including other plant adjustments, were $1.094 billion. At December 31, 2006, utility plant additions were $470 million and utility plant retirements, including other plant adjustments, were $82 million. Included in net property, plant and equipment are intangible assets.

CE-72

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table summarizes our intangible assets:

December 31			2007				2006
	Amortization				Accumulated				Accumulated
Description	Life in years		Gross Cost		Amortization		Gross Cost		Amortization
	(In Millions)
Software development		7-15	$	207	$	170	$	204	$	153
Rights of way		50-75		116		32		114		31
Leasehold improvements		various		19		16		19		15
Franchises and consents		various		14		5		19		10
Other intangibles		various		18		13		18		13
Total			$	374	$	236	$	374	$	222

Pretax amortization expense related to these intangible assets was $21 million for the year ended December 31, 2007, $22 million for the year ended December 31, 2006 and $19 million for the year ended December 31, 2005. Amortization of intangible assets is forecasted to range between $12 million and $22 million per year over the next five years.

Asset Acquisition: In December 2007, we purchased a 935 MW gas-fired power 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 10, Leases.

12: 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		2007		2006		2007		2006		2007		2006
	(%)						(In Millions)
Campbell Unit 3		93.3	$	664	$	262	$	337	$	370	$	44	$	353
Ludington		51.0		65		68		104		95		1		1
Distribution		Various		89		98		44		47		5		4

(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.

13: 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.

CE-73

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Accounting policies of our segments are as described in the summary of significant 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 (loss) available to common stockholder by segment. The “Other” segment includes our consolidated special purpose entity for the sale of trade receivables, and in 2005 and 2006 the MCV Partnership and the FMLP.

The following tables provide financial information by reportable segment:

Years Ended December 31	2007			2006			2005
	(In Millions)
Operating Revenues
Electric	$	3,443		$	3,302		$	2,701
Gas		2,621			2,374			2,483
Other		—			45			48
	$	6,064		$	5,721		$	5,232
Earnings from Equity Method Investees
Electric	$	—		$	1		$	—
Other		—			—			1
	$	—		$	1		$	1
Depreciation and Amortization
Electric	$	397		$	380		$	292
Gas		127			122			117
Other		—			25			75
	$	524		$	527		$	484
Interest Charges
Electric	$	193		$	167		$	133
Gas		70			73			68
Other		1			49			71
	$	264		$	289		$	272
Income Tax Expense (Benefit)
Electric	$	100		$	95		$	85
Gas		47			18			39
Other		(22	)		(22	)		(171	)
	$	125		$	91		$	(47	)
Net Income (Loss) Available to Common Stockholder
Electric	$	196		$	199		$	153
Gas		87			37			48
Other		27			(52	)		(299	)
	$	310		$	184		$	(98	)
Investments in Equity Method Investees
Electric	$	—		$	5		$	3
Other		—			—			4
	$	—		$	5		$	7

CE-74

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Years Ended December 31	2007		2006		2005
	(In Millions)
Total Assets
Electric(a)	$	8,492	$	8,516	$	7,755
Gas(a)		4,102		3,950		3,609
Other		807		379		1,814
	$	13,401	$	12,845	$	13,178
Capital Expenditures(b)
Electric	$	1,319	$	462	$	384
Gas		168		172		168
Other		—		19		32
	$	1,487	$	653	$	584

(a)	Amounts include a portion of our other common assets attributable to both the electric and gas utility businesses.
(b)	Amounts include purchase of nuclear fuel and capital lease additions. Amounts also include a portion of our capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.

14: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)

	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

	2006
Quarters Ended	March 31		June 30		Sept. 30		Dec. 31(a)
			In Millions
Operating revenue	$	1,782	$	1,138	$	1,191	$	1,610
Operating income (loss)		7		78		239		36
Net income		10		36		99		41
Preferred stock dividends		—		1		—		1
Net income available to common stockholder		10		35		99		40

(a) The quarter ended December 31, 2006 includes a $41 million net loss on the sale of our investment in the MCV Partnership, including the associated asset impairment charge. For additional details, see Note 2, Asset Sales and Impairment Charges.

CE-75

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholder

In our opinion, the accompanying consolidated balance sheet 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, 2007, and the results of their operations and their cash flows for the year ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index at Item 15(a)2 presents 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, 2007, 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 schedule, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audit. 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 and whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

As discussed in note 8 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 20, 2008

CE-76

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 balance sheets and the related statements of operations, of partners’ equity (deficit) and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and December 31, 2005, and the results of its operations and its cash flows for the period ended November 21, 2006 and the year ended December 31, 2005 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-77

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder of Consumers Energy Company

We have audited the accompanying consolidated balance sheets of Consumers Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) as of December 31, 2006, and the related consolidated statements of income (loss), common stockholder’s equity, and cash flows for each of the two years in the period ended December 31, 2006. Our audits also included the financial statement schedule as it relates to 2006 and 2005 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 audits. 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 2), which statements reflect total revenues constituting 9.5% in 2006 and 11.3% in 2005 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 periods indicated above for Midland Cogeneration Venture Limited Partnership is based solely on the report of the other auditors.

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 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 audits and the report of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the report of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Consumers Energy Company at December 31, 2006, and the consolidated results of their operations and their cash flows for each of the two years in the period 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 6 to the consolidated financial statements, in 2006, the Company adopted 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).” As discussed in Note 9 to the consolidated financial statements, in 2006, the Company adopted FASB Statement of Financial Accounting Standards No. 123(R) “Share-Based Payment.”

/s/ Ernst & Young LLP

Detroit, Michigan

February 21, 2007

CE-78

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, 2007.

Management’s 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 generally accepted accounting principles in the United States of America 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 generally accepted accounting principles in the United States of America, 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, 2007. 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, 2007.

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.

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ITEM 9A. 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, 2007.

Management’s 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 generally accepted accounting principles in the United States of America 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 generally accepted accounting principles in the United States of America, 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, 2007. 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, 2007.

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

For other information related to the Officer Incentive Compensation Plan, see ITEM 11. EXECUTIVE COMPENSATION.

Consumers

For other information related to the Officer Incentive Compensation Plan, see ITEM 11. EXECUTIVE COMPENSATION.

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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.

CODES 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 and Consumers have also adopted a Directors Code of Conduct that applies to the directors of the Boards. The codes of ethics, included in our Code of Conduct and Statement of Ethics Handbook, and the Directors Code of Conduct can be found on our website at www.cmsenergy.com. Our Code of Conduct and Statement of Ethics, including the code of ethics, is administered by the Chief Compliance Officer, who reports directly to the Audit Committees of our Boards of Directors. The Directors Code of Conduct is administered by the Audit Committee of the Board. Any alleged violation of the Code of Conduct by a Director will be investigated by disinterested members of the Audit Committee, or if none, by disinterested members of the entire Board. Any amendment to, or waiver from, a provision of our code of ethics that applies to our CEO, CFO, CAO or persons performing similar functions will be disclosed on our 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.

CODES 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. CMS Energy and Consumers have also adopted a Directors Code of Conduct that applies to the directors of the Boards. The codes of ethics, included in our Code of Conduct and Statement of Ethics Handbook, and the Directors Code of Conduct can be found on our website at www.cmsenergy.com. Our Code of Conduct and Statement of Ethics, including the code of ethics, is administered by the Chief Compliance Officer, who reports directly to the Audit Committees of our Boards of Directors. The Directors Code of Conduct is administered by the Audit Committee of the Board. Any alleged violation of the Code of Conduct by a Director will be investigated by disinterested members of the Audit Committee, or if none, by disinterested members of the entire Board. Any amendment to, or waiver from, a provision of our code of ethics that applies to our CEO, CFO, CAO or persons performing similar functions will be disclosed on our website at www.cmsenergy.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.

OFFICER INCENTIVE COMPENSATION PLAN

On February 19, 2008, the Compensation and Human Resources Committees of the Boards of Directors of CMS Energy and Consumers (the “C&HR Committees”) approved the payout of cash bonuses for 2007 under the Annual Officer Incentive Compensation Plan (the “Plan”).

The C&HR Committees approved achievement of the composite plan performance factor resulting in payout under the Plan at 148 percent. In doing so the C&HR Committees decided to exclude the $519 million Zeeland plant

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purchase, which was not included in the 2007 budget but was completed in December 2007, from what constitutes corporate free cash flow. Completing the purchase in 2007 provided significant benefits including certain tax benefits to Consumers that would otherwise not have been available had the transaction been completed in 2008.

On January 24, 2008, the C&HR Committees approved the material terms of the Plan, including the 2008 corporate performance goals thereunder. The Plan includes the material terms detailed below, although the specific target levels for the corporate performance goals vary from year to year.

Corporate Performance: The composite plan performance factor depends on corporate performance in two areas as described in the Plan: (1) the adjusted net income per outstanding CMS Energy common share (“Plan EPS”); and (2) the corporate free cash flow of CMS Energy (“CFCF”). Plan EPS performance constitutes one-half of the composite plan performance factor and CFCF performance constitutes one-half of the composite plan performance factor. There will be a payout under the Plan if either Plan EPS performance is not less than 10 cents below target EPS or CFCF is not less than $100 million below target CFCF. Even if only one but not both of these target minimums is achieved, a partial payout would result. The composite plan performance factor to be used for payouts is capped at a maximum of 200 percent. Annual awards under the Plan to Consumers’ officers may be reduced by 25 percent in the event that there is no payout to non-officer, non-union employees under a separate Consumers’ employee incentive plan.

Annual Award Formula: Annual awards for each eligible officer will be based upon a standard award percentage of the officer’s base salary as in effect on January 1 of the performance year. The maximum amount that can be awarded under the Plan for any Internal Revenue Code Section 162(m) employee will not exceed $2.5 million in any one performance year. Annual awards for officers will be calculated and made as follows: Individual Award = Base Salary times Standard Award% times Performance Factor%.

The standard award percentages for officers are based on individual salary grade levels and remain unchanged from the 2007 plan except for two eligible officers. The standard award percentage target for the Chief Executive Officer was increased to 100 percent from 65 percent and the Chief Operating Officer’s standard award percentage target was increased to 60 percent from 55 percent as described in the Form 8-K filed December 4, 2007.

Payment of Annual Awards: All annual awards for a performance year will be paid in cash no later than March 15th of the calendar year following the performance year provided that they first have been reviewed and approved by the C&HR Committees, and provided further that the annual award for a particular performance year has not been deferred voluntarily. The amounts required by law to be withheld for income and employment taxes will be deducted from the annual award payments. All annual awards become the obligation of the company on whose payroll the employee is enrolled at the time the C&HR Committees make the annual award.

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.

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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.

		Page
Schedule II	Valuation and Qualifying Accounts and Reserves
	CMS Energy Corporation	CO-11
	Consumers Energy Company	CO-11
Report of Independent Registered Public Accounting Firm
	CMS Energy Corporation	CMS-101
	Consumers Energy Company	CE-75

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

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(3)(a)	1-9513	(99)(a)	—	Restated Articles of Incorporation of CMS Energy dated June 1, 2004 (Form 8-K filed June 3, 2004)
(3)(b)	1-9513	(3)(b)	—	CMS Energy Corporation Bylaws, amended and restated as of August 10, 2007 (3rd qtr. 2007 Form 10-Q)
(3)(c)	1-5611	3(c)	—	Restated Articles of Incorporation dated May 26, 2000, of Consumers (2000 Form 10-K)
(3)(d)	1-5611	(3)(d)	—	Consumers Energy Company Bylaws, amended and restated as of August 10, 2007 (3rd qtr. 2007 Form 10-Q)
(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 (Designated in Consumers Power Company’s Registration No. 2-65973 as Exhibit (b)(1)(4))
			—	Indentures Supplemental thereto:
	1-5611	(4)(a)	—	70th dated as of 2/01/98 (1997 Form 10-K)
	1-5611	(4)(a)	—	71st dated as of 3/06/98 (1997 Form 10-K)
	1-5611	(4)(b)	—	75th dated as of 10/1/99 (1999 Form 10-K)
	1-5611	(4)(d)	—	77th dated as of 10/1/99 (1999 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)(a)	—	101st dated as of 4/1/05 (1st qtr 2005 Form 10-Q)
	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)
			—	106th dated as of November 30, 2007
(4)(b)			—	105th Supplemental Indenture (dated as of March 30, 2007) to the Indenture dated as of September 1, 1945 between Consumers and Chemical Bank (successor to Manufacturers Hanover Trust Company), as Trustee
(4)(c)	1-5611	(4)(b)	—	Indenture dated as of January 1, 1996 between Consumers and The Bank of New York, as Trustee (1995 Form 10-K)
(4)(d)	1-5611	(4)(c)	—	Indenture dated as of February 1, 1998 between Consumers and JPMorgan Chase Bank, N.A. (formerly The Chase Manhattan Bank), as Trustee (1997 Form 10-K)
(4)(e)	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)

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	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
	1-9513	4.2	—	20th dated as of July 3, 2007 (Form 8-K filed July 5, 2007)
	1-9513	4.3	—	21st dated as of July 3, 2007 (Form 8-K filed July 5, 2007)
(4)(f)	1-9513	(4a)	—	Indenture dated as of June 1, 1997, between CMS Energy and The Bank of New York, 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)(g)	1-9513	(4)(i)	—	Certificate of Designation of 4.50% Cumulative Convertible Preferred Stock of CMS Energy dated as of December 2, 2003 (2003 Form 10-K)
(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:
				Amendment No. 1 dated December 19, 2007
	1-9513	10.1	—	Assumptions thereto:
				Assumption and Acceptance dated January 8, 2008 (Form 8-K filed January 11, 2008)
(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
(10)(c)			—	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
(10)(d)	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)(e)			—	2004 Form of Executive Severance Agreement
(10)(f)			—	2004 Form of Officer Severance Agreement
(10)(g)			—	2004 Form of Change-in-Control Agreement
(10)(h)			—	CMS Energy’s Performance Incentive Stock Plan effective June 1, 2004 and as further amended effective November 30, 2007
(10)(i)			—	CMS Deferred Salary Savings Plan effective December 1, 1989 and as further amended effective December 1, 2007
(10)(j)			—	Annual Officer Incentive Compensation Plan for CMS Energy Corporation and its Subsidiaries effective January 1, 2004, amended and restated effective as of January 1, 2007 and further amended November 30, 2007
(10)(k)			—	Supplemental Executive Retirement Plan for Employees of CMS Energy/Consumers Energy Company effective January 1, 1982, as further amended December 1, 2007
(10)(l)			—	Defined Contribution Supplemental Executive Retirement Plan effective April 1, 2006 and as further amended effective December 1, 2007
(10)(m)	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)

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	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(10)(n)	1-9513	(19)(d)*	—	Environmental Agreement dated as of June 1, 1990 made by CMS Energy to The Connecticut National Bank and Others (1990 Form 10-K)
(10)(o)	1-9513	(10)(z)*	—	Indemnity Agreement dated as of June 1, 1990 made by CMS Energy to Midland Cogeneration Venture Limited Partnership (1990 Form 10-K)
(10)(p)	1-9513	(10)(aa)*	—	Environmental Agreement dated as of June 1, 1990 made by CMS Energy to United States Trust Company of New York, Meridian Trust Company, each Subordinated Collateral Trust Trustee and Holders from time to time of Senior Bonds and Subordinated Bonds and Participants from time to time in Senior Bonds and Subordinated Bonds (1990 Form 10-K)
(10)(q)	33-37977	10.4	—	Power Purchase Agreement dated as of July 17, 1986 between MCV Partnership and Consumers (MCV Partnership) (Designated in Midland Cogeneration Venture Limited Partnership’s Form S-1 filed November 23, 1999, File No. 33-37977 as Exhibit 10.4)
				Amendments thereto:
	33-37977	10.5	—	Amendment No. 1 dated September 10, 1987 (MCV Partnership)
	33-37977	10.6	—	Amendment No. 2 dated March 18, 1988 (MCV Partnership)
	33-37977	10.7	—	Amendment No. 3 dated August 28, 1989 (MCV Partnership)
	33-37977	10.8	—	Amendment No. 4A dated May 25, 1989 (MCV Partnership)
(10)(r)	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)(s)	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)(t)	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)(u)	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)(v)	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)(w)	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)(x)	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)(y)	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)
(10)(z)	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)

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	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(10)(aa)	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)(bb)	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)(cc)	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)(dd)	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)(ee)	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)(ff)	1-9513	10.1	—	Agreement of Purchase and Sale by and between CMS Energy Corporation and Petroleos de Venezuela, S.A. dated March 30, 2007 (Form 8-K filed April 5, 2007)
(10)(gg)	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)(hh)	1-5611	99.2	—	Purchase and Sale Agreement by and between Broadway Gen Funding, LLC as Seller and Consumers Energy Company as Buyer (Form 8-K filed May 29, 2007)
(10)(ii)	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)(jj)	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)(kk)	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)(ll)	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)
(10)(mm)	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)

CO-9

	Previously Filed
	With File	As Exhibit
Exhibits	Number	Number		Description
(10)(nn)	1-9513	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)
(12)(a)			—	Statement regarding computation of CMS Energy’s Ratio of Earnings to Fixed Charges and Preferred Dividends
(12)(b)			—	Statement regarding computation of Consumers’ Ratio of Earnings to Fixed Charges and Preferred Dividends and Distributions
(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
(23)(a)			—	Consent of PricewaterhouseCoopers LLP for CMS Energy
(23)(b)			—	Consent of Ernst & Young 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 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 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-10

CMS ENERGY CORPORATION

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

					Charged/
	Balance at				Accrued				Balance
	Beginning		Charged		to other				at End
Description	of Period		to Expense		Accounts		Deductions		of Period
	(In Millions)
Accumulated provision for uncollectible accounts:
2007	$	25	$	37	$	7	$	34	$	21
2006	$	25	$	30	$	—	$	30	$	25
2005	$	32	$	23	$	—	$	30	$	25
Deferred tax valuation allowance:
2007	$	72	$	—	$	81	$	121	$	32
2006	$	10	$	31	$	42	$	11	$	72
2005	$	42	$	1	$	—	$	33	$	10
Allowance for notes receivable, including related parties:
2007	$	101	$	—	$	1	$	69	$	33
2006	$	49	$	55	$	1	$	4	$	101
2005	$	40	$	9	$	—	$	—	$	49

CONSUMERS ENERGY COMPANY

SCHEDULE II — VALUATION AND QUALIFYING ACCOUNTS AND RESERVES

YEARS ENDED DECEMBER 31, 2007, 2006 AND 2005

					Charged/
	Balance at				Accrued				Balance
	Beginning		Charged		to other				at End
Description	of Period		to Expense		Accounts		Deductions		of Period
	(In Millions)
Accumulated provision for uncollectible accounts:
2007	$	14	$	33	$	—	$	31	$	16
2006	$	13	$	30	$	—	$	29	$	14
2005	$	10	$	24	$	—	$	21	$	13
Deferred tax valuation allowance:
2007	$	15	$	—	$	8	$	23	$	—
2006	$	—	$	16	$	—	$	1	$	15
2005	$	9	$	1	$	—	$	10	$	—

CO-11

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 21st day of February 2008.

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 21st day of February 2008.

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 including those named above:
	* 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

CO-12

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

CO-13

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 21st day of February 2008.

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 21st day of February 2008.

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 including those named above:
	* 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

CO-14

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

CO-15

CMS ENERGY’S AND CONSUMERS’ EXHIBIT INDEX

Exhibits			Description
	(4)(a)	—	106th Supplemental Indenture dated as of November 30, 2007, supplement to Indenture dated as of September 1, 1945, between Consumers and Chemical Bank
	(4)(b)	—	105th Supplemental Indenture (dated as of March 30, 2007) to the Indenture dated as of September 1, 1945 between Consumers and Chemical Bank
	(10)(a)	—	Amendment No. 1 dated December 19, 2007 to $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
	(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
	(10)(c)		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
	(10)(e)	—	2004 Form of Executive Severance Agreement
	(10)(f)	—	2004 Form of Officer Severance Agreement
	(10)(g)	—	2004 Form of Change-in-Control Agreement
	(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
	(10)(i)	—	CMS Deferred Salary Savings Plan effective December 1, 1989 and as further amended effective December 1, 2007
	(10)(j)	—	Annual Officer Incentive Compensation Plan for CMS Energy Corporation and its Subsidiaries effective January 1, 2004, amended and restated effective as of January 1, 2007 and further amended November 30, 2007
	(10)(k)	—	Supplemental Executive Retirement Plan for Employees of CMS Energy/Consumers Energy Company effective January 1, 1982, as further amended December 1, 2007
	(10)(l)	—	Defined Contribution Supplemental Executive Retirement Plan effective April 1, 2006 and as further amended effective December 1, 2007
	(12)(a)	—	Statement regarding computation of CMS Energy’s Ratio of Earnings to Fixed Charges and Preferred Dividends
	(12)(b)	—	Statement regarding computation of Consumers’ Ratio of Earnings to Fixed Charges and Preferred Dividends and Distributions
	(21)	—	Subsidiaries of CMS Energy and Consumers
	(23)(a)	—	Consent of PricewaterhouseCoopers LLP for CMS Energy
	(23)(b)	—	Consent of Ernst & Young 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 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