CMS ENERGY CORP - 10-K Annual Report

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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, 2004
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

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 [ ]

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. [ ]

Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Exchange Act Rule 12 b-2).
CMS ENERGY CORPORATION: Yes X No [ ]
CONSUMERS ENERGY COMPANY: Yes [ ] No X

The aggregate market value of CMS Energy voting and non-voting common equity
held by non-affiliates was $1.472 billion for the 161,261,572 CMS Energy Common
Stock shares outstanding on June 30, 2004 based on the closing sale price of
$9.13 for CMS Energy Common Stock, as reported by the New York Stock Exchange on
such date.

There were 195,466,087 shares of CMS Energy Common Stock outstanding on March 7,
2005. On March 7, 2005, 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 2005 annual meeting of
shareholders to be held May 20, 2005, is incorporated by reference in Parts II
and 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, 2004

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.

TABLE OF CONTENTS

2

GLOSSARY

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

ABATE..................................... Association of Businesses Advocating Tariff Equity
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.
AEP....................................... American Electric Power, a non-affiliated company
AFUDC..................................... Allowance for Funds Used During Construction
ALJ....................................... Administrative Law Judge
Alliance RTO.............................. Alliance Regional Transmission Organization
Alstom.................................... Alstom Power Company
AMT....................................... Alternative minimum tax
APB....................................... Accounting Principles Board
APB Opinion No. 18........................ APB Opinion No. 18, "The Equity Method of Accounting for
Investments in Common Stock"
APB Opinion No. 30........................ APB Opinion No. 30, "Reporting Results of Operations --
Reporting the Effects of Disposal of a Segment of a
Business"
APT....................................... Australian Pipeline Trust
ARO....................................... Asset retirement obligation
Articles.................................. Articles of Incorporation
Attorney General.......................... Michigan Attorney General
bcf....................................... Billion cubic feet
Big Rock.................................. Big Rock Point nuclear power plant, owned by Consumers
Bluewater Pipeline........................ Bluewater Pipeline, a 24.9-mile pipeline that extends
from Marysville, Michigan to Armada, Michigan
Board of Directors........................ Board of Directors of CMS Energy
Brownfield site........................... Provides for a tax incentive for the redevelopment or
improvement of a facility (contaminated property), or
functionally obsolete or blighted property, provided
that certain conditions are met.
Btu....................................... British thermal unit
CEO....................................... Chief Executive Officer
CFO....................................... Chief Financial Officer
CFTC...................................... Commodity Futures Trading Commission
Clean Air Act............................. Federal Clean Air Act, as amended
CMS Electric and Gas...................... CMS Electric and Gas Company, a subsidiary of
Enterprises
CMS Energy................................ CMS Energy Corporation, the parent of Consumers and
Enterprises
CMS Energy Common Stock or common stock... Common stock of CMS Energy, par value $.01 per share
CMS ERM................................... CMS Energy Resource Management Company, formerly CMS
MST, a subsidiary of Enterprises
CMS Field Services........................ CMS Field Services, formerly a wholly owned subsidiary
of CMS Gas Transmission. The sale of this subsidiary
closed in July 2003.
CMS Gas Transmission...................... CMS Gas Transmission Company, a wholly owned subsidiary
of Enterprises
CMS Generation............................ CMS Generation Co., a wholly owned subsidiary of
Enterprises
CMS Holdings.............................. CMS Midland Holdings Company, a subsidiary of Consumers
CMS Land.................................. CMS Land Company, a subsidiary of Enterprises
CMS Midland............................... CMS Midland Inc., a subsidiary of Consumers

3

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
CMS Pipeline Assets....................... CMS Enterprises pipeline assets in Michigan and
Australia
CMS Viron................................. CMS Viron Corporation, formerly a wholly owned
subsidiary of CMS MST. The sale of this subsidiary
closed in June 2003.
Common Stock.............................. All classes of Common Stock of CMS Energy and each of
its subsidiaries, or any of them individually, at the
time of an award or grant under the Performance
Incentive Stock Plan
Consumers................................. Consumers Energy Company, a subsidiary of CMS Energy
Court of Appeals.......................... Michigan Court of Appeals
CPEE...................................... Companhia Paulista de Energia Eletrica, a subsidiary of
Enterprises
Customer Choice Act....................... Customer Choice and Electricity Reliability Act, a
Michigan statute enacted in June 2000 that allows all
retail customers choice of alternative electric
suppliers as of January 1, 2002, provides for full
recovery of net stranded costs and implementation costs,
establishes a five percent reduction in residential
rates, establishes rate freeze and rate cap, and allows
for Securitization
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
DSM....................................... Demand-side management
EBITDA.................................... Earnings before income taxes, depreciation, and
amortization
EISP...................................... Executive Incentive Separation Plan
EITF...................................... Emerging Issues Task Force
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 No. 97-04...................... Deregulation of the Pricing of Electricity -- Issues
Related to the Application of FASB Statements No. 71 and
101
El Chocon................................. The 1,200 MW hydro power plant located in Argentina, in
which CMS Generation holds a 17.23 percent ownership
interest
Enterprises............................... CMS Enterprises Company, a subsidiary of CMS Energy
EPA....................................... U.S. Environmental Protection Agency
EPS....................................... Earnings per share
ERISA..................................... Employee Retirement Income Security Act
Ernst & Young............................. Ernst & Young LLP
Exchange Act.............................. Securities Exchange Act of 1934, as amended
FASB...................................... Financial Accounting Standards Board
FASB Staff Position, No. 106-2............ Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and
Modernization Act of 2003 (May 19, 2004)
FERC...................................... Federal Energy Regulatory Commission
First Mortgage Bond Indenture............. The indenture dated as of September 1, 1945 between
Consumers and JPMorgan Chase Bank, N.A. (ultimate
successor to City Bank Farmers Trust Company), as
Trustee, and as amended and supplemented
FMB....................................... First Mortgage Bonds

4

FMLP...................................... First Midland Limited Partnership, a partnership that
holds a lessor interest in the MCV facility
Ford...................................... Ford Motor Company
FSP....................................... FASB Staff Position
GAAP...................................... Generally Accepted Accounting Principles
GasAtacama................................ An integrated natural gas pipeline and electric
generation project located in Argentina and Chile, which
includes 702 miles of natural gas pipeline and a 720 MW
gross capacity power plant
GCR....................................... Gas cost recovery
Goldfields................................ A pipeline business located in Australia, in which CMS
Energy formerly held a 39.7 percent ownership interest
Guardian.................................. Guardian Pipeline, L.L.C., in which CMS Gas Transmission
owned a one-third interest
GVK....................................... GVK Facility, a 250 MW gas fired power plant located in
South Central India, in which CMS Generation holds a 33
percent interest
Health Care Plan.......................... The medical, dental, and prescription drug programs
offered to eligible employees of Consumers and CMS
Energy
IPP....................................... Independent Power Production
ITC....................................... Investment tax credit
Jorf Lasfar............................... The 1,356 MW coal-fueled power plant in Morocco, jointly
owned by CMS Generation and ABB Energy Ventures, Inc.
Karn...................................... D.E Karn/J.C. Weadock Generating Complex, which is owned
by Consumers
kWh....................................... Kilowatt-hour
LIBOR..................................... London Inter-Bank Offered Rate
Loy Yang.................................. The 2,000 MW brown coal fueled Loy Yang A power plant
and an associated coal mine in Victoria, Australia, in
which CMS Generation formerly held a 50 percent
ownership interest
LNG....................................... Liquefied natural gas
Ludington................................. Ludington pumped storage plant, jointly owned by
Consumers and Detroit Edison
Marysville................................ CMS Marysville Gas Liquids Company, a Michigan
corporation and a former subsidiary of CMS Gas
Transmission that held a 100 percent interest in
Marysville Fractionation Partnership and a 51 percent
interest in St. Clair Underground Storage Partnership
mcf....................................... Thousand cubic feet
MCV Expansion, LLC........................ An agreement entered into with General Electric Company
to expand the MCV Facility
MCV Facility.............................. A natural gas-fueled, combined-cycle cogeneration
facility operated by the MCV Partnership and in which
Consumers' holds a 35 percent lessor interest
MCV Partnership........................... Midland Cogeneration Venture Limited Partnership in
which Consumers has a 49 percent interest through CMS
Midland
MD&A...................................... Management's Discussion and Analysis
MDEQ...................................... Michigan Department of Environmental Quality
METC, LLC................................. Michigan Electric Transmission Company, formerly a
subsidiary of Consumers Energy and now an indirect
subsidiary of Trans-Elect
Michigan Power............................ CMS Generation Michigan Power L.L.C., owner of the
Kalamazoo River Generating Station and the Livingston
Generating Station

5

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, scheduled
to begin April l, 2005
MISO...................................... Midwest Independent System Operator
MPSC...................................... Michigan Public Service Commission
MSBT...................................... Michigan Single Business Tax
MTH....................................... Michigan Transco Holdings, Limited Partnership
MW........................................ Megawatts
NEIL...................................... Nuclear Electric Insurance Limited, an industry mutual
insurance company owned by member utility companies
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 four
utilities
NERC...................................... North American Electric Reliability Council
NRC....................................... Nuclear Regulatory Commission
NYMEX..................................... New York Mercantile Exchange
OPEB...................................... Postretirement benefit plans other than pensions for
retired employees
Palisades................................. Palisades nuclear power plant, which is owned by
Consumers
Panhandle Eastern Pipe Line or
Panhandle............................... Panhandle Eastern Pipe Line Company, including its
subsidiaries Trunkline, Pan Gas Storage, Panhandle
Storage, and Panhandle Holdings. Panhandle was a wholly
owned subsidiary of CMS Gas Transmission. The sale of
this subsidiary closed in June 2003.
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
Pension Plan.............................. The trusteed, non-contributory, defined benefit pension
plan of Panhandle, Consumers and CMS Energy
PJM RTO................................... Pennsylvania-Jersey-Maryland Regional Transmission
Organization
Powder River.............................. CMS Oil and Gas previously owned a significant interest
in coalbed methane fields or projects developed within
the Powder River Basin which spans the border between
Wyoming and Montana. The Powder River properties have
been sold.
PPA....................................... The Power Purchase Agreement between Consumers and the
MCV Partnership with a 35-year term commencing in March
1990
Price Anderson Act........................ Price Anderson Act, enacted in 1957 as an amendment to
the Atomic Energy Act of 1954, as revised and extended
over the years. This act stipulates between nuclear
licensees and the U.S. government the insurance,
financial responsibility, and legal liability for
nuclear accidents.
PSCR...................................... Power supply cost recovery
PUHCA..................................... Public Utility Holding Company Act of 1935
PURPA..................................... Public Utility Regulatory Policies Act of 1978
RCP....................................... Resource Conservation Plan
ROA....................................... Retail Open Access
RTO....................................... Regional Transmission Organization
SCP....................................... Southern Cross Pipeline in Australia, in which CMS Gas
Transmission formerly held a 45 percent ownership
interest
SEC....................................... U.S. Securities and Exchange Commission

6

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
subsidiary of Enterprises
SERP...................................... Supplemental Executive Retirement Plan
SFAS...................................... Statement of Financial Accounting Standards
SFAS No. 5................................ SFAS No. 5, "Accounting for Contingencies"
SFAS No. 52............................... SFAS No. 52, "Foreign Currency Translation"
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. 88............................... SFAS No. 88, "Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for
Termination Benefits"
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. 115.............................. SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities"
SFAS No. 123.............................. SFAS No. 123, "Accounting for Stock-Based Compensation"
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. 148.............................. SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure"
SFAS No. 149.............................. SFAS No. 149, "Amendment of Statement No. 133 on
Derivative Instruments and Hedging Activities"
SFAS No. 150.............................. SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and
Equity"
Shuweihat................................. A power and desalination plant of Emirates CMS Power
Company, in which CMS Generation holds a 20 percent
interest
SLAP...................................... Scudder Latin American Power Fund
Southern Union............................ Southern Union Company, a non-affiliated company
Special Committee......................... A special committee of independent directors,
established by CMS Energy's Board of Directors, to
investigate matters surrounding round-trip trading
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

7

Taweelah.................................. Al Taweelah A2, a power and desalination plant of
Emirates CMS Power Company, in which CMS Generation
holds a forty percent interest
Toledo Power.............................. Toledo Power Company, the 135 MW coal and fuel oil power
plant located on Cebu Island, Philippines, in which CMS
Generation held a 47.5 percent interest.
Trunkline................................. CMS Trunkline Gas Company, LLC, formerly a subsidiary of
CMS Panhandle Holdings, LLC
Trunkline LNG............................. CMS Trunkline LNG Company, LLC, formerly a subsidiary of
LNG 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
Union..................................... Utility Workers of America, AFL-CIO
VEBA Trusts............................... VEBA employees' beneficiary association trusts accounts
established to specifically set aside employer
contributed assets to pay for future expenses of the
OPEB plan
X-TRAS.................................... Extendible tenor rate adjusted securities

8

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 and in selected markets
around the world. Its two principal subsidiaries are Consumers and Enterprises.
Consumers is a public utility that provides natural gas and/or electricity to
almost 6.5 million of Michigan's 10 million residents and serves customers in
all 68 of the state's Lower Peninsula counties. Enterprises, through various
subsidiaries and affiliates, is engaged in diversified energy businesses in the
United States and in selected international markets.

CMS Energy's consolidated operating revenue was approximately $5.472
billion in 2004, $5.513 billion in 2003, and $8.673 billion in 2002. CMS Energy
operates in three business segments -- electric utility, gas utility, and
Enterprises. See BUSINESS SEGMENTS later 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' service areas include companies operating in the
automotive, metal, chemical and food products industries as well as a
diversified group of other industries. In 2004, Consumers served 1.77 million
electric customers and 1.69 million gas customers.

Consumers' consolidated operations account for a majority of CMS Energy's
total assets and income, as well as a substantial portion of its operating
revenue. Consumers' consolidated operating revenue was $4.711 billion in 2004,
$4.435 billion in 2003, and $4.169 billion in 2002.

Consumers' rates and certain other aspects of its business are subject to
the jurisdiction of the MPSC and FERC, as described in CMS ENERGY AND CONSUMERS
REGULATION later 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
Operations -- Electric Utility Properties, and -- Consumers' Gas Utility
Operations -- Gas Utility Properties, below.

BUSINESS SEGMENTS

CMS ENERGY FINANCIAL INFORMATION

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

CONSUMERS FINANCIAL INFORMATION

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

9

CONSUMERS ELECTRIC UTILITY OPERATIONS

ELECTRIC UTILITY OPERATIONS

Consumers' electric utility operating revenue was $2.586 billion in 2004,
$2.590 billion in 2003, and $2.648 billion in 2002. Consumers' electric utility
operations include the generation, purchase, distribution and sale of
electricity. At year-end 2004, it was authorized to provide service in 60 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 includes a mix of
residential, commercial and diversified industrial customers, the largest
segment of which is the automotive industry. Consumers' electric utility
operations are not dependent upon a single customer, or even a few customers,
and the loss of any one or even a few of 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
usually increase demand for electric energy, principally due to the use of air
conditioners and other cooling equipment, thereby affecting revenues. In 2004,
Consumers' electric sales were 36 billion kWh and retail open access deliveries
were 4 billion kWh, for total electric deliveries of 40 billion kWh. In 2003,
Consumers' electric sales were 36 billion kWh and retail open access deliveries
were 3 billion kWh, for total electric deliveries of 39 billion kWh.

Consumers' 2004 summer peak demand was 6,958 MW excluding retail open
access loads and 7,643 MW including retail open access loads. For the 2003-04
winter period, Consumers' peak demand was 5,636 MW excluding retail open access
loads and 6,076 MW including retail open access loads. In December 2004,
Consumers experienced peak demand of 5,750 MW excluding retail open access loads
and 6,385 MW including retail open access loads. Based on its summer 2004
forecast, Consumers carried an 11 percent reserve margin target. However, as a
result of lower than forecasted peak loads and additional purchases in response
to the uncertainty surrounding the Karn 4 exciter failure and eventual
replacement, Consumers' ultimate reserve margin was 29.6 percent compared to
14.7 percent in 2003. Currently, Consumers has a reserve margin of approximately
5.4 percent, or supply resources equal to 105.4 percent of projected summer peak
load for summer 2005 and is in the process of securing the additional capacity
needed to meet its summer 2005 reserve margin target of 11 percent (111 percent
of projected summer peak load). The ultimate use of the reserve margin will
depend primarily on summer weather conditions, the level of retail open access
requirements being served by others during the summer, and any unscheduled plant
outages.

ELECTRIC UTILITY PROPERTIES

GENERATION: At December 31, 2004, Consumers' electric generating system
consisted of the following:

- -------------------------
(a) Represents Consumers' share of the capacity of the J H Campbell 3 unit, net
of 6.69 percent (ownership interests 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) Represents Consumers' share of the capacity of Ludington. Consumers and
Detroit Edison have 51 percent and 49 percent undivided ownership,
respectively, in the plant.

(d) Represents Consumers' share of net pumped storage generation. This facility
electrically pumps water during off-peak hours for storage to later
generate electricity during peak-demand hours.

(e) Includes 1,240 MW of purchased contract capacity from the MCV Facility.

In 2004, through long-term purchase contracts, options, spot market and
other seasonal purchases, Consumers purchased up to 2,542 MW of net capacity
from other power producers (the largest of which was the MCV Partnership), which
amounted to 36.6 percent of Consumers' total system requirements.

DISTRIBUTION: Consumers' distribution system includes:

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

- 4,178 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;

- 55,157 miles of electric distribution overhead lines;

- 8,896 subsurface miles of underground distribution lines; and

- substations having an aggregate transformer capacity of 20,787,500
kilovoltamperes.

Consumers is interconnected to METC, LLC, a member of MISO. METC, LLC is
interconnected with neighboring utilities as well as out-state transmission
systems.

FUEL SUPPLY: Consumers has four generating plant sites that burn coal.
These plants constitute 77.5 percent of Consumers' baseload supply, the capacity
used to serve a constant level of customer demand. In 2004, these

11

plants produced a combined total of 18,810 million kWhs of electricity and
burned 9.7 million tons of coal. On December 31, 2004, Consumers had on hand a
31-day supply of coal.

Consumers enters into a number of purchase obligations that represent
normal business operating contracts. These contracts are used to assure an
adequate supply of goods and services necessary for the operation of its
business and to minimize exposure to market price fluctuations. Consumers
believes that these future costs are prudent and reasonably assured of recovery
in future rates.

Consumers has entered into coal supply contracts with various suppliers and
associated rail transportation contracts for its coal-fired generating stations.
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
$205 million. Long-term coal supply contracts have accounted for approximately
60 to 90 percent of Consumers' annual coal requirements over the last 10 years.
Although future contract coverage is not finalized at this time, Consumers
believes that it will be within the historic 60 to 90 percent range.

As of December 31, 2004, Consumers had future unrecognized commitments to
purchase power transmission services under fixed price forward contracts for
2005 totaling $4 million. Consumers also had 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 2005 through 2030 total an
estimated $4.503 billion, undiscounted. This amount may vary depending upon
plant availability and fuel costs. If a plant were not available to deliver
electricity to Consumers, then Consumers would not be obligated to make the
capacity payment until the plant could deliver.

Consumers owns Palisades, an operating nuclear power plant located near
South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers
transferred its authority to operate Palisades to NMC. During 2004, Palisades'
net generation was 5,336 million kWhs, constituting 22 percent of Consumers'
baseload supply. Palisades' nuclear fuel supply responsibilities are under NMC's
control as agent for Consumers. New fuel contracts are being written as NMC
agreements. Consumers/NMC currently have sufficient contracts in place to supply
93 percent of the uranium concentrates and conversion services and 100 percent
of the enrichment services requirements for the 2006 reload. A contract for
conversion services is in place to supply approximately 26 percent of the 2007
reload requirements and a contract for enrichment services is in place to supply
approximately 100 percent of the 2007 reload requirements. A mix of spot, medium
and long-term contracts are being negotiated with producers and service
suppliers who participate in the world nuclear fuel marketplace to provide for
the remaining open requirements for the 2007 reload.

Consumers has a contract for nuclear fuel fabrication services in place for
the 2006 reload. Contract negotiations are currently ongoing with the current
nuclear fuel fabrication vendor to enter into a new contract to cover reloads in
2006 through 2013.

12

As shown below, Consumers generates electricity principally from coal and
nuclear fuel.

- -------------------------
(a) On June 20, 2001, the Palisades reactor was shut down so technicians could
inspect a small steam leak on a control rod drive assembly. The defective
components were replaced and the plant returned to service on January 21,
2002.

The cost of all fuels consumed, shown below, fluctuates with the mix of
fuel burned.

- -------------------------
(a) Weighted average fuel costs.

The Nuclear Waste Policy Act of 1982 made the federal government
responsible for the permanent disposal of spent nuclear fuel and high-level
radioactive waste by 1998. The DOE has not arranged for storage facilities and
it does not expect to receive spent nuclear fuel for storage in 2005. Palisades
currently has spent nuclear fuel that exceeds its temporary on-site storage pool
capacity. Therefore, Consumers is storing spent nuclear fuel in NRC-approved
steel and concrete vaults known as "dry casks." For additional information on
disposal of nuclear fuel and Consumers' use of dry casks, see ITEM 7. CMS
ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC
UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC
UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 7. CONSUMERS' MANAGEMENT'S
DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS
UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 2 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS.

CONSUMERS GAS UTILITY

GAS UTILITY OPERATIONS

Consumers' gas utility operating revenue was $2.081 billion in 2004, $1.845
billion in 2003, and $1.519 billion in 2002. Consumers' gas utility operations
purchase, transport, store, distribute and sell natural gas. As of December 31,
2004, it was authorized to provide service in 47 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 of such customers is
not reasonably likely to have a material adverse effect on its financial
condition.

13

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 usually occurs in the winter
due to colder temperatures and the resulting increased demand for heating fuels.
In 2004, total deliveries of natural gas sold by Consumers and by other sellers
who deliver natural gas to customers (including the MCV Partnership) through
Consumers' pipeline and distribution network totaled 389.47 bcf.

GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system
consists of:

- 25,756 miles of distribution mains throughout Michigan's Lower Peninsula;

- 1,642 miles of transmission lines throughout Michigan's Lower Peninsula;

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

- 15 gas storage fields located across Michigan with an aggregate storage
capacity of 308 bcf and a working storage capacity of 142.8 bcf.

GAS SUPPLY: In 2004, Consumers purchased 1 percent of the gas it delivered
from Michigan producers, 70 percent from United States producers outside
Michigan and 22 percent from Canadian producers. Authorized suppliers in the gas
customer choice program supplied the remaining 7 percent of gas that Consumers
delivered.

Consumers' firm gas transportation agreements are with ANR Pipeline
Company, Great Lakes Gas Transmission, L.P., Trunkline Gas Co., Panhandle
Eastern Pipe Line Company, and Vector Pipeline. Consumers uses these agreements
to deliver gas to Michigan for ultimate deliveries to market. Consumers' firm
transportation and city gate arrangements are capable of delivering over 90
percent of Consumers' total gas supply requirements. As of December 31, 2004,
Consumers' portfolio of firm transportation from pipelines to Michigan is as
follows:

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 varies 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, affiliates, and equity
investments, is engaged in domestic and international diversified energy
businesses including independent power production, natural gas transmission,
storage and processing, and energy services. Enterprises' operating revenue was
$808 million in 2004, $1.085 billion in 2003, and $4.508 billion in 2002.

14

NATURAL GAS TRANSMISSION

CMS Gas Transmission was formed in 1988 and owns, develops and manages
domestic and international natural gas facilities. In 2004, CMS Gas
Transmission's operating revenue was $22 million.

In June 2003, CMS Gas Transmission sold Panhandle to Southern Union
Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union
Panhandle Corp. purchased all of Panhandle's outstanding capital stock for
approximately $582 million in cash and 3.15 million shares of Southern Union
common stock. Southern Union Panhandle Corp. also assumed approximately $1.166
billion in debt.

In July 2003, CMS Gas Transmission completed the sale of CMS Field Services
to Cantera Natural Gas, Inc. for gross cash proceeds of approximately $113
million, subject to post closing adjustments, and a $50 million face value note
of Cantera Natural Gas, Inc. The note is payable to CMS Energy for up to $50
million subject to the financial performance of the Fort Union and Bighorn
natural gas gathering systems from 2004 through 2008.

In August 2004, CMS Gas Transmission sold its interest in Goldfields and
its Parmelia business, a discontinued operation, to APT for A$204 million
(approximately $147 million in U.S. dollars). A $45 million ($29 million
after-tax) gain on the sale of Goldfields includes a $9 million ($6 million
after-tax) foreign currency translation gain. A $10 million ($6 million
after-tax) gain on the sale of Parmelia includes a $3 million ($2 million
after-tax) foreign currency translation loss.

NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of
265 miles of gathering and transmission pipelines located in the state of
Michigan, with a daily capacity of 0.75 bcf. At December 31, 2004, CMS Gas
Transmission had nominal processing capabilities of approximately 0.33 bcf per
day of natural gas in Michigan.

At December 31, 2004, CMS Gas Transmission had ownership interests in the
following international pipelines:

INDEPENDENT POWER PRODUCTION

CMS Generation was formed in 1986. It invests in, acquires, develops,
constructs and operates non-utility power generation plants in the United States
and abroad. In 2004, the independent power production business segment's
operating revenue was $258 million, which includes revenues from CMS Generation,
CMS Operating, S.R.L., the MCV Facility and the MCV Partnership.

INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2004, CMS
Generation had ownership interests in operating power plants totaling 8,219
gross MW (3,455 net MW). At December 31, 2004, additional plants totaling
approximately 322 gross MW (69 net MW) were under construction or in advanced
stages of development. These plants include the Saudi Petrochemical Company
power plant, which is under construction in the Kingdom of Saudi Arabia. In
2005, CMS Generation plans to complete the restructuring of its operations by
narrowing the scope of its existing operations and commitments to three regions:
the U.S., South America, and the Middle East/North Africa. In addition, it plans
to sell designated assets and investments that are under-performing, non-region
focused and non-synergistic with other CMS Energy business units.

15

The following table details CMS Generation's interest in independent power
plants as of year-end 2004 (excluding the plants owned by CMS Operating S.R.L.
and CMS Electric and Gas and the MCV facility, discussed further below):

- -------------------------

(a) El Chocon is primarily on a spot market basis, however, it has a high
dispatch rate due to low cost. The El Chocon facility is held pursuant to a
30-year possession agreement.

(b) CMS Generation sold its interest in GVK in the first quarter of 2005.

(c) The Jorf Lasfar facility is held pursuant to a right of possession
agreement with the Moroccan state-owned Office National de l'Electricite.

Through a CMS International Ventures subsidiary called CMS Operating,
S.R.L., CMS Enterprises, CMS Gas Transmission and CMS Generation have a 100
percent ownership interest in a 128 MW natural gas power plant and a 92.6
percent ownership interest in a 597 MW natural gas power plant, each in
Argentina.

Through CMS Electric and Gas, CMS Enterprises has an 87 percent ownership
interest in 287 MW of gas turbine and diesel generating capacity in Venezuela.

CMS Midland owns a 49 percent general partnership interest in the MCV
Partnership, which was formed to construct and operate the MCV Facility. The MCV
Facility was sold to five owner trusts and leased back to the MCV Partnership.
CMS Holdings is a limited partner in the FMLP, which is a beneficiary of one of
these trusts. Through FMLP, CMS Holdings has a 35 percent Lessor interest in the
MCV Facility. The MCV Facility has a net electrical generating capacity of
approximately 1,500 MW. The MCV Partnership contracted to sell electricity to
Consumers for a 35-year period beginning in 1990, and to supply electricity and
steam to Dow.

16

For information on capital expenditures, see ITEM 7. CMS ENERGY'S
MANAGEMENT'S DISCUSSION AND ANALYSIS -- CAPITAL RESOURCES AND LIQUIDITY AND ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 4 OF CMS ENERGY'S NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS (FINANCINGS AND CAPITALIZATION).

OIL AND GAS EXPLORATION AND PRODUCTION

CMS Energy used to own an oil and gas exploration and production company.
In October 2002, CMS Energy completed its exit from the oil and gas exploration
and production business.

ENERGY RESOURCE MANAGEMENT

In 2003, CMS ERM closed its Houston, Texas office and in 2004, CMS ERM
changed its name from CMS Marketing, Services and Trading Company to CMS Energy
Resource Management Company. CMS ERM concentrates on the purchase and sale of
energy commodities in support of CMS Energy's generating facilities. In March
2004, CMS ERM discontinued its natural gas retail program as customer contracts
expired. In 2004, CMS ERM marketed approximately 53.1 bcf of natural gas and
1,243.5 GWh of electricity. Its operating revenue was $381 million in 2004, $711
million in 2003, and $4.137 billion in 2002.

INTERNATIONAL ENERGY DISTRIBUTION

In October 2001, CMS Energy discontinued the operations of its
international energy distribution business. In 2002, CMS Energy discontinued new
development outside North America, which included closing all non-U.S.
development offices. In 2003, due to the uncertainty of executing an asset sale
on acceptable terms and conditions, CMS Energy reclassified to continuing
operations SENECA, which is its energy distribution business in Venezuela, and
CPEE, which is its energy distribution business in Brazil, and restated the
prior year's earnings for these businesses.

CMS ENERGY AND CONSUMERS REGULATION

CMS Energy is a public utility holding company that is exempt from
registration under PUHCA. CMS Energy, Consumers and their subsidiaries are
subject to regulation by various federal, state, local and foreign governmental
agencies, including those described below.

MICHIGAN PUBLIC SERVICE COMMISSION

Consumers is subject to the MPSC's jurisdiction, which regulates public
utilities in Michigan with respect to retail utility rates, accounting, utility
services, certain facilities and various other matters. The MPSC also has rate
jurisdiction over several limited liability companies in which CMS Gas
Transmission has ownership interests. These companies own, or will own, and
operate intrastate gas transmission pipelines.

The Attorney General, ABATE, and the MPSC staff typically intervene in MPSC
electric- and gas-related proceedings concerning Consumers. For many years, most
significant MPSC orders affecting Consumers have been appealed. Certain appeals
from the MPSC orders are pending in the Court of Appeals.

RATE PROCEEDINGS: In 1996, the MPSC issued an order that established the
electric authorized rate of return on common equity at 12.25 percent. In 2002,
the MPSC issued an order that established the gas authorized rate of return on
common equity at 11.4 percent.

MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the
retail electric and gas utility businesses has undergone significant changes. In
2000, the Michigan Legislature enacted the Customer Choice Act. The Customer
Choice Act provides that as of January 2002, all electric customers have the
choice to buy generation service from an alternative electric supplier. The
Customer Choice Act also imposes rate reductions, rate freezes and rate caps.
For additional information regarding the Customer Choice Act, see

17

ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC
UTILITY BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING and
ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- ELECTRIC
BUSINESS UNCERTAINTIES -- COMPETITION AND REGULATORY RESTRUCTURING.

As a result of regulatory changes in the natural gas industry, Consumers
transports the natural gas commodity that is sold to some customers by
competitors like gas producers, marketers and others. Pursuant to a gas customer
choice program that Consumers implemented, as of April 2003 all of Consumers'
gas customers were eligible to select an alternative gas commodity supplier.
Consumers' current GCR mechanism allows it to recover from its customers all
prudently incurred costs to purchase natural gas commodity and transport it to
Consumers' facilities. For additional information, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- CONSUMERS' GAS UTILITY RATE
MATTERS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 2 OF
CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- GAS
RATE MATTERS.

FEDERAL ENERGY REGULATORY COMMISSION

FERC has exercised limited jurisdiction over several independent power
plants in which CMS Generation has ownership interests, as well as over CMS ERM.
Among other things, FERC jurisdiction relates to the acquisition, operation and
disposal of assets and facilities and to the service provided and rates charged.
Some of Consumers' gas business is also subject to regulation by FERC, including
a blanket transportation tariff pursuant to which Consumers can transport gas in
interstate commerce.

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. FERC is currently soliciting
comments on whether it should exercise jurisdiction over power marketers like
CMS ERM, requiring them to follow FERC's uniform system of accounts and seek
authorization for issuance of securities and assumption of liabilities. These
issues are pending before the agency.

NUCLEAR REGULATORY COMMISSION

Under the Atomic Energy Act of 1954, as amended, and the Energy
Reorganization Act of 1974, Consumers is subject to the jurisdiction of the NRC
with respect to the design, construction, operation and decommissioning of its
nuclear power plants. Consumers is also subject to NRC jurisdiction with respect
to certain other uses of nuclear material. These and other matters concerning
Consumers' nuclear plants are more fully discussed in ITEM 7. CMS ENERGY'S
MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC UTILITY
BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CMS ENERGY'S CONSOLIDATED
FINANCIAL STATEMENTS -- NUCLEAR PLANT DECOMMISSIONING and ITEM 7. CONSUMERS'
MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS
UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 2 (CONTINGENCIES) OF CONSUMERS' CONSOLIDATED
FINANCIAL STATEMENTS -- NUCLEAR PLANT DECOMMISSIONING.

OTHER REGULATION

The Secretary of Energy regulates the importation and exportation of
natural gas and has delegated various aspects of this jurisdiction to FERC and
the DOE's Office of Fossil Fuels.

Pipelines owned by system companies are subject to the Natural Gas Pipeline
Safety Act of 1968 and the Pipeline Safety Improvement Act of 2002, which
regulates the safety of gas pipelines. Consumers is also subject to the
Hazardous Liquid Pipeline Safety Act of 1979, which regulates oil and petroleum
pipelines.

18

CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE

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

Consumers 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 regarding nitrogen oxide and
particulate-related emissions. These regulations will require Consumers to make
significant capital expenditures.

Consumers is in the process of closing older ash disposal areas at two
plants. 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 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 filler for asphalt, for
incorporation into concrete products 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.
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 site, to share in remediation costs for the
site.

CMS Energy's and Consumers' current insurance coverage does not extend to
certain environmental clean-up 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.

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.

In the wholesale electricity markets, Consumers competes with other
wholesale suppliers, marketers and brokers. Electric competition in the
wholesale markets increased significantly since 1996 due to FERC Order 888.
While Consumers is still active in wholesale electricity markets, wholesale for
resale transactions by Consumers

19

generated an immaterial amount of Consumers' 2004 revenues from electric utility
operations. Consumers believes future loss of wholesale for resale transactions
will be insignificant.

A significant increase in retail electric competition has occurred because
of the Customer Choice Act and the availability of retail open access. Price is
the principal method of competition for generation services. The Customer Choice
Act gives all electric customers the right to buy generation service from an
alternative electric supplier. As of March 2005, alternative electric suppliers
are providing 900 MW of generation supply to retail open access customers. This
represents approximately 12 percent of Consumers' total distribution load and an
increase of approximately 23 percent in generation supply being purchased from
alternative electric suppliers by retail open access customers over March 2004.
In June 2004, the MPSC granted Consumers recovery of implementation costs
incurred for the Electric Customer Choice program. In November 2004, the MPSC
adopted a mechanism pursuant to the Customer Choice Act to provide for recovery
of stranded costs that occur when customers leave Consumers' system to purchase
electricity from alternative electric suppliers. Consumers cannot predict the
total amount of electric supply load that may be lost to competitor suppliers.

In addition to retail electric customer choice, Consumers also has
competition or potential competition from:

- customers relocating for economic reasons outside Consumers' service
territory;

- 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 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, equipment sales (such as transformers), power quality analysis,
fiber optic line construction, 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 segment, another non-utility electric
subsidiary, faces competition from generators, marketers and brokers, as well as
other utilities marketing power at lower power 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 has existed for the past decade in various aspects of
Consumers' gas utility business, and is likely to increase. Competition
traditionally comes from other gas suppliers taking advantage of direct access
to Consumers' customers and alternate 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. As CMS Energy renews
its policies it is possible that some of the insurance coverage may not be
renewed or obtainable on commercially reasonable terms due to restrictive
insurance markets.

20

EMPLOYEES

CMS ENERGY

As of December 31, 2004, CMS Energy and its wholly owned subsidiaries,
including Consumers, had 8,660 full-time equivalent employees, of whom 8,603 are
full-time employees and 57 are full-time equivalent employees associated with
the part-time work force. Included in the total are 3,734 employees who are
covered by union contracts.

CONSUMERS

As of December 31, 2004, Consumers and its subsidiaries had 8,050 full-time
equivalent employees, of whom 7,995 are full-time employees and 55 are full-time
equivalent employees associated with the part-time work force. Included in the
total are 3,407 full-time operating, maintenance and construction employees and
308 full-time and part-time call center employees who are represented by the
Utility Workers Union of America. Consumers and the Union negotiated a
collective bargaining agreement for the operating, maintenance and construction
employees that became effective as of June 1, 2000 and will continue in full
force and effect until June 1, 2005. Negotiations to reach a new contract are
underway currently. Consumers and the Union negotiated a collective bargaining
agreement for the call center employees that became effective as of April 1,
2003 and will continue in full force and effect until August 1, 2005.

CMS ENERGY EXECUTIVE OFFICERS

(as of March 1, 2005)

- -------------------------

* From July 1997 until October 1999, Mr. Russell served as Manager -- Electric
Customer Operations of Consumers.

** From 1997 to 1999, Mr. Mengebier served as Executive Director of Federal
Governmental Affairs for CMS Enterprises.

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 20, 2005).

AVAILABLE INFORMATION

CMS Energy's internet address is http://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

25

amendments to those reports filed pursuant to Section 13(a) or 15(d) of the
Exchange Act. Such reports are available as soon as practical after they are
electronically filed with the SEC. Also on our website are our:

- Corporate Governance Principles;

- Code of Conduct (Code of Business Conduct and Ethics); and

- Board Committee Charters (including the Audit Committee and the
Governance and Public Responsibility Committee).

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

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 herein:

- BUSINESS -- GENERAL -- Consumers -- Consumers Properties -- General;

- BUSINESS -- BUSINESS SEGMENTS -- Consumers Electric Utility
Operations -- Electric Utility Properties;

- BUSINESS -- BUSINESS SEGMENTS -- Consumers Gas Utility Operations -- Gas
Utility Properties;

- BUSINESS -- BUSINESS SEGMENTS -- Natural Gas Transmission -- Natural Gas
Transmission Properties;

- BUSINESS -- BUSINESS SEGMENTS -- Independent Power
Production -- Independent Power Production Properties; and

- BUSINESS -- BUSINESS SEGMENTS -- International Energy Distribution.

ITEM 3. LEGAL PROCEEDINGS.

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

CMS ENERGY

SEC REQUEST

On August 5, 2004, CMS Energy received a request from the SEC that CMS
Energy voluntarily produce all documents and data relating to the SEC's inquiry
into payments made to the government and 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.

From 1991 through January 3, 2002, subsidiaries of CMS Energy held interest
in, and beginning in 1995 operated, hydrocarbon production and processing
facilities and a methanol plant in Equatorial Guinea. On January 3, 2002, CMS
Energy sold all its Equatorial Guinea holdings. The SEC's inquiry follows an
investigation and public hearing conducted by the United States Senate Permanent
Subcommittee on investigations, which reviewed the U.S. banking transactions of
various foreign governments, including that of Equatorial Guinea. The
investigation and hearing also reviewed the operations of certain U.S. oil
companies in Equatorial Guinea. There

26

were no findings of violations of the U.S. Foreign Corrupt Practices Act by the
U.S. oil companies in the report of the Minority Staff of the Subcommittee, the
only report issued to date as a result of the hearing. The Subcommittee did find
that oil companies operating in Equatorial Guinea may have contributed to
corrupt practices in that country.

DEMAND FOR ACTIONS AGAINST OFFICERS AND DIRECTORS

In May 2002, the Board of Directors of CMS Energy received a demand, on
behalf of a shareholder of CMS Energy Common Stock, that it commence civil
actions (i) to remedy alleged breaches of fiduciary duties by certain CMS Energy
officers and directors in connection with round-trip trading by CMS MST, and
(ii) to recover damages sustained by CMS Energy as a result of alleged insider
trades alleged to have been made by certain current and former officers of CMS
Energy and its subsidiaries. In December 2002, two new directors were appointed
to the Board. The Board formed a special litigation committee in January 2003 to
determine whether it is in CMS Energy's best interest to bring the action
demanded by the shareholder. The disinterested members of the Board appointed
the two new directors to serve on the special litigation committee.

In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. CMS Energy cannot predict the outcome of this matter.

GAS INDEX PRICE REPORTING LITIGATION

In August 2003, Cornerstone Propane Partners, L.P. (Cornerstone) filed a
putative class action complaint in the United States District Court for the
Southern District of New York against CMS Energy and dozens of other energy
companies. The court ordered the Cornerstone complaint to be consolidated with
similar complaints filed by Dominick Viola and Roberto Calle Gracey. The
plaintiffs filed a consolidated complaint on January 20, 2004. The consolidated
complaint alleges that false natural gas price reporting by the defendants
manipulated the prices of NYMEX natural gas futures and options. The complaint
contains two counts under the Commodity Exchange Act, one for manipulation and
one for aiding and abetting violations. Plaintiffs are seeking to have a class
certified and to have the class recover actual damages and costs, including
attorneys fees. CMS Energy is no longer a defendant, however, CMS MST and CMS
Field Services are named as defendants. (CMS Energy sold CMS Field Services to
Cantera Natural Gas, LLC, which changed the name from CMS Field Services to
Cantera Gas Company. CMS Energy is required to indemnify Cantera Natural Gas,
LLC with respect to this action.)

In a similar but unrelated matter, 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. CMS Energy is named as
a defendant. The complaint alleges defendants entered into a price-fixing scheme
by engaging in activities to manipulate the price of natural gas in California.
The complaint contains counts alleging 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
seeks 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 multi district court litigation
(MDL) panel decided to transfer 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,
although none contain a federal Sherman Act claim. In November 2004, those seven
complaints, as well as a number of others that were originally filed in various
state courts in California and subsequently transferred to the MDL proceeding,
were remanded back to California state court. The Texas-Ohio case remains in
Nevada federal district court, and defendants, with CMS Energy joining, filed a
motion to dismiss, which remains pending.

Three federal putative class actions, Fairhaven Power Company v. Encana
Corp. et al., Utility Savings & Refund Services LLP v. Reliant Energy Resources
Inc. et al., and Abelman Art Glass v. Encana Corp. et al., all of which make
allegations similar to those in the Texas-Ohio case regarding price manipulation
and seek similar relief, were originally filed in the United States District
Court for the Eastern District of California in September

27

2004, November 2004 and December 2004, respectively. The Fairhaven and Abelman
Art Glass cases also include claims for unjust enrichment and a constructive
trust. The three complaints were filed against CMS Energy and many of the other
defendants named in the Texas-Ohio case. In addition, the Utility Savings case
names CMS MST and Cantera Resources Inc. (Cantera Resources Inc. is the parent
of Cantera Natural Gas, LLC. and CMS Energy is required to indemnify Cantera
Natural Gas, LLC and Cantera Resources Inc. with respect to these actions.)

Both the Fairhaven and Utility Savings cases have been transferred to the
MDL proceeding, where the Texas-Ohio case is pending. Pursuant to stipulation by
the parties and court order, defendants are not required to respond to the
Fairhaven and Utility Savings complaints until the court rules on defendants'
Motion to Dismiss, which is pending in the Texas-Ohio case. Should the court
grant defendants' motion without leave to amend, any remaining cases in the MDL
proceeding shall be refiled as a consolidated complaint within 20 days of such
ruling. If the motion is denied, or granted with leave to amend, the Texas-Ohio
case and any others pending in the MDL proceeding shall be refiled as a
consolidated complaint within 20 days of the court's ruling. In February 2005,
the Abelman Art Glass case was conditionally transferred to the MDL proceeding.
Abelman Art Glass has until March 10, 2005 to oppose the conditional transfer
order.

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 above. In addition to CMS Energy, CMS MST is
named in all of the 15 state law complaints. Cantera Gas Company and Cantera
Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in
all but the Benscheidt complaint. Two of these cases are styled as class
actions, Benscheidt v. AEP Energy Services, Inc., et al. and Older v. Sempra
Energy, et al., and include a claim for violation of the California Business and
Professions Code relating to unlawful, unfair and deceptive business practices.
Two others, City and County of San Francisco and the People of the State of
California, ex rel. Dennis J. Herrera, in his official capacity as City Attorney
for the City and County of San Francisco v. Sempra Energy, et al. and
Owens-Brockway Glass Container Inc. v. Sempra Energy et al., also include such a
claim under the California Business and Professions Code and are styled as
representative actions.

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 pending coordinated
proceedings, Natural Gas Antitrust Cases I-IV, involve an alleged 1990's
conspiracy by major gas pipeline companies not to build a new pipeline into
Southern California, and a conspiracy to limit gas transmission over an existing
pipeline. The 24 state court complaints involving price reporting were
coordinated as Natural Gas Antitrust Cases V. Plaintiffs in Natural Gas
Antitrust Cases V have been ordered to file a consolidated complaint.

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.

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

ROUND-TRIP TRADING INVESTIGATIONS

During the period of 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 so called
round-trip trades had no impact on previously reported consolidated net income,
earnings per share, or

28

cash flows, but had the effect of increasing operating revenues, operating
expenses, accounts receivable, accounts payable, and reported trading volumes.

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.

CMS ENERGY AND CONSUMERS

EMPLOYMENT RETIREMENT INCOME SECURITY ACT CLASS ACTION LAWSUITS

CMS Energy is a named defendant, along with Consumers, CMS MST, and certain
named and unnamed officers and directors, in two lawsuits brought as purported
class actions on behalf of participants and beneficiaries of the CMS Employees'
Savings and Incentive Plan (the "Plan"). The two cases, filed in July 2002 in
United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek restitution
on behalf of the Plan with respect to a decline in value of the shares of CMS
Energy Common Stock held in the Plan. Plaintiffs also seek other equitable
relief and legal fees. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants filed
answers to the amended complaint on May 14, 2004. The judge issued an opinion
and order dated December 27, 2004, conditionally granting plaintiffs' motion for
class certification. A trial date has not been set, but is expected to be no
earlier than late in 2005. CMS Energy and Consumers will defend themselves
vigorously but cannot predict the outcome of this litigation.

SECURITIES CLASS ACTION LAWSUITS

Beginning on May 17, 2002, a number of securities class action complaints
were filed against CMS Energy, Consumers, and certain officers and directors of
CMS Energy and its affiliates. The complaints were filed as purported class
actions in the United States District Court for the Eastern District of
Michigan, by shareholders who allege that they purchased CMS Energy's securities
during a purported class period. The cases were consolidated into a single
lawsuit and an amended and consolidated class action complaint was filed on May
1, 2003. The consolidated complaint contains a purported class period beginning
on May 1, 2000 and running through March 31, 2003. It 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. The judge issued an opinion and order dated March 31, 2004
in connection with various pending motions, including plaintiffs' motion to
amend the complaint and the motions to dismiss the complaint filed by CMS
Energy, Consumers and other defendants. The judge directed plaintiffs to file an
amended complaint under seal and ordered an expedited hearing on the motion to
amend, which was held on May 12, 2004. At the hearing, the judge ordered
plaintiffs to file a Second Amended Consolidated Class Action complaint deleting
Counts III and IV relating to purchasers of CMS PEPS, which the judge ordered
dismissed with prejudice. Plaintiffs filed this complaint on May 26, 2004. CMS
Energy, Consumers, and the individual defendants filed new motions to dismiss on
June 21, 2004. The judge issued an opinion and order dated January 7, 2005,
granting the motion to dismiss for Consumers and three of the individual
defendants, but denying the motions to dismiss for CMS Energy and the 13
remaining individual defendants. CMS Energy and the individual defendants will
defend themselves vigorously but cannot predict the outcome of this litigation.

29

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 2004, CMS Energy did not submit any matters to
a vote of security holders.

CONSUMERS

During the fourth quarter of 2004, Consumers did not submit any matters to
a vote of security holders.

30

PART II

ITEM 5. MARKET FOR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

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. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 17 OF
CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND
COMMON STOCK INFORMATION), which is incorporated by reference herein. At March
7, 2005, the number of registered holders of CMS Energy Common Stock totaled
57,787. In January 2003, CMS Energy suspended the payment of dividends on its
common stock. 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. In February, May, August, and November
2004, Consumers paid $77.5 million, $27 million, $81.9 million and $3.6 million
in cash dividends, respectively, on its common stock. In January, May, August
and November 2003, Consumers paid $77.5 million, $31 million, $53 million and
$56.5 million in cash dividends, respectively, on its common stock.

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.

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.

31

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.

32

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

Index to Financial Statements:

34

(CMS ENERGY LOGO)

2004 CONSOLIDATED FINANCIAL STATEMENTS

CMS-1

CMS ENERGY CORPORATION
SELECTED FINANCIAL INFORMATION

- -------------------------
(a) Under revised FASB Interpretation No. 46, we are the primary beneficiary of
the MCV Partnership and the FMLP. As a result, we have consolidated their
assets, liabilities and activities into our financial statements as of and
for the year ended December 31, 2004. These partnerships had third party
obligations totaling $582 million at December 31, 2004. Property, plant and
equipment serving as collateral for these obligations had a carrying value
of $1.426 billion at December 31, 2004.

(b) Effective December 31, 2003, Trust Preferred Securities are classified on
the balance sheet as long-term debt-related parties.

(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 and Consumers. The terms
"we" and "our" as used in this report refer to CMS Energy and its subsidiaries
as a consolidated entity, except where it is clear that such term means only CMS
Energy.

EXECUTIVE OVERVIEW

CMS Energy is an integrated energy company with a business strategy focused
primarily in Michigan. We are the parent holding company of Consumers and
Enterprises. Consumers is a combination electric and gas utility company serving
Michigan's Lower Peninsula. Enterprises, through various subsidiaries and equity
investments, is engaged in domestic and international diversified energy
businesses including independent power production and natural gas transmission,
storage, and processing. We manage our businesses by the nature of services each
provides. We operate principally in three business segments: electric utility,
gas utility, and enterprises.

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

- weather, especially during the traditional heating and cooling seasons,

- economic conditions primarily in Michigan,

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

- interest rates,

- our debt credit rating, and

- energy commodity prices.

Our business strategy involves improving our balance sheet and maintaining
focus on our core strength: superior utility operation and service. Our primary
focus with respect to our non-utility businesses has been to optimize cash flow
and further reduce our business risk and leverage through the sale of
non-strategic assets, and to improve earnings and cash flow from the businesses
we plan to retain. Although much of our asset sales program is complete, we
still may sell certain remaining businesses that are not strategic to us. Over
the next few years, we expect that this strategy will result in reduced parent
company debt, improved credit ratings, earnings growth, restoration of a common
stock dividend, and a company positioned to make new investments consistent with
our strengths. In the near term, our new investments will focus principally on
the utility.

We face important challenges in the future. We continue to lose industrial
and commercial customers to alternative electric suppliers as a result of
Michigan's Customer Choice Act. As of March 2005, we have lost 900 MW, or 12
percent, of our electric load to these alternative electric suppliers. Based on
current trends, we predict total load loss by the end of 2005 to be in the range
of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load
loss will fall within that range. Existing state legislation encourages
competition and provides for recovery of Stranded Costs caused by the lost
sales. In fact, in November 2004, the MPSC ordered Consumers to recover 2002 and
2003 Stranded Costs in the amount of $63 million. In 2004, several bills were
introduced into the Michigan Senate that could change Michigan's Customer Choice
Act.

Another important challenge relates to the economics of the MCV
Partnership. The MCV Partnership's costs of producing electricity are tied to
the cost of natural gas. Because natural gas prices have increased substantially
in recent years and the price the MCV Partnership can charge us for energy has
not, the MCV Partnership's financial performance has been impacted negatively.
In January 2005, the MPSC issued an order approving the RCP to change the way
the facility is used. The purpose of the RCP is to conserve natural gas

CMS-3

through a change in the dispatch of the MCV Facility and thereby improve the
financial performance of the MCV Partnership without increased costs to
customers. The approved plan will:

- allow for dispatching the MCV Facility based on natural gas market
prices, which is expected to reduce gas consumption by an estimated 30 to
40 bcf per year,

- allocate 50 percent of Consumers' direct savings to customers in 2005 and
70 percent of Consumers' direct savings to customers thereafter, and

- fund $5 million annually for renewable energy sources such as wind power
projects.

Our business plan is targeted at predictable earnings growth and debt
reduction. Between 2001 and 2003, we reduced parent debt (ie: excluding
Consumers' and other subsidiaries' debt) by 50 percent. We are now in the second
year of a five-year plan to reduce further, by about half, the debt of CMS
Energy. In 2004, we issued 32.8 million shares of our common stock. We also
issued over $1 billion in FMBs and $288 million of convertible senior notes.
Proceeds from these transactions were used to retire higher-interest rate
long-term debt and to make capital infusions of $250 million into Consumers,
providing additional liquidity and flexibility for our utility operations. In
January 2005, we continued to retire higher-interest rate debt through the use
of proceeds from the issuance of $150 million of CMS Energy senior notes and
$250 million of Consumers' FMBs. We also infused an additional $200 million into
Consumers in January 2005. These efforts, and others, are designed to lead us to
be a strong, reliable energy company that will be poised to take advantage of
opportunities for further growth.

CONSOLIDATION OF VARIABLE INTEREST ENTITIES

Under Revised FASB Interpretation No. 46, we are the primary beneficiary of
several entities, most notably the MCV Partnership and the FMLP. As a result, we
have consolidated the assets, liabilities, and activities of these entities into
our financial statements as of and for the year ended December 31, 2004. These
entities are reported as equity method investments in our financial statements
for all periods prior to January 1, 2004. For additional details, see Note 16,
Implementation of New Accounting Standards.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

- capital and financial market conditions, including the price of CMS
Energy Common Stock and the effect of such market conditions on the
Pension Plan, interest rates, and access to the capital markets as well
as 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,

- credit ratings of CMS Energy, Consumers, or any of their affiliates,

- currency fluctuations, transfer restrictions, and exchange controls,

- 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,

- international, national, regional, and local economic, competitive, and
regulatory policies, conditions and developments,
CMS-4

- 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 and/or regulatory lag concerning
a number of significant questions presently before the MPSC relating to
the Customer Choice Act including:

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

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

- power supply and natural gas supply costs when oil prices and other
fuel prices are rapidly increasing,

- timely recognition in rates of additional equity investments in
Consumers, and

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

- the impact of adverse natural gas prices on the MCV Partnership
investment, and regulatory decisions that limit our recovery of capacity
and fixed energy payments,

- federal regulation of electric sales and transmission of electricity
including periodic re-examination by federal regulators of the
market-based sales authorizations under which our subsidiaries
participate in wholesale power markets without price restrictions,

- energy markets, including 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,

- potential for the Midwest Energy Market to develop into an active energy
market in the state of Michigan, which may lead us to account for
electric capacity and energy contracts with the MCV Partnership and other
independent power producers as derivatives,

- the GAAP requirement that we utilize mark-to-market accounting on certain
of our energy commodity contracts and interest rate swaps, which may
have, in any given period, a significant positive or negative effect on
earnings, which could change dramatically or be eliminated in subsequent
periods and could add to earnings volatility,

- potential disruption, expropriation or interruption of facilities or
operations due to accidents, war, terrorism, or changing political
conditions and the ability to obtain or maintain insurance coverage for
such events,

- nuclear power plant performance, decommissioning, policies, procedures,
incidents, and regulation, including the availability of spent nuclear
fuel storage,

- 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,

- outcome, cost, and other effects of legal and administrative proceedings,
settlements, investigations and claims, including particularly claims,
damages, and fines resulting from round-trip trading and inaccurate
commodity price reporting, including investigations by the DOJ regarding
round-trip trading and price reporting,

- limitations on our ability to control the development or operation of
projects in which our subsidiaries have a minority interest,

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

CMS-5

- the efficient sale of non-strategic or under-performing domestic or
international assets and discontinuation of certain operations,

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

- other uncertainties that are difficult to predict, and many of which are
beyond our control.

RESULTS OF OPERATIONS

Our business strategy involves improving our balance sheet and maintaining
focus on our core strength: superior utility operation and service. Our primary
focus with respect to our non-utility businesses has been to optimize cash flow
and further reduce our business risk and leverage through the sale of
non-strategic assets, and to improve earnings and cash flow from the businesses
we plan to retain. The level of inflation in the U.S. and in other countries in
which we have businesses or investments has not had a significant effect on our
consolidated results of operations.

CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS

2004 COMPARED TO 2003: For the year ended December 31, 2004, our net income
available to common stockholders was $110 million, compared to a net loss
available to common stockholders of $44 million for the year ended December 31,
2003. The improvement reflects the increased earnings from our utility due in
large part to rulings from the MPSC. The increase also reflects our continued
commitment to cost management, the continued reduction of debt at our parent
company, lower interest expense from refinanced debt, and benefits from recent
tax legislation. This improvement was offset partially by increased impairment
charges as we continued to dispose of certain businesses that are not strategic
to us. Net income was also reduced by an environmental remediation charge
related to our involvement in Bay Harbor.

Specific increases to net income available to common stockholders are:

- a $56 million increase in net income at our electric utility as favorable
treatment of depreciation and interest under the Customer Choice Act and
reduced pension and benefit costs more than offset the effects of milder
weather, reduced tariff revenues equivalent to the Big Rock nuclear
decommissioning surcharge, and customers choosing alternative electric
suppliers,

- a $56 million net reduction in corporate interest expense,

- a $35 million net gain from the 2004 sales of our Parmelia business and
our interest in Goldfields;

CMS-6

- a $33 million increase in net income at our gas utility resulting from
favorable impacts of MPSC rate orders, reduced pension and benefit costs
outpacing increased interest costs, and the effects of milder weather,

- a $21 million income tax benefit recorded at Enterprises resulting from
the American Jobs Creation Act of 2004,

- a $20 million net reduction in operating and maintenance expenses at
Enterprises resulting from a reduction in expenses at CMS ERM, which sold
its non-essential business segments and moved its headquarters from
Houston, Texas to Jackson, Michigan in 2003,

- a $5 million net reduction in debt retirement charges,

- a $22 million reduction in charges related to changes in accounting, and

- the absence in 2004 of a $34 million deferred tax asset valuation reserve
established in 2003.

These increases were offset partially by:

- a $36 million increase in net asset impairment charges,

- a $29 million net environmental remediation charge associated with our
involvement in Bay Harbor,

- a $10 million increase in the declaration and payment of CMS Energy
preferred dividends;

- the absence in 2004 of $30 million of MSBT refunds received in 2003, and

- the absence in 2004 of $23 million in gains in Discontinued Operations
recorded in 2003.

2003 COMPARED TO 2002: For the year ended December 31, 2003, our net loss
available to common stockholders was $44 million, compared to a net loss
available to common stockholders of $650 million for the year ended December 31,
2002. The improvement reflects the absence of impairment charges from businesses
that were not strategic to us, reduced corporate debt, and increased earnings
from equity method investments. These improvements were offset partially by
lower earnings at our electric utility, a net settlement and curtailment loss
related to our employee benefit plans, and changes in accounting.

Specific increases to net income available to common stockholders are:

- the absence in 2003 of $379 million of net goodwill impairments
associated with discontinued operations recorded in 2002,

- a $427 million increase in net income at Enterprises, primarily due to a
significant reduction in asset impairment charges and increased earnings
from equity investments,

- $30 million of MSBT refunds, and

- a $25 million net reduction in corporate interest.

These increases were offset partially by:

- a $97 million reduction in net income from our electric utility due to
the impact of milder weather on electric deliveries, higher pension
expense, greater depreciation and amortization expense, and customers
choosing alternative electric suppliers,

- a $48 million net settlement and curtailment charge related to a large
number of employees retiring and exiting our employee benefit plans,

- a $44 million net loss on the sale of Panhandle,

- a $34 million deferred tax asset valuation reserve established in 2003,

- a $24 million charge related to changes in accounting primarily due to
energy trading contracts that did not meet the definition of a
derivative, and

CMS-7

- an $8 million decrease in net income at our gas utility primarily due to
increased pension and benefit expense, greater depreciation expense and
higher average debt levels, offset partially by the favorable impact of a
MPSC rate order.

ELECTRIC UTILITY RESULTS OF OPERATIONS

ELECTRIC DELIVERIES: For the year 2004, electric deliveries including
transactions with other wholesale marketers, other electric utilities, and
customers choosing alternative electric suppliers increased 1.3 billion kWh or
3.3 percent versus 2003. Despite the increase in electric deliveries, electric
delivery revenue decreased due to the milder summer temperatures' negative
impact on higher margin residential customer air conditioning usage, customers
choosing alternative electric suppliers, and tariff revenue reductions. The
tariff revenue reductions began on January 1, 2004, and were equivalent to the
Big Rock nuclear decommissioning surcharge in effect when our electric retail
rates were frozen from June 2000 through December 31, 2003. The tariff revenue
reductions decreased electric delivery revenue by $35 million.

Surcharges related to the recovery of costs incurred in the transition to
customer choice offset partially the reductions to electric delivery revenue.
Recovery of these costs began on July 1, 2004 and increased electric delivery
revenue by $10 million.

For the year 2003, electric delivery revenue decreased, reflecting lower
deliveries versus 2002. Most significantly, sales volumes to commercial and
industrial customers were lower than in 2002, a result of these sectors'
continued migration to alternative electric suppliers as allowed by the Customer
Choice Act. Milder summer temperatures reduced air conditioning usage by the
higher-margin residential customers, further decreasing electric delivery
revenue. Overall, electric deliveries, including transactions with other
wholesale marketers and other electric utilities, decreased 0.4 billion kWh or
1.1 percent.

POWER SUPPLY COSTS AND RELATED REVENUE: For the year 2004, our recovery of
power supply costs was capped for the residential and small commercial customer
classes. Operating income decreased $31 million in 2004 versus 2003 primarily
due to power supply-related costs exceeding power supply-related revenue charged
to capped customers. Power supply-related costs increased in 2004 primarily due
to higher priced purchased power necessary to replace the generation loss from
an extended refueling outage at our Palisades nuclear generating plant and
higher coal prices.

For the year 2003, our recovery of power supply costs was fixed for all
customers, as required under the Customer Choice Act. Therefore, power
supply-related revenue in excess of actual power supply costs increased
operating income. By contrast, if power supply-related revenue had been less
than actual power supply costs, the impact would have decreased operating
income. For the year 2003, power supply-related revenue in excess of actual
power supply costs benefited operating income by $26 million versus 2002. This
increase was primarily the

CMS-8

result of increased intersystem revenue, efficient operation of our generating
plants, and lower priced purchased power.

OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: For the
year 2004, other income increased $7 million, other operating expenses decreased
$82 million, and non-commodity revenue decreased $3 million versus 2003. Other
income increased primarily due to $7 million of interest income related to our
2002 and 2003 Stranded Cost recovery as authorized by the MPSC. Our recognition
of this recovery decreased operating expense $57 million in 2004, and along with
decreased depreciation, pension, and benefit costs contributed to the reduction
in other operating expenses. The decrease in depreciation expense reflects our
ability to defer depreciation expense on the excess of capital expenditures over
our depreciation base as authorized by the Customer Choice Act. The decrease in
pension expense reflects fewer current year retirees choosing to receive a
single lump sum distribution and increased plan earnings from higher average
plan assets. The reduction in benefit expense is due to the subsidy provided
under Part D of the Medicare Prescription Drug, Improvement and Modernization
Act.

For the year 2003, net other operating expenses, other income and
non-commodity revenue decreased operating income versus 2002. The decrease
related to increased pension and other benefit costs, a scheduled refueling
outage at Palisades, and higher transmission costs. In addition, depreciation
and amortization expense increased, reflecting higher levels of plant in
service, and higher amortization of securitized assets. Higher non-commodity
revenue associated with other income offset slightly the increased operating
expenses.

REGULATORY RETURN ON CAPITAL EXPENDITURES: As allowed by Section 10d(4) of
the Customer Choice Act, on January 1, 2004, we began recording the 2004 portion
of the return on certain capital expenditures incurred during the rate freeze
period of June 2000 through December 2003. This increased income by $41 million
in 2004. Based on an interpretation of the Customer Choice Act by the MPSC in a
rate order involving Detroit Edison, in November 2004 we recorded an additional
$72 million return on Clean Air Act costs incurred during the period of June
2000 through December 2003.

GAIN ON ASSET SALES: The reduction in operating income from asset sales for
2003 versus 2002 reflected the $31 million pretax gain associated with the 2002
sale of our electric transmission system and the $7 million pretax gain
associated with the 2002 sale of nuclear equipment from the cancelled Midland
project.

GENERAL TAXES: For the year 2004, general taxes increased primarily due to
increases in property tax expense and the absence of a MSBT credit received in
2003. The 2003 MSBT credit was associated with the construction of our corporate
headquarters on a qualifying Brownfield site. For the year 2003, this MSBT
credit decreased general taxes versus 2002.

FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to
higher average debt levels, offset partially by a 46 basis point reduction in
the average rate of interest. Additionally, to recognize a recently issued
interpretation of the Customer Choice Act by the MPSC, we expensed $31 million
of capitalized interest in November related to Clean Air Act costs incurred
during the period of June 2000 through December 2003.

For the year 2003, fixed charges increased versus 2002 due to higher
average debt levels and higher average interest rates.

INCOME TAXES: For the year 2004, income taxes increased due to increased
earnings from the electric utility versus 2003. The increase in income taxes
from the tax treatment of items related to plant, property and equipment as
required by past MPSC orders was offset by Part D of the Medicare Prescription
Drug, Improvement and Modernization Act which provides a subsidy that is exempt
from federal taxation. For the year 2003, income tax expense decreased versus
2002 primarily due to lower earnings by the electric utility.

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GAS UTILITY RESULTS OF OPERATIONS

RESULTS OF FASB INTERPRETATION NO. 46: Due to the implementation of FASB
Interpretation No. 46, certain equity investments, determined to be variable
interest entities under this interpretation, which were previously included in
equity earnings are now included as fully consolidated subsidiaries in the
results of operations. The MCV Partnership and the FMLP were determined to be
variable interest entities under this interpretation, and are included as fully
consolidated subsidiaries in the results of operations in 2004. Three electric
generating plants in Michigan, T.E.S. Filer City Station Limited Partnership,
Grayling Generating Station Limited Partnership, and Genesee Power Station
Limited Partnership, were determined to be variable interest entities under this
interpretation and were included in the results of operations beginning in 2003.
For comparability purposes, the change in net earnings of these entities is
presented separately.

For 2004, earnings decreased versus 2003 primarily due to mark-to-market
losses related to gas contracts and increased fuel and dispatch costs at the MCV
Partnership. These decreases were offset partially by dispatch and variable
energy rate variance revenue.

For 2003 versus 2002, consolidation of the three electric generating plants
in Michigan had no impact on earnings.

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OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For 2004, operating
revenues, net of the related cost of gas and purchased power, increased versus
2003. This increase was primarily due to higher margins from South American
subsidiaries, offset partially by the sale of wholesale gas and power contracts
at CMS ERM.

For 2003, operating revenues, net of the related cost of gas and purchased
power, decreased versus 2002 primarily due to the sale of wholesale gas and
power contracts at CMS ERM.

EARNINGS FROM EQUITY METHOD INVESTEES: Earnings from equity method
investees decreased for 2004 versus 2003 due to a reduction in earnings from
Goldfields, which was sold in August 2004, and losses on the settlement of
derivative contracts. These decreases were offset partially by earnings from
Shuweihat, which became partially operational during the fourth quarter of 2004.

Equity earnings increased for 2003 versus 2002 due to impairment losses in
2002 and an increase in mark-to-market valuation adjustments on interest rate
swaps and power contracts in 2003. Lower earnings offset these increases
partially in 2003 due to sales of equity investments in 2002.

OPERATION AND MAINTENANCE: Operating and maintenance decreased for 2004
versus 2003 and for 2003 versus 2002. These decreases were the result of a
reduction in expenses at CMS ERM, which sold its non-essential business segments
and moved its headquarters from Houston, Texas to Jackson, Michigan in 2003.

GENERAL TAXES, DEPRECIATION AND OTHER INCOME: For 2004, the net of general
tax expense, depreciation and other income decreased income versus 2003. The
change was due to foreign exchange losses offset partially by lower depreciation
due to the sale of non-essential assets at ERM in 2003.

For 2003, the net of general tax expense, depreciation and other income
increased income versus 2002. The change was due to lower depreciation from
assets impaired in 2002, higher interest income, and foreign exchange gains
offset partially by higher general taxes.

GAIN (LOSS) ON SALE OF ASSETS: Gains on asset sales increased in 2004
versus 2003. This is primarily due to the gains on the sales of Goldfields and
land in Moapa, Nevada in 2004.

For 2003, loss on asset sales increased versus 2002. This is primarily due
to the losses on the sales of CMS ERM Wholesale Gas contracts and Guardian
Pipeline in 2003.

For additional details, see Note 2, Discontinued Operations, Other Asset
Sales, Impairments, and Restructuring.

ASSET IMPAIRMENT CHARGES: Asset impairment charges increased in 2004 versus
2003. Impairments recorded in 2004 included a reduction in the fair value of Loy
Yang and impairments related to the sales of our interests in SLAP and GVK. In
February 2005, we completed the sale of our interest in GVK. We expect to
complete the sale of SLAP in 2005.

Asset impairment charges decreased in 2003 versus 2002. In 2003, the
impairments of our equity investments at CMS Generation and our investment in
CMS Electric and Gas' Venezuelan distribution utility were significantly lower
than our 2002 asset impairments that were related primarily to DIG and Michigan
Power.

For additional details, see Note 2, Discontinued Operations, Other Asset
Sales, Impairments, and Restructuring.

ENVIRONMENTAL REMEDIATION: For 2004, we recorded estimated environmental
remediation costs for indemnification claims related to our involvement in Bay
Harbor.

For additional details, see Note 3, Contingencies.

FIXED CHARGES: For 2004, fixed charges decreased versus 2003 due to lower
average debt levels and lower average interest rates primarily resulting from
the payoff of a short-term revolving credit line held by Enterprises during
2003, offset partially by the payment of preferred dividends to the investor in
our Michigan gas assets in 2004 and higher letter of credit fees.

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For 2003, fixed charges increased versus 2002 due to higher average debt
levels and higher average interest rates primarily due to a short-term revolving
credit line held by Enterprises during part of 2003.

INCOME TAXES: For 2004, income taxes decreased as compared to 2003
primarily due to the foreign earnings repatriation tax benefit arising from the
American Jobs Creation Act of 2004, and a decrease in tax reserves.

For 2003, income taxes increased as compared to 2002 due to the absence in
2003, of the tax benefit related to the 2002 impairment charges.

CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS

For the year ended December 31, 2004, corporate interest and other net
expenses were $197 million, a decrease of $59 million versus the same period in
2003. The decrease reflects $56 million of lower interest due to lower average
debt levels and a 58 basis point reduction in the average rate of interest, a $5
million reduction in debt retirement charges, and the absence in 2004 of a $34
million deferred tax asset valuation reserve established in 2003. These
decreases were offset partially by a $24 million increase in general taxes
primarily due to the absence of MSBT refunds received in 2003, a $10 million
increase in the declaration and payment of CMS Energy preferred dividends and a
$2 million increase in other various expenses.

Our 2003 corporate interest and other net expenses decreased $29 million
from 2002 primarily due to reduced restructuring costs and reduced taxes, offset
partially by an increase in interest allocated to continuing operations.

DISCONTINUED OPERATIONS: For the year ended December 31, 2004, our net loss
from Discontinued Operations was $4 million, a decrease of $27 million versus
the same period in 2003. The net loss for 2004 was related primarily to income
tax adjustments offset partially by gains on asset sales. Income from 2003
primarily reflects an increase to net income due to the reclassification of our
international energy distribution business from discontinued operations to
continuing operations. The reclassification resulted in a reversal of a
previously recognized impairment loss. This increase was offset partially by an
impairment of Parmelia, interest allocated to discontinued operations, and a
loss on the disposal of CMS Viron.

For additional details, see Note 2, Discontinued Operations, Other Asset
Sales, Impairments, and Restructuring.

ACCOUNTING CHANGES: In 2004, we recorded a $2 million loss for the
cumulative effect of a change in accounting principle. The loss was the result
of a change in the measurement date on our benefit plans. For additional
details, see Note 7, Retirement Benefits.

A $24 million loss for the cumulative effect of changes in accounting
principle was recognized in the first quarter of 2003, of which $23 million was
related to energy trading contracts and $1 million was related to asset
retirement obligations.

CRITICAL ACCOUNTING POLICIES

The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A:

- use of estimates and assumptions in accounting for long-lived assets,
contingencies, and equity method investments,

- accounting for the effects of industry regulation

- accounting for financial and derivative instruments, trading activities,
and market risk information,

CMS-13

- accounting for international operations and foreign currency,

- accounting for pension and OPEB,

- accounting for asset retirement obligations, and

- accounting for nuclear decommissioning costs.

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

USE OF ESTIMATES AND ASSUMPTIONS

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

LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. Tests of impairment are performed periodically if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $15.872
billion at December 31, 2004, 59 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,

- domestic and foreign regulatory and political environments,

- state and federal regulatory and political environments,

- historical and future cash flow and profitability measurements, and

- other external market conditions or factors.

If an event occurs or circumstances change in a manner that indicates the
recoverability of a long-lived asset should be assessed, we evaluate the asset
for impairment. An 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. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. An asset considered
held-for-sale is recorded at the lower of its carrying amount or fair value,
less cost to sell.

We also assess our ability to recover the carrying amounts of our equity
method investments. This assessment requires us to determine the fair values of
our equity method investments. The determination of fair value is based on
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 also consider the existence of CMS Energy guarantees on
obligations of the investee or other commitments to provide further financial
support. If the fair value is less than the carrying value and the decline in
value is considered to be other than temporary, an appropriate write-down is
recorded.

Our assessments of fair value using these valuation methodologies represent
our best estimates at the time of the reviews and are consistent with our
internal planning. The estimates we use can change over time. If fair values
were estimated differently, they could have a material impact on our financial
statements.

CONTINGENCIES: We are involved in various regulatory and legal proceedings
that arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that the occurrence of

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loss is probable and the amount of loss can be reasonably estimated. The
recording of estimated liabilities for contingencies is guided by the principles
in SFAS No. 5. We consider many factors in making these assessments, including
history and the specifics of each matter. The most significant of these
contingencies are our pending class actions arising out of round-trip trading
and gas price reporting, our electric and gas environmental estimates, our
indemnity and environmental remediation obligations at Bay Harbor, and the
potential underrecoveries from our power purchase contract with the MCV
Partnership.

The amount of income taxes we pay is subject to ongoing audits by federal,
state, foreign tax authorities, which can result in proposed assessments. Our
estimate for the potential outcome for any uncertain tax issue is highly
judgmental. We believe we have adequately provided for any likely outcome
related to these matters. However, our future results may include favorable or
unfavorable adjustments to our estimated tax liabilities in the period the
assessments are made or resolved or when statutes of limitation on potential
assessments expire. As a result, our effective tax rate may fluctuate
significantly on a quarterly basis.

MCV UNDERRECOVERIES: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990 and to supply electricity and steam to Dow. We hold a 49
percent partnership interest in the MCV Partnership, and a 35 percent lessor
interest in the MCV Facility.

The cost that we incur under the MCV Partnership PPA exceeds the recovery
amount allowed by the MPSC. As a result, we estimate that cash underrecoveries
of capacity and fixed energy payments will aggregate $150 million from 2005
through 2007. After September 15, 2007, we expect to claim relief under the
regulatory out provision in the PPA, thereby limiting our capacity and fixed
energy payments to the MCV Partnership to the amounts collected from our
customers. The effect of any such action would be to:

- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and

- eliminate our underrecoveries of capacity and fixed energy payments.

The MCV Partnership has indicated that it may take issue with our exercise
of the regulatory out clause after September 2007. We believe that the clause is
valid and fully effective, but cannot assure that it will prevail in the event
of a dispute. The MPSC's future actions on the capacity and fixed energy
payments recoverable from customers subsequent to September 2007 may affect
negatively the earnings of the MCV Partnership and the value of our investment
in the MCV Partnership.

Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned at our coal plants and our operation and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been impacted negatively. Even with the approved RCP, if gas prices continue at
present levels or increase, the economics of operating the MCV Facility may be
adverse enough to require us to recognize an impairment.

In January 2005, the MPSC issued an order approving the RCP, with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas by an
estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced
natural gas consumed by the MCV Facility will benefit our ownership interest in
the MCV Partnership.

The substantial MCV Facility fuel cost savings will be used first to offset
fully the cost of replacement power. Second, $5 million annually will be used to
fund a renewable energy program. Remaining savings will be split between the MCV
Partnership and Consumers. Consumers' direct savings will be shared 50 percent
with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct
savings from the RCP, after a portion is allocated to customers, will be used to
offset our capacity and fixed energy underrecoveries expense. Since the MPSC has
excluded these underrecoveries from the rate making process, we anticipate that
our savings from the RCP will not affect our return on equity used in our base
rate filings.

CMS-15

In January 2005, Consumers and the MCV Partnership's general partners
accepted the terms of the order and implemented the RCP. The underlying
agreement for the RCP between Consumers and the MCV Partnership extends through
the term of the PPA. However, either party may terminate that agreement under
certain conditions. In February 2005, a group of intervenors in the RCP case
filed an application for rehearing of the MPSC order. The Attorney General also
filed a claim of appeal with the Michigan Court of Appeals. We cannot predict
the outcome of these appeals.

For additional details on the MCV Partnership, see Note 3, Contingencies,
"Other Consumers' Electric Utility Contingencies -- The Midland Cogeneration
Venture."

ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION

Because we are involved in a regulated industry, regulatory decisions
affect the timing and recognition of revenues and expenses. We use SFAS No. 71
to account for the effects of these regulatory decisions. 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 such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. As of
December 31, 2004, we had $1.696 billion recorded as regulatory assets and
$1.574 billion recorded as regulatory liabilities.

For additional details on industry regulation, see Note 1, Corporate
Structure and Accounting Policies, "Utility Regulation."

ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND
MARKET RISK INFORMATION

FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities classified as
available-for-sale are reported at fair value determined from quoted market
prices. Debt and equity securities classified as held-to-maturity are reported
at cost. Unrealized gains or losses resulting from changes in fair value of
certain available-for-sale debt and equity securities are reported, net of tax,
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless the related changes in fair value are
determined to be other than temporary.

Unrealized gains or losses on our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized
gains or losses would not affect our earnings or cash flows.

DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if
certain contracts must be accounted for as derivative instruments. This criteria
is complex and significant judgment is often required in applying the criteria
to specific contracts. If a contract is accounted for as a derivative
instrument, it is recorded in the financial statements as an asset or a
liability at the fair value of the contract. The recorded fair value is then
adjusted quarterly to reflect any change in the market value of the contract, a
practice known as marking the contract to market. Changes in fair value (that
is, gains or losses) are reported either in earnings or accumulated other
comprehensive income, depending on whether the derivative qualifies for cash
flow hedge accounting treatment.

The types of contracts we typically classify as derivative instruments are
interest rate swaps, foreign currency exchange contracts, electric call options,
gas supply call and put options, gas fuel futures and swaps, gas fuel options,
certain gas fuel contracts, and certain gas and electric forward contracts. The
majority of our contracts are not subject to derivative accounting under SFAS
No. 133 because they qualify for the normal purchases and sales exception, or
because there is not an active market for the commodity. Certain of our electric
capacity and energy contracts are not accounted for as derivatives due to the
lack of an active energy market in the state of Michigan and the significant
transportation costs that would be incurred to deliver the power under the
contracts to the closest active energy market at the Cinergy hub in Ohio.
Similarly, our coal purchase contracts are not accounted for as derivatives due
to the lack of an active market for the coal that we purchase. If active

CMS-16

markets for these commodities develop in the future, we may be required to
account for these contracts as derivatives, and the resulting mark-to-market
impact on earnings could be material to our financial statements.

The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005,
which will include day-ahead and real-time energy market information and
centralized dispatch for market participants. At this time, we believe that the
commencement of this market will not constitute the development of an active
energy market in the state of Michigan. However, after having adequate
experience with the Midwest Energy Market, we will reevaluate whether or not the
activity level within this market leads to the conclusion that an active energy
market exists. For additional information, see "Electric Utility Business
Uncertainties -- Competition and Regulatory Restructuring -- Transmission Market
Developments" within this MD&A.

The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. The MCV Partnership believes that
certain of its long-term gas contracts qualify as normal purchases under SFAS
No. 133 and therefore, these contracts are not recognized at fair value on the
balance sheet. Due to the implementation of the RCP in January 2005, the MCV
Partnership has determined that a significant portion of its gas fuel contracts
no longer qualify as normal purchases because the contracted gas will not be
consumed as fuel for electric production. Accordingly, these contracts will be
treated as derivatives and will be marked-to-market through earnings each
quarter, which could increase earnings volatility. Based on market prices for
natural gas as of January 31, 2005, the accounting for the MCV Partnership's
long-term gas contracts, including those affected by the implementation of the
RCP, could result in an estimated $100 million (pretax before minority interest)
gain recorded to earnings in the first quarter of 2005. This estimated gain will
reverse in subsequent quarters as the contracts settle. For further details on
the RCP, see "Critical Accounting Policies -- Use of Estimates and
Assumptions -- MCV Underrecoveries" within this MD&A. If there are further
changes in the level of planned electric production or gas consumption, the MCV
Partnership may be required to account for additional long-term gas contracts as
derivatives, which could add to earnings volatility.

To determine the fair value of our derivative contracts, we use a
combination of quoted market prices, prices obtained from external sources, such
as brokers, and mathematical valuation models. Valuation models require various
inputs, including forward prices, strike prices, volatilities, interest rates,
and maturity dates. Changes in forward prices or volatilities could change
significantly the calculated fair value of certain contracts. At December 31,
2004, we assumed a market-based interest rate of 2.75 percent and monthly
volatility rates ranging between 38 percent and 73 percent to calculate the fair
value of our gas options. Also, at December 31, 2004, we assumed a market-based
interest rate of 2.75 percent and daily volatility rates ranging between 80
percent and 157 percent to calculate the fair value of our electric options. At
December 31, 2004, we assumed market-based interest rates ranging between 2.40
percent and 4.48 percent (depending on the term of the contract) and monthly
volatility rates ranging between 25 percent and 68 percent to calculate the fair
value of the gas fuel derivative contracts held by the MCV Partnership.

In certain contracts, long-term commitments may extend beyond the period in
which market quotations for such contracts are available. Mathematical models
are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. In connection with the market valuation of our derivative contracts, we
maintain reserves, if necessary, for credit risks based on the financial
condition of counterparties.

CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts that are
related to activities considered to be an integral part of CMS Energy's ongoing
operations. CMS ERM holds certain forward contracts for the purchase and sale of
electricity and natural gas that result in physical delivery of the underlying
commodity at contractual prices. These contracts are generally long-term in
nature and are classified as non-trading. CMS ERM also uses various financial
instruments, including swaps, options, and futures, to manage the commodity
price risks associated with its forward purchase and sales contracts as well as
generation assets owned by CMS Energy or its subsidiaries. These financial
contracts are classified as trading activities. Non-trading and trading
contracts that meet the definition of a derivative under SFAS No. 133 are
recorded as assets or liabilities in the financial statements at the fair value
of the contracts. Gains or losses arising from changes in fair value of these
contracts are recognized into earnings in the period in which the changes occur.
Gains and losses on trading

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contracts are recorded net in accordance with EITF Issue No. 02-03. Contracts
that do not meet the definition of a derivative are accounted for as executory
contracts (i.e., on an accrual basis).

The fair value of the derivative contracts held by CMS ERM is included 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 as of December 31, 2004:

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

(b) Reflects changes in price and net increase/(decrease) of forward positions
as well as changes to mark-to-market and credit reserves.

MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various derivative contracts to
manage these risks, including swaps, options, futures, and forward contracts. We
intend that gains or losses on these contracts will be offset by an opposite
movement in the value of the item at risk. Risk management contracts are
classified as either non-trading or trading.

These contracts contain credit risk if the counterparties, including
financial institutions and energy marketers, fail to perform under the
agreements. We minimize such risk through established credit policies that
include performing financial credit reviews of our counterparties. Determination
of our counterparties' credit

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quality is based upon a number of factors, including credit ratings, disclosed
financial condition, and collateral requirements. Where contractual terms
permit, we employ standard agreements that allow for netting of positive and
negative exposures associated with a single counterparty. Based on these
policies, our current exposures, and our credit reserves, we do not anticipate a
material adverse effect on our financial position or earnings as a result of
counterparty nonperformance.

The following risk sensitivities indicate the potential loss in fair value,
cash flows, or future earnings from our derivative contracts and other financial
instruments based upon a hypothetical 10 percent adverse change in market rates
or prices. Changes in excess of the amounts shown in the sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses.

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 a 10 percent adverse
change in market interest rates):

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

Certain equity method investees have entered into interest rate swaps.
These instruments are not required to be included in the sensitivity analysis,
but can have an impact on financial results.

Commodity Price Risk: For purposes other than trading, we enter into
electric call options and gas supply call and put options. Electric call options
are purchased to protect against the risk of fluctuations in the market price of
electricity, and to ensure a reliable source of capacity to meet our customers'
electric needs. Purchased electric call options give us the right, but not the
obligation, to purchase electricity at predetermined fixed prices. Our gas
supply call and put options are used to purchase reasonably priced gas supply.
Purchases of gas supply call options give us the right, but not the obligation,
to purchase gas supply at predetermined fixed prices. Gas supply put options
sold give third-party suppliers the right, but not the obligation, to sell gas
supply to us at predetermined fixed prices. At December 31, 2004, we held gas
supply call options and had sold gas supply put options. Also, at December 31,
2004, CMS ERM held certain non-trading derivative contracts for the purchase and
sale of electricity and natural gas as further explained under "CMS ERM
Contracts" within this section.

The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. Some of these contracts are treated as
derivative instruments. The MCV Partnership also enters into natural gas futures
contracts, option contracts, and over-the-counter swap transactions in order to
hedge against unfavorable changes in the market price of natural gas in future
months when gas is expected to be needed. These financial instruments are being
used principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements.

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

CMS-19

We did not perform a sensitivity analysis for the derivative contracts held
by the MCV Partnership as of December 31, 2003, because the MCV Partnership was
not consolidated into our financial statements until 2004, as discussed in Note
16, Implementation of New Accounting Standards.

Trading Activity Commodity Price Risk: CMS ERM uses various financial
instruments, including swaps, options, and futures, to manage the commodity
price risks associated with its forward purchase and sales contracts as well as
generation assets owned by CMS Energy or its subsidiaries.

Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10
percent adverse change in market prices):

Currency Exchange Risk: We are exposed to currency exchange risk arising
from investments in foreign operations as well as various international projects
in which we have an equity interest and which have debt denominated in U.S.
dollars. We may use forward exchange contracts and other risk mitigating
instruments to hedge currency exchange rates. The purpose of our foreign
currency hedging activities is to protect the company from the risk associated
with adverse changes in currency exchange rates that could affect cash flow
materially. As of December 31, 2004, we had no outstanding foreign exchange
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:

- -------------------------
(a) Primarily SERP Investments.

(b) Assumes a 10 percent adverse change in market prices.

(c) Assumes a 50 basis point increase in the yield to maturity of the 10-year
Treasury Note, which approximates a 10 percent change in market yields.

Consumers maintains trust funds, as required by the NRC, which may only be
used to fund certain costs of nuclear plant decommissioning. As of December 31,
2004 and 2003, these funds were invested primarily in equity securities,
fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are
recorded at fair value on our Consolidated Balance Sheets. Those investments are
exposed to price fluctuations in equity markets and changes in interest rates.
Because the accounting for nuclear plant decommissioning recognizes that costs
are recovered through Consumers' electric rates, fluctuations in equity prices
or interest rates do not affect earnings or cash flows.

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

CMS-20

INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY

We have investments in energy-related projects in selected markets around
the world. As a result of a change in business strategy, we have been selling
certain foreign investments. For additional details on the divestiture of
foreign investments, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.

BALANCE SHEET: Our subsidiaries and affiliates whose functional currency is
other than 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. Gains
or losses that result from this translation and gains or losses on long-term
intercompany foreign currency transactions are reflected as a component of
stockholders' equity on our Consolidated Balance Sheets as "Accumulated Other
Comprehensive Loss." As of December 31, 2004, cumulative foreign currency
translation decreased stockholders' equity by $319 million. We translate the
revenue and expense accounts of these subsidiaries and affiliates into U.S.
dollars at the average exchange rate during the period.

Australia: The Foreign Currency Translation component of stockholders'
equity at December 31, 2003 included an approximate $110 million unrealized net
foreign currency translation loss related to our investment in Loy Yang and an
approximate $6 million unrealized net foreign currency translation gain related
to our investments in SCP and Parmelia. In March 2004, we recognized the Loy
Yang foreign currency translation loss in earnings as a component of the Loy
Yang impairment of approximately $81 million, net of tax, recorded as a result
of the sale of Loy Yang that was completed in April 2004. In August 2004, we
sold our investments in SCP and Parmelia and recognized the $6 million foreign
currency translation gain. As of December 31, 2004, we no longer have any
investments in Australia.

Argentina: 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 President of Argentina to
renegotiate such tariffs.

Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.

As of December 31, 2004, the net foreign currency loss due to the
unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency
Translation component of stockholders' equity using an exchange rate of 2.976
pesos per U.S. dollar was $264 million. This amount also reflects the effect of
recording, at December 31, 2002, U.S. income taxes on temporary differences
between the book and tax bases of foreign investments, including the foreign
currency translation associated with our Argentine investments.

INCOME STATEMENT: We use the U.S. dollar as the functional currency of
subsidiaries operating in highly inflationary economies and of subsidiaries that
meet the U.S. dollar functional currency criteria in SFAS No. 52. Gains and
losses that arise from transactions denominated in a currency other than the
U.S. dollar, except those that are hedged, are included in determining net
income.

HEDGING STRATEGY: We may use forward exchange and option contracts to hedge
certain receivables, payables, long-term debt, and equity value relating to
foreign investments. The purpose of our foreign currency hedging activities is
to protect the company from the risk associated with adverse changes in currency
exchange rates that could affect cash flow materially. These contracts would
limit the risk from exchange rate movements because gains and losses on such
contracts offset losses and gains, respectively, on assets and liabilities being
hedged.

ACCOUNTING FOR PENSION AND OPEB

Pension: We have established external trust funds to provide retirement
pension benefits to our employees under a non-contributory, defined benefit
Pension Plan. We have implemented a cash balance plan for certain employees
hired after June 30, 2003. We use SFAS No. 87 to account for pension costs.

CMS-21

401(k): In our efforts to reduce costs, the employer's match for the 401(k)
plan was suspended effective September 1, 2002. The employer's match for the
401(k) plan resumed on January 1, 2005.

OPEB: We provide postretirement health and life benefits under our OPEB
plan to substantially all our retired employees. We use SFAS No. 106 to account
for other postretirement benefit costs.

Liabilities for both pension and OPEB are recorded on the balance sheet at
the present value of their future obligations, net of any plan assets. The
calculation of the liabilities and associated expenses requires the expertise of
actuaries. Many assumptions are made 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.

Any change in these assumptions can significantly change the liability and
associated expenses recognized in any given year.

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

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 8.75 percent to 8.50 percent) would increase estimated
pension cost for 2005 by $3 million. Lowering the discount rate by 0.25 percent
(from 6.00 percent to 5.75 percent) would increase estimated pension cost for
2005 by $4 million.

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

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

SFAS No. 143 became effective January 2003. It requires companies 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, including our nuclear plants, at the end of their useful
lives. For our regulated utility, as required by SFAS No. 71, we account for the
implementation of this standard by recording regulatory assets and liabilities
instead of a cumulative effect of a change in accounting principle.

The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions, such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. 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, electric and gas transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded

CMS-22

for these assets. Also, no liability has been recorded for assets that have
insignificant cumulative disposal costs, such as substation batteries. The
measurement of the ARO liabilities for Palisades and Big Rock are based on
decommissioning studies that largely utilize third-party cost estimates. For
additional details on ARO, see Note 8, Asset Retirement Obligations.

ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS

The MPSC and the FERC regulate the recovery of costs to decommission our
Big Rock and Palisades nuclear plants. We have established external trust funds
to finance the decommissioning of both plants. We record the trust fund balances
as a non-current asset on our Consolidated Balance Sheets.

Our decommissioning cost estimates for the Big Rock and Palisades plants
assume:

- each plant site will be restored to conform to the adjacent landscape,

- all contaminated equipment and material will be removed and disposed of
in a licensed burial facility, and

- the site will be released for unrestricted use.

Independent contractors with expertise in decommissioning have helped us
develop decommissioning cost estimates. Various inflation rates for labor,
non-labor, and contaminated equipment disposal costs are used to escalate these
cost estimates to the future decommissioning cost. A portion of future
decommissioning cost will result from the failure of the DOE to remove fuel from
the sites, as required by the Nuclear Waste Policy Act of 1982.

The decommissioning trust funds include equities and fixed income
investments. Equities will be converted to fixed income investments during
decommissioning, and fixed income investments are converted to cash as needed.
The funds provided by the trusts, additional customer surcharges, and potential
funds from the DOE litigation are all required to cover fully the
decommissioning costs. The costs of decommissioning these sites and the adequacy
of the trust funds could be affected by:

- variances from expected trust earnings,

- a lower recovery of costs from the DOE and lower rate recovery from
customers, and

- changes in decommissioning technology, regulations, estimates, or
assumptions.

Based on current projections, the current level of funds provided by the
trusts is not adequate to fund fully the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel on schedule and lower returns on the trust funds. We are attempting to
recover our additional costs for storing spent nuclear fuel through litigation.
We are also seeking additional relief from the MPSC. For additional details on
nuclear decommissioning, see Note 3, Contingencies, "Other Consumers' Electric
Utility Contingencies -- Nuclear Plant Decommissioning" and "Nuclear Matters."

CAPITAL RESOURCES AND LIQUIDITY

Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
working capital needs, and collateral requirements. During the summer months, we
purchase natural gas and store it for resale primarily during the winter heating
season. The market price for natural gas has increased. Although our natural gas
purchases are recoverable from our customers, the amount paid for natural gas
stored as inventory could require additional liquidity due to the timing of the
cost recoveries. In addition, a few of our commodity suppliers have requested
nonstandard payment terms or other forms of assurances, including margin calls,
in connection with maintenance of ongoing deliveries of gas and electricity.

Our current financial plan includes controlling our operating expenses and
capital expenditures and evaluating market conditions for financing
opportunities. We believe our current level of cash and access to borrowing
capacity in the capital markets, along with anticipated cash flows from
operating and investing activities, will be sufficient to meet our liquidity
needs through 2006. We have not made a specific determination

CMS-23

concerning the reinstatement of common stock dividends. The Board of Directors
may reconsider or revise its dividend policy based upon certain conditions,
including our results of operations, financial condition, and capital
requirements, as well as other relevant factors.

CASH POSITION, INVESTING, AND FINANCING

Our operating, investing, and financing activities meet consolidated cash
needs. At December 31, 2004, $725 million consolidated cash was on hand, which
includes $56 million of restricted cash and $128 million from the effect of
Revised FASB Interpretation No. 46 consolidation. For additional details on cash
equivalents and restricted cash, see Note 1, Corporate Structure and Accounting
Policies. For additional details on FASB Interpretation No. 46, see Note 16,
Implementation of New Accounting Standards.

Our primary ongoing source of cash is dividends and other distributions
from our subsidiaries, including proceeds from asset sales. For the year ended
December 31, 2004, Consumers paid $190 million in common stock dividends and
Enterprises paid $336 million in common stock dividends and other distributions
to CMS Energy.

SUMMARY OF CASH FLOWS:

OPERATING ACTIVITIES:

2004: Net cash provided by operating activities was $398 million in 2004
compared to net cash used in operating activities of $250 million in 2003. The
increase of $648 million primarily represents the absence, in 2004, of $560
million in pension contributions made in 2003 and the reduced effect of rising
gas prices on inventory. These changes were offset partially by increases in
accounts receivable due to higher gas prices and the net effect of the sale of
CMS ERM's wholesale gas and power contracts in 2003 resulting from our continued
focus to optimize cash flow through the sale of non-strategic assets.

2003: Net cash used in operating activities was $250 million in 2003
compared to net cash provided by operating activities of $614 million in 2002.
The change of $864 million was primarily due to an increase in pension plan
contributions of $496 million, an increase in inventories of $428 million due to
higher gas purchases at higher prices by our gas utility operations, and the net
effect of the sale of CMS ERM's wholesale gas and power contracts resulting from
our focus on optimizing cash flow through the sale of non-strategic assets.

INVESTING ACTIVITIES:

2004: Net cash used in investing activities increased $595 million
primarily due to a decrease in asset sale proceeds of $720 million and an
increase in investments in unconsolidated subsidiaries of $71 million. In 2003,
we sold Panhandle, Field Services, and CMS ERM's wholesale gas and power
contracts. Our 2004 $71 million investment was primarily for our equity interest
in Shuweihat. These changes were offset partially by a decrease in the amount of
cash restricted of $308 million resulting from our improved financial condition.
In 2004, $145 million in restricted cash was no longer required to be held as
collateral for letters of credit.

2003: Net cash provided by investing activities decreased $626 million
primarily due to a decrease in asset sale proceeds from Equatorial Guinea,
Powder River, and GMS Oil & Gas of $720 million in 2002. This was

CMS-24

offset by a decrease in 2003 capital expenditures of $212 million as a result of
our strategic plan to reduce capital expenditures.

FINANCING ACTIVITIES:

2004: Net cash used in financing activities increased $272 million
primarily due to a decrease of $232 million in net proceeds from borrowings.

2003: Net cash provided by financing activities increased $1.452 billion
primarily due to an increase in net proceeds from borrowings of $988 million and
net proceeds from preferred securities issuances of $272 million.

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

SUBSEQUENT FINANCING ACTIVITIES: In January 2005, we redeemed $103 million of
general term notes. In January 2005, we issued $150 million of 6.30 percent
Senior Notes due 2012. We used the net proceeds of $147 million to redeem the
remaining general term notes and for other corporate purposes.

In January 2005, Consumers issued $250 million of 5.15 percent FMBs due
2017. Consumers used the net proceeds of $247 million to pay off its $60 million
long-term bank loan, to redeem the $73 million 8.36 percent subordinated
deferrable interest notes, and to redeem the $124 million 8.20 percent
subordinated deferrable interest notes. The subordinated deferrable interest
notes are classified as Long-term debt -- related parties on our accompanying
Consolidated Balance Sheets.

OBLIGATIONS AND COMMITMENTS

CONTRACTUAL OBLIGATIONS: The following table summarizes our contractual
cash obligations for each of the periods presented. The table shows the timing
and effect that such obligations are expected to have 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. The majority of current
liabilities will be paid in cash in 2005.

Long-Term Debt: The amounts in the table above represent the principal
amounts due on outstanding debt obligations, current and long-term, as of
December 31, 2004. For additional details on long-term debt, see Note 4,
Financings and Capitalization.

Interest Payments on Long-term Debt: The amounts in the table above
represent the 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, 2004.

CMS-25

Capital and Finance Leases: The amounts in the table above represent the
minimum lease payments payable under our capital and finance leases. They are
comprised mainly of the leased portion of the MCV Partnership facility, leased
service vehicles, and leased office furniture.

Interest Payments on Capital and Finance Leases: The amounts in the table
represent imputed interest in the capital leases and currently scheduled
interest payments on the finance leases.

Operating Leases: The amounts in the table above represent the 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.

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

- natural gas,

- electricity,

- coal and associated transportation, and

- electric transmission.

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 $10 million per month during 2005. If a plant is not available to
deliver electricity, we are not obligated to make the capacity payments to the
plant for that period of time. 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."

Long-term Service Agreements: These obligations of the MCV Partnership
represent the cost of the current MCV Facility maintenance service agreements
and cost of spare parts.

REVOLVING CREDIT FACILITIES: At December 31, 2004, CMS Energy had $194
million available, Consumers had $475 million available, and the MCV Partnership
had $48 million available in secured revolving credit facilities. The facilities
are available for general corporate purposes, working capital, and letters of
credit. For additional details on revolving credit facilities, see Note 4,
Financings and Capitalization.

OFF-BALANCE SHEET ARRANGEMENTS: CMS Energy and certain of its subsidiaries
enter into guarantee arrangements in the normal course of business to facilitate
commercial transactions with third parties. These arrangements include financial
and performance guarantees, letters of credit, debt guarantees, surety bonds and
indemnifications. For additional details on guarantee arrangements, see Note 4,
Financings and Capitalization, "FASB Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," and in "Commercial Commitments" within
this section.

Non-recourse Debt: Our share of unconsolidated debt associated with
partnerships and joint ventures in which we have a minority interest is
non-recourse and totals $1.368 billion at December 31, 2004. The timing of the
payments of non-recourse debt only affects the cash flow and liquidity of the
partnerships and joint ventures. For additional details, see Note 12, Equity
Method Investments.

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

COMMERCIAL COMMITMENTS: Our contingent commercial commitments include
guarantees, indemnities, and letters of credit. Guarantees represent our
guarantees of performance, commitments, and liabilities of our consolidated and
unconsolidated subsidiaries, partnerships, and joint ventures. Indemnities are
agreements to reimburse other companies, such as an insurance company, if those
companies have to complete our contractual performance in a third-party
contract. Banks, on our behalf, issue letters of credit guaranteeing payment to
a third party. Letters of credit substitute the bank's credit for ours and
reduce credit risk for the third-party beneficiary. We monitor these obligations
and believe it is unlikely that we would be required to perform or otherwise
incur
CMS-26

any material losses associated with these guarantees. Our off-balance sheet
commitments at December 31, 2004, expire as follows:

- -------------------------
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.

DIVIDEND RESTRICTIONS: Our amended and restated $300 million secured
revolving credit facility restricts payments of dividends on our common stock
during a 12-month period to $75 million, dependent on the aggregate amounts of
unrestricted cash and unused commitments under the facility.

Under the provisions of its articles of incorporation, at December 31,
2004, Consumers had $456 million of unrestricted retained earnings available to
pay common stock dividends. However, covenants in Consumers' debt facilities cap
common stock dividend payments at $300 million in a calendar year. In October
2004, the MPSC rescinded its December 2003 interim gas rate order, which
included a $190 million annual dividend cap imposed on Consumers. For the year
ended December 31, 2004, we received $190 million of common stock dividends from
Consumers.

CAPITAL EXPENDITURES: We estimate that we will make the following capital
expenditures, including new lease commitments, by business segments during 2005
through 2007. We prepare these estimates for planning purposes and may revise
them.

- -------------------------
(a) These amounts include a portion of Consumers' anticipated capital
expenditures for plant and equipment attributable to both the electric and
gas utility businesses.

(b) These amounts include estimates for capital expenditures that may be
required by recent revisions to the Clean Air Act's national air quality
standards.

OUTLOOK

CORPORATE OUTLOOK

During 2004, we have continued to implement a business strategy that
involves improving our balance sheet and providing superior utility operations
and service. This strategy is designed to generate cash to pay down debt and
provide for more predictable future operating revenues and earnings.

Our primary focus with respect to our non-utility businesses has been to
optimize cash flow and further reduce our business risk and leverage through the
sale of non-strategic assets, and to improve earnings and cash flow from
businesses we plan to retain. Although much of our asset sales program is
complete, we still may sell certain remaining businesses that are not strategic
to us. As this continues, the percentage of our future earnings relating to our
larger equity method investments, including Jorf Lasfar, may increase and our
total future earnings

CMS-27

may depend more significantly upon the performance of those investments. For
additional details, see Note 12, Equity Method Investments.

Over the next few years, we expect our business strategy to reduce parent
company debt substantially, improve our credit ratings, grow earnings, restore a
common stock dividend, and position the company to make new investments
consistent with our strengths. In the near term, our new investments will focus
principally on the utility.

ELECTRIC UTILITY BUSINESS OUTLOOK

GROWTH: In 2004, we experienced cooler than normal summer weather. As a
result, our electric deliveries in 2004, including deliveries to customers who
chose to buy generation service from alternative electric suppliers, increased
less than one-half of one percent over the levels experienced in 2003. In 2005,
we project electric deliveries to grow almost three percent. This short-term
outlook for 2005 assumes a stronger economy than in 2004 and normal weather
conditions throughout the year.

Over the next five years, we expect electric deliveries to grow at an
average rate of approximately two percent per year, based primarily on a
steadily growing customer base and economy. This growth rate includes both
full-service sales and delivery service to customers who choose to buy
generation service from an alternative electric supplier, but excludes
transactions with other wholesale market participants and other electric
utilities. This growth rate reflects a long-range expected trend of growth.
Growth from year to year may vary from this trend due to customer response to
fluctuations in weather conditions and changes in economic conditions, including
utilization and expansion of manufacturing facilities.

ELECTRIC UTILITY BUSINESS UNCERTAINTIES

Several electric business trends or uncertainties may affect our financial
results and condition. These trends or uncertainties have, or we reasonably
expect could have, a material impact on revenues or income from continuing
electric operations. Such trends and uncertainties include:

Environmental

- increasing capital expenditures and operating expenses for Clean Air Act
compliance and/or Clear Skies legislation compliance,

- compliance with legislative proposals that would require reductions in
emissions of greenhouse gases, and

- potential environmental liabilities arising from various environmental
laws and regulations, including potential liability or expenses relating
to the Michigan Natural Resources and Environmental Protection Acts and
Superfund.

Restructuring

- response of the MPSC and Michigan legislature to electric industry
restructuring issues,

- ability to meet peak electric demand requirements at a reasonable cost,
without market disruption,

- recovery of our Section 10d(4) Regulatory Assets,

- effects of lost electric supply load to alternative electric suppliers,
and

- status as an electric transmission customer instead of an electric
transmission owner and the impact of the evolving RTO infrastructure.

Regulatory

- financial and operating effects of regulatory requirements imposed by the
MISO, the FERC, state and federal regulators, or others, seeking to
improve reliability of national and state transmission systems,

- inadequate regulatory response to applications for requested rate
increases,

- responses from regulators regarding the storage and ultimate disposal of
spent nuclear fuel,

CMS-28

- recovery of nuclear decommissioning costs. For additional details, see
"Accounting for Nuclear Decommissioning Costs" within this MD&A, and

- potential for the Midwest Energy Market to develop into an active energy
market in the state of Michigan and the potential derivative accounting
impact. For additional details, see "Accounting for Financial and
Derivative Instruments, Trading Activities, and Market Risk Information"
within this MD&A.

Other

- effects of commodity fuel prices such as natural gas, oil, and coal,

- pending litigation filed by PURPA qualifying facilities, and

- other pending litigation.

For additional details about these trends or uncertainties, see Note 3,
Contingencies.

ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to
environmental laws and regulations. Costs to operate our facilities in
compliance with these laws and regulations generally have been recovered in
customer rates.

Clean Air: Compliance with the federal Clean Air Act and resulting
regulations has been, and will continue to be, a significant focus for us. The
Title I provisions of the Clean Air Act require significant reductions in
nitrogen oxide emissions. To comply with the regulations, we expect to incur
capital expenditures totaling $802 million. The key assumptions included in the
capital expenditure estimate include:

- construction commodity prices, especially construction material and
labor,

- project completion schedules,

- cost escalation factor used to estimate future years' costs, and

- allowance for funds used during construction (AFUDC) rate.

Our current capital cost estimates include an escalation rate of 2.6
percent and an AFUDC capitalization rate of 8.06 percent. As of December 31,
2004, we have incurred $525 million in capital expenditures to comply with these
regulations and anticipate that the remaining $277 million of capital
expenditures will be made between 2005 and 2011. These expenditures include
installing selective catalytic reduction technology at four of our coal-fired
electric plants. In addition to modifying the coal-fired electric plants, we
expect to utilize nitrogen oxide emissions allowances for years 2005 through
2009, most of which have been purchased. The cost of the allowances is estimated
to average $8 million per year for 2005-2006. The need for allowances will
decrease after year 2006 with the installation of emissions control technology.
The cost of the allowances is accounted for as inventory. The allowance
inventory is expensed as the coal-fired electric generating units emit nitrogen
oxide.

The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.

The EPA has proposed a Clean Air Interstate Rule that would require
additional coal-fired electric plant emission controls for nitrogen oxides and
sulfur dioxide. If implemented, this rule potentially would require expenditures
equivalent to those efforts in progress to reduce nitrogen oxide emissions as
required under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury from coal-fired
electric plants and nickel from oil-fired electric plants. Until the proposed
environmental rules are finalized, an accurate cost of compliance cannot be
determined.

CMS-29

Our switch to western coal as a primary fuel source has resulted in reduced
plant emissions and increased our flexibility in meeting future regulatory
compliance requirements. Excess sulfur dioxide allowances optimize our overall
cost of regulatory compliance by delaying capital expenditures and minimizing
regulatory uncertainty. Additionally, the excess sulfur dioxide allowances can
be used to trade for nitrogen oxide allowances supplementing our nitrogen oxide
allowance bank. Western coal has reduced our overall cost of fuel and reduced
the economic impact from the recent increases in eastern coal prices.

Several legislative proposals have been introduced in the United States
Congress that would require reductions in emissions of greenhouse gases,
however, none have yet been enacted. We cannot predict whether any federal
mandatory greenhouse gas emission reduction rules ultimately will be enacted, or
the specific requirements of any such rules.

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

Water: In March 2004, the EPA issued rules that govern generating plant
cooling water intake systems. The new rules require significant reduction in
fish killed by operating equipment. Some of our facilities will be required to
comply with the new rules by 2006. We are currently studying the rules to
determine the most cost-effective solutions for compliance.

For additional details on electric environmental matters, see Note 3,
Contingencies, "Consumers' Electric Utility Contingencies -- Electric
Environmental Matters."

COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act
and other developments will continue to result in increased competition in the
electric business. The Customer Choice Act allows all of our electric customers
to buy electric generation service from us or from an alternative electric
supplier. As of March 2005, alternative electric suppliers are providing 900 MW
of generation supply to ROA customers. This amount represents 12 percent of our
distribution load and an increase of 23 percent compared to March 2004. Based on
current trends, we predict total load loss by the end of 2005 to be in the range
of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load
loss will fall within that range.

In July 2004, as a result of legislative hearings, several bills were
introduced into the Michigan Senate that could change Michigan's Customer Choice
Act. The proposals include:

- requiring that all rate classes of regulated utilities be based on cost
of service,

- establishing a defined Stranded Cost calculation method,

- allowing customers who stay with or switch to alternative electric
suppliers after December 31, 2005 to return to utility services, and
requiring them to pay current market rates upon return,

- establishing reliability standards that all electric suppliers must
follow,

- requiring utilities and alternative electric suppliers to maintain a 15
percent power reserve margin,

- creating a service charge to fund the Low Income and Energy Efficiency
Fund,

- giving kindergarten through twelfth-grade schools a discount of 10
percent to 20 percent on electric rates, and

- authorizing a service charge payable by all customers for meeting Clean
Air Act requirements.

This legislation was not enacted before the end of the 2003-2004
legislative session. We anticipate that some or all of the bills may be
reintroduced in the 2005-2006 legislative session. We cannot predict the outcome
of these legislative proceedings.

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Implementation Costs: Applications for recovery of $7 million of
implementation costs for 2002 and $1 million for 2003 are pending MPSC approval.
In September 2004, the ALJ issued a Proposal for Decision recommending full
recovery of these costs.

We are also pursuing authorization at the FERC for the MISO to reimburse us
for approximately $8 million of Alliance RTO development costs. Included in this
amount is $5 million pending approval by the MPSC as part of our 2002
implementation costs application. The FERC has denied our request for
reimbursement and we are appealing the FERC ruling at the United States Court of
Appeals for the District of Columbia. Although we believe these implementation
costs are fully recoverable in accordance with the Customer Choice Act, we
cannot predict the amount, if any, the MPSC or the FERC will approve as
recoverable.

Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act
allows us to recover certain regulatory assets through deferred recovery of
annual capital expenditures in excess of depreciation levels and certain other
expenses incurred prior to and throughout the rate freeze and rate cap periods,
including the cost of money. In October 2004, we filed an application with the
MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets for
the period June 2000 through December 2005 consisting of:

- capital expenditures in excess of depreciation,

- Clean Air Act costs,

- other expenses related to changes in law or governmental action incurred
during the rate freeze and rate cap periods, and

- the associated cost of money through the period of collection.

Of the $628 million, $152 million relates to the cost of money. In March
2005, the MPSC Staff filed testimony recommending the MPSC approve recovery of
approximately $323 million. We cannot predict the amount, if any, the MPSC will
approve as recoverable.

Rate Caps: The Customer Choice Act imposes certain limitations on electric
rates that could result in our inability to collect our full cost of conducting
business from electric customers. Rate caps are effective through December 31,
2005 for residential customers. As a result, we may be unable to maintain our
profit margins in our electric utility business during the rate cap period. In
particular, if we need to purchase power supply from wholesale suppliers while
retail rates are capped, the rate restrictions may preclude full recovery of
purchased power and associated transmission costs.

Power Supply Costs: To reduce the risk of high electric prices during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasing electric capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. We are currently planning for a reserve margin of approximately 11
percent for summer 2005, or supply resources equal to 111 percent of projected
summer peak load. Of the 2005 supply resources target of 111 percent, we expect
to meet approximately 102 percent from our electric generating plants and
long-term power purchase contracts, and approximately 9 percent from short-term
contracts, options for physical deliveries, and other agreements. We have
purchased capacity and energy contracts partially covering the estimated reserve
margin requirements for 2005 through 2007. As a result, we have recognized an
asset of $12 million for unexpired capacity and energy contracts as of December
31, 2004.

PSCR: The PSCR process assures recovery of all reasonable and prudent power
supply costs actually incurred by us. In September 2004, we submitted our 2005
PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a
portion of our increased power supply costs from commercial and industrial
customers and, subject to the overall rate caps, from other customers. We
self-implemented the proposed 2005 PSCR charge in January 2005. The revenues
from the PSCR charges are subject to reconciliation at the end of the year after
actual costs have been reviewed for reasonableness and prudence. We cannot
predict the outcome of these PSCR proceedings.

Special Contracts: We entered into multi-year electric supply contracts
with certain industrial and commercial customers. The contracts provide
electricity at specially negotiated prices that are at a discount from

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tariff prices, but above our incremental cost of service. As of February 2005,
special contracts for approximately 630 MW of load are in place, most of which
are in effect through 2005. We cannot predict the amount of electric load from
these customers that will continue with our electric service after their
contracts expire.

Transmission Costs: In May 2002, we sold our electric transmission system
for $290 million to MTH. We are in arbitration with MTH regarding property tax
items used in establishing the selling price of our electric transmission
system. An unfavorable outcome could result in a reduction of sale proceeds
previously recognized by approximately $2 million to $3 million.

There are multiple proceedings and a proposed rulemaking pending before the
FERC regarding transmission pricing mechanisms and standard market design for
electric bulk power markets and transmission. The results of these proceedings
and proposed rulemaking could affect significantly:

- transmission cost trends,

- delivered power costs to us, and

- delivered power costs to our retail electric customers.

In November 2004, the FERC ruled on MISO and PJM RTO "through and out"
rates. Through and out rates are applied to transmission transactions when a
transmission customer purchases electricity that travels through multiple
transmission pricing zones. Effective December 1, 2004, regional through and out
rates for transactions between the PJM RTO and the MISO were eliminated by the
FERC. In that November 2004 order, the FERC conditionally accepted, for a period
beginning December 1, 2004 and ending January 31, 2008, a "license plate"
pricing structure. License plate pricing provides for access to the combined
regional transmission systems of the PJM RTO and the MISO at a single rate,
although the rate may vary based on where the customer's load is located.

The order also adopts a transitional charge from December 1, 2004 through
March 31, 2006, intended to mitigate abrupt cost shifts between transmission
owners and customers as a result of the pricing structure change. The manner in
which these transitional charges are calculated and implemented is currently the
subject of multiple disputes pending at the FERC. Based on the compliance
filings with the FERC made by the MISO and PJM RTO transmission owners, the new
transitional charges will not have a significant impact on our electric results
of operations. However, we cannot predict the outcome of the disputes concerning
these transitional charges pending at the FERC.

Transmission Market Developments: The MISO is scheduled to begin the
Midwest Energy Market on April 1, 2005. At that time, the MISO will implement a
day-ahead and real-time energy market and centralized dispatch for the MISO's
market participants. These changes are anticipated to ensure that load
requirements in the region are met reliably and efficiently, to better manage
congestion on the grid, and to produce consumer savings through the centralized
dispatch of generation throughout the region. The MISO is expected to provide
other functions, including long-term regional planning and market monitoring.

In addition, we are evaluating whether or not there may be impacts on
electric reliability associated with changes in the composition of transmission
markets. For example, Commonwealth Edison Company joined the PJM RTO in May 2004
and American Electric Power Service Corporation joined the PJM RTO in October
2004. These integrations may be creating different patterns of power flow within
the Midwest area and could affect adversely our ability to provide reliable
service to our customers. We are presently evaluating what financial impacts, if
any, these market developments are having on our operations.

August 14, 2003 Blackout: The NERC and the U.S. and Canadian Power System
Outage Task Force have released electric operations recommendations resulting
from their investigation into the August 14, 2003 blackout. Few of the
recommendations apply directly to us, since we are not a transmission owner.
However, the recommendations could result in increased transmission costs to us
and require upgrades to our distribution system. We cannot quantify the
financial impact of these recommendations at this time.

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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 Restructuring Matters," and
"Consumers' Electric Utility Rate Matters."

ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC
to increase our retail electric base rates. The electric rate case filing
requests an annual increase in revenues of approximately $320 million. The
primary reasons for the request are increased system maintenance and improvement
costs, Clean Air Act related expenditures, and employee pension costs. A final
order from the MPSC on our electric rate case is expected in late 2005. If
approved as requested, the rate increase would go into effect in January 2006
and would apply to all retail electric customers. We cannot predict the amount
or timing of the rate increase, if any, which the MPSC will approve.

BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of
Appeals upheld a lower court decision that requires Detroit Edison to obey a
municipal ordinance enacted by the City of Taylor, Michigan. The ordinance
requires Detroit Edison to bury a section of its overhead power lines at its own
expense. Detroit Edison has filed an appeal with the Michigan Supreme Court.
Unless overturned by the Michigan Supreme Court, the decision could encourage
other municipalities to adopt similar ordinances, as has occurred or is being
discussed in a few municipalities in Consumers' service territory. If incurred,
we would seek recovery of these costs from our customers, subject to MPSC
approval. This case has potentially broad ramifications for the electric utility
industry in Michigan; however, at this time, we cannot predict the outcome of
this matter.

OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES

NUCLEAR MATTERS:

Big Rock: Dismantlement of plant systems is essentially complete and
demolition of the remaining plant structures has begun. The restoration project
is on schedule to return approximately 530 acres of the site, including the area
formerly occupied by the nuclear plant, to a natural setting for unrestricted
use in mid-2006. An additional 30 acres, the area where seven transportable dry
casks loaded with spent nuclear fuel and an eighth cask loaded with high-level
radioactive waste material are stored, will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.

Palisades: In August 2004, the NRC completed its mid-cycle plant
performance assessment of Palisades. The assessment for Palisades covered the
first half of 2004. The NRC determined that Palisades was operated in a manner
that preserved public health and safety and fully met all cornerstone
objectives. As of December 2004, all inspection findings were classified as
having very low safety significance and all performance indicators show
performance at a level requiring no additional oversight. Based on the plant's
performance, only regularly scheduled inspections are planned through March
2006.

The amount of spent nuclear fuel at Palisades exceeds the plant's temporary
onsite storage pool capacity. We are using dry casks for temporary onsite
storage. As of December 31, 2004, we have loaded 22 dry casks with spent nuclear
fuel. For additional information on disposal of spent nuclear fuel, see Note 3,
Contingencies, "Other Consumers' Electric Utility Contingencies -- Nuclear
Matters."

In September 2004, we announced that we will seek a license renewal for the
Palisades plant. The plant's current license from the NRC expires in 2011. NMC,
which operates the facility, will apply for a 20-year license renewal for the
plant on behalf of Consumers. The Palisades renewal application is scheduled to
be filed by the end of the first quarter of 2005.

We have authorized the purchase of a replacement reactor vessel closure
head. The replacement head is being manufactured and scheduled to be installed
in 2007. Palisades, like many other nuclear plants, has experienced cracking in
reactor head nozzle penetrations. Repairs to two nozzles were made in 2004. The
replacement head nozzles will be manufactured from materials less susceptible to
cracking and should minimize inspection and repair costs after replacement.

Spent nuclear fuel complaint: In March 2003, the Michigan Environmental
Council, the Public Interest Research Group in Michigan, and the Michigan
Consumer Federation filed a complaint with the MPSC, which

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was served on us by the MPSC in April 2003. The complaint asks the MPSC to
initiate a generic investigation and contested case to review all facts and
issues concerning costs associated with spent nuclear fuel storage and disposal.
The complaint seeks a variety of relief with respect to Consumers, Detroit
Edison, Indiana & Michigan Electric Company, Wisconsin Electric Power Company,
and Wisconsin Public Service Corporation. The complaint states that amounts
collected from customers for spent nuclear fuel storage and disposal should be
placed in an independent trust. The complaint also asks the MPSC to take
additional actions. In May 2003, Consumers and other named utilities each filed
motions to dismiss the complaint. We are unable to predict the outcome of this
matter.

GAS UTILITY BUSINESS OUTLOOK

GROWTH: Over the next five years, we expect gas deliveries to grow at an
average rate of less than one percent per year. Actual gas deliveries in future
periods may be affected by:

- fluctuations in weather patterns,

- use by independent power producers,

- competition in sales and delivery,

- Michigan economic conditions,

- gas consumption per customer, and

- increases in gas commodity prices.

In February 2004, we filed an application with the MPSC for a Certificate
of Public Convenience and Necessity to construct a 25-mile gas transmission
pipeline in northern Oakland County. The project is necessary to meet estimated
peak load beginning in the winter of 2005 through 2006. In December 2004, the
MPSC approved a settlement agreement authorizing us to construct and operate the
pipeline. Construction is expected to begin late spring of 2005.

In October 2004, we filed an application with the MPSC for a Certificate of
Public Convenience and Necessity to construct a 10.8-mile gas transmission
pipeline in northwestern Wayne County. The project is necessary to meet the
projected capacity demands beginning in the winter of 2007. If we are unable to
construct the pipeline, we will need to pursue more costly alternatives or
curtail serving the system's load growth in that area.

GAS UTILITY BUSINESS UNCERTAINTIES

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

Regulatory

- inadequate regulatory response to applications for requested rate
increases,

- response to increases in gas costs, including adverse regulatory response
and reduced gas use by customers, and

- proposed distribution pipeline integrity rules and mandates.

Environmental

- potential environmental remediation costs at a number of sites, including
sites formerly housing manufactured gas plant facilities.

Other

- transmission pipeline integrity mandates, maintenance and remediation
costs, and

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- other pending litigation.

GAS TITLE TRACKING FEES AND SERVICES: On February 14, 2005, the FERC issued
its latest order involving Consumers' Gas Title Transfer Tracking Fees and
Services. In doing so, the FERC agreed with us that such orders only apply to a
title transfer tracking fee charged and collected in connection with the
Consumers' FERC blanket transportation service. Because of the newly stated
limits on what fees are subject to refund, we believe that if any such refunds
are ultimately required, they will not be material.

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 for prudency in an annual
reconciliation proceeding.

The following table summarizes our GCR reconciliation filings with the
MPSC. For additional details, see Note 3, Contingencies, "Consumers' Gas Utility
Rate Matters -- Gas Cost Recovery."

GAS COST RECOVERY RECONCILIATION

Net over-recovery amounts included in the table above include refunds that
we received from our suppliers that are required to be refunded to our
customers.

GCR year 2003-2004: In February 2005, the MPSC approved a settlement
agreement that resulted in a credit to our GCR customers for a $28 million
over-recovery, plus $3 million interest, using a roll-in refund methodology. The
roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan
year.

GCR plan for year 2004-2005: In December 2003, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan
approving a settlement. The settlement included a quarterly mechanism for
setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual
gas costs and revenues will be subject to an annual reconciliation proceeding.

GCR plan for year 2005-2006: In December 2004, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2005
through March 2006. Our request proposes using a GCR factor consisting of:

- a base GCR factor of $6.98 per mcf, plus

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

The GCR factor can be adjusted monthly, provided it remains at or below the
current ceiling price. The quarterly adjustment mechanism allows an increase in
the GCR ceiling price to reflect a portion of cost increases if the average
NYMEX price for a specified period is greater than that used in calculating the
base GCR factor. Actual gas costs and revenues will be subject to an annual
reconciliation proceeding.

2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a gas rate increase in the annual amount of $156 million. In December 2003,
the MPSC granted an interim rate increase in the amount of $19 million annually.
The MPSC also ordered an annual $34 million reduction in our annual depreciation
expense and related taxes.

CMS-35

On October 14, 2004, the MPSC issued its Opinion and Order on final rate
relief. In the order, the MPSC authorized us to place into effect surcharges
that would increase annual gas revenues by $58 million. Further, the MPSC
rescinded the $19 million annual interim rate increase. The final rate relief
was contingent upon our agreement to:

- achieve a common equity level of at least $2.3 billion by year-end 2005
and propose a plan to improve the common equity level thereafter until
our target capital structure is reached,

- make certain safety-related operation and maintenance, pension, retiree
health-care, employee health-care, and storage working capital
expenditures for which the surcharge is granted,

- refund surcharge revenues when our rate of return on common equity
exceeds its authorized 11.4 percent rate,

- prepare and file annual reports that address certain issues identified in
the order, and

- file a general rate case on or before the date that the surcharge expires
(which is two years after the surcharge goes into effect).

On October 15, 2004, we agreed to these commitments.

2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. On December 18,
2003, the MPSC ordered an annual $34 million reduction in our depreciation
expense and related taxes in an interim rate order issued in our 2003 gas rate
case.

In October and December 2004, the MPSC issued Opinions and Orders in our
gas depreciation case. The October 2004 order requires us to file an application
for new depreciation accrual rates for our natural gas utility plant on, or no
earlier than three months prior to, the date we file our next natural gas
general rate case. The MPSC also directed us to undertake a study to determine
why our removal costs are in excess of those of other regulated Michigan natural
gas utilities and file a report with the MPSC Staff on or before December 31,
2005.

In February 2005, we requested a delay in the filing date for the next
depreciation case until after the MPSC considers the removal cost study, and
after the MPSC issues an order in a pending case relating to asset retirement
obligation accounting.

GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. We expect to fund most of these costs through insurance
proceeds and through the MPSC approved rates charged to our customers. 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 remedial action costs.
For additional details, see Note 3, Contingencies, "Consumers' Gas Utility
Contingencies -- Gas Environmental Matters."

OTHER CONSUMERS' OUTLOOK

MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $10 million of interest. The Michigan Tax Tribunal
decision has been appealed to the Michigan Court of Appeals by the City of
Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court
of Appeals. The MCV Partnership also has a pending case with the Michigan Tax
Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the
outcome of these proceedings; therefore, the above refund (net of approximately
$16 million of deferred expenses) has not been recognized in 2004 earnings.

COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees
are represented by the Utility Workers of America Union. The Union represents
Consumers' operating, maintenance, and construction employees and our call
center employees. The collective bargaining agreement with the Union for our
operating, maintenance, and construction employees will expire on June 1, 2005
and negotiations for a new agreement is
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underway currently. The collective bargaining agreement with the Union for our
call center employees will expire on August 1, 2005.

ENTERPRISES OUTLOOK

INDEPENDENT POWER PRODUCTION: We plan to continue the restructuring of our
IPP business with the objective of narrowing the focus of our operations to
primarily North America, South America, and the Middle East/North Africa. We
will continue to sell designated assets and investments that are
under-performing or are not consistent with this focus. In February 2005, we
sold our interest in GVK for $20 million.

CMS ERM: CMS ERM has streamlined its portfolio in order to reduce business
risk and outstanding credit guarantees. Our future activities will be centered
on fuel procurement activities and merchant power marketing in such a way as to
optimize the earnings from our IPP generation assets.

CMS GAS TRANSMISSION: CMS Gas Transmission has completed its plan to sell
the majority of its international assets and businesses. Future operations will
be conducted mainly in Michigan and South America.

GasAtacama: On March 24, 2004, the Argentine Government authorized the
restriction of exports of natural gas to Chile, giving priority to domestic
demand in Argentina. This restriction could have a detrimental effect on
GasAtacama's earnings since GasAtacama's gas-fired electric generation plant is
located in Chile and uses Argentine gas for fuel. From April through December
2004, Bolivia agreed to export 4 million cubic meters of gas per day to
Argentina, which allowed Argentina to minimize its curtailments to Chile.

Argentina and Bolivia extended the term of that agreement through December
31, 2005. With the Bolivian gas supply, Argentina relaxed its export
restrictions to GasAtacama, currently allowing GasAtacama to receive
approximately 50 percent of its contracted gas quantities at its electric
generation plant. At this point in time, it is not possible to predict the
outcome of these events and their effect on the earnings of GasAtacama.

Other: In July 2003, CMS Gas Transmission completed the sale of CMS Field
Services to Cantera Natural Gas, Inc. for gross cash proceeds of approximately
$113 million, subject to post closing adjustments, and a $50 million face value
contingent note of Cantera Natural Gas, Inc., which is not included in our
consolidated financial statements. The contingent note is payable to CMS Energy
for up to $50 million, subject to the financial performance of the Fort Union
and Bighorn natural gas gathering systems from 2004 through 2008. The financial
performance is dependent primarily on the number of new wells connected,
transportation volumes, and revenue with certain EBITDA thresholds required to
be achieved in order for us to receive payments on the contingent note. It has
not been determined for 2004 results whether we will receive a payment on the
note in 2005.

UNCERTAINTIES: The results of operations and the financial position of our
diversified energy businesses may be affected by a number of trends or
uncertainties. Those that could have a material impact on our income, cash
flows, or balance sheet and credit improvement include:

- our ability to sell or to improve the performance of assets and
businesses in accordance with our business plan,

- changes in exchange rates or in local economic or political conditions,
particularly in Argentina, Venezuela, Brazil, and the Middle East,

- changes in foreign laws or in governmental or regulatory policies that
could reduce significantly the tariffs charged and revenues recognized by
certain foreign subsidiaries, or increase expenses,

- imposition of stamp taxes on South American contracts that could increase
project expenses substantially,

- impact of any future rate cases, FERC actions, or orders on regulated
businesses,

- impact of ratings downgrades on our liquidity, operating costs, and cost
of capital,

- impact of 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, and

CMS-37

- changes in available gas supplies or Argentine government regulations
that could restrict natural gas exports to our GasAtacama generating
plant.

OTHER OUTLOOK

LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an
investigation by the DOJ regarding round-trip trading transactions by CMS MST.
Additionally, we are named as a party in various litigation matters including,
but not limited to, a shareholder derivative lawsuit, a securities class action
lawsuit, a class action lawsuit alleging ERISA violations, and several lawsuits
regarding alleged false natural gas price reporting and price manipulation. For
additional details regarding these investigations and litigation, see Note 3,
Contingencies.

NEW ACCOUNTING STANDARDS

For a discussion of new pronouncements, see Note 16, Implementation of New
Accounting Standards.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to
expense the grant date fair value of employee stock options and similar awards.
The Statement also clarifies and expands SFAS No. 123's guidance in several
areas, including measuring fair value, classifying an award as equity or as a
liability, and attributing compensation cost to reporting periods.

In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to
require that excess tax benefits related to the excess of the tax deductible
amount over the compensation cost recognized be classified as a financing cash
inflow rather than as a reduction of taxes paid in operating cash flows.

This Statement is effective for us as of the beginning of the third quarter
of 2005. We adopted the fair value method of accounting for share-based awards
effective December 2002, and therefore, expect this Statement to have an
insignificant impact on our results of operations when it becomes effective.

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CMS ENERGY CORPORATION
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 such term is defined in
Rule 13a-15(f) under the Exchange Act. 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
based on 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 control reporting was effective as of December 31, 2004.

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.

CMS Energy's management's assessment of the effectiveness of CMS Energy's
internal control over financial reporting as of December 31, 2004 has been
audited by Ernst & Young LLP, an independent registered public accounting firm,
who audited the consolidated financial statements of CMS Energy included in this
Form 10-K. Ernst & Young LLP's attestation report on CMS Energy's management's
assessment of internal control over financial reporting follows this report.

CMS-39

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Shareholders of CMS Energy Corporation

We have audited management's assessment, included in MANAGEMENT'S REPORT ON
INTERNAL CONTROL OVER FINANCIAL REPORTING, that CMS Energy Corporation (a
Michigan Corporation) and subsidiaries maintained effective internal control
over financial reporting as of December 31, 2004, based on criteria established
in Internal Control -- Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (the COSO criteria). CMS
Energy Corporation's management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express an opinion on management's assessment and an opinion on the
effectiveness of the company's internal control over financial reporting based
on our audit. We did not examine the effectiveness of internal control over
financial reporting of Midland Cogeneration Venture Limited Partnership, a 49%
owned variable interest entity which has been consolidated pursuant to Revised
Financial Accounting Standards Board Interpretation No. 46, "Consolidation of
Variable Interest Entities", whose financial statements reflect total assets and
revenues constituting 12% and 12%, respectively, of the related consolidated
financial statement amounts as of and for the year ended December 31, 2004. The
effectiveness of Midland Cogeneration Venture Limited Partnership's internal
control over financial reporting was audited by other auditors whose report has
been furnished to us, and our opinion, insofar as it relates to the
effectiveness of Midland Cogeneration Venture Limited Partnership's internal
control over financial reporting, is based solely on the report of the other
auditors.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit and the report of the other auditors
provide a reasonable basis for our opinion.

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 (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
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 (3) 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.

In our opinion, based on our audit and the report of the other auditors,
management's assessment that CMS Energy Corporation maintained effective
internal control over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on the COSO criteria. Also, in our
opinion, based on our audit and the report of the other auditors, CMS Energy
Corporation maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of CMS Energy Corporation and subsidiaries as of December 31, 2004 and
2003, and the related consolidated statements of income (loss), common
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2004 and our report dated March 7, 2005 expressed an
unqualified opinion thereon.

/s/ Ernst & Young LLP

Detroit, Michigan
March 7, 2005

CMS-40

MCV MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

MCV's management is responsible for establishing and maintaining an
adequate system of internal control over financial reporting of MCV. This system
is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the
United States of America.

MCV'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 MCV; (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
MCV are being made only in accordance with authorizations of management and the
Management Committee of MCV; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of MCV's assets that could have a material effect on the financial statements.

Because of its inherent limitations, a system of internal control over
financial reporting can provide only reasonable assurance and may not prevent or
detect misstatements. Further, because of changes in conditions, effectiveness
of internal controls over financial reporting may vary over time. Our system
contains self-monitoring mechanisms, and actions are taken to correct
deficiencies as they are identified.

MCV management conducted an evaluation of the effectiveness of the system
of internal control over financial reporting based on the framework in "Internal
Control -- Integrated Framework" issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation, management
concluded that MCV's system of internal control over financial reporting was
effective as of December 31, 2004. MCV management's assessment of the
effectiveness of MCV's internal control over financial reporting has been
audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which is included herein.

CMS-41

CMS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF INCOME (LOSS)

CMS-42

The accompanying notes are an integral part of these statements.

CMS-43

CMS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

CMS-44

The accompanying notes are an integral part of these statements.

CMS-45

CMS ENERGY CORPORATION

CONSOLIDATED BALANCE SHEETS

CMS-46

CMS ENERGY CORPORATION

The accompanying notes are an integral part of these statements.

CMS-47

CMS ENERGY CORPORATION

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

CMS-48

The accompanying notes are an integral part of these statements.

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CMS-50

CMS ENERGY CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES

CORPORATE STRUCTURE: CMS Energy is an integrated energy company with a
business strategy focused primarily in Michigan. We are the parent holding
company of Consumers and Enterprises. Consumers is a combination electric and
gas utility company serving Michigan's Lower Peninsula. Enterprises, through
various subsidiaries and equity investments, is engaged in domestic and
international diversified energy businesses, including independent power
production and natural gas transmission, storage and processing. 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
the accounts of CMS Energy, Consumers, Enterprises, and all other entities in
which we have a controlling financial interest or are the primary beneficiary,
in accordance with Revised FASB Interpretation No. 46. The primary beneficiary
of a variable interest entity is the party that absorbs or receives a majority
of the entity's expected losses or expected residual returns or both as a result
of holding variable interests, which are ownership, contractual, or other
economic interests. In accordance with Revised FASB Interpretation No. 46, in
2003, we consolidated three Michigan electric generating plants and in 2004, we
consolidated the MCV Partnership and the FMLP. For additional details, see Note
16, Implementation of New Accounting Standards. 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. Intercompany transactions and
balances have been eliminated.

USE OF ESTIMATES: We prepare our consolidated financial statements in
conformity with U.S. generally accepted accounting principles. We are required
to make estimates using assumptions that may affect the reported amounts and
disclosures. Actual results could differ from those estimates.

We are required to record estimated liabilities in the consolidated
financial statements when it is probable that a loss will be incurred in the
future as a result of a current event, and when an amount can be reasonably
estimated. We have used this accounting principle to record estimated
liabilities as discussed in Note 3, Contingencies.

REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of
electricity and natural gas, and the transportation, processing, and storage of
natural gas when services are provided. Sales taxes are recorded as liabilities
and are not included in revenues. Revenues on sales of marketed electricity,
natural gas, and other energy products are recognized at delivery.
Mark-to-market changes in the fair values of energy trading contracts that
qualify as derivatives are recognized as revenues in the periods in which the
changes occur.

ACCRETION EXPENSE: CMS ERM has entered into prepaid sales arrangements to
provide natural gas to various entities over periods of up to 12 years at
predetermined price levels. CMS ERM has established a liability for these
outstanding obligations equal to the discounted present value of the contracts,
and has hedged its exposures under these arrangements. The amounts recorded as
liabilities on our Consolidated Balance Sheets are guaranteed by Enterprises. As
CMS ERM fulfills its obligations under the contracts, it recognizes revenues
upon the delivery of natural gas, records a reduction to the outstanding
obligation, and recognizes accretion expense.

CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred, and our non-regulated businesses are prohibited
from imputing interest costs on any equity funds. Our regulated businesses are
permitted to capitalize an allowance for funds used during construction on
regulated construction projects and to include such amounts in plant in service.

CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an
original maturity of three months or less are considered cash equivalents.

CMS-51

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

At December 31, 2004, our restricted cash on hand was $56 million.
Restricted cash dedicated for repayment of Securitization bonds is classified as
a current asset as the payments on the related Securitization bonds occur within
one year.

COST METHOD INVESTMENTS: At December 31, 2004, our cost method investments
totaled $22 million, substantially all of which were evaluated for impairment in
2004. We periodically reevaluate the fair value of our cost method investments
if there are specific events or changes in circumstances that may have a
significant adverse effect on the fair value of our investments.

EARNINGS PER SHARE: Basic and diluted earnings per share are based on 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 earnings per share, includes the effects of dilutive stock
options, warrants and convertible securities. The effect on number of shares of
such potential common stock is computed using the treasury stock method or the
if-converted method, as applicable. For earnings per share computation, see Note
5, Earnings Per Share.

FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities classified as
available-for-sale are reported at fair value determined from quoted market
prices. Debt and equity securities classified as held-to-maturity are reported
at cost. Unrealized gains or losses resulting from changes in fair value of
certain available-for-sale debt and equity securities are reported, net of tax,
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless the related changes in fair value are
determined to be other than temporary.

Unrealized gains or losses on our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized
gains or losses would not affect our earnings or cash flows.

For additional details regarding financial instruments, see Note 6,
Financial and Derivative Instruments.

FOREIGN CURRENCY TRANSLATION: 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. The gains or losses that result from this process are shown
in the stockholders' equity section on our Consolidated Balance Sheets. For
subsidiaries operating in highly inflationary economies, the U.S. dollar is
considered to be the functional currency, and transaction gains and losses are
included in determining net income. Gains and losses that arise from exchange
rate fluctuations on transactions denominated in a currency other than the
functional currency, except those that are hedged, are included in determining
net income.

GAS INVENTORY: We use the weighted average cost method for valuing working
gas and recoverable cushion gas in underground storage facilities.

GENERATING PLANT FUEL STOCK INVENTORY: We use the weighted average cost
method for valuing coal inventory and classify these costs as generating plant
fuel stock on our Consolidated Balance Sheets. The MCV Partnership's natural gas
inventory is also included in this category, stated at the lower of cost or
market and valued using the last-in, first-out ("LIFO") method.

GOODWILL: Goodwill represents the excess of the purchase price over the
fair value of the net assets of acquired companies. Goodwill is not amortized,
but is tested annually for impairment. For additional information, see Note 13,
Goodwill.

IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate potential
impairments of our investments in long-lived assets, other than goodwill, based
on various analyses, including the projection of undiscounted cash flows,
whenever events or changes in circumstances indicate that the carrying amount of
the assets may not be recoverable. If the carrying amount of the investment or
asset exceeds its estimated

CMS-52

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

undiscounted future cash flows, an impairment loss is recognized and the
investment or asset is written down to its estimated fair value.

MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property
replacements to maintenance expense. We also 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 straight-line rates approved by the MPSC. The composite depreciation rates
for our properties are:

NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on
the quantity of heat produced for electric generation. For nuclear fuel used
after April 6, 1983, we charge certain disposal costs to nuclear fuel expense,
recover these costs through electric rates, and remit them to the DOE quarterly.
We elected to defer payment for disposal of spent nuclear fuel burned before
April 7, 1983. As of December 31, 2004, we have recorded a liability to the DOE
of $141 million, including interest, which is payable upon the first delivery of
spent nuclear fuel to the DOE. The amount of this liability, excluding a portion
of interest, was recovered through electric rates. For additional details on
disposal of spent nuclear fuel, see Note 3, Contingencies, "Other Consumers'
Electric Utility Contingencies -- Nuclear Matters."

OTHER INCOME AND OTHER EXPENSE: The following tables show the components of
Other income and Other expense:

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, the original cost is
charged to accumulated depreciation. The cost of removal, less salvage, is
recorded as a regulatory liability. For additional details, see Note 8, Asset
Retirement Obligations. An allowance for funds used during

CMS-53

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

construction is capitalized on regulated construction projects. With respect to
the retirement or disposal of non-regulated assets, the resulting gains or
losses are recognized in income.

Property, plant, and equipment at December 31, 2004 and 2003, was as
follows:

- -------------------------
(a) Capital leases presented in this table are gross amounts. Amortization of
capital leases was $49 million in 2004 and $38 million in 2003.

(b) Includes unrecoverable base natural gas in underground storage of $26
million at December 31, 2004 and $23 million at December 31, 2003, which is
not subject to depreciation.

(c) Accumulated depreciation, depletion, and amortization is made up of $5.665
billion from our public utility plant assets and $450 million from other
plant assets as of December 31, 2004 and $4.417 billion from public utility
plant assets and $425 million from other plant assets as of December 31,
2003.

(d) Included in net property, plant and equipment are intangible assets related
primarily to software development costs, consents, leasehold improvements,
and rights of way. The estimated amortization life for software development
costs is seven years, leasehold improvements is over the life of the lease
and other intangible

CMS-54

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

amortization lives range from 50 to 105 years. Intangible assets at December
31, 2004 and 2003 were as follows:

Pretax amortization expense related to these intangible assets was $21
million for the year ended December 31, 2004, $21 million for the year ended
December 31, 2003, and $20 million for the year ended December 31, 2002.
Intangible assets amortization is forecasted to range from $10 million to
$21 million per year over the next five years.

(e) The following table illustrates the depreciable life for electric and gas
structures and improvements.

RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income (loss) for the years presented.

CMS-55

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

RELATED-PARTY TRANSACTIONS: We received income from related parties as
follows:

We recorded expense from related parties as follows:

- -------------------------
(a) At December 31, 2003, we consolidated the T.E.S. Filer City Station Limited
Partnership, Grayling Generating Station Limited Partnership, and Genessee
Power Station Limited Partnership into our consolidated financial
statements in accordance with Revised FASB Interpretation No. 46. For
additional details, see Note 16, Implementation of New Accounting
Standards.

(b) In 2004, we consolidated the MCV Partnership and the FMLP into our
consolidated financial statements in accordance with Revised FASB
Interpretation No. 46. For additional details, see Note 16, Implementation
of New Accounting Standards.

(c) We issued Trust Preferred Securities through several CMS Energy and
Consumers affiliated companies. As of December 31, 2003, we deconsolidated
the trusts that hold the mandatorily redeemable Trust Preferred Securities.
As a result of the deconsolidation, we now record on our Consolidated
Statements of Income (Loss), Interest on Long-term debt -- related parties
to the trusts holding the Trust Preferred Securities. For additional
information on our affiliated Trust Preferred Securities companies, see
Note 16, Implementation of New Accounting Standards.

TRADE RECEIVABLES: We record our accounts receivable at fair value.
Accounts deemed uncollectible are charged to operating expense.

UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums,
discounts, and expenses incurred in connection with the issuance of long-term
debt and amortize those costs ratably over the terms of the debt issues. Any
refinancing costs are charged to expenses 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 ratably over the
terms of the newly issued debt.

UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.

We reflect the following regulatory assets and liabilities, which include
both current and non-current amounts, on our Consolidated Balance Sheets. We
expect to recover these costs through rates over periods of up

CMS-56

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

to 14 years. We recognized an OPEB transition obligation in accordance with SFAS
No. 106 and established a regulatory asset for the amount that we expect to
recover in rates over the next eight years.

DISCONTINUED OPERATIONS

We have discontinued the following operations:

- -------------------------
(a) In August 2004, we sold our Parmelia business and our interest in
Goldfields, which did not meet the criteria for discontinued operations, to
APT for A$204 million (approximately $147 million in U.S. dollars). The $10
million ($6 million after-tax) gain on the sale of Parmelia includes a $3
million ($2 million after-tax) foreign currency translation loss.

CMS-58

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following amounts are reflected in the Consolidated Statements of
Income (Loss), in the Gain (Loss) From Discontinued Operations line:

The gain (loss) from discontinued operations includes a reduction in asset
values, a provision for anticipated closing costs, and a portion of CMS Energy's
interest expense. Interest expense of less than $1 million for 2004, $22 million
for 2003, and $71 million for 2002 has been allocated based on a ratio of the
expected proceeds for the asset to be sold divided by CMS Energy's total
capitalization of each discontinued operation multiplied by CMS Energy's
interest expense.

OTHER ASSET SALES

Our other asset sales include the following assets. The impacts of these
sales are included in Gain (loss) on asset sales, net in our Consolidated
Statements of Income (Loss).

For the year ended December 31, 2004, we sold the following assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:

- -------------------------
(a) In April 2004, we and our partners sold the 2,000 MW Loy Yang power plant
and adjacent coal mine in Victoria, Australia for about A$3.5 billion ($2.6
billion in U.S. dollars), including A$145 million for the project equity.
Our share of the proceeds, net of transaction costs and closing
adjustments, was $44 million. In anticipation of the sale, we recorded an
impairment in the first quarter, as discussed in "Asset Impairments" within
this Note.

(b) In May 2004, we sold our interest in the American Gas Index fund for $7
million.

(c) In August 2004, we sold our interest in Goldfields and our Parmelia
business, a discontinued operation, to APT for A$204 million (approximately
$147 million in U.S. dollars). The $45 million ($29 million after-

CMS-59

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

tax) gain on the sale of Goldfields includes a $9 million ($6 million
after-tax) foreign currency translation gain.

(d) In December 2004, we sold land in Moapa, Nevada for $3 million.

For the year ended December 31, 2003, we sold the following assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:

For the year ended December 31, 2002, we sold the following assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:

ASSET IMPAIRMENTS

We record an asset impairment when we determine that the expected future
cash flows from an asset would be insufficient to provide for recovery of the
asset's carrying value. An 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. The
impairment loss recognized is the amount by which the carrying amount exceeds
the fair value. We estimate the fair market value of the asset utilizing the
best information available. This information includes quoted market prices,
market prices of similar assets, and discounted future cash flow analyses. The
assets written down include both domestic and foreign electric power plants, gas
processing facilities, and certain equity method and other investments. In
addition, we have written off the carrying value of projects under development
that will no longer be pursued.

CMS-60

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The table below summarizes our asset impairments:

- -------------------------
(a) In the first quarter of 2004, an impairment charge was recorded to
recognize the reduction in fair value as a result of the sale of Loy Yang,
completed in April 2004, which included a cumulative net foreign currency
translation loss of approximately $110 million.

(b) In September 2003, we wrote down our investment in CMS Electric and Gas'
Venezuelan electric distribution utility to reflect fair value. The
impairment was based on estimates of the utility's future cash flows,
incorporating certain assumptions about Venezuela's regulatory, political,
and economic environment.

(c) In December 2004, we recorded impairment charges to adjust our carrying
value to fair market value as a result of the planned sales of our
investments in GVK and SLAP. We closed on the sale of GVK in February 2005.
We expect the sale of SLAP to close in the first quarter of 2005.

(d) DIG's reduced valuation was primarily a reflection of the unfavorable terms
of its power purchase agreement.

(e) In 2003, we determined that the fair values of certain equity investments
at CMS Generation were lower than their carrying amount, and that these
declines in value were other than temporary. Therefore, in accordance with
APB No. 18, we recognized an impairment charge of $16 million ($11 million,
net of tax).

CMS-61

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

RESTRUCTURING AND OTHER COSTS

In June 2002, we announced a series of initiatives to reduce our annual
operating costs.

The following table shows the amount charged to expense for restructuring
costs, the payments made, and the unpaid balance of accrued costs at December
31, 2002, 2003, and 2004:

3: CONTINGENCIES

SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading
transactions by CMS MST, CMS Energy's Board of Directors established a Special
Committee to investigate matters surrounding the transactions and retained
outside counsel to assist in the investigation. The Special Committee completed
its investigation and reported its findings to the Board of Directors in October
2002. The Special Committee concluded, based on an extensive investigation, that
the round-trip trades were undertaken to raise CMS MST's profile as an energy
marketer with the goal of enhancing its ability to promote its services to new
customers. The Special Committee found no effort to manipulate the price of CMS
Energy Common Stock or affect energy prices. The Special Committee also made
recommendations designed to prevent any recurrence of this practice. Previously,
CMS Energy terminated its speculative trading business and revised its risk
management policy. The Board of Directors adopted, and CMS Energy implemented,
the recommendations of the Special Committee.

CMS Energy is cooperating with an investigation by the DOJ concerning
round-trip trading. 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.

SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. The complaints
were filed as purported class actions in the United States District Court for
the Eastern District of Michigan, by shareholders who allege that they purchased
CMS Energy's securities during a purported class period. These cases were later
consolidated by the court. The plaintiffs generally seek 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. CMS
Energy, Consumers, and the individual defendants filed motions to dismiss on
June 21, 2004. The judge issued an opinion and order dated January 7, 2005,
granting the motion to dismiss for Consumers and three of the individual
defendants, but denying the motions to dismiss for CMS Energy and the 13
remaining individual defendants.

CMS-62

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

CMS Energy and the individual defendants will defend themselves vigorously but
cannot predict the outcome of this litigation.

DEMAND FOR ACTION AGAINST OFFICERS AND DIRECTORS: In May 2002, the Board of
Directors of CMS Energy received a demand, on behalf of a shareholder of CMS
Energy Common Stock, that it commence civil actions (i) to remedy alleged
breaches of fiduciary duties by certain CMS Energy officers and directors in
connection with round-trip trading by CMS MST, and (ii) to recover damages
sustained by CMS Energy as a result of alleged insider trades alleged to have
been made by certain current and former officers of CMS Energy and its
subsidiaries. In December 2002, two new directors were appointed to the Board.
The Board formed a special litigation committee in January 2003 to determine
whether it is in CMS Energy's best interest to bring the action demanded by the
shareholder. The disinterested members of the Board appointed the two new
directors to serve on the special litigation committee.

In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. CMS Energy cannot predict the outcome of this matter.

ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS
MST, and certain named and unnamed officers and directors, in two lawsuits
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings and Incentive Plan (the "Plan"). The two cases
were filed in July 2002 in United States District Court for the Eastern District
of Michigan and were later consolidated by the court. Plaintiffs allege breaches
of fiduciary duties under ERISA and seek restitution on behalf of the Plan with
respect to a decline in value of the shares of CMS Energy Common Stock held in
the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge
issued an opinion and order dated December 27, 2004, conditionally granting
plaintiffs' motion for class certification. A trial date has not been set, but
is expected to be no earlier than late in 2005. CMS Energy and Consumers will
defend themselves vigorously but cannot predict the outcome of this litigation.

GAS INDEX PRICE REPORTING INVESTIGATION: 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 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 alleges the two engaged in reporting false natural
gas trade information, and the action seeks to enjoin such acts, compel
compliance with the Commodities Exchange Act, and impose monetary penalties.

BAY HARBOR: Certain subsidiaries of CMS Energy participated in the
development of Bay Harbor, a residential/commercial real estate project on the
site of a discontinued cement and quarry operation near Petoskey, Michigan. As
part of the development, which went forward under an agreement with the MDEQ, a
golf course was constructed over several abandoned cement kiln dust piles (CKD
piles), leftover from the former cement plant operation. Another former CKD area
has been converted into a park. Part of the agreement with the MDEQ required the
construction of a water collection system to recover seep water from one of the
CKD piles. In 2002, CMS Energy sold its interests in Bay Harbor, but retained
its obligations under previous environmental indemnifications entered into at
the inception of the project.

From January to September 2004, the seep collection system was down for
maintenance and/or awaiting permission to restart from the City of Petoskey. In
September 2004, the MDEQ issued a notice of noncompliance (NON), after finding
high pH-seep water in Lake Michigan adjacent to the project. The MDEQ also found
higher than acceptable levels of heavy metals, including mercury, in the seep
water.

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Coincident with the MDEQ inspections, the EPA also assigned an inspector to
the site. In November 2004, the EPA issued a Notice of Potential Liability under
the Comprehensive Environmental Response, Compensation, and Liability Act, and
initiated discussions with the MDEQ, CMS Energy and other parties, toward
arriving at a suitable administrative consent order to address problems at Bay
Harbor.

In February 2005, CMS Energy signed an Administrative Order on Consent
(AOC) with the EPA and the EPA has executed the AOC. Under the AOC, CMS Energy
is generally obligated, among other things, to: (i) engage in measures to
restrict access to seep areas, install methods to interrupt the flow of seep
water to Lake Michigan, and take other measures as may be required by the EPA
under an approved plan; (ii) investigate and study the extent of hazardous
substances at the site, evaluate alternatives to address a long-term remedy, and
issue a report of the investigation and study; and (iii) within 120 days after
EPA approval of the investigation report, enter into an enforceable agreement
with the MDEQ to address a long-term remedy under certain criteria set forth in
the AOC.

Several parties have issued demand letters to CMS Energy claiming breach of
the indemnification provisions, making requests for payment of their expenses
related to the NON, and/or claiming damages to property or personal injury with
regard to the matter. CMS Energy responded to the indemnification claims by
stating that it had not breached its indemnity obligations, it will comply with
the indemnities, it has restarted the seep water collection facility and it has
responded to the NON. CMS Energy will defend vigorously any property damage and
personal injury claims, and has reserved all rights and defenses.

Based on preliminary studies, CMS Energy has identified several remediation
options. The estimated potential capital and near-term expenditures for these
options range from $25 million to $40 million, with continuing yearly operating
and maintenance expenses ranging from $0.8 million to $1.6 million. Final
remediation and resulting claims against third parties for reimbursement of
remediation costs could increase or decrease these amounts. CMS Energy has
recorded a liability for its obligations associated with this matter in the
amount of $45 million, with a resultant charge to its income statement of $29
million, net of deferred income taxes, in the fourth quarter of 2004, reflecting
CMS Energy's current best estimate of both the capital and near-term costs as
well as the present value of continuing future operating costs.

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 ultimate cost or outcome of this matter.

CONSUMERS' ELECTRIC UTILITY CONTINGENCIES

ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental
laws and regulations. Costs to operate our facilities in compliance with these
laws and regulations generally have been recovered in customer rates.

Clean Air: The EPA and the state regulations require us to make significant
capital expenditures estimated to be $802 million. As of December 31, 2004, we
have incurred $525 million in capital expenditures to comply with the EPA
regulations and anticipate that the remaining $277 million of capital
expenditures will be made between 2005 and 2011.

The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.

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In addition to modifying the coal-fired electric plants, we expect to
utilize nitrogen oxide emissions allowances for years 2005 through 2009, most of
which have been purchased. The cost of the allowances is estimated to average $8
million per year for 2005-2006. The need for allowances will decrease after year
2006 with the installation of emissions control technology.

Cleanup and Solid Waste: Under the Michigan Natural Resources and
Environmental Protection Act, we expect that we will ultimately incur
investigation and remedial action 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 several contaminated sites
administered under Superfund. Superfund liability is joint and several, meaning
that many other creditworthy parties with substantial assets are potentially
responsible with respect to the individual sites. Based on past experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $9 million. As of December 31, 2004, we have
recorded a liability for the minimum amount of our estimated Superfund
liability.

In October 1998, during routine maintenance activities, we identified PCB
as a component in certain paint, grout, and sealant materials at the Ludington
Pumped Storage facility. We removed and replaced part of the PCB material. We
have proposed a plan to deal with the remaining materials and are awaiting a
response from the EPA.

LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges that we incorrectly calculated the energy charge payments made pursuant
to power purchase agreements with qualifying facilities. In February 2004, the
Ingham County Circuit Court 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 eight
plaintiff qualifying facilities have appealed the dismissal of the circuit court
case to the Michigan Court of Appeals. We cannot predict the outcome of this
appeal.

CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS

ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates,
terms, and conditions under which retail customers are permitted to choose an
electric supplier. These revised tariffs allow ROA customers, upon as little as
30 days notice to us, to return to our generation service at current tariff
rates. If any class of customers' (residential, commercial, or industrial) ROA
load reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods. We cannot predict the total amount of electric supply load that may be
lost to alternative electric suppliers. As of March 2005, alternative electric
suppliers are providing 900 MW of generation supply to ROA customers. This
amount represents 12 percent of our distribution load and an increase of 23
percent compared to March 2004.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings.

The following chart summarizes our electric restructuring filings with the
MPSC:

- -------------------------

(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes recovery of Clean Air Act costs
through the Section 10d(4) Regulatory Asset case.

(b) Amount includes the cost of money through the year prior to the year filed.

Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act
allows us to recover certain regulatory assets through deferred recovery of
annual capital expenditures in excess of depreciation levels and certain other
expenses incurred prior to and throughout the rate freeze and rate cap periods,
including the cost of money. The section also allows deferred recovery of
expenses incurred during the rate freeze and rate cap periods that result from
changes in taxes, laws, or other state or federal governmental actions. In
October 2004, we filed an application with the MPSC seeking recovery of $628
million of Section 10d(4) Regulatory Assets for the period June 2000 through
December 2005 consisting of:

- capital expenditures in excess of depreciation,

- Clean Air Act costs,

- other expenses related to changes in law or governmental action incurred
during the rate freeze and rate cap periods, and

- the associated cost of money through the period of collection.

Of the $628 million, $152 million relates to the cost of money.

As allowed by the Customer Choice Act, in January 2004, we began accruing
and deferring for recovery the 2004 portion of our Section 10d(4) Regulatory
Assets. In November 2004, the MPSC issued an order in Detroit Edison's general
electric rate case which concluded that Detroit Edison's return of and on Clean
Air Act costs incurred from June 2000 through December 2003 are recoverable
under Section 10d(4). Based on the precedent set by this order, we recorded an
additional regulatory asset in November 2004 for our return of and on Clean Air
Act expenditures incurred from 2000 through 2003. Unless we receive an order
from the MPSC to the contrary, we will continue to record additional accruals.
However, certain aspects of Detroit Edison's electric rate case are different
from our Section 10d(4) Regulatory Asset filing. In March 2005, the MPSC Staff
filed testimony
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

recommending the MPSC approve recovery of approximately $323 million. We cannot
predict the amount, if any, the MPSC will approve as recoverable. At December
31, 2004, total Section 10d(4) Regulatory Assets totaled $141 million.

TRANSMISSION SALE: In May 2002, we sold our electric transmission system to
MTH, a non-affiliated limited partnership whose general partner is a subsidiary
of Trans-Elect, Inc. We are in arbitration with MTH regarding property tax items
used in establishing the selling price of our electric transmission system. An
unfavorable outcome could result in a reduction of sale proceeds previously
recognized of approximately $2 million to $3 million.

CONSUMERS' ELECTRIC UTILITY RATE MATTERS

ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC
to increase our retail electric base rates. The electric rate case filing
requests an annual increase in revenues of approximately $320 million. The
primary reasons for the request are increased system maintenance and improvement
costs, Clean Air Act related expenditures, and employee pension costs. A final
order from the MPSC on our electric rate case is expected in late 2005. If
approved as requested, the rate increase would go into effect in January 2006
and would apply to all retail electric customers. We cannot predict the amount
or timing of the rate increase, if any, which the MPSC will approve.

POWER SUPPLY COSTS: To reduce the risk of high electric prices during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasing electric capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. We have purchased capacity and energy contracts partially covering the
estimated reserve margin requirements for 2005 through 2007. As a result, we
have recognized an asset of $12 million for unexpired capacity and energy
contracts as of December 31, 2004. The total premium costs of electric capacity
and energy contracts for 2004 were approximately $12 million.

PSCR: The PSCR process assures recovery of all reasonable and prudent power
supply costs actually incurred by us. In September 2004, we submitted our 2005
PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a
portion of our increased power supply costs from commercial and industrial
customers and, subject to the overall rate caps, from other customers. We
self-implemented the proposed 2005 PSCR charge in January 2005. We estimate the
increased recovery of power supply costs from commercial and industrial
customers to be approximately $49 million in 2005. The revenues from the PSCR
charges are subject to reconciliation at the end of the year after actual costs
have been reviewed for reasonableness and prudence. We cannot predict the
outcome of these PSCR proceedings.

OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES

THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and
operates the MCV Facility, contracted to sell electricity to Consumers for a
35-year period beginning in 1990 and to supply electricity and steam to Dow. We
hold a 49 percent partnership interest in the MCV Partnership, and a 35 percent
lessor interest in the MCV Facility.

In 2004, we consolidated the MCV Partnership and the FMLP into our
consolidated financial statements in accordance with Revised FASB Interpretation
No. 46. For additional details, see Note 16, Implementation of New Accounting
Standards. Our consolidated retained earnings include undistributed earnings
from the MCV Partnership of $237 million at December 31, 2004 and $245 million
at December 31, 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The cost that we incur under the MCV Partnership PPA exceeds the recovery
amount allowed by the MPSC. We expense all cash underrecoveries directly to
income. We estimate cash underrecoveries of capacity and fixed energy payments
as follows:

After September 15, 2007, we expect to claim relief under the regulatory
out provision in the PPA, limiting our capacity and fixed energy payments to the
MCV Partnership to the amount collected from our customers. The MCV Partnership
has indicated that it may take issue with our exercise of the regulatory out
clause after September 2007. We believe that the clause is valid and fully
effective, but cannot assure that it will prevail in the event of a dispute. The
MPSC's future actions on the capacity and fixed energy payments recoverable from
customers subsequent to September 15, 2007 may affect negatively the earnings of
the MCV Partnership and the value of our investment in the MCV Partnership.

Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned at our coal plants and our operation and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been impacted negatively. Even with the approved RCP, if gas prices continue at
present levels or increase, the economics of operating the MCV Facility may be
adverse enough to require us to recognize an impairment.

In January 2005, the MPSC issued an order approving the RCP, with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas by an
estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced
natural gas consumed by the MCV Facility will benefit our ownership interest in
the MCV Partnership.

The substantial MCV Facility fuel cost savings will be used first to offset
fully the cost of replacement power. Second, $5 million annually will be used to
fund a renewable energy program. Remaining savings will be split between the MCV
Partnership and Consumers. Consumers' direct savings will be shared 50 percent
with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct
savings from the RCP, after a portion is allocated to customers, will be used to
offset our capacity and fixed energy underrecoveries expense. Since the MPSC has
excluded these underrecoveries from the rate making process, we anticipate that
our savings from the RCP will not affect our return on equity used in our base
rate filings.

In January 2005, Consumers and the MCV Partnership's general partners
accepted the terms of the order and implemented the RCP. The underlying
agreement for the RCP between Consumers and the MCV Partnership extends through
the term of the PPA. However, either party may terminate that agreement under
certain conditions. In February 2005, a group of intervenors in the RCP case
filed an application for rehearing of the MPSC order. The Attorney General also
filed a claim of appeal with the Michigan Court of Appeals. We cannot predict
the outcome of these appeals.

MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $10 million of interest. The Michigan Tax Tribunal
decision has been appealed to the Michigan Court of Appeals by the City of
Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court
of Appeals. The MCV Partnership also has a pending case with the Michigan Tax
Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the
outcome of these proceedings; therefore,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

the above refund (net of approximately $16 million of deferred expenses) has not
been recognized in 2004 earnings.

NUCLEAR PLANT DECOMMISSIONING: Decommissioning funding practices approved
by the MPSC require us to file a report on the adequacy of funds for
decommissioning at three-year intervals. We prepared and filed updated cost
estimates for Big Rock and Palisades on March 31, 2004. Excluding additional
costs for spent nuclear fuel storage, due to the DOE's failure to accept this
spent nuclear fuel on schedule, these reports show a decommissioning cost of
$361 million for Big Rock and $868 million for Palisades. Since Big Rock is
currently in the process of being decommissioned, the estimated cost includes
historical expenditures in nominal dollars and future costs in 2003 dollars,
with all Palisades costs given in 2003 dollars.

In 1999, the MPSC orders for Big Rock and Palisades provided for fully
funding the decommissioning trust funds for both sites. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. The MPSC order set the
annual decommissioning surcharge for Palisades at $6 million through 2007.
Amounts collected from electric retail customers and deposited in trusts,
including trust earnings, are credited to a regulatory liability and asset
retirement obligation.

BIG ROCK: Excluding the additional nuclear fuel storage costs due to the
DOE's failure to accept this spent fuel on schedule, we are currently projecting
that the level of funds provided by the trust for Big Rock will fall short of
the amount needed to complete the decommissioning by $26 million. At this time,
we plan to provide the additional amounts needed from our corporate funds and,
subsequent to the completion of radiological decommissioning work, seek recovery
of such expenditures at the MPSC. We cannot predict how the MPSC will rule on
our request. The following table shows our Big Rock decommissioning activities:

- -------------------------

(a) Includes site restoration expenditures.

These activities had no material impact on net income. At December 31,
2004, we have an investment in nuclear decommissioning trust funds of $52
million for Big Rock. In addition, at December 31, 2004, we have charged $8
million to our FERC jurisdictional depreciation reserve for the decommissioning
of Big Rock.

PALISADES: Excluding additional nuclear fuel storage costs due to the DOE's
failure to accept this spent fuel on schedule, we concluded that the existing
surcharge for Palisades needed to be increased to $25 million annually,
beginning January 1, 2006, and continue through 2011, our current license
expiration date. In June 2004, we filed an application with the MPSC seeking
approval to increase the surcharge for recovery of decommissioning costs related
to Palisades beginning in 2006. In September 2004, we announced that we will
seek a 20-year license renewal for Palisades. In January 2005, we filed a
settlement agreement with the MPSC that was agreed to by four of the six
parties. The settlement agreement provides for the continuation of the existing
$6 million annual decommissioning surcharge through 2011 and for the next
periodic review to be filed in March 2007. We are seeking MPSC approval of the
settlement, under a contested settlement proceeding, but cannot predict the
outcome.

At December 31, 2004, we have an investment in the MPSC nuclear
decommissioning trust funds of $513 million for Palisades. In addition, at
December 31, 2004, we have a FERC decommissioning trust fund with a balance of
$10 million. For additional details on decommissioning costs accounted for as
asset retirement obligations, see Note 8, Asset Retirement Obligations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

NUCLEAR MATTERS:

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

There are two court decisions that 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. Over 60 utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. In July 2004, the DOE filed an amended answer and motion to
dismiss the complaint. In October 2004, we filed a response to the DOE's motion
and our motion for summary judgment on liability. Oral argument has been held,
and the motions are now before the Court for a decision. If our litigation
against the DOE is successful, we anticipate future recoveries from the DOE. We
plan to use recoveries to pay the cost of spent nuclear fuel storage until the
DOE takes possession as required by law. We can make no assurance that the
litigation against the DOE will be successful.

In July 2002, Congress approved and the President signed a bill designating
the site at Yucca Mountain, Nevada, for the development of a repository for the
disposal of high-level radioactive waste and spent nuclear fuel. We expect that
the DOE will submit an application to the NRC sometime in 2005 for a license to
begin construction of the repository. The application and review process is
estimated to take several years.

Insurance: We maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $27 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.

At Palisades, we maintain nuclear liability insurance for third-party
bodily injury and off-site property damage resulting from a nuclear hazard for
up to approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. Part of the Price-Anderson
Act's financial protection is a mandatory industry-wide program under which
owners of nuclear generating facilities could be assessed if a nuclear incident
occurs at any nuclear generating facility. The maximum assessment against us
could be $101 million per occurrence, limited to maximum annual installment
payments of $10 million.

We also maintain insurance under a program that covers tort claims for
bodily injury to nuclear workers caused by nuclear hazards. The policy contains
a $300 million nuclear industry aggregate limit. Under a previous insurance
program providing coverage for claims brought by nuclear workers, we remain
responsible for a maximum assessment of up to $6 million.

Big Rock remains insured for nuclear liability by a combination of
insurance and a NRC indemnity totaling $544 million, and a nuclear property
insurance policy from NEIL.

Insurance policy terms, limits, and conditions are subject to change during
the year as we renew our policies.

CONSUMERS' GAS UTILITY CONTINGENCIES

GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial
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. We have completed initial
investigations at the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

23 sites. We will continue to implement remediation plans for sites where we
have received MDEQ remediation plan approval. We will also work toward resolving
environmental issues at sites as studies are completed.

We have estimated our costs for investigation and remedial action at all 23
sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost
Model. We expect our remaining costs to be between $37 million and $90 million.
The range reflects multiple alternatives with various assumptions for resolving
the environmental issues at each site. We base the estimates on discounted 2003
costs using a discount rate of three percent. The discount rate represents 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 insurance
proceeds and MPSC-approved rates. As of December 31, 2004, we have recorded a
liability of $38 million, net of $44 million of expenditures incurred to date,
and a regulatory asset of $65 million. 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 remedial action costs.

In its November 2002 gas distribution rate order, the MPSC authorized us to
continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.

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 for prudency in an annual
reconciliation proceeding.

The following table summarizes our GCR reconciliation filings with the
MPSC. Additional details related to these proceedings follow the table.

GAS COST RECOVERY RECONCILIATION

Net over-recovery amounts included in the table above include refunds that
we received from our suppliers which are required to be refunded to our
customers.

GCR Year 2003-2004: In February 2005, the MPSC approved a settlement
agreement that resulted in a credit to our GCR customers for a $28 million
over-recovery, plus $3 million interest, using a roll-in refund methodology. The
roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan
year.

GCR Plan for Year 2004-2005: In December 2003, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan
approving a settlement. The settlement included a quarterly mechanism for
setting a GCR

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

ceiling price. The current ceiling price is $6.57 per mcf. Actual gas costs and
revenues will be subject to an annual reconciliation proceeding.

GCR Plan for Year 2005-2006: In December 2004, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2005
through March 2006. Our request proposes using a GCR factor consisting of:

- a base GCR factor of $6.98 per mcf, plus

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

The GCR factor can be adjusted monthly, provided it remains at or below the
current ceiling price. The quarterly adjustment mechanism allows an increase in
the GCR ceiling price to reflect a portion of cost increases if the average
NYMEX price for a specified period is greater than that used in calculating the
base GCR factor. Actual gas costs and revenues will be subject to an annual
reconciliation proceeding.

2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a gas rate increase in the annual amount of $156 million. In December 2003,
the MPSC granted an interim rate increase in the amount of $19 million annually.
The MPSC also ordered an annual $34 million reduction in our annual depreciation
expense and related taxes.

On October 14, 2004, the MPSC issued its Opinion and Order on final rate
relief. In the order, the MPSC authorized us to place into effect surcharges
that would increase annual gas revenues by $58 million. Further, the MPSC
rescinded the $19 million annual interim rate increase. The final rate relief
was contingent upon our agreement to:

- achieve a common equity level of at least $2.3 billion by year-end 2005
and propose a plan to improve the common equity level thereafter until
our target capital structure is reached,

- make certain safety-related operation and maintenance, pension, retiree
health-care, employee health-care, and storage working capital
expenditures for which the surcharge is granted,

- refund surcharge revenues when our rate of return on common equity
exceeds its authorized 11.4 percent rate,

- prepare and file annual reports that address certain issues identified in
the order, and

- file a general rate case on or before the date that the surcharge expires
(which is two years after the surcharge goes into effect).

On October 15, 2004, we agreed to these commitments.

2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. On December 18,
2003, the MPSC ordered an annual $34 million reduction in our depreciation
expense and related taxes in an interim rate order issued in our 2003 gas rate
case.

In October and December 2004, the MPSC issued Opinions and Orders in our
gas depreciation case. The October 2004 order requires us to file an application
for new depreciation accrual rates for our natural gas utility plant on, or no
earlier than three months prior to, the date we file our next natural gas
general rate case. The MPSC also directed us to undertake a study to determine
why our removal costs are in excess of those of other regulated Michigan natural
gas utilities and file a report with the MPSC Staff on or before December 31,
2005.

In February 2005, we requested a delay in the filing date for the next
depreciation case until after the MPSC considers the removal cost study, and
after the MPSC issues an order in a pending case relating to asset retirement
obligation accounting.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

OTHER MATTERS

COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees
are represented by the Utility Workers of America Union. The Union represents
Consumers' operating, maintenance, and construction employees and our call
center employees. The collective bargaining agreement with the Union for our
operating, maintenance, and construction employees will expire on June 1, 2005
and negotiations for a new agreement is underway currently. The collective
bargaining agreement with the Union for our call center employees will expire on
August 1, 2005.

OTHER CONTINGENCIES

EQUATORIAL GUINEA TAX CLAIM: CMS Energy received a request for
indemnification from Perenco, the purchaser of CMS Oil and Gas. The
indemnification claim relates to the sale by CMS Energy of its oil, gas, and
methanol projects in Equatorial Guinea and the claim of the government of
Equatorial Guinea that $142 million in taxes is owed it in connection with that
sale. Based on information currently available, CMS Energy and its tax advisors
have concluded that the government's tax claim is without merit, and Perenco has
submitted a response to the government rejecting the claim. CMS Energy cannot
predict the outcome of this matter.

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

DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD)
presented DIG with a change order to their construction contract and filed an
action in Michigan state court claiming damages in the amount of $110 million,
plus interest and costs, which DFD states represents the cumulative amount owed
by DIG for delays DFD believes DIG caused and for prior change orders that DIG
previously rejected. DFD also filed a construction lien for the $110 million.
DIG, in addition to drawing down on three letters of credit totaling $30 million
that it obtained from DFD, has filed an arbitration claim against DFD asserting
in excess of an additional $75 million in claims against DFD. The judge in the
Michigan state court case entered an order staying DFD's prosecution of its
claims in the court case and permitting the arbitration to proceed. DFD has
appealed the decision by the judge in the Michigan state court case to stay the
litigation. DIG will continue to defend itself vigorously and pursue its claims.
DIG cannot predict the outcome of this matter.

DIG NOISE ABATEMENT LAWSUIT: In February 2003, DIG was served with a
three-count first amended complaint filed in Wayne County Circuit Court seeking
damages and injunctive relief based upon allegations of excessive noise and
vibration created by operation of the power plant on behalf of six named
plaintiffs, all alleged to be adjacent or nearby residents or property owners
and a class of "potentially thousands" who have been similarly affected. The
parties entered into a settlement agreement on June 25, 2004, whereby DIG agreed
to remediate the sound emitted from various pieces of plant equipment to a level
below the ambient noise level and pay a substantial portion of plaintiffs'
attorney fees and costs. The court entered an Order for Conditional Class
Certification and Settlement Approval on August 27, 2004. No class members opted
out of the settlement. DIG believes remediation is now complete at a cost of
approximately $0.6 million. The parties shall seek a Final Order for Class
Certification and Settlement Approval and dismissal of the action. Until such
time as the entry of this Order, DIG cannot predict the final cost associated
with the settlement of this matter, but expects that it will be less than $1
million.

FORMER CMS OIL AND GAS OPERATIONS: A Michigan trial judge granted Star
Energy, Inc. and White Pine Enterprises, LLC a declaratory 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

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committed to drill. A jury then awarded the plaintiffs a $7.6 million award.
Terra appealed this matter to the Michigan Court of Appeals. The Michigan Court
of Appeals reversed the trial court judgment with respect to the appropriate
measure of damages and remanded the case for a new trial on damages. The trial
judge reinstated the judgment against Terra and awarded Terra title to the
minerals. Terra has appealed this judgment. Enterprises has an indemnity
obligation with regard to losses to Terra that might result from this
litigation.

LEONARD FIELD DISPUTE: CMS Gas Transmission is involved in various disputes
related to the Leonard Storage Field in Addison Township, Michigan. The dispute
centers around excess odor discharge and untimely removal of certain equipment
from the Leonard Facility. CMS Gas Transmission cannot predict the outcome of
this matter, and the ultimate consequence of an adverse outcome would be our
inability to extract approximately 500,000 mcf of gas remaining in the Leonard
Field that has a $1 million book value at December 31, 2004.

CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase
agreement, CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery
in La Plata, Argentina. As a result of the so-called "Emergency Laws," payments
by YPF Repsol under the power purchase agreement have been converted to pesos at
the exchange rate of one U.S. dollar to one Argentine peso. Such payments are
currently insufficient to cover CMS Ensenada's operating costs, including
quarterly debt service payments to the OPIC. Enterprises is party to a Sponsor
Support Agreement pursuant to which Enterprises has guaranteed CMS Ensenada's
debt service payments to OPIC up to an amount which is in dispute, but which
Enterprises estimated to be approximately $9 million at June 30, 2004. Following
a payment made to OPIC in July 2004, Enterprises now believes this amount to be
approximately $7 million.

The Argentine commercial court granted injunctive relief to CMS Ensenada
pursuant to an ex parte action, and such relief will remain in effect until
completion of an arbitration on the matter, to be administered by the
International Chamber of Commerce.

OTHER: CMS Generation does not currently expect to incur significant
capital costs at its power facilities for compliance with current U.S.
environmental regulatory standards.

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 results of operations.

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4: FINANCINGS AND CAPITALIZATION

Long-term debt as of December 31 follows:

- -------------------------

(a) Contingently convertible notes. See "Contingently Convertible Securities"
within this Note for further discussion of the conversion features.

(b) Redeemed $103 million in January 2005 and $117 million in February 2005.

(c) Represents the weighted average interest rate at December 31, 2004.

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(d) Maturity date uncertain.

(e) Paid off in January 2005.

FINANCINGS: The following is a summary of significant long-term debt
issuances and retirements during 2004:

Issuance costs associated with the issuances of senior notes totaled $8
million and are being amortized ratably over the lives of the related debt.
Issuance costs associated with the issuances of FMBs totaled $7 million and are
being amortized ratably over the lives of the related debt. Call premiums
associated with the Consumers debt retirements totaled $20 million and are being
amortized ratably over the lives of the newly issued debt. An option payment
associated with CMS Energy's retirement of the X-TRAS totaled $22 million and
was charged to other interest expense in 2004.

SUBSEQUENT FINANCING ACTIVITIES: In January 2005, we redeemed $103 million
of general term notes. In January 2005, we issued $150 million of 6.30 percent
Senior Notes due 2012. We used the net proceeds of $147 million to redeem the
remaining general term notes and for other corporate purposes.

In January 2005, Consumers issued $250 million of 5.15 percent FMBs due
2017. Consumers used the net proceeds of $247 million to pay off its $60 million
long-term bank loan and to redeem the $73 million 8.36 percent and the $124
million 8.20 percent subordinated deferrable interest notes. The subordinated
deferrable interest notes are classified as Long-term debt -- related parties on
the accompanying Consolidated Balance Sheets.

FIRST MORTGAGE BONDS: Consumers secures its FMBs by a mortgage and lien on
substantially all of its property. Its ability to issue and sell securities is
restricted by certain provisions in the first mortgage bond indenture, its
articles of incorporation, and the need for regulatory approvals under federal
law.

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SECURITIZATION BONDS: Securitization bonds are collateralized by certain
regulatory assets. 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 on the
Securitization bonds. Securitization surcharges totaled $50 million annually in
2003 and 2004.

FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB
Interpretation No. 46. At December 31, 2004, long-term debt of the FMLP consists
of:

The FMLP debt is essentially project debt secured by certain assets of the
MCV Partnership and the FMLP. The debt is non-recourse to other assets of CMS
Energy and Consumers.

LONG-TERM DEBT -- RELATED PARTIES: CMS Energy and Consumers each formed
various statutory wholly-owned business trusts for the sole purpose of issuing
preferred securities and lending the gross proceeds to ourselves. The sole
assets of the trusts consist of the debentures described below. These debentures
have terms similar to those of the mandatorily redeemable preferred securities
the trusts issued. We determined that we do not hold the controlling financial
interest in our trust preferred security structures. Accordingly, those entities
were deconsolidated as of December 31, 2003 and are reflected in Long-term
debt -- related parties. The trust preferred securities were previously included
in mezzanine equity.

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

- -------------------------
(a) Redeemed in February 2005.

(b) Redeemed in January 2005 with available cash.

In the event of default, holders of the trust preferred securities would be
entitled to exercise and enforce the trusts' 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

taken together with our obligations under the debentures, related indenture and
trust documents, provide full and unconditional guarantees for the trusts'
obligations under the preferred securities.

DEBT MATURITIES: At December 31, 2004, the aggregate annual maturities for
long-term debt for the next five years are:

REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers has FERC authorization
to issue or guarantee up to $1.1 billion of short-term securities and up to $1.1
billion of short-term FMBs as collateral for such short-term securities.
Consumers has FERC authorization to issue up to $1 billion of long-term
securities for refinancing or refunding purposes, $1.5 billion of long-term
securities for general corporate purposes, and $2.5 billion of long-term FMBs to
be issued solely as collateral for other long-term securities.

REVOLVING CREDIT FACILITIES: The following secured revolving credit
facilities with banks are available as of December 31, 2004:

- -------------------------
(a) The annual interest rate on borrowings under this facility is LIBOR plus
275 basis points. Annual fees for letters-of-credit are 275 basis points on
the amount outstanding. A quarterly fee of 50 basis points is payable on
the average daily unused balance.

(b) This facility expires in August 2005 and may be extended annually at
Consumers' option to July 31, 2007. The annual interest rate on borrowings
under this facility is LIBOR plus 125 basis points. Annual fees for
letters-of-credit are 125 basis points on the amount outstanding. A
quarterly fee of 22.5 basis points is payable on the average daily unused
balance.

SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently 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. We sold $304 million of receivables at December 31, 2004 and we
sold $297 million of receivables at December 31, 2003. These sold amounts are
excluded from accounts receivable on our Consolidated Balance Sheets. We
continue to service the receivables sold to the special purpose entity. The
purchaser of the receivables has no recourse against our other assets for
failure of a debtor to pay when due and the purchaser has no right to any
receivables not sold. No gain or loss has been recorded on the receivables sold
and we retain no interest in the receivables sold.

Certain cash flows under our accounts receivable sales program are shown in
the following table:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

DIVIDEND RESTRICTIONS: Our amended and restated $300 million secured
revolving credit facility restricts payments of dividends on our common stock
during a 12-month period to $75 million, dependent on the aggregate amounts of
unrestricted cash and unused commitments under the facility.

Under the provisions of its articles of incorporation, at December 31,
2004, Consumers had $456 million of unrestricted retained earnings available to
pay common stock dividends. However, covenants in Consumers' debt facilities cap
common stock dividend payments at $300 million in a calendar year. In October
2004, the MPSC rescinded its December 2003 interim gas rate order, which
included a $190 million annual dividend cap imposed on Consumers. For the year
ended December 31, 2004, we received $190 million of common stock dividends from
Consumers.

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.

In October 2004, we issued 32.8 million shares of our common stock. We
realized net proceeds of $288 million.

PREFERRED STOCK: Our Preferred Stock outstanding follows:

- -------------------------
(a) See the "Contingently Convertible Securities" section within this Note for
further discussion of the convertible preferred stock.

(b) In December 2003, we sold, in a private placement, a non-voting preferred
interest in an indirect subsidiary of Enterprises that owns certain gas
pipeline and power generation assets. CMS Energy received $30 million for
the preferred interest, of which $19 million has been recorded as an
addition to other paid-in capital (deferred gain) and $11 million has been
recorded as a preferred stock issuance.

PREFERRED STOCK OF SUBSIDIARY: Consumers' Preferred Stock outstanding
follows:

FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE
REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF
OTHERS: This Interpretation became effective January 2003. It describes the
disclosure to be made by a guarantor about its obligations under certain
guarantees that it has

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

issued. At the inception of a guarantee, it requires a guarantor to recognize a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and measurement provision of this
Interpretation does not apply to some guarantee contracts, such as warranties,
derivatives, or guarantees between either parent and subsidiaries or
corporations under common control, although disclosure of these guarantees is
required. For contracts that are within the recognition and measurement
provision of this Interpretation, the provisions were to be applied to
guarantees issued or modified after December 31, 2002.

The following table describes our guarantees at December 31, 2004:

- -------------------------
(a) The majority of this amount arises from routine provisions in stock and
asset sales agreements under which we indemnify the purchaser for losses
resulting from events such as failure of title to the assets or stock sold
by us to the purchaser. We believe the likelihood of a loss for any
remaining indemnifications to be remote.

(b) The carrying amount represents the fair market value of guarantees and
indemnities recorded on our balance sheet that are entered into subsequent
to January 1, 2003.

(c) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.

The following table provides additional information regarding our
guarantees:

We have entered into typical tax indemnity agreements in connection with a
variety of transactions including transactions for the sale of subsidiaries and
assets, equipment leasing, and financing agreements. These indemnity

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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

agreements generally are not limited in amount and, while a maximum amount of
exposure cannot be identified, the probability of liability is considered
remote.

We have guaranteed payment of obligations through letters of credit,
indemnities, surety bonds, and other guarantees of unconsolidated affiliates and
related parties of $400 million as of December 31, 2004. We monitor and approve
these obligations and believe it is unlikely that we would be required to
perform or otherwise incur any material losses associated with the above
obligations.

CONTINGENTLY CONVERTIBLE SECURITIES: The following transactions took place
in December 2004:

- we completed an exchange offering in which 82 percent of our 3.375
percent contingently convertible senior notes and 98 percent of our 4.50
percent contingently convertible preferred stock were exchanged, and

- we issued $287.5 million of 2.875 percent contingently convertible senior
notes.

At December 31, 2004, the significant terms of our contingently convertible
securities were as follows:

- -------------------------
(a) The notes are putable to CMS Energy by the note holders at par on July 15,
2008, 2013, and 2018 for our 3.375 percent convertible senior notes and on
December 1, 2011, 2014, and 2019 for our 2.875 percent convertible senior
notes. On or after December 5, 2008, we may cause the 4.50 percent
convertible preferred stock to convert if the closing price of our common
stock remains at or above $12.86 for 20 of any 30 consecutive trading days.
The $12.86 price may be adjusted if there is a payment or distribution to
our common stockholders.

(b) 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 the previous
quarter. The trigger price at which these securities become convertible is
120 percent of the conversion price, which may be adjusted if there is a
payment or distribution to our common stockholders.

(c) The exchanged 3.375 percent convertible senior notes, the exchanged 4.50
percent convertible preferred stock, and all of our 2.875 percent
convertible senior notes require us, if converted, to pay cash up to the
principal (or par) amount of the securities and any conversion value in
excess of that amount in shares of our common stock. This method of
conversion is referred to as the "net share settlement" method. The
remaining securities that were not exchanged retained their original
settlement features.

In January 2005, the remaining 18 percent, or $27.1 million of our 3.375
percent convertible senior notes and the remaining 2 percent, or $4.5 million of
our 4.50 percent convertible preferred stock were exchanged, bringing the total
exchanged for both securities to 100 percent. As a result, all of our
contingently convertible securities now have a net share settlement feature.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

5: EARNINGS PER SHARE

The following table presents the basic and diluted earnings per share
computations.

- -------------------------
(a) Computation of diluted earnings per share for the years ended 2002 and 2003
excluded conversion of our 3.375 percent contingently convertible senior
notes and our 4.50 percent contingently convertible preferred stock.
Neither security was outstanding in 2002. In 2003, both securities were
excluded from diluted earnings per share due to antidilution.

(b) Since the exercise price was greater than the average market price of the
common stock, options and warrants to purchase 4.5 million shares of common
stock were excluded from the computation of diluted earnings per share for
the year ended 2004. Due to antidilution, options and warrants to purchase
6.0 million shares of common stock were excluded for the year ended 2003,
and 5.1 million shares of common stock were excluded for the year ended
2002.

Contingently Convertible Securities: At its September 2004 meeting, the
EITF reached a final consensus that contingently convertible instruments should
be included in the diluted earnings per share computation (if dilutive)
regardless of whether the market price trigger has been met. We adopted EITF
Issue No. 04-8 for the period ending December 31, 2004. For additional details,
see Note 16, Implementation of New Accounting Standards. Prior to our adoption
of EITF Issue No. 04-8, we completed an exchange offer for our 3.375 percent
contingently convertible senior notes and our 4.50 percent contingently
convertible preferred stock, intended to mitigate the earnings per share impact.

The exchanged securities have the potential to dilute earnings per share to
the extent that the conversion value exceeds the principal or par value.

The remaining contingently convertible securities that were not exchanged
were included in the diluted earnings per share calculation using the
"if-converted" method for the year ended December 31, 2004. All such

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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

remaining contingently convertible securities were exchanged in January 2005.
For additional details, see Note 4, Financings and Capitalization, "Contingently
Convertible Securities."

Trust Preferred Securities: Due to antidilution, the computation of diluted
earnings per share excluded the conversion of Trust Preferred Securities into
4.2 million shares of common stock and an $8.7 million reduction of interest
expense, net of tax, for the years ended 2002, 2003, and 2004. Effective July
2001, we can revoke the conversion rights if certain conditions are met.

Other: In October 2004, we issued 32.8 million shares of our common stock.
For additional details, see Note 4, Financings and Capitalization.

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 cost and fair value of our long-term financial instruments are as
follows:

- -------------------------
(a) Includes current maturities of $267 million at December 31, 2004 and $509
million at December 31, 2003. Settlement of long-term debt is generally not
expected until maturity.

(b) Includes current maturities of $180 million at December 31, 2004.

(c) Nuclear decommissioning investments include cash and equivalents and
accrued income totaling $11 million at December 31, 2004 and $11 million at
December 31, 2003. Unrealized gains and losses on nuclear decommissioning
investments are reflected as regulatory liabilities.

(d) The fair value of available-for-sale debt securities by contractual
maturity as of December 31, 2004 is as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Our held-to-maturity investments consist of debt securities held by the MCV
Partnership totaling $139 million as of December 31, 2004. These securities
represent funds restricted primarily for future lease payments and are
classified as Other assets on our Consolidated Balance Sheets. These investments
have original maturity dates of approximately one year or less and, because of
their short maturities, their carrying amounts approximate their fair values.

DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks including swaps, options, futures, and forward contracts.

We intend that any gains or losses on these contracts will be offset by an
opposite movement in the value of the item at risk. Risk management contracts
are classified as either non-trading or trading. These contracts contain credit
risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk through
established credit policies that include performing financial credit reviews of
our counterparties. Determination of our counterparties' credit quality is based
upon a number of factors, including credit ratings, disclosed financial
condition, and collateral requirements. Where contractual terms permit, we
employ standard agreements that allow for netting of positive and negative
exposures associated with a single counterparty. Based on these policies, our
current exposures, and our credit reserves, we do not anticipate a material
adverse effect on our financial position or earnings as a result of counterparty
nonperformance.

Contracts used to manage market risks may be considered derivative
instruments that are subject to derivative and hedge accounting pursuant to SFAS
No. 133. If a contract is accounted for as a derivative instrument, it is
recorded in the financial statements as an asset or a liability, at the fair
value of the contract. The recorded fair value is then adjusted quarterly to
reflect any change in the market value of the contract, a practice known as
marking the contract to market. Changes in fair value (that is, gains or losses)
are reported either in earnings or accumulated other comprehensive income,
depending on whether the derivative qualifies for cash flow hedge accounting
treatment.

For derivative instruments to qualify for hedge accounting, the hedging
relationship must be formally documented at inception and be highly effective in
achieving offsetting cash flows or offsetting changes in fair value attributable
to the risk being hedged. If hedging a forecasted transaction, the forecasted
transaction must be probable. If a derivative instrument, used as a cash flow
hedge, is terminated early because it is probable that a forecasted transaction
will not occur, any gain or loss as of such date is recognized immediately in
earnings. If a derivative instrument, used as a cash flow hedge, is terminated
early for other economic reasons, any gain or loss as of the termination date is
deferred and recorded when the forecasted transaction affects earnings. The
ineffective portion, if any, of all hedges is recognized in earnings.

We use a combination of quoted market prices, prices obtained from external
sources, such as brokers, and mathematical valuation models to determine the
fair value of those contracts requiring derivative accounting. In certain
contracts, long-term commitments may extend beyond the period in which market
quotations for such contracts are available. Mathematical models are developed
to determine various inputs into the fair value calculation including price and
other variables that may be required to calculate fair value. Realized cash
returns on these commitments may vary, either positively or negatively, from the
results estimated through application of the mathematical model. In connection
with the market valuation of our derivative contracts, we maintain reserves, if
necessary, for credit risks based on the financial condition of counterparties.

The majority of our contracts are not subject to derivative accounting
under SFAS No. 133 because they qualify for the normal purchases and sales
exception, or because there is not an active market for the commodity. Certain
of our electric capacity and energy contracts are not accounted for as
derivatives due to the lack of an

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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

active energy market in the state of Michigan and the significant transportation
costs that would be incurred to deliver the power under the contracts to the
closest active energy market at the Cinergy hub in Ohio. Similarly, our coal
purchase contracts are not accounted for as derivatives due to the lack of an
active market for the coal that we purchase. If active markets for these
commodities develop in the future, we may be required to account for these
contracts as derivatives, and the resulting mark-to-market impact on earnings
could be material to our financial statements.

The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005,
which will include day-ahead and real-time energy market information and
centralized dispatch for market participants. At this time, we believe that the
commencement of this market will not constitute the development of an active
energy market in the state of Michigan. However, after having adequate
experience with the Midwest Energy Market, we will reevaluate whether or not the
activity level within this market leads to the conclusion that an active energy
market exists.

Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk, interest rate risk, and foreign exchange risk.
The following table reflects the fair value of all contracts requiring
derivative accounting:

Notional amounts reflect the volume of transactions but do not represent
the amount exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not necessarily reflect our exposure to credit or market
risks. The weighted average interest rate associated with outstanding swaps was
approximately 7.4 percent at December 31, 2004 and December 31, 2003.

There was no ineffectiveness associated with any of the interest rate swaps
that qualified for hedge accounting treatment. As of December 31, 2004, we have
recorded an unrealized loss of $1 million, net of tax, in Accumulated other
comprehensive loss related to interest rate risk contracts accounted for as cash
flow hedges. We expect to reclassify this amount as a decrease to earnings
during the next 12 months primarily to offset the variable-rate interest expense
on hedged debt.

At December 31, 2004 and 2003, Shuweihat, Taweelah, and Jorf Lasfar, three
of our equity method investees, held interest rate swaps that hedged the risk
associated with variable-rate debt. These instruments are not included in this
analysis, but can have an impact on financial results. The accounting for these
instruments depends on whether they qualify for cash flow hedge accounting
treatment. The interest rate swaps held by Taweelah do not qualify as cash flow
hedges, and therefore, we record our proportionate share of the change in the
fair value of these contracts in Earnings from Equity Method Investees. The
remainder of these instruments do qualify as cash flow hedges, and we record our
proportionate share of the change in the fair value of these contracts in
Accumulated other comprehensive loss.

DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP:

Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to
buy gas as fuel for generation, and to manage gas fuel costs. The MCV
Partnership believes that certain of its long-term natural gas contracts qualify
as normal purchases under SFAS No. 133 and therefore, these contracts were not
recognized at fair value on the balance sheet as of December 31, 2004. The MCV
Partnership also held certain long-term gas contracts that did not qualify as
normal purchases as of December 31, 2004, because these contracts contained
volume optionality. Accordingly, these contracts were accounted for as
derivatives, with changes in fair value recorded in earnings each quarter. The
MCV Partnership expects future earnings volatility on these contracts, since
gains and

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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

losses will be recorded each quarter. For the year ended December 31, 2004, we
recorded a $19 million net loss associated with these gas contracts in Fuel for
electric generation on our Consolidated Statements of Income. The fair value of
these contracts will reverse over the remaining life of the contracts ranging
from 2005 to 2007.

Due to the implementation of the RCP in January 2005, the MCV Partnership
has determined that a significant portion of its gas fuel contracts no longer
qualify as normal purchases because the contracted gas will not be consumed for
electric production. Accordingly, these contracts will be treated as derivatives
and will be marked-to-market through earnings each quarter, which could increase
earnings volatility. Based on market prices for natural gas as of January 31,
2005, the accounting for the MCV Partnership's long-term gas contracts,
including those affected by the implementation of the RCP, could result in an
estimated $100 million (pretax before minority interest) gain recorded to
earnings in the first quarter of 2005. This estimated gain will reverse in
subsequent quarters as the contracts settle. For further details on the RCP, see
Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The
Midland Cogeneration Venture." If there are further changes in the level of
planned electric production or gas consumption, the MCV Partnership may be
required to account for additional long-term gas contracts as derivatives, which
could add to earnings volatility.

Gas Fuel Futures and Swaps: The MCV Partnership enters into natural gas
futures contracts, option contracts, and over-the-counter swap transactions in
order to hedge against unfavorable changes in the market price of natural gas in
future months when gas is expected to be needed. These financial instruments are
used principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements. At December 31, 2004, the MCV
Partnership held gas fuel futures and swaps.

The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. The MCV Partnership also engages in cost mitigation
activities to offset the fixed charges the MCV Partnership incurs in operating
the MCV Facility. These cost mitigation activities include the use of futures
and options contracts to purchase and/or sell natural gas to maximize the use of
the transportation and storage contracts when it is determined that they will
not be needed for the MCV Facility operation. Although these cost mitigation
activities do serve to offset the fixed monthly charges, these cost mitigation
activities are not considered a normal course of business for the MCV
Partnership and do not qualify as hedges. Therefore, the mark-to-market gains
and losses from these cost mitigation activities are recorded in earnings each
quarter.

As of December 31, 2004, we have recorded a cumulative net gain of $21
million, net of tax, in Accumulated other comprehensive loss relating to our
proportionate share of the contracts held by the MCV Partnership that qualify as
cash flow hedges. This balance represents natural gas futures, options, and
swaps with maturities ranging from January 2005 to December 2009, of which $11
million of this gain is expected to be reclassified as an increase to earnings
during the next 12 months. In addition, for the year ended December 31, 2004, we
recorded a net gain of $37 million in earnings from hedging activities related
to natural gas requirements for the MCV Facility operations and a net gain of $2
million in earnings from the MCV Partnership's cost mitigation activities.

CMS ERM CONTRACTS: Through December 31, 2002, our wholesale power and gas
trading activities were accounted for under the mark-to-market method of
accounting in accordance with EITF Issue No. 98-10. Effective January 1, 2003,
EITF Issue No. 98-10 was rescinded and replaced by EITF Issue No. 02-03. As a
result, only energy contracts that meet the definition of a derivative under
SFAS No. 133 are to be carried at fair value. The impact of this change was
recognized as a cumulative effect of a change in accounting principle loss of
$23 million, net of tax, for the three month period ended March 31, 2003.

During 2003, we sold a majority of our wholesale natural gas and
power-trading portfolio, and exited the energy services and retail customer
choice business. As a result, our trading activities have been reduced

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significantly. Our current activities center around entering into energy
contracts that are related to the activities considered to be an integral part
of our ongoing operations. CMS ERM holds certain forward contracts for the
purchase and sale of electricity and natural gas that result in physical
delivery of the underlying commodity at contractual prices. These contracts are
generally long-term in nature and are classified as non-trading. CMS ERM also
uses various financial instruments, including swaps, options, and futures, to
manage the commodity price risks associated with its forward purchase and sales
contracts as well as generation assets owned by CMS Energy or its subsidiaries.
These financial contracts are classified as trading activities.

Non-trading and trading contracts that meet the definition of a derivative
under SFAS No. 133 are recorded as assets or liabilities in the financial
statements at the fair value of the contracts. Gains or losses arising from
changes in fair value of these contracts are recognized into earnings as a
component of Operating Revenue in the period in which the changes occur. Gains
and losses on trading contracts are recorded net in accordance with EITF Issue
No. 02-03. Contracts that do not meet the definition of a derivative are
accounted for as executory contracts (i.e., on an accrual basis).

FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option
contracts to hedge certain receivables, payables, long-term debt, and equity
value relating to our investments in foreign operations. The purpose of our
foreign currency hedging activities is to protect the company from the risk
associated with adverse changes in currency exchange rates that could affect
cash flow materially. These contracts would limit the risk from exchange rate
movements because gains and losses on such contracts offset losses and gains,
respectively, on assets and liabilities being hedged. At December 31, 2004 and
2003, we had no outstanding foreign exchange contracts.

The impact of hedges on our investments in foreign operations is reflected
in Accumulated other comprehensive loss as a component of the foreign currency
translation adjustment on our Consolidated Balance Sheets. Gains or losses from
the settlement of these hedges are maintained in the foreign currency
translation adjustment until we sell or liquidate the investments on which the
hedges were taken. At December 31, 2004, the total foreign currency translation
adjustment was a net loss of $319 million, which included a net hedging loss of
$27 million, net of tax, related to settled contracts.

At December 31, 2004 and 2003, Taweelah, one of our equity method
investees, held a foreign exchange contract that hedged the foreign currency
risk associated with payments to be made under an operating and maintenance
service agreement. This contract did not qualify as a cash flow hedge; and
therefore, we record our proportionate share of the change in the fair value of
the contract in Earnings from Equity Method Investees.

7: RETIREMENT BENEFITS

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

- non-contributory, defined benefit Pension Plan,

- a cash balance pension plan for certain employees hired after June 30,
2003,

- benefits to certain management employees under SERP,

- a defined contribution 401(k) plan,

- benefits to a select group of management under EISP, and

- health care and life insurance benefits under OPEB.

Pension Plan: The Pension Plan includes funds for all of our employees, and
the employees of our subsidiaries, including Panhandle. The Pension Plan's
assets are not distinguishable by company.

In June 2003, we sold Panhandle to Southern Union Panhandle Corp. No
portion of the Pension Plan assets were transferred with the sale and Panhandle
employees are no longer eligible to accrue additional benefits. The
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Pension Plan retained pension payment obligations for Panhandle employees that
were vested under the Pension Plan.

The sale of Panhandle resulted in a significant change in the makeup of the
Pension Plan. A remeasurement of the obligation was required at the date of
sale. The remeasurement further resulted in the following:

- an increase in OPEB expense of $4 million for 2003, and

- an additional charge to accumulated other comprehensive income of $34
million ($22 million after-tax) in 2003 as a result of the increase in
the additional minimum pension liability. As a result of Company
contributions in 2003, the additional minimum pension liability was
eliminated as of December 31, 2003.

Additionally, a significant number of Panhandle employees elected to retire
as of July 1, 2003. As a result, in 2003, we recorded a $25 million ($16 million
after-tax) settlement loss, and a $10 million ($7 million after-tax) curtailment
gain, pursuant to the provisions of SFAS No. 88, which is reflected in
discontinued operations.

In 2003, a substantial number of non-Panhandle retiring employees also
elected a lump sum payment instead of receiving pension benefits as an annuity
over time. Lump sum payments constitute a settlement under SFAS No. 88. A
settlement loss must be recognized when the cost of all settlements paid during
the year exceeds the sum of the service and interest costs for that year. We
recorded a settlement loss of $59 million ($39 million after-tax) in December
2003.

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 consolidated assets. Trust assets were
$67 million at December 31, 2004, and $66 million at December 31, 2003. The
assets are classified as Other non-current assets. The Accumulated Benefit
Obligation for SERP was $67 million at December 31, 2004 and $62 million at
December 31, 2003.

401(k): Employer matching contributions to the 401(k) plan are invested in
CMS Energy common stock. The amount charged to expense for this plan was $12
million in 2002. The employer's match for the 401(k) plan was suspended on
September 1, 2002 and was resumed on January 1, 2005.

The MCV Partnership sponsors a defined contribution retirement plan
covering all employees. Under the terms of the plan, the MCV Partnership makes
contributions of either 5 or 10 percent of an employee's eligible annual
compensation dependent upon the employee's age. The MCV Partnership also
sponsors a 401(k) savings plan for employees. Contributions and costs for this
plan are based on matching an employee's savings up to a maximum level. Amounts
contributed under these plans were $1 million in 2004.

EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select 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 premium for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. EISP expense was less than $1 million in 2004, $1 million in
2003, and $2 million in 2002. The Accumulated Benefit Obligation for EISP was $4
million at December 31, 2004 and $3 million at December 31, 2003.

OPEB: Retiree health care costs at December 31, 2004 are based on the
assumption that costs would increase 7.5 percent in 2004. The rate of increase
is expected to be 10 percent for 2005. The rate of increase is expected to slow
to an estimated 5 percent by 2010 and thereafter.

The MCV Partnership sponsors defined cost postretirement health care plans
that cover all full-time employees, except key management. Participants in the
postretirement health care plans become eligible for the benefits if they retire
on or after the attainment of age 65 or upon a qualified disability retirement,
or if they have 10 or more years of service and retire at age 55 or older. The
accumulated benefit obligation of the MCV Partnership's postretirement plans was
$5 million at December 31, 2004. The MCV Partnership's net periodic
postretirement health care cost for 2004 was less than $1 million.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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:

We adopted SFAS No. 106, effective as of the beginning of 1992. Consumers
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.

The measurement date for all CMS Energy plans is November 30 for 2004, and
December 31 for 2003 and 2002. We believe accelerating the measurement date on
our benefits plans by one month is preferable as it improves control procedures
and allows more time to review the completeness and accuracy of the actuarial
measurements. As a result of the measurement date change in 2004, we recorded a
$2 million cumulative effect of change in accounting, net of tax benefit, as a
decrease to earnings. We also increased the amount of accrued benefit cost on
our Consolidated Balance Sheets by $4 million. The effect of the measurement
date change was immaterial. The measurement date for the MCV Partnership's plan
is December 31, 2004.

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

- -------------------------
(a) We determine our long-term rate of return by considering historical market
returns, the current and future economic environment, the capital market
principles of risk and return, and the expert opinions of individuals and
firms with financial market knowledge. We use the asset allocation of the
portfolio to forecast 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. The use of forecasted returns for various classes
of assets used to construct an expected return model is reviewed
periodically for reasonability and appropriateness.

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Costs: The following table recaps the costs incurred in our retirement
benefits plans:

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

- -------------------------
(a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. The Act 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated, retroactively, the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No.
SFAS 106-2. We remeasured our obligation as of December 31, 2003 to
incorporate the impact of the Act, which resulted in a reduction to the
accumulated postretirement benefit obligation of $158 million. The
remeasurement resulted in a reduction of OPEB cost of $24 million for 2004.
The reduction of $24 million includes $7 million in capitalized OPEB costs.
For additional details, see Note 16, Implementation of New Accounting
Standards.

(b) The Pension Plan's Accumulated Benefit Obligation of $1.082 billion
exceeded the value of the Pension Plan assets and net balance sheet asset
at December 31, 2004. As a result, we recorded an additional minimum
liability of $419 million. Consistent with MPSC guidance, Consumers
recognized the cost of their additional minimum liability as a regulatory
asset. Accordingly, our additional minimum liability includes an intangible
asset of $22 million, $17 million, net of tax of accumulated other
comprehensive income, and a regulatory asset of $372 million. The
Accumulated Benefit Obligation for the Pension Plan was $1.019 billion at
December 31, 2003.

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

- -------------------------
(a) At November 30, 2004, there were 4,892,000 shares of CMS Energy Common
Stock in the Pension Plan assets with a fair value of $50 million, and
493,000 shares in the OPEB plan assets with a fair value of $5 million. At
December 31, 2003, there were 4,970,000 shares of CMS Energy Common Stock
in the Pension Plan assets with a fair value of $42 million, and 414,000
shares in the OPEB plan assets with a fair value of $4 million.

(b) The percentage of fixed income at December 31, 2003 is high because our
December 2003 contribution of $350 million was deposited temporarily into
fixed income securities.

We contributed $63 million to our OPEB plan in 2004. We plan to contribute
$63 million to our OPEB plan in 2005. We did not contribute to our Pension Plan
in 2004. We do not plan to contribute to our Pension Plan in 2005.

We have established a target asset allocation for our Pension Plan assets
of 65 percent equity and 35 percent fixed income 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
a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a
Foreign Equity Index Fund. Fixed income investments are diversified across
investment grade instruments of both government and corporate issuers. Annual
liability measurements, quarterly portfolio reviews, and periodic
asset/liability studies are used to evaluate the need for adjustments to the
portfolio allocation.

We have established union and non-union VEBA trusts to fund our future
retiree health and life insurance benefits. These trusts are funded through the
rate making process for Consumers, and through direct contributions from the
non-utility subsidiaries. The equity portions of the union and non-union health
care VEBA trusts are invested in a Standard & Poor's 500 Index fund. The fixed
income portion of the union health care VEBA trust is invested in domestic
investment grade taxable instruments. The fixed income portion of the non-union
health care VEBA trust is invested in a diversified mix of domestic tax-exempt
securities. The investment selections of each

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

VEBA 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.

Benefit Payments: The expected benefit payments for each of the next five
years and the five-year period thereafter are as follows:

- -------------------------
(a) OPEB benefit payments are net of employee contributions and expected
Medicare Part D prescription drug subsidy payments.

8: ASSET RETIREMENT OBLIGATIONS

SFAS NO. 143: This standard became effective January 2003. It requires
companies to record the fair value of the cost to remove assets at the end of
their useful life, if there is a legal obligation to remove them. We have legal
obligations to remove some of our assets, including our nuclear plants, at the
end of their useful lives. For our regulated utility, as required by SFAS No.
71, we account for the implementation of this standard by recording regulatory
assets and liabilities instead of a cumulative effect of a change in accounting
principle.

The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. 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 would increase by $22 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. Generally, electric and gas transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets. Also, no liability has been recorded for assets that have
insignificant cumulative disposal costs, such as substation batteries. The
measurement of the ARO liabilities for Palisades and Big Rock are based on
decommissioning studies that largely utilize third-party cost estimates.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:

- -------------------------
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and
CMS Field Services.

The Palisades and Big Rock cash flow revisions resulted from new
decommissioning reports filed with the MPSC in March 2004. The Palisades ARO
also reflects a cash flow revision for the probability of operating license
renewal; the renewal would extend the plant's operating license by twenty years.
For additional details, see Note 3, Contingencies, "Other Consumers' Electric
Utility Contingencies -- Nuclear Plant Decommissioning."

On October 14, 2004, the MPSC issued a generic proceeding to review SFAS
No. 143, Accounting for Asset Retirement Obligations, FERC Order No. 631,
Accounting, Financial Reporting, and Rate Filing Requirements for Asset
Retirement Obligations, and their accounting and ratemaking issues. Utilities
are required to respond to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

the Order by March 15, 2005. We consider the proceeding a clarification of
accounting and reporting issues that relate to all Michigan utilities; we
anticipate no financial impact.

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. We utilize deferred tax accounting for temporary differences.

We use ITC to reduce current income taxes payable, and amortize ITC over
the life of the related property. 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, 2004, we had AMT credit carryforwards in the amount of $218 million that do
not expire and tax loss carryforwards in the amount of $1.348 billion that
expire from 2021 through 2024. We do not believe that a valuation allowance is
required, as we expect to utilize the loss carryforward prior to its expiration.
In addition, we had general business credit carryforwards in the amount of $41
million and charitable contribution carryforwards in the amount of $21 million
that primarily expire in 2005, for which valuation allowances have been
provided.

U.S. income taxes are not recorded on the undistributed earnings of foreign
subsidiaries that have been or are intended to be reinvested indefinitely. Upon
distribution, those earnings may be subject to both U.S. income taxes (adjusted
for foreign tax credits or deductions) and withholding taxes payable to various
foreign countries. We determine annually the amount of undistributed foreign
earnings that we expect will remain invested indefinitely in foreign
subsidiaries. Cumulative undistributed earnings of foreign subsidiaries for
which income taxes have not been provided totaled approximately $211 million at
December 31, 2004. It is impractical to estimate the amount of unrecognized
deferred income taxes or withholding taxes on these undistributed earnings.
Also, at December 31, 2004 and 2003, we recorded U.S. income taxes with respect
to temporary differences between the book and tax bases of foreign investments
that were determined to be no longer essentially permanent in duration.

The American Jobs Creation Act of 2004 creates a one-year opportunity to
receive a tax benefit for U.S. corporations that reinvest dividends from
controlled foreign corporations in the U.S. in a 12-month period (calendar year
2005 for CMS Energy). Although the tax benefit is subject to a number of
limitations, we believe that we have the information necessary to make an
informed decision on the impact of this act on our repatriation plan.

In January 2005, we repatriated $80 million in cash, $71 million of which
should qualify for the tax benefit. Historically, we recorded deferred taxes on
these repatriated earnings. Since this repatriation should qualify for the tax
benefit and our decision to repatriate was made in 2004, we have reversed $21
million of our deferred tax liability. This adjustment was recorded as a
component of income from continuing operations in 2004.

During 2005, we may have the ability to repatriate additional amounts that
may qualify for the repatriation tax benefit. If successful, our current
estimate is that additional amounts could range between $100 million and $120
million. The amount of additional repatriation remains uncertain because it is
based on future foreign subsidiary operations, cash flow, financings, and
repatriation limitations. This potential additional repatriation could reduce
our recorded deferred tax liability $30 million to $36 million. We expect to be
in a position to finalize our assessment, which may be higher or lower,
regarding any potential repatriation in the fourth quarter of 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

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 the 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 principal components of deferred tax assets (liabilities) recognized in
our Consolidated Balance Sheets are as follows:

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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 before income taxes as follows:

- -------------------------
(a) The increased income tax expense from 2002 to 2003 is primarily
attributable to the valuation reserve provisions for the possible lost
general business credit, capital loss, and charitable contribution
carryforwards. The decreased income tax expense from 2003 to 2004 is
primarily attributable to the benefit recorded from the American Jobs
Creation Act of 2004 of $21 million.

(b) Because of the small size of the net income in 2003, the effective tax rate
is not meaningful. Changes in the effective tax rate in 2002 from 2001
resulted principally from the reduction in AMT credit carryforwards.

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. The
IRS is currently conducting audits of our federal income tax returns for the
years 1998 through 2002. Our estimate for the potential outcome for any
uncertain tax issue is highly judgmental. We believe that our accrued tax
liabilities are adequate for all years.

10: EXECUTIVE INCENTIVE COMPENSATION

We provide a Performance Incentive Stock Plan (the Plan) to key employees
and non-employee Directors or consultants based on their contributions to the
successful management of the company. On May 28, 2004, shareholders approved an
amendment to the Plan, with an effective date of June 1, 2004. The amendment
established a 5-year term for the Plan. The Plan includes the following type of
awards:

- phantom shares,

- performance units,

- restricted stock,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

- stock options,

- stock appreciation rights, and

- management stock purchases.

Phantom shares are valued at the fair market price of common stock when
granted. They give the holder the right to receive the appreciation value of
common stock on one or more valuation dates, according to a specified vesting
schedule determined at time of grant. These shares are subject to forfeiture if
employment terminates before vesting.

Performance units have an initial value that is established at time of
grant. Performance criteria are established at the time of grant and, depending
upon the extent to which they are met, will determine the value of the payout,
which may be in the form of cash, common stock, or a combination of both. These
units are subject to forfeiture if employment terminates.

Restricted shares of common stock are outstanding shares with full voting
and dividend rights. These awards vest 100 percent after three years and are
subject to achievement of specified levels of total shareholder return including
a comparison to a peer group of companies. Some awards vest based solely on
continued employment. These awards are subject to forfeiture if employment
terminates before vesting. Restricted shares vest fully if control of CMS Energy
changes, as defined by the Plan.

Stock options give the holder the right to purchase common stock at a given
price over an extended period of time. Stock appreciation rights give the holder
the right to receive common stock appreciation, defined as the excess of the
market price of the stock at the date of exercise over the grant date price. All
stock options and stock appreciation rights are valued at fair market price when
granted. All options and rights may be exercised upon grant, and expire up to 10
years and one month from the date of grant.

Management stock purchases are the election of select participants in the
Officer's Incentive Compensation Plan to receive all or a portion of their
incentive payments in the form of shares of restricted common stock or shares of
restricted stock units. These participants may also receive awards of additional
restricted common stock or restricted stock units provided that the total value
of these additional grants does not exceed $2.5 million for any fiscal year.

Under the revised Plan, shares awarded or subject to options, phantom
shares and performance units may not exceed 6 million shares from June 2004
through May 2009, nor may such grants or awards to any participant exceed
250,000 shares in any fiscal year.

Shares for which payment or exercise is in cash, as well as shares or
options that are forfeited, may be awarded or granted again under the Plan.

Awards of up to 5,482,690 shares of CMS Energy Common Stock may be issued
as of December 31, 2004. All grants awarded under this Plan in 2004 were in the
form of restricted stock.

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CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table summarizes the restricted stock and stock options
granted to our key employees under the Performance Incentive Stock Plan:

At December 31, 2004, 426,500 of the 1,377,010 shares of restricted common
stock outstanding are subject to performance objectives. Compensation expense
included in income for restricted stock was $2 million for 2004, $2 million in
2003, and less than $1 million in 2002.

The following table summarizes our stock options outstanding at December
31, 2004:

The number of stock options exercisable was 4,778,488 at December 31, 2004,
5,795,145 at December 31, 2003 and 5,007,329 at December 31, 2002.

In December 2002, we adopted the fair value based method of accounting for
stock-based employee compensation, under SFAS No. 123, as amended by SFAS No.
148. We elected to adopt the prospective method recognition provisions of this
Statement, which applies the recognition provisions to all awards granted,
modified, or settled after the beginning of the fiscal year that the recognition
provisions are first applied.

The following table summarizes the weighted average fair value of stock
options granted:

- -------------------------
(a) There were no stock option grants during 2004.

(b) For 2002, there were two stock option grants totaling 1,492,200 options.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The stock options fair value is estimated using the Black-Scholes model, a
mathematical formula used to value options traded on securities exchanges. The
following assumptions were used in the Black-Scholes model:

- -------------------------
(a) There were no stock option grants during 2004.

(b) For 2002, there were two stock option grants totaling 1,492,200 options.

We recorded $5 million as stock-based employee compensation cost for 2003
and $4 million for 2002. All stock options vest at date of grant.

11: LEASES

We lease various assets, including vehicles, railcars, construction
equipment, furniture, and buildings. We have both full-service and net leases. A
net lease requires us to pay for taxes, maintenance, operating costs, and
insurance. Most of our leases contain options at the end of the initial lease
term to:

- purchase the asset at fair value, or

- renew the lease at fair rental value.

Our capital leases are comprised mainly of leased service vehicles and
office furniture. As of December 31, 2004, capital lease obligations totaled $58
million. Consumers is authorized by the MPSC to record both capital and
operating lease payments as operating expenses and recover the total costs from
their customers. Capital lease expenses were $13 million in 2004, $17 million in
2003, and $20 million in 2002. In November 2003, we exercised our purchase
option under the capital lease agreement for our main headquarters building in
Jackson, Michigan. Operating lease charges were $14 million in 2004, $14 million
in 2003, and $13 million in 2002. Income from subleases was $1 million in 2004
and $1 million in 2003.

In order to obtain permanent financing for the MCV Facility, the MCV
Partnership entered into a sale and lease back agreement with a lessor group,
which includes the FMLP, for substantially all of the MCV Partnership's fixed
assets. In accordance with SFAS No. 98, the MCV Partnership accounted for the
transaction as a financing arrangement. As of December 31, 2004, finance lease
obligations totaled $286 million, which represents the third-party portion of
the MCV Partnership's finance lease obligation.

Charges under the MCV Partnership's finance lease obligation were $105
million in 2004. For additional details on transactions with the MCV Partnership
and the FMLP, see Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies -- The Midland Cogeneration Venture."

CMS-100

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Minimum annual rental commitments under our non-cancelable leases at
December 31, 2004 were:

- -------------------------
(a) Minimum payments have not been reduced by minimum sublease rentals of $2
million due in the future under noncancelable subleases.

12: EQUITY METHOD INVESTMENTS

Where ownership is more than 20 percent but less than a majority, we
account for certain investments in other companies, partnerships, and joint
ventures by the equity method of accounting in accordance with APB Opinion No.
18. Net income from these investments included undistributed earnings of $88
million in 2004, $41 million in 2003, and $39 million in 2002.

The most significant of these investments are:

- our 50 percent interest in Jorf Lasfar, and

- our 40 percent interest in Taweelah.

CMS-101

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

Income Statement Data

CMS-102

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Balance Sheet Data

- -------------------------
(a) Our investment in Jorf Lasfar was $309 million at December 31, 2004 and
$256 million at December 31, 2003. Our share of net income from Jorf Lasfar
was $63 million for the year ended December 31, 2004, $60 million for the
year ended December 31, 2003, and $66 million for the year ended December
31, 2002.

(b) Under Revised FASB Interpretation No. 46, we are the primary beneficiary of
the FMLP and have consolidated their assets, liabilities, and financial
activities for 2004.

(c) In August 2004, we sold our investment in SCP.

(d) For 2003 and 2002, the MCV Partnership was accounted for as an equity
method investment but their summarized financial information is not
included in these tables. Our 49 percent investment in the MCV Partnership
was $419 million at December 31, 2003 and our share of net income was $29
million for the year ended December 31, 2003 and $65 million for the year
ended December 31, 2002. Such information is shown below in the section
"Summarized Financial Information of Significant Related Energy Supplier."
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of
the MCV Partnership. We consolidated their assets, liabilities, and
financial activities into our financial statements as of and for the

CMS-103

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

year ended December 31, 2004. As of December 31, 2004, the MCV Partnership had
total assets of $1.980 billion and a net loss of $24 million for the year.

SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY
SUPPLIER: Under the PPA with the MCV Partnership discussed in Note 3,
Contingencies, our 2003 obligation to purchase electric capacity from the MCV
Partnership provided 15 percent of our owned and contracted electric generating
capacity. Summarized financial information of the MCV Partnership for 2003 and
2002 follows:

Statements of Income

Balance Sheet

- -------------------------
(a) Revenue from Consumers totaled $514 million in 2003 and $557 million in
2002.

(b) On April 1, 2002, the MCV Partnership implemented a new accounting standard
for derivatives. As a result, the MCV Partnership began accounting for
several natural gas contracts containing an option component at fair value.
The MCV Partnership recorded a $58 million cumulative effect adjustment for
the change in accounting principle as an increase to earnings. CMS
Midland's 49 percent ownership share was $28 million ($18 million
after-tax), which is reflected as a change in accounting principle on our
Consolidated Statements of Income (Loss) in 2002.

(c) Receivables from Consumers totaled $40 million for December 31, 2003.

(d) FMLP is the sole beneficiary of a trust that is the lessor in a long-term
direct finance lease with the MCV Partnership. CMS Holdings holds a 46.4
percent ownership interest in the FMLP. The MCV Partnership's

CMS-104

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

lease obligations, assets, and operating revenues secure FMLP's debt. The
following table summarizes obligation and payment information regarding the
direct finance lease.

- -------------------------
(a) In 2003, we performed an impairment test on the Enterprises segment which
determined the book value of our goodwill related to CPEE exceeded the fair
value. Therefore, we recorded a goodwill impairment.

(b) In the fourth quarter of 2004, an impairment charge was recorded to
recognize a reduction in fair value as a result of the sale of GVK, which
included a goodwill impairment of $5 million. We closed on the sale of GVK
in February 2005.

14: JOINTLY OWNED REGULATED UTILITY FACILITIES

We are required to provide only our share of financing for the jointly
owned utility facilities. The direct expenses of the jointly owned plants are
included in operating expenses. Operation, maintenance, and other expenses of
these jointly owned utility facilities are shared in proportion to each
participant's undivided
CMS-105

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

ownership interest. The following table indicates the extent of our investment
in jointly owned regulated utility facilities:

15: REPORTABLE SEGMENTS

Our reportable segments consist of business units organized and managed by
their products and services. We evaluate performance based upon the net income
of each segment. We operate principally in three reportable segments: electric
utility, gas utility, and enterprises.

The electric utility segment consists of regulated activities associated
with the generation and distribution of electricity in the state of Michigan
through our subsidiary, Consumers. The gas utility segment consists of regulated
activities associated with the transportation, storage, and distribution of
natural gas in the state of Michigan through our subsidiary, Consumers. The
enterprises segment consists of:

- investing in, acquiring, developing, constructing, managing, and
operating non-utility power generation plants and natural gas facilities
in the United States and abroad, and

- providing gas, oil, and electric marketing services to energy users.

Accounting policies of our segments are the same as we describe in the
summary of significant accounting policies. Our financial statements reflect the
assets, liabilities, revenues, and expenses directly related to the individual
segments where it is appropriate. We allocate accounts between the segments
where 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. 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, discontinued
operations, and the cumulative effect of accounting changes. The following
tables show our financial information by reportable segment:

Reportable Segments

CMS-106

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

CMS-107

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Geographic Areas(c)

- -------------------------
(a) Amounts includes a portion of Consumers' assets for both the Electric and
Gas utility units.

(b) Amounts include electric restructuring implementation plan, purchase of
nuclear fuel, and other assets. Amounts also include a portion of
Consumers' capital expenditures for plant and equipment that both the
electric and gas utility units use.

(c) Revenues are based on the country location of customers.

16: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST
ENTITIES: The FASB issued this Interpretation in January 2003. The objective of
the Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.

In December 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that had not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.

We determined that we are the primary beneficiary of both the MCV
Partnership and the FMLP. We have a 49 percent partnership interest in the MCV
Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is
the primary purchaser of power from the MCV Partnership through a long-term
power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the
MCV Facility, which results in Consumers holding a 35 percent lessor interest in
the MCV Facility. Collectively, these interests make us the primary beneficiary
of these entities. As such, we consolidated their assets, liabilities, and
activities into our financial statements as of and for the year ended December
31, 2004. These partnerships have third-party obligations totaling $582 million
at December 31, 2004. Property, plant, and equipment serving as collateral for
these

CMS-108

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

obligations has a carrying value of $1.426 billion at December 31, 2004. The
creditors of these partnerships do not have recourse to the general credit of
CMS Energy.

At December 31, 2003, we determined that we are the primary beneficiary of
three other entities that are determined to be variable interest entities. We
have 50 percent partnership interest in the T.E.S. Filer City Station Limited
Partnership, the Grayling Generating Station Limited Partnership, and the
Genesee Power Station Limited Partnership. Additionally, we have operating and
management contracts and are the primary purchaser of power from each
partnership through long-term power purchase agreements. Collectively, these
interests make us the primary beneficiary as defined by the Interpretation.
Therefore, we consolidated these partnerships into our consolidated financial
statements beginning in 2003. These partnerships have third-party obligations
totaling $116 million at December 31, 2004. Property, plant, and equipment
serving as collateral for these obligations has a carrying value of $168 million
as of December 31, 2004. Other than outstanding letters of credit and guarantees
of $5 million, the creditors of these partnerships do not have recourse to the
general credit of CMS Energy.

We determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities were deconsolidated
as of December 31, 2003. Company Obligated Trust Preferred Securities totaling
$663 million that were previously included in mezzanine equity, were eliminated
due to deconsolidation. At December 31, 2004, we reflected Long-term
debt -- related parties of $504 million, current portion of Long-term
debt -- related parties of $180 million, and an investment in related parties of
$21 million.

We are not required to restate prior periods for the impact of this
accounting change.

Additionally, we have variable interest entities in which we are not the
primary beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The following chart details our involvement in
these entities at December 31, 2004:

- -------------------------
(a) At December 31, 2004, the balance includes our proportionate share of the
negative fair value of derivative instruments of $25 million.

Our maximum exposure to loss through our interests in these variable
interest entities is limited to our investment balance of $122 million, and
letters of credit, guarantees, and indemnities relating to Taweelah and
Shuweihat totaling $84 million. In the third quarter of 2004, we contributed an
investment of $70 million in Shuweihat. The contribution was made pursuant to
the Shuweihat Shareholders' Agreement, which was entered into in 2001.

FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS
RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF
2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt

CMS-109

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

from federal taxation, to sponsors of retiree health care benefit plans that
provide a benefit that is actuarially equivalent to Medicare Part D.

We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $158 million. The remeasurement resulted in
a total OPEB cost reduction of $24 million for 2004. Consumers capitalizes a
portion of OPEB cost in accordance with regulatory accounting. As such, the
remeasurement resulted in a net reduction of OPEB expense of $17 million for
2004.

EITF ISSUE NO. 04-8, THE EFFECT OF CONTINGENTLY CONVERTIBLE DEBT ON DILUTED
EARNINGS PER SHARE: At its September 2004 meeting, the EITF reached a final
consensus that contingently convertible instruments should be included in the
diluted earnings per share computation (if dilutive) regardless of whether the
market price trigger has been met.

In December 2004, we completed an exchange offer for our 3.375 percent
contingently convertible senior notes and our 4.50 percent contingently
convertible preferred stock. For additional information, see Note 4, Financings
and Capitalization, "Contingently Convertible Securities."

We adopted the provisions of EITF Issue No. 04-8 as of December 31, 2004.
Upon adoption, our 2004 year-to-date diluted earnings per share was reduced by
$0.01 per share. Adoption of this EITF Issue did not impact our diluted earnings
per share for any prior periods.

FSP 109-1, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE TAX DEDUCTION
PROVIDED TO U.S. BASED MANUFACTURERS BY THE AMERICAN JOBS CREATION ACT OF
2004: The American Jobs Creation Act of 2004 provides for a deduction, starting
in 2005, of a portion of the income from certain production activities,
including the production of electricity. FSP 109-1 indicates that the deduction
should be accounted for as a special deduction rather than a tax rate reduction
under SFAS No. 109. We are currently studying this act for its impact on us;
however, we do not anticipate a material amount of tax benefit from the domestic
production activities deduction in the near future.

FSP 109-2, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE FOREIGN EARNINGS
REPATRIATION PROVISION WITHIN THE AMERICAN JOBS CREATION ACT OF 2004: The
American Jobs Creation Act of 2004 creates a one-year opportunity to receive a
tax benefit for U.S. corporations that reinvest dividends from controlled
foreign corporations in the U.S. in a 12-month period (2005 for CMS Energy).
Although the tax benefit is subject to a number of limitations, we believe that
we have the information necessary to make an informed decision on the impact of
this act on our repatriation plan. FSP 109-2 provides accounting guidance and
disclosure requirements relating to this act. For additional details, see Note
9, Income Taxes.

EITF ISSUE NO. 03-1, THE MEANING OF OTHER-THAN-TEMPORARY IMPAIRMENTS: The
Issue addresses the definition of an other-than-temporary impairment of certain
investments and provides additional disclosure requirements. The scope of EITF
Issue No. 03-1 includes debt and equity securities accounted for under SFAS No.
115, debt and equity securities held by non-profit organizations under SFAS No.
124, and cost method investments under APB No. 18. We analyzed our in-scope
investments under the guidance of this Issue and have provided additional
disclosures.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to
expense the grant date fair value of employee stock options and similar awards.
The Statement also clarifies and expands SFAS No. 123's guidance in several
areas, including measuring fair value, classifying an award as equity or as a
liability, and attributing compensation cost to reporting periods.

CMS-110

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to
require that excess tax benefits related to the excess of the tax deductible
amount over the compensation cost recognized be classified as a financing cash
inflow rather than as a reduction of taxes paid in operating cash flows.

This Statement is effective for us as of the beginning of the third quarter
of 2005. We adopted the fair value method of accounting for share-based awards
effective December 2002, and therefore, expect this Statement to have an
insignificant impact on our results of operations when it becomes effective.

17: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)

CMS-111

CMS ENERGY CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

- -------------------------
(a) As of March 31, 2004, we determined that the MCV Partnership and the FMLP
should be consolidated in accordance with revised FASB Interpretation No.
46. As such, we consolidated their financial activities into our financial
statements as of and for the year ended December 31, 2004. For additional
details, see Note 16, Implementation of New Accounting Standards.

(b) Net of tax.

(c) Quarterly data for March 31, 2004 differs from amounts previously reported
as a result of accelerating the measurement date on our benefit plans by
one month. For additional information, see Note 7, Retirement Benefits.

(d) Quarterly data for March 31, 2004 differs from amounts previously reported
due to the remeasurement of our post retirement benefit obligation in
accordance with FASB Staff Position, No. SFAS 106-2. For additional
information, see Note 16, Implementation of New Accounting Standards.

(e) Sum of the quarters may not equal the annual earnings per share due to
changes in shares outstanding.

(f) Based on New York Stock Exchange -- Composite transactions.

CMS-112

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, 2004 and 2003, and the
related consolidated statements of income (loss), common stockholders' equity
and cash flows for each of three years in the period ended December 31, 2004.
Our audits also included the financial statement schedule 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. The financial statements
of Midland Cogeneration Venture Limited Partnership, a 49% owned variable
interest entity which has been consolidated in 2004 pursuant to Revised
Financial Accounting Standards Board Interpretation No. 46, "Consolidation of
Variable Interest Entities" and accounted for under the equity method of
accounting in 2003 and 2002 and Jorf Lasfar Energy Company S.C.A., which
represents an investment accounted for under the equity method of accounting,
have been audited by other auditors whose reports have been furnished to us;
insofar as our opinion on the consolidated financial statements relates to the
amounts included for Midland Cogeneration Venture Limited Partnership and Jorf
Lasfar Energy Company S.C.A., respectively, it is based solely on their reports.

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 reports of other auditors provide a reasonable basis for our
opinion.

In our opinion, based on our audits and the reports of other auditors, the
consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of CMS Energy Corporation
at December 31, 2004 and 2003, and the consolidated results of their operations
and their cash flows for each of the three years in the period ended December
31, 2004 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 16 to the consolidated financial statements, in 2004,
the Company adopted Revised Financial Accounting Standards Board (FASB)
Interpretation No. 46, "Consolidation of Variable Interest Entities". In
addition, as discussed in Note 7 to the consolidated financial statements, in
2004, the Company changed its measurement date for all CMS Energy Corporation
pension and postretirement benefit plans. As discussed in Notes 6, 8, and 16 to
the consolidated financial statements, in 2003, the Company adopted the
provisions of Statement of Financial Accounting Standards (SFAS) No. 143,
"Accounting for Asset Retirement Obligations", EITF Issue No. 02-03,
"Recognition and Reporting of Gains and Losses on Energy Trading Contracts" and
of FASB Interpretation No. 46, "Consolidation of Variable Interest Entities".

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of CMS
Energy Corporation's internal control over financial reporting as of December
31, 2004, based on criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 7, 2005 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Detroit, Michigan
March 7, 2005

CMS-113

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:

We have completed an integrated audit of Midland Cogeneration Venture
Limited Partnership's 2004 consolidated financial statements and of its internal
control over financial reporting as of December 31, 2004 and audits of its 2003
and 2002 consolidated financial statements in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Our opinions,
based on our audits, are presented below.

CONSOLIDATED FINANCIAL STATEMENTS

In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, partners' equity and cash flows
(not presented herein) present fairly, in all material respects, the financial
position of Midland Cogeneration Limited Partnership (a Michigan limited
partnership) and its subsidiaries (MCV) at December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of MCV'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 of financial
statements 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.

As explained in Note 2 to the financial statements, effective April 1,
2002, Midland Cogeneration Venture Limited Partnership changed its method of
accounting for derivative and hedging activities in accordance with Derivative
Implementation Group ("DIG") Issue C-16.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Also, in our opinion, management's assessment, included in Management's
Report on Internal Control Over Financial Reporting, that MCV maintained
effective internal control over financial reporting as of December 31, 2004
based on criteria established in Internal Control -- Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, MCV maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control -- Integrated Framework issued by COSO.
MCV's management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express opinions on
management's assessment and on the effectiveness of MCV's internal control over
financial reporting based on our audit. We conducted our audit of internal
control over financial reporting 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
effective internal control over financial reporting was maintained in all
material respects. An audit of internal control over financial reporting
includes obtaining an understanding of internal control over financial
reporting, evaluating management's assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.

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,

CMS-114

accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the company's assets that could have a material effect on the financial
statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan
February 25, 2005

CMS-115

REPORT OF INDEPENDENT AUDITORS

To the Management Committee
and Stockholders of Jorf Lasfar
Energy Company S.C.A.
B.P. 99 Sidi Bouzid
El Jadida

We have audited the accompanying balance sheets of Jorf Lasfar Energy
Company S.C.A. (the "Company") as of December 31, 2004, 2003 and 2002, and the
related statements of income, of stockholders' equity and of cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public
Company Accounting Oversight Board (United States of America). 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 statements presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Jorf Lasfar Energy Company
S.C.A. at December 31, 2004, 2003 and 2002, and the results of its operations
and its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States of America.

/s/ Price Waterhouse

Price Waterhouse
Casablanca, Morocco,
February 11, 2005

CMS-116

[CONSUMERS ENERGY LOGO]

2004 CONSOLIDATED FINANCIAL STATEMENTS

CE-1

CONSUMERS ENERGY COMPANY

SELECTED FINANCIAL INFORMATION

- -------------------------
(a) See Notes 1 and 2 in the notes to the consolidated financial statements.

(b) Under revised FASB Interpretation No. 46, we are the primary beneficiary of
the MCV Partnership and the FMLP. As a result, we have consolidated their
assets, liabilities and activities into our financial statements as of and
for the year ended December 31, 2004. These partnerships had third party
obligations totaling $582 million at December 31, 2004. Property, plant and
equipment serving as collateral for these obligations had a carrying value
of $1.426 billion at December 31, 2004.

(c) Effective December 31, 2003, Trust Preferred Securities are classified on
the balance sheets as Long-term debt -- related parties.

(d) Effective November 2002, Michigan Gas Storage Company was merged into
Consumers.

(e) Excludes off-system transportation customers.

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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."

EXECUTIVE OVERVIEW

Consumers, a subsidiary of CMS Energy, a holding company, is a combination
electric and gas utility company that provides service to customers in
Michigan's Lower Peninsula. Our customer base includes a mix of residential,
commercial, and diversified industrial customers, the largest segment of which
is the automotive industry.

We manage our business by the nature of services each provides. We 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 transmission
and storage, and other energy related services. Our businesses are affected
primarily by:

- weather, especially during the traditional heating and cooling seasons,

- economic conditions,

- regulation and regulatory issues,

- interest rates,

- our debt credit rating, and

- energy commodity prices.

Our business strategy involves improving our balance sheet and maintaining
focus on our core strength: superior utility operation and service. Over the
next few years, we expect that this strategy will result in improved credit
ratings, earnings growth, and a company positioned to make new investments.

Despite strong financial and operational performance, we face important
challenges in the future. We continue to lose industrial and commercial
customers to alternative electric suppliers as a result of Michigan's Customer
Choice Act. As of March 2005, we have lost 900 MW, or 12 percent, of our
electric load to these alternative electric suppliers. Based on current trends,
we predict total load loss by the end of 2005 to be in the range of 1,000 MW to
1,200 MW. However, no assurance can be made that the actual load loss will fall
within that range. Existing state legislation encourages competition and
provides for recovery of Stranded Costs caused by the lost sales. In fact, in
November 2004, the MPSC ordered us to recover 2002 and 2003 Stranded Costs in
the amount of $63 million. In 2004, several bills were introduced into the
Michigan Senate that could change Michigan's Customer Choice Act.

Another important challenge relates to the economics of the MCV
Partnership. The MCV Partnership's costs of producing electricity are tied to
the cost of natural gas. Because natural gas prices have increased substantially
in recent years and the price the MCV Partnership can charge us for energy has
not, the MCV Partnership's financial performance has been impacted negatively.
In January 2005, the MPSC issued an order approving the RCP to change the way
the facility is used. The purpose of the RCP is to conserve natural gas through
a change in the dispatch of the MCV Facility and thereby improve the financial
performance of the MCV Partnership without increased costs to customers. The
approved plan will:

- allow for dispatching the MCV Facility based on natural gas market
prices, which is expected to reduce gas consumption by an estimated 30 to
40 bcf per year,

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- allocate 50 percent of our direct savings to customers in 2005 and 70
percent of our direct savings to customers thereafter, and

- fund $5 million annually for renewable energy sources such as wind power
projects.

We are focused on further reducing our business, financial, and regulatory
risks, while growing the equity base of our company. In 2004, we issued over $1
billion in FMBs. Proceeds from these transactions were used to retire other
higher-interest rate long-term debt. Also in 2004, we received cash
contributions from CMS Energy of $250 million, providing additional liquidity
and flexibility for our operations. In January 2005, we continued to retire
higher-interest rate debt through the use of proceeds from the issuance of $250
million of FMBs. We also received an additional cash contribution from CMS
Energy of $200 million in January 2005. The efforts, and others, are designed to
lead us to be a strong, reliable utility company that will be poised to take
advantage of opportunities for further growth.

CONSOLIDATION OF THE MCV PARTNERSHIP AND THE FMLP

Under Revised FASB Interpretation No. 46, we are the primary beneficiary of
the MCV Partnership and the FMLP. As a result, we have consolidated the assets,
liabilities, and activities of these entities into our financial statements as
of and for the year ended December 31, 2004. These entities are reported as
equity method investments in our financial statements for all periods prior to
January 1, 2004. For additional details, see Note 13, Implementation of New
Accounting Standards.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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:

- capital and financial market conditions, including the price of CMS
Energy Common Stock and the effect of such market conditions on the
Pension Plan, interest rates, and access to the capital markets as well
as 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,

- credit ratings of 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,

- international, 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 and/or regulatory lag concerning
a number of significant questions presently before the MPSC relating to
the Customer Choice Act including:

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

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

- power supply and natural gas supply costs when oil prices and other
fuel prices are rapidly increasing,
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- timely recognition in rates of additional equity investments in
Consumers, and

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

- the impact of adverse natural gas prices on the MCV Partnership
investment, and regulatory decisions that limit our recovery of capacity
and fixed energy payments,

- 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 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,

- potential for the Midwest Energy Market to develop into an active energy
market in the state of Michigan, which may lead us to account for
electric capacity and energy contracts with the MCV Partnership and other
independent power producers as derivatives,

- the GAAP requirement that we utilize mark-to-market accounting on certain
of our energy commodity contracts and interest rate swaps, which may
have, in any given period, a significant positive or negative effect on
earnings, which could change dramatically or be eliminated in subsequent
periods and could add to earnings volatility,

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

- nuclear power plant performance, decommissioning, policies, procedures,
incidents, and regulation, including the availability of spent nuclear
fuel storage,

- 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,

- outcome, cost, and other effects of legal and administrative proceedings,
settlements, investigations and claims,

- limitations on our ability to control the development or operation of
projects in which our subsidiaries have a minority interest,

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

- 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, and

- other uncertainties that are difficult to predict, and many of which are
beyond our control.

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RESULTS OF OPERATIONS

NET INCOME AVAILABLE TO COMMON STOCKHOLDER

For the year 2004, our net income available to the common stockholder was
$277 million, compared to net income available to the common stockholder of $194
million for the year 2003. The $83 million increase in net income available to
the common stockholder reflects:

- an $82 million decrease in operating expense, reflecting the MPSC's
approval for recovery of stranded costs for 2002 and 2003, the deferral
of electric depreciation expense on our excess capital expenditures as
permitted by the Customer Choice Act, reduced gas depreciation rates as
authorized by the MPSC, decreased pension costs, and the 2004 reduction
to benefit expense due to the subsidy provided under Part D of the
Medicare Prescription Drug, Improvement and Modernization Act,

- a $73 million increase in other income, reflecting the return on certain
costs recoverable under the Customer Choice Act beginning in 2004,

- an $18 million increase in gas utility revenues due to the MPSC's
December 2003 interim and October 2004 final gas rate orders,

- the absence of a $12 million charge taken in 2003 to reflect a decline in
the market value of CMS Energy common stock held by us,

- a $5 million increase in gas wholesale and retail services and other gas
revenues, primarily due to the absence of a 2003 revenue reduction due to
the 2002-2003 GCR disallowance.

These increases to net income available to the common stockholder were
offset partially by reductions to net income available to the common stockholder
from:

- a $33 million increase in fixed charges because we expensed capitalized
interest on the Clean Air Act costs incurred during the period of June
2000 through December 2003 and increased our average borrowings,

- a $22 million decrease in electric delivery revenue primarily due to
tariff revenue reductions, customers choosing alternative electric
suppliers, and milder summer temperatures' negative impact on air
conditioning usage,

- a $19 million decrease in earnings from our ownership interest in the MCV
Partnership primarily due to increases in non-recoverable fuel costs
incurred at the MCV Facility,

- a $20 million underrecovery of power supply revenue due to
non-recoverable power supply costs related to capped customers,

- an $8 million increase in general taxes primarily due to the absence of a
2003 reduction to MSBT expense from a tax credit received for
construction of our corporate headquarters on a Brownfield site, and

- a $5 million reduction in gas delivery revenue due to milder weather.

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For the year 2003, our net income available to the common stockholder was
$194 million, compared to net income available to the common stockholder of $335
million for the year 2002. The $141 million decrease in net income available to
the common stockholder primarily reflects:

- an $80 million increase in operating expense due to higher pension and
other benefit costs, and increased depreciation and amortization expense,

- a $27 million decrease in electric delivery revenue due to milder summer
weather and the migration of commercial and industrial customers to
alternative electric suppliers,

- a $27 million decline in earnings from our ownership interest in the MCV
Partnership primarily due to the decrease in fair value of certain gas
contracts held by the MCV Partnership,

- a $23 million increase in fixed charges due to higher average debt levels
and higher average interest rates,

- a $7 million charge at CMS Holdings to reflect the loss of certain tax
credits, and

- the absence of a $31 million gain primarily associated with the sale of
our electric transmission system in 2002.

These decreases to net income were offset partially by increases to net
income from:

- a $25 million increase in gas tariff rates authorized by the MPSC in late
2002,

- an $8 million decrease of general tax expense primarily due to reduced
MSBT expense from a tax credit received for building our corporate
headquarters on a Brownfield site, and

- a $17 million benefit from power supply overrecoveries due to lower
average fuel costs and higher market prices for excess capacity sold.

For additional details, see "Electric Utility Results of Operations" and
"Gas Utility Results of Operations" within this section and Note 2,
Contingencies.

ELECTRIC UTILITY RESULTS OF OPERATIONS

ELECTRIC DELIVERIES: For the year 2004, electric deliveries including
transactions with other wholesale marketers, other electric utilities, and
customers choosing alternative electric suppliers increased 1.3 billion kWh or
3.3 percent versus 2003. Despite the increase in electric deliveries, electric
delivery revenue decreased due to the milder summer temperatures' negative
impact on higher margin residential customer air conditioning usage, customers
choosing alternative electric suppliers, and tariff revenue reductions. The
tariff revenue reductions

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began on January 1, 2004, and were equivalent to the Big Rock nuclear
decommissioning surcharge in effect when our electric retail rates were frozen
from June 2000 through December 31, 2003. The tariff revenue reductions
decreased electric delivery revenue by $35 million.

Surcharges related to the recovery of costs incurred in the transition to
customer choice offset partially the reductions to electric delivery revenue.
Recovery of these costs began on July 1, 2004 and increased electric delivery
revenue by $10 million.

For the year 2003, electric delivery revenue decreased, reflecting lower
deliveries versus 2002. Most significantly, sales volumes to commercial and
industrial customers were lower than in 2002, a result of these sectors'
continued migration to alternative electric suppliers as allowed by the Customer
Choice Act. Milder summer temperatures reduced air conditioning usage by the
higher-margin residential customers, further decreasing electric delivery
revenue. Overall, electric deliveries, including transactions with other
wholesale marketers and other electric utilities, decreased 0.4 billion kWh or
1.1 percent.

POWER SUPPLY COSTS AND RELATED REVENUE: For the year 2004, our recovery of
power supply costs was capped for the residential and small commercial customer
classes. Operating income decreased $31 million in 2004 versus 2003 primarily
due to power supply-related costs exceeding power supply-related revenue charged
to capped customers. Power supply-related costs increased in 2004 primarily due
to higher priced purchased power necessary to replace the generation loss from
an extended refueling outage at our Palisades nuclear generating plant and
higher coal prices.

For the year 2003, our recovery of power supply costs was fixed for all
customers, as required under the Customer Choice Act. Therefore, power
supply-related revenue in excess of actual power supply costs increased
operating income. By contrast, if power supply-related revenue had been less
than actual power supply costs, the impact would have decreased operating
income. For the year 2003, power supply-related revenue in excess of actual
power supply costs benefited operating income by $26 million versus 2002. This
increase was primarily the result of increased intersystem revenue, efficient
operation of our generating plants, and lower priced purchased power.

OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: For the
year 2004, other income increased $7 million, other operating expenses decreased
$82 million, and non-commodity revenue decreased $3 million versus 2003. Other
income increased primarily due to $7 million of interest income related to our
2002 and 2003 Stranded Cost recovery as authorized by the MPSC. Our recognition
of this recovery decreased operating expense $57 million in 2004, and along with
decreased depreciation, pension, and benefit costs contributed to the reduction
in other operating expenses. The decrease in depreciation expense reflects our
ability to defer depreciation expense on the excess of capital expenditures over
our depreciation base as authorized by the Customer Choice Act. The decrease in
pension expense reflects fewer current year retirees choosing to receive a
single lump sum distribution, and increased plan earnings from higher average
plan assets. The reduction in benefit expense is due to the subsidy provided
under Part D of the Medicare Prescription Drug, Improvement and Modernization
Act.

For the year 2003, net other operating expenses, other income and
non-commodity revenue decreased operating income versus 2002. The decrease
related to increased pension and other benefit costs, a scheduled refueling
outage at Palisades, and higher transmission costs. In addition, depreciation
and amortization expense increased, reflecting higher levels of plant in
service, and higher amortization of securitized assets. Higher non-commodity
revenue associated with other income offset slightly the increased operating
expenses.

REGULATORY RETURN ON CAPITAL EXPENDITURES: As allowed by Section 10d(4) of
the Customer Choice Act, on January 1, 2004, we began recording the 2004 portion
of the return on certain capital expenditures incurred during the rate freeze
period of June 2000 through December 2003. This increased income by $41 million
in 2004. Based on an interpretation of the Customer Choice Act by the MPSC in a
rate order involving Detroit Edison, in November 2004 we recorded an additional
$72 million return on Clean Air Act costs incurred during the period of June
2000 through December 2003.

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GAIN ON ASSET SALES: The reduction in operating income from asset sales for
2003 versus 2002 reflected the $31 million pretax gain associated with the 2002
sale of our electric transmission system and the $7 million pretax gain
associated with the 2002 sale of nuclear equipment from the cancelled Midland
project.

GENERAL TAXES: For the year 2004, general taxes increased primarily due to
increases in property tax expense and the absence of a MSBT credit received in
2003. The 2003 MSBT credit was associated with the construction of our corporate
headquarters on a qualifying Brownfield site. For the year 2003, this MSBT
credit decreased general taxes versus 2002.

FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to
higher average debt levels, offset partially by a 46 basis point reduction in
the average rate of interest. Additionally, to recognize a recently issued
interpretation of the Customer Choice Act by the MPSC, we expensed $31 million
of capitalized interest in November related to Clean Air Act costs incurred
during the period of June 2000 through December 2003.

For the year 2003, fixed charges increased versus 2002 due to higher
average debt levels and higher average interest rates.

INCOME TAXES: For the year 2004, income taxes increased due to increased
earnings from the electric utility versus 2003. The increase in income taxes
from the tax treatment of items related to plant, property and equipment as
required by past MPSC orders was offset by Part D of the Medicare Prescription
Drug, Improvement and Modernization Act which provides a subsidy that is exempt
from federal taxation. For the year 2003, income tax expense decreased versus
2002 primarily due to lower earnings by the electric utility.

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF TAX EXPENSE: The
measurement date for all of Consumers' plans is November 30 for 2004, and
December 31 for 2003 and 2002. We believe accelerating the measurement date on
our benefit plans by one month is preferable as it improves control procedures
and allows more time to review the completeness and accuracy of the actuarial
measurements. As a result of the measurement date change, we recorded a $1
million, net of tax, cumulative effect adjustment as a decrease to earnings. For
additional details, see Note 5, Retirement Benefits.

GAS UTILITY RESULTS OF OPERATIONS

GAS DELIVERIES: For the year 2004, gas deliveries, including transportation
to end-use customers, decreased 15.5 bcf or 4.6 percent due to milder weather
versus 2003. Most significantly, temperatures in the first quarter of the year
were 12.1 percent warmer than in the same period in 2003.

For the year 2003, gas deliveries, including miscellaneous transportation,
increased due to colder weather during the first quarter of 2003 versus 2002.
Increased deliveries to the residential and commercial sectors resulted in a $6
million increase in gas revenue. This revenue increase was offset by a $7
million reduction to gas revenue associated with our analysis of gas losses
related to the gas transmission and distribution system.

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GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate
order authorizing a $19 million annual increase to gas tariff rates. In October
2004, the MPSC issued a final order authorizing an increase of $58 million in
each of the next two years. As a result of these orders, gas revenues increased
$28 million for the year 2004 versus 2003.

In November 2002, the MPSC issued a final gas rate order authorizing a $56
million annual increase to gas tariff rates. As a result of this order, gas
revenue increased $39 million for the year 2003 versus 2002.

GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUE AND OTHER INCOME: In
2004, gas wholesale and retail services and other gas revenue increased
primarily due to the absence of certain 2003 reductions to revenue. In 2003, gas
revenue was reduced primarily due to an $11 million 2002-2003 GCR disallowance.

For the year 2003, gas wholesale and retail services and other gas revenue
increased versus 2002. This increase was primarily due to increased gas title
tracking services and miscellaneous revenue in 2003. The increased revenue was
offset partially by a disallowance for the 2002-2003 GCR year.

OPERATION AND MAINTENANCE: For the year 2004 versus 2003, operation and
maintenance expenses decreased versus 2003 primarily due to reduced pension and
benefit expense of $23 million. The decrease in pension expense reflects fewer
current year retirees choosing to receive a single lump sum distribution, and
increased plan earnings from higher average plan assets. The reduction in
benefit expense is due to the subsidy provided under Part D of the Medicare
Prescription Drug, Improvement and Modernization Act. These reductions were
offset partially by additional expenditures on safety, reliability, and customer
service.

For the year 2003, operation and maintenance expenses increased versus 2002
due to increases in pension and other benefit costs of $27 million and
additional expenditures on safety, reliability, and customer service.

GENERAL TAXES: For the year 2004, general taxes increased due to the
absence of a MSBT credit received in 2003. The 2003 MSBT credit received from
the State of Michigan was associated with the construction of our corporate
headquarters on a qualifying Brownfield site. For the year 2003, this MSBT
credit decreased general taxes versus 2002.

DEPRECIATION: For the year 2004 versus 2003, depreciation expense decreased
primarily due to reduced rates authorized by the MPSC's December 2003 interim
rate order and the MPSC's October 2004 order, as modified by its December 2004
order granting rehearing. For the year 2003, depreciation expense increased
because of increased plant in service versus 2002.

FIXED CHARGES: Fixed charges increased for the year 2004 versus 2003 due to
higher average debt levels, offset partially by a 46 basis point reduction in
the average rate of interest. For the year 2003, fixed charges increased versus
2002 due to higher average debt levels and higher average interest rates.

INCOME TAXES: For the year 2004, income taxes increased due to increased
earnings from the gas utility versus 2003. The increase in income taxes was
offset partially by reductions from the tax treatment of items related to plant,
property and equipment as required by past MPSC orders, and by Part D of the
Medicare Prescription Drug, Improvement and Modernization Act which provides a
subsidy that is exempt from federal taxation.

For the year 2003 versus 2002, income tax expense increased primarily due
to the tax treatment of items related to plant, property and equipment as
required by past MPSC orders.

CRITICAL ACCOUNTING POLICIES

The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A:

- use of estimates and assumptions in accounting for contingencies and
equity method investments,

- accounting for the effects of industry regulation,

- accounting for financial and derivative instruments and market risk
information,

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- accounting for pension and OPEB,

- accounting for asset retirement obligations,

- accounting for nuclear decommissioning costs, and

- accounting for related party transactions.

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

USE OF ESTIMATES AND ASSUMPTIONS

In preparing our financial statements, we use estimates and assumptions
that may affect reported amounts and disclosures. Accounting estimates are used
for asset valuations, depreciation, amortization, financial and derivative
instruments, employee benefits, and contingencies. For example, we estimate the
rate of return on plan assets and the cost of future health-care benefits to
determine our annual pension and other postretirement benefit costs. There are
risks and uncertainties that may cause actual results to differ from estimated
results, such as changes in the regulatory environment, competition, regulatory
decisions, and lawsuits.

CONTINGENCIES: We are involved in various regulatory and legal proceedings
that arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that the occurrence of loss is probable
and the amount of loss can be reasonably estimated. The recording of estimated
liabilities for contingencies is guided by the principles in SFAS No. 5. We
consider many factors in making these assessments, including history and the
specifics of each matter. The most significant of these contingencies are our
electric and gas environmental estimates, which are discussed in the "Outlook"
section included in this MD&A, and the potential underrecoveries from our power
purchase contract with the MCV Partnership.

MCV UNDERRECOVERIES: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990 and to supply electricity and steam to Dow. We hold a 49
percent partnership interest in the MCV Partnership, and a 35 percent lessor
interest in the MCV Facility.

The cost that we incur under the MCV Partnership PPA exceeds the recovery
amount allowed by the MPSC. As a result, we estimate that cash underrecoveries
of capacity and fixed energy payments will aggregate $150 million from 2005
through 2007. After September 15, 2007, we expect to claim relief under the
regulatory out provision in the PPA, thereby limiting our capacity and fixed
energy payments to the MCV Partnership to the amounts collected from our
customers. The effect of any such action would be to:

- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and

- eliminate our underrecoveries of capacity and fixed energy payments.

The MCV Partnership has indicated that it may take issue with our exercise
of the regulatory out clause after September 2007. We believe that the clause is
valid and fully effective, but cannot assure that it will prevail in the event
of a dispute. The MPSC's future actions on the capacity and fixed energy
payments recoverable from customers subsequent to September 2007 may affect
negatively the earnings of the MCV Partnership and the value of our investment
in the MCV Partnership.

Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned at our coal plants and our operation and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been impacted negatively. Even with the approved RCP, if gas prices continue at
present levels or increase, the economics of operating the MCV Facility may be
adverse enough to require us to recognize an impairment.

In January 2005, the MPSC issued an order approving the RCP, with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce

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the MCV Facility's annual production of electricity and, as a result, reduce the
MCV Facility's consumption of natural gas by an estimated 30 to 40 bcf annually.
This decrease in the quantity of high-priced natural gas consumed by the MCV
Facility will benefit our ownership interest in the MCV Partnership.

The substantial MCV Facility fuel cost savings will be used first to offset
fully the cost of replacement power. Second, $5 million annually will be used to
fund a renewable energy program. Remaining savings will be split between the MCV
Partnership and Consumers. Consumers' direct savings will be shared 50 percent
with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct
savings from the RCP, after a portion is allocated to customers, will be used to
offset our capacity and fixed energy underrecoveries expense. Since the MPSC has
excluded these underrecoveries from the rate making process, we anticipate that
our savings from the RCP will not affect our return on equity used in our base
rate filings.

In January 2005, Consumers and the MCV Partnership's general partners
accepted the terms of the order and implemented the RCP. The underlying
agreement for the RCP between Consumers and the MCV Partnership extends through
the term of the PPA. However, either party may terminate that agreement under
certain conditions. In February 2005, a group of intervenors in the RCP case
filed an application for rehearing of the MPSC order. The Attorney General also
filed a claim of appeal with the Michigan Court of Appeals. We cannot predict
the outcome of these appeals.

For additional details on the MCV Partnership, see Note 2, Contingencies,
"Other Electric Contingencies -- The Midland Cogeneration Venture."

ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION

Because we are involved in a regulated industry, regulatory decisions
affect the timing and recognition of revenues and expenses. We use SFAS No. 71
to account for the effects of these regulatory decisions. 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 such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. As of
December 31, 2004, we had $1.696 billion recorded as regulatory assets and
$1.574 billion recorded as regulatory liabilities.

For additional details on industry regulation, see Note 1, Corporate
Structure and Accounting Policies, "Utility Regulation."

ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION

FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities classified as
available-for-sale are reported at fair value determined from quoted market
prices. Debt and equity securities classified as held-to-maturity are reported
at cost. Unrealized gains or losses resulting from changes in fair value of
certain available-for-sale debt and equity securities are reported, net of tax,
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless the related changes in fair value are
determined to be other than temporary.

Unrealized gains or losses on our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized
gains or losses would not affect our earnings or cash flows.

DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if
certain contracts must be accounted for as derivative instruments. This criteria
is complex and significant judgment is often required in applying the criteria
to specific contracts. If a contract is accounted for as a derivative
instrument, it is recorded in the financial statements as an asset or a
liability at the fair value of the contract. The recorded fair value is then
adjusted quarterly to reflect any change in the market value of the contract, a
practice known as marking the contract to market. Changes in fair value (that
is, gains or losses) are reported either in earnings or accumulated

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other comprehensive income, depending on whether the derivative qualifies for
cash flow hedge accounting treatment.

The types of contracts we typically classify as derivative instruments are
interest rate swaps, electric call options, gas supply call and put options, gas
fuel futures and swaps, gas fuel options, and certain gas fuel contracts. The
majority of our contracts are not subject to derivative accounting under SFAS
No. 133 because they qualify for the normal purchases and sales exception, or
because there is not an active market for the commodity. Our electric capacity
and energy contracts are not accounted for as derivatives due to the lack of an
active energy market in the state of Michigan and the significant transportation
costs that would be incurred to deliver the power under the contracts to the
closest active energy market at the Cinergy hub in Ohio. Similarly, our coal
purchase contracts are not accounted for as derivatives due to the lack of an
active market for the coal that we purchase. If active markets for these
commodities develop in the future, we may be required to account for these
contracts as derivatives, and the resulting mark-to-market impact on earnings
could be material to our financial statements.

The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005,
which will include day-ahead and real-time energy market information and
centralized dispatch for market participants. At this time, we believe that the
commencement of this market will not constitute the development of an active
energy market in the state of Michigan. However, after having adequate
experience with the Midwest Energy Market, we will reevaluate whether or not the
activity level within this market leads to the conclusion that an active energy
market exists. For additional information, see "Electric Business
Uncertainties -- Competition and Regulatory Restructuring -- Transmission Market
Developments" within this MD&A.

The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. The MCV Partnership believes that
certain of its long-term gas contracts qualify as normal purchases under SFAS
No. 133, and therefore, these contracts are not recognized at fair value on the
balance sheet. Due to the implementation of the RCP in January 2005, the MCV
Partnership has determined that a significant portion of its gas fuel contracts
no longer qualify as normal purchases because the contracted gas will not be
consumed as fuel for electric production. Accordingly, these contracts will be
treated as derivatives and will be marked-to-market through earnings each
quarter, which could increase earnings volatility. Based on market prices for
natural gas as of January 31, 2005, the accounting for the MCV Partnership's
long-term gas contracts, including those affected by the implementation of the
RCP, could result in an estimated $100 million (pretax before minority interest)
gain recorded to earnings in the first quarter of 2005. This estimated gain will
reverse in subsequent quarters as the contracts settle. For further details on
the RCP, see "Critical Accounting Policies -- Use of Estimates and
Assumptions -- MCV Underrecoveries" within this MD&A. If there are further
changes in the level of planned electric production or gas consumption, the MCV
Partnership may be required to account for additional long-term gas contracts as
derivatives, which could add to earnings volatility.

To determine the fair value of our derivative contracts, we use a
combination of quoted market prices, prices obtained from external sources, such
as brokers, and mathematical valuation models. Valuation models require various
inputs, including forward prices, strike prices, volatilities, interest rates,
and maturity dates. Changes in forward prices or volatilities could change
significantly the calculated fair value of certain contracts. At December 31,
2004, we assumed a market-based interest rate of 2.75 percent and monthly
volatility rates ranging between 60 percent and 73 percent to calculate the fair
value of our gas options. At December 31, 2004, we assumed market-based interest
rates ranging between 2.40 percent and 4.48 percent (depending on the term of
the contract) and monthly volatility rates ranging between 25 percent and 68
percent to calculate the fair value of the gas fuel derivative contracts held by
the MCV Partnership.

In certain contracts, long-term commitments may extend beyond the period in
which market quotations for such contracts are available. Mathematical models
are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. In connection with the market valuation of our derivative contracts, we
maintain reserves, if necessary, for credit risks based on the financial
condition of counterparties.

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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 manage these risks using established policies and procedures, under
the direction of both an executive oversight committee consisting of senior
management representatives and a risk committee consisting of business-unit
managers. We may use various derivative contracts to manage these risks,
including swaps, options, futures, and forward contracts. We intend that any
gains or losses on these contracts will be offset by an opposite movement in the
value of the item at risk. We enter into all risk management contracts for
purposes other than trading.

These contracts contain credit risk if the counterparties, including
financial institutions and energy marketers, fail to perform under the
agreements. We minimize such risk through established credit policies that
include performing financial credit reviews of our counterparties. Determination
of our counterparties' credit quality is based upon a number of factors,
including credit ratings, disclosed financial condition, and collateral
requirements. Where contractual terms permit, we employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies and our current exposures, we do not
anticipate a material adverse effect on our financial position or earnings as a
result of counterparty nonperformance.

The following risk sensitivities indicate the potential loss in fair value,
cash flows, or future earnings from our derivative contracts and other financial
instruments based upon a hypothetical 10 percent adverse change in market rates
or prices. Changes in excess of the amounts shown in the sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses.

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 a 10 percent adverse
change in market interest rates):

- ------------------------

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

Commodity Price Risk: For purposes other than trading, we enter into
electric call options and gas supply call and put options. Electric call options
are purchased to protect against the risk of fluctuations in the market price of
electricity, and to ensure a reliable source of capacity to meet our customers'
electric needs. Purchased electric call options give us the right, but not the
obligation, to purchase electricity at predetermined fixed prices. Our gas
supply call and put options are used to purchase reasonably priced gas supply.
Purchases of gas supply call options give us the right, but not the obligation,
to purchase gas supply at predetermined fixed prices. Gas supply put options
sold give third-party suppliers the right, but not the obligation, to sell gas
supply to us at predetermined fixed prices. At December 31, 2004, we held gas
supply call options and had sold gas supply put options.

The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation and to manage gas fuel costs. Some of these contracts are treated as
derivative instruments. The MCV Partnership also enters into natural gas futures
contracts, option contracts, and over-the-counter swap transactions in order to
hedge against unfavorable changes in the market price of natural gas in future
months when gas is expected to be needed. These financial instruments are being
used principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements.

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

We did not perform a sensitivity analysis for the derivative contracts held
by the MCV Partnership as of December 31, 2003, because the MCV Partnership was
not consolidated into our financial statements until 2004, as discussed in Note
13, Implementation of New Accounting Standards.

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:

- ------------------------

(a) Primarily SERP investments and investments in CMS Energy common stock.

(b) Assumes a 10 percent adverse change in market prices.

(c) Assumes a 50 basis point increase in the yield to maturity of the 10-year
Treasury Note which approximates a 10 percent change in market yields.

We maintain trust funds, as required by the NRC, which may only be used to
fund certain costs of nuclear plant decommissioning. As of December 31, 2004 and
2003, these funds were invested primarily in equity securities, fixed-rate,
fixed-income debt securities, and cash and cash equivalents, and are recorded at
fair value on our Consolidated Balance Sheets. Those investments are exposed to
price fluctuations in equity markets and changes in interest rates. Because the
accounting for nuclear plant decommissioning recognizes that costs are recovered
through our electric rates, fluctuations in equity prices or interest rates do
not affect consolidated earnings or cash flows.

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

ACCOUNTING FOR PENSION AND OPEB

Pension: We have established external trust funds to provide retirement
pension benefits to our employees under a non-contributory, defined benefit
Pension Plan. We implemented a cash balance plan for certain employees hired
after June 30, 2003. We use SFAS No. 87 to account for pension costs.

401(k): In our effort to reduce costs, the employer's match for the 401(k)
plan was suspended effective September 1, 2002. The employer's match for the
401(k) plan resumed on January 1, 2005.

OPEB: We provide postretirement health and life benefits under our OPEB
plan to substantially all our retired employees. We use SFAS No. 106 to account
for other postretirement benefit costs.

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Liabilities for both pension and OPEB are recorded on the balance sheet at
the present value of their future obligations, net of any plan assets. The
calculation of the liabilities and associated expenses requires the expertise of
actuaries. Many assumptions are made 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.

Any change in these assumptions can significantly change the liability and
associated expenses recognized in any given year.

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

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 8.75 percent to 8.50 percent) would increase estimated
pension cost for 2005 by $3 million. Lowering the discount rate by 0.25 percent
(from 6.00 percent to 5.75 percent) would increase estimated pension cost for
2005 by $4 million.

For additional details on postretirement benefits, see Note 5, Retirement
Benefits.

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

SFAS No. 143 became effective January 2003. It requires companies 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, including our nuclear plants, at the end of their useful
lives. As required by SFAS No. 71, we accounted for the implementation of this
standard by recording regulatory assets and liabilities instead of a cumulative
effect of a change in accounting principle.

The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. 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, gas transmission and electric and gas distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets. Also, no liability has been recorded for assets that have
insignificant cumulative disposal costs, such as substation batteries. The
measurement of the ARO liabilities for Palisades and Big Rock are based on
decommissioning studies that largely utilize third-party cost estimates. For
additional details on ARO, see Note 6, Asset Retirement Obligations.

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ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS

The MPSC and the FERC regulate the recovery of costs to decommission our
Big Rock and Palisades nuclear plants. We have established external trust funds
to finance the decommissioning of both plants. We record the trust fund balances
as a non-current asset on our Consolidated Balance Sheets.

Our decommissioning cost estimates for the Big Rock and Palisades plants
assume:

- each plant site will be restored to conform to the adjacent landscape,

- all contaminated equipment and material will be removed and disposed of
in a licensed burial facility, and

- the site will be released for unrestricted use.

Independent contractors with expertise in decommissioning have helped us
develop decommissioning cost estimates. Various inflation rates for labor,
non-labor, and contaminated equipment disposal costs are used to escalate these
cost estimates to the future decommissioning cost. A portion of future
decommissioning cost will result from the failure of the DOE to remove fuel from
the sites, as required by the Nuclear Waste Policy Act of 1982.

The decommissioning trust funds include equities and fixed income
investments. Equities will be converted to fixed income investments during
decommissioning, and fixed income investments are converted to cash as needed.
The funds provided by the trusts, additional customer surcharges, and potential
funds from the DOE litigation are all required to cover fully the
decommissioning costs. The costs of decommissioning these sites and the adequacy
of the trust funds could be affected by:

- variances from expected trust earnings,

- a lower recovery of costs from the DOE and lower rate recovery from
customers, and

- changes in decommissioning technology, regulations, estimates, or
assumptions.

Based on current projections, the current level of funds provided by the
trusts is not adequate to fund fully the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel on schedule and lower returns on the trust funds. We are attempting to
recover our additional costs for storing spent nuclear fuel through litigation.
We are also seeking additional relief from the MPSC. For additional details on
nuclear decommissioning, see Note 2, Contingencies, "Other Electric
Contingencies -- Nuclear Plant Decommissioning" and "Nuclear Matters."

RELATED PARTY TRANSACTIONS

We enter into a number of significant transactions with related parties.
These transactions include:

- issuance of trust preferred securities with Consumers' affiliated
companies,

- purchase and sale of electricity from and to Enterprises,

- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,

- payment of parent company overhead costs to CMS Energy, and

- investment in CMS Energy Common Stock.

Transactions involving CMS Energy and its affiliates generally are based on
regulated prices, market prices, or competitive bidding. 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", and Note 2,
Contingencies, "Other Electric Contingencies -- The Midland Cogeneration
Venture."

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CAPITAL RESOURCES AND LIQUIDITY

Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
working capital needs, and collateral requirements. During the summer months, we
purchase natural gas and store it for resale primarily during the winter heating
season. The market price for natural gas has increased. Although our natural gas
purchases are recoverable from our customers, the amount paid for natural gas
stored as inventory could require additional liquidity due to the timing of the
cost recoveries. In addition, a few of our commodity suppliers have requested
nonstandard payment terms or other forms of assurances, including margin calls,
in connection with maintenance of ongoing deliveries of gas and electricity.

Our current financial plan includes controlling our operating expenses and
capital expenditures and evaluating market conditions for financing
opportunities. We believe our current level of cash and access to borrowing
capacity in the capital markets, along with anticipated cash flows from
operating and investing activities, will be sufficient to meet our liquidity
needs through 2006.

CASH POSITION, INVESTING, AND FINANCING

Our operating, investing, and financing activities meet consolidated cash
needs. At December 31, 2004, $192 million consolidated cash was on hand, which
includes $21 million of restricted cash and $126 million from the effect of
Revised FASB Interpretation No. 46 consolidation. For additional details on cash
equivalents and restricted cash, see Note 1, Corporate Structure and Accounting
Policies. For additional details on FASB Interpretation No. 46, see Note 13,
Implementation of New Accounting Standards.

SUMMARY OF CASH FLOWS:

OPERATING ACTIVITIES:

2004: Net cash provided by operating activities increased $635 million in
2004. The absence, in 2004, of $501 million in pension contributions made in
2003, the reduced effect of rising gas prices on inventory, and other timing
differences represent the majority of the increase. These increases more than
offset an increase in accounts receivable and accrued revenue resulting from
higher gas prices.

2003: Net cash provided by operating activities decreased $755 million in
2003 primarily due to an increase in pension plan contributions of $454 million
and an increase in gas inventory of $346 million due to higher gas purchases at
higher prices.

INVESTING ACTIVITIES:

2004: Net cash used in investing activities increased $34 million in 2004
primarily due to an increase in capital expenditures of $22 million. The
increase in capital expenditures resulted from the consolidation of the MCV
Partnership and the FMLP.

2003: Net cash used in investing activities increased $203 million in 2003
primarily due to a decrease in asset sale proceeds of $288 million resulting
from the sale of METC in 2002, offset by a decrease in 2003 versus 2002 capital
expenditures of $73 million as a result of our strategic plan to reduce capital
expenditures.

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FINANCING ACTIVITIES:

2004: Net cash used in financing activities increased $452 million in 2004
primarily due to a decrease in net proceeds from borrowings of $699 million.
This decrease was offset by a $250 million stockholder's contribution from the
parent.

2003: Net cash provided by financing activities increased $529 million in
2003 primarily due to an increase in net proceeds from borrowings of $490
million.

For additional details on long-term debt activity, see Note 3, Financings
and Capitalization.

SUBSEQUENT FINANCING ACTIVITIES:

In January 2005, we issued $250 million of 5.15 percent FMBs due 2017. We
used the net proceeds of $247 million to pay off our $60 million long-term bank
loan, to redeem our $73 million 8.36 percent subordinated deferrable interest
notes, and to redeem our $124 million 8.20 percent subordinated deferrable
interest notes. The subordinated deferrable interest notes are classified as
Long-term debt -- related parties on our accompanying Consolidated Balance
Sheets.

OBLIGATIONS AND COMMITMENTS

CONTRACTUAL OBLIGATIONS: The following table summarizes our contractual
cash obligations for each of the periods presented. The table shows the timing
and effect that such obligations are expected to have 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. The majority of current
liabilities will be paid in cash in 2005.

CONTRACTUAL OBLIGATIONS AS OF DECEMBER 31, 2004

Long-Term Debt: The amounts in the table above represent the principal
amounts due on outstanding debt obligations, current and long-term, as of
December 31, 2004. For additional details on long-term debt, see Note 3,
Financings and Capitalization.

Interest Payments on Long-term Debt: The amounts in the table above
represent the 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, 2004.

Capital and Finance Leases: The amounts in the table above represent the
minimum lease payments payable under our capital and finance leases. They are
comprised mainly of the leased portion of the MCV Partnership facility, leased
service vehicles, and leased office furniture.

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Interest Payments on Capital and Finance Leases: The amounts in the table
represent imputed interest in the capital leases and currently scheduled
interest payments on the finance leases.

Operating Leases: The amounts in the table above represent the 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.

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

- natural gas,

- electricity,

- coal and associated transportation, and

- electric transmission.

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 $14 million per month during 2005. If a plant is not available to
deliver electricity, we are not obligated to make the capacity payments to the
plant for that period of time. For additional details on power supply costs, see
"Electric Utility Results of Operations" within this MD&A and Note 2,
Contingencies, "Electric Rate Matters -- Power Supply Costs."

Long-term Service Agreements: These obligations of the MCV Partnership
represent the cost of the current MCV Facility maintenance service agreements
and cost of spare parts.

REVOLVING CREDIT FACILITIES: At December 31, 2004, we had $475 million
available and the MCV Partnership had $48 million available in revolving credit
facilities. The facilities are available for general corporate purposes, working
capital, and letters of credit. For additional details on revolving credit
facilities, see Note 3, Financings and Capitalization.

OFF-BALANCE SHEET ARRANGEMENTS: We enter into guarantee arrangements in the
normal course of business to facilitate commercial transactions with third
parties. These arrangements include letters of credit, surety bonds and
indemnifications. For additional details on guarantee arrangements, see Note 3,
Financings and Capitalization, "FASB Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others," and in "Commercial Commitments" within
this section.

Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. For
additional details, see Note 3, Financings and Capitalization.

COMMERCIAL COMMITMENTS: Our commercial contingent commitments include
indemnities and letters of credit. Indemnities are agreements to reimburse other
companies, such as an insurance company, if those companies have to complete our
contractual performance in a third-party contract. Banks, on our behalf, issue
letters of credit guaranteeing payment to a third party. Letters of credit
substitute the bank's credit for ours and reduce credit risk for the third-party
beneficiary. We monitor these obligations and believe it is unlikely that we

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would be required to perform or otherwise incur any material losses associated
with these guarantees. Our off-balance sheet commitments at December 31, 2004
will expire as follows:

CONTINGENT COMMITMENTS

- -------------------------
(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis.

(b) The $2 million letter of credit for workers compensation self insurance and
$5 million of MDEQ letters of credit are renewed annually.

DIVIDEND RESTRICTIONS: Under the provisions of our articles of
incorporation, at December 31, 2004, we had $456 million of unrestricted
retained earnings available to pay common stock dividends. However, covenants in
our debt facilities cap common stock dividend payments at $300 million in a
calendar year. In October 2004, the MPSC rescinded its December 2003 interim gas
rate order, which included a $190 million annual dividend cap. For the year
ended December 31, 2004, we paid $190 million in common stock dividends to CMS
Energy.

CAPITAL EXPENDITURES: We estimate that we will make the following capital
expenditures, including new lease commitments, by expenditure type and by
business segments during 2005 through 2007. We prepare these estimates for
planning purposes and may revise them.

- -------------------------
(a) These amounts include a portion of our anticipated capital expenditures for
plant and equipment attributable to both the electric and gas utility
businesses.

(b) These amounts include estimates for capital expenditures that may be
required by revisions to the Clean Air Act's national air quality
standards.

OUTLOOK

ELECTRIC BUSINESS OUTLOOK

GROWTH: In 2004, we experienced cooler than normal summer weather. As a
result, our electric deliveries in 2004, including deliveries to customers who
chose to buy generation service from alternative electric suppliers, increased
less than one-half of one percent over the levels experienced in 2003. In 2005,
we project electric deliveries to grow almost three percent. This short-term
outlook for 2005 assumes a stronger economy than in 2004 and normal weather
conditions throughout the year.

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Over the next five years, we expect electric deliveries to grow at an
average rate of approximately two percent per year, based primarily on a
steadily growing customer base and economy. This growth rate includes both
full-service sales and delivery service to customers who choose to buy
generation service from an alternative electric supplier, but excludes
transactions with other wholesale market participants and other electric
utilities. This growth rate reflects a long-range expected trend of growth.
Growth from year to year may vary from this trend due to customer response to
fluctuations in weather conditions and changes in economic conditions, including
utilization and expansion of manufacturing facilities.

ELECTRIC BUSINESS UNCERTAINTIES

Several electric business trends or uncertainties may affect our financial
results and condition. These trends or uncertainties have, or we reasonably
expect could have, a material impact on revenues or income from continuing
electric operations. Such trends and uncertainties include:

Environmental

- increasing capital expenditures and operating expenses for Clean Air Act
compliance and/or Clear Skies legislation compliance,

- compliance with legislative proposals that would require reductions in
emissions of greenhouse gases, and

- potential environmental liabilities arising from various environmental
laws and regulations, including potential liability or expenses relating
to the Michigan Natural Resources and Environmental Protection Acts and
Superfund.

Restructuring

- response of the MPSC and Michigan legislature to electric industry
restructuring issues,

- ability to meet peak electric demand requirements at a reasonable cost,
without market disruption,

- recovery of our Section 10d(4) Regulatory Assets,

- effects of lost electric supply load to alternative electric suppliers,
and

- status as an electric transmission customer instead of an electric
transmission owner and the impact of the evolving RTO infrastructure.

Regulatory

- financial and operating effects of regulatory requirements imposed by the
MISO, the FERC, state and federal regulators, or others, seeking to
improve reliability of national and state transmission systems,

- inadequate regulatory response to applications for requested rate
increases,

- responses from regulators regarding the storage and ultimate disposal of
spent nuclear fuel,

- recovery of nuclear decommissioning costs. For additional details, see
"Accounting for Nuclear Decommissioning Costs" within this MD&A, and

- potential for the Midwest Energy Market to develop into an active energy
market in the state of Michigan and the potential derivative accounting
impact. For additional details, see "Accounting for Financial and
Derivative Instruments and Market Risk Information" within this MD&A.

Other

- effects of commodity fuel prices such as natural gas, oil, and coal,

- pending litigation filed by PURPA qualifying facilities, and

- other pending litigation.

For additional details about these trends or uncertainties, see Note 2,
Contingencies.

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ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to
environmental laws and regulations. Costs to operate our facilities in
compliance with these laws and regulations generally have been recovered in
customer rates.

Clean Air: Compliance with the federal Clean Air Act and resulting
regulations has been, and will continue to be, a significant focus for us. The
Title I provisions of the Clean Air Act require significant reductions in
nitrogen oxide emissions. To comply with the regulations, we expect to incur
capital expenditures totaling $802 million. The key assumptions included in the
capital expenditure estimate include:

- construction commodity prices, especially construction material and
labor,

- project completion schedules,

- cost escalation factor used to estimate future years' costs, and

- allowance for funds used during construction (AFUDC) rate.

Our current capital cost estimates include an escalation rate of 2.6
percent and an AFUDC capitalization rate of 8.06 percent. As of December 31,
2004, we have incurred $525 million in capital expenditures to comply with these
regulations and anticipate that the remaining $277 million of capital
expenditures will be made between 2005 and 2011. These expenditures include
installing selective catalytic reduction technology at four of our coal-fired
electric plants. In addition to modifying the coal-fired electric plants, we
expect to utilize nitrogen oxide emissions allowances for years 2005 through
2009, most of which have been purchased. The cost of the allowances is estimated
to average $8 million per year for 2005-2006. The need for allowances will
decrease after year 2006 with the installation of emissions control technology.
The cost of the allowances is accounted for as inventory. The allowance
inventory is expensed as the coal-fired electric generating units emit nitrogen
oxide.

The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.

The EPA has proposed a Clean Air Interstate Rule that would require
additional coal-fired electric plant emission controls for nitrogen oxides and
sulfur dioxide. If implemented, this rule potentially would require expenditures
equivalent to those efforts in progress to reduce nitrogen oxide emissions as
required under the Title I provisions of the Clean Air Act. The rule proposes a
two-phase program to reduce emissions of sulfur dioxide by 70 percent and
nitrogen oxides by 65 percent by 2015. Additionally, the EPA also proposed two
alternative sets of rules to reduce emissions of mercury from coal-fired
electric plants and nickel from oil-fired electric plants. Until the proposed
environmental rules are finalized, an accurate cost of compliance cannot be
determined.

Our switch to western coal as a primary fuel source has resulted in reduced
plant emissions and increased our flexibility in meeting future regulatory
compliance requirements. Excess sulfur dioxide allowances optimize our overall
cost of regulatory compliance by delaying capital expenditures and minimizing
regulatory uncertainty. Additionally, the excess sulfur dioxide allowances can
be used to trade for nitrogen oxide allowances supplementing our nitrogen oxide
allowance bank. Western coal has reduced our overall cost of fuel and reduced
the economic impact from the recent increases in eastern coal prices.

Several legislative proposals have been introduced in the United States
Congress that would require reductions in emissions of greenhouse gases,
however, none have yet been enacted. We cannot predict whether any federal
mandatory greenhouse gas emission reduction rules ultimately will be enacted, or
the specific requirements of any such rules.

To the extent that greenhouse gas emission reduction rules come into
effect, such mandatory emissions reduction requirements could have far-reaching
and significant implications for the energy sectors. We cannot estimate the
potential effect of federal or state level greenhouse gas policy on our future
consolidated results of

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operations, cash flows, or financial position due to the speculative nature of
the policies at this time. However, we stay abreast of and engage in the
greenhouse gas policy developments and will continue to assess and respond to
their potential implications on our business operations.

Water: In March 2004, the EPA issued rules that govern generating plant
cooling water intake systems. The new rules require significant reduction in
fish killed by operating equipment. Some of our facilities will be required to
comply with the new rules by 2006. We are currently studying the rules to
determine the most cost-effective solutions for compliance.

For additional details on electric environmental matters, see Note 2,
Contingencies, "Electric Contingencies -- Electric Environmental Matters."

COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act
and other developments will continue to result in increased competition in the
electric business. The Customer Choice Act allows all of our electric customers
to buy electric generation service from us or from an alternative electric
supplier. As of March 2005, alternative electric suppliers are providing 900 MW
of generation supply to ROA customers. This amount represents 12 percent of our
distribution load and an increase of 23 percent compared to March 2004. Based on
current trends, we predict total load loss by the end of 2005 to be in the range
of 1,000 MW to 1,200 MW. However, no assurance can be made that the actual load
loss will fall within that range.

In July 2004, as a result of legislative hearings, several bills were
introduced into the Michigan Senate that could change Michigan's Customer Choice
Act. The proposals include:

- requiring that all rate classes of regulated utilities be based on cost
of service,

- establishing a defined Stranded Cost calculation method,

- allowing customers who stay with or switch to alternative electric
suppliers after December 31, 2005 to return to utility services, and
requiring them to pay current market rates upon return,

- establishing reliability standards that all electric suppliers must
follow,

- requiring utilities and alternative electric suppliers to maintain a 15
percent power reserve margin,

- creating a service charge to fund the Low Income and Energy Efficiency
Fund,

- giving kindergarten through twelfth-grade schools a discount of 10
percent to 20 percent on electric rates, and

- authorizing a service charge payable by all customers for meeting Clean
Air Act requirements.

This legislation was not enacted before the end of the 2003-2004
legislative session. We anticipate that some or all of the bills may be
reintroduced in the 2005-2006 legislative session. We cannot predict the outcome
of these legislative proceedings.

Implementation Costs: Applications for recovery of $7 million of
implementation costs for 2002 and $1 million for 2003 are pending MPSC approval.
In September 2004, the ALJ issued a Proposal for Decision recommending full
recovery of these costs.

We are also pursuing authorization at the FERC for the MISO to reimburse us
for approximately $8 million of Alliance RTO development costs. Included in this
amount is $5 million pending approval by the MPSC as part of our 2002
implementation costs application. The FERC has denied our request for
reimbursement and we are appealing the FERC ruling at the United States Court of
Appeals for the District of Columbia. Although we believe these implementation
costs are fully recoverable in accordance with the Customer Choice Act, we
cannot predict the amount, if any, the MPSC or the FERC will approve as
recoverable.

Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act
allows us to recover certain regulatory assets through deferred recovery of
annual capital expenditures in excess of depreciation levels and certain other
expenses incurred prior to and throughout the rate freeze and rate cap periods,
including the cost of

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money. In October 2004, we filed an application with the MPSC seeking recovery
of $628 million of Section 10d(4) Regulatory Assets for the period June 2000
through December 2005 consisting of:

- capital expenditures in excess of depreciation,

- Clean Air Act costs,

- other expenses related to changes in law or governmental action incurred
during the rate freeze and rate cap periods, and

- the associated cost of money through the period of collection.

Of the $628 million, $152 million relates to the cost of money. In March 2005,
the MPSC Staff filed testimony recommending the MSPC approve recovery of
approximately $323 million. We cannot predict the amount, if any, the MPSC will
approve as recoverable.

Rate Caps: The Customer Choice Act imposes certain limitations on electric
rates that could result in our inability to collect our full cost of conducting
business from electric customers. Rate caps are effective through December 31,
2005 for residential customers. As a result, we may be unable to maintain our
profit margins in our electric utility business during the rate cap period. In
particular, if we need to purchase power supply from wholesale suppliers while
retail rates are capped, the rate restrictions may preclude full recovery of
purchased power and associated transmission costs.

Power Supply Costs: To reduce the risk of high electric prices during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasing electric capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. We are currently planning for a reserve margin of approximately 11
percent for summer 2005, or supply resources equal to 111 percent of projected
summer peak load. Of the 2005 supply resources target of 111 percent, we expect
to meet approximately 102 percent from our electric generating plants and
long-term power purchase contracts, and approximately 9 percent from short-term
contracts, options for physical deliveries, and other agreements. We have
purchased capacity and energy contracts partially covering the estimated reserve
margin requirements for 2005 through 2007. As a result, we have recognized an
asset of $12 million for unexpired capacity and energy contracts as of December
31, 2004.

PSCR: The PSCR process assures recovery of all reasonable and prudent power
supply costs actually incurred by us. In September 2004, we submitted our 2005
PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a
portion of our increased power supply costs from commercial and industrial
customers and, subject to the overall rate caps, from other customers. We
self-implemented the proposed 2005 PSCR charge in January 2005. The revenues
from the PSCR charges are subject to reconciliation at the end of the year after
actual costs have been reviewed for reasonableness and prudence. We cannot
predict the outcome of these PSCR proceedings.

Special Contracts: We entered into multi-year electric supply contracts
with certain industrial and commercial customers. The contracts provide
electricity at specially negotiated prices that are at a discount from tariff
prices, but above our incremental cost of service. As of February 2005, special
contracts for approximately 630 MW of load are in place, most of which are in
effect through 2005. We cannot predict the amount of electric load from these
customers that will continue with our electric service after their contracts
expire.

Transmission Costs: In May 2002, we sold our electric transmission system
for $290 million to MTH. We are in arbitration with MTH regarding property tax
items used in establishing the selling price of our electric transmission
system. An unfavorable outcome could result in a reduction of sale proceeds
previously recognized by approximately $2 million to $3 million.

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There are multiple proceedings and a proposed rulemaking pending before the
FERC regarding transmission pricing mechanisms and standard market design for
electric bulk power markets and transmission. The results of these proceedings
and proposed rulemaking could affect significantly:

- transmission cost trends,

- delivered power costs to us, and

- delivered power costs to our retail electric customers.

In November 2004, the FERC ruled on MISO and PJM RTO "through and out"
rates. Through and out rates are applied to transmission transactions when a
transmission customer purchases electricity that travels through multiple
transmission pricing zones. Effective December 1, 2004, regional through and out
rates for transactions between the PJM RTO and the MISO were eliminated by the
FERC. In that November 2004 order, the FERC conditionally accepted, for a period
beginning December 1, 2004 and ending January 31, 2008, a "license plate"
pricing structure. License plate pricing provides for access to the combined
regional transmission systems of the PJM RTO and the MISO at a single rate,
although the rate may vary based on where the customer's load is located.

The order also adopts a transitional charge from December 1, 2004 through
March 31, 2006, intended to mitigate abrupt cost shifts between transmission
owners and customers as a result of the pricing structure change. The manner in
which these transitional charges are calculated and implemented is currently the
subject of multiple disputes pending at the FERC. Based on the compliance
filings with the FERC made by the MISO and PJM RTO transmission owners, the new
transitional charges will not have a significant impact on our electric results
of operations. However, we cannot predict the outcome of the disputes concerning
these transitional charges pending at the FERC.

Transmission Market Developments: The MISO is scheduled to begin the
Midwest Energy Market on April 1, 2005. At that time, the MISO will implement a
day-ahead and real-time energy market and centralized dispatch for the MISO's
market participants. These changes are anticipated to ensure that load
requirements in the region are met reliably and efficiently, to better manage
congestion on the grid, and to produce consumer savings through the centralized
dispatch of generation throughout the region. The MISO is expected to provide
other functions, including long-term regional planning and market monitoring.

In addition, we are evaluating whether or not there may be impacts on
electric reliability associated with changes in the composition of transmission
markets. For example, Commonwealth Edison Company joined the PJM RTO in May 2004
and American Electric Power Service Corporation joined the PJM RTO in October
2004. These integrations may be creating different patterns of power flow within
the Midwest area and could affect adversely our ability to provide reliable
service to our customers. We are presently evaluating what financial impacts, if
any, these market developments are having on our operations.

August 14, 2003 Blackout: The NERC and the U.S. and Canadian Power System
Outage Task Force have released electric operations recommendations resulting
from their investigation into the August 14, 2003 blackout. Few of the
recommendations apply directly to us, since we are not a transmission owner.
However, the recommendations could result in increased transmission costs to us
and require upgrades to our distribution system. We cannot quantify the
financial impact of these recommendations at this time.

For additional details and material changes relating to the restructuring
of the electric utility industry and electric rate matters, see Note 2,
Contingencies, "Electric Restructuring Matters," and "Electric Rate Matters."

ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC
to increase our retail electric base rates. The electric rate case filing
requests an annual increase in revenues of approximately $320 million. The
primary reasons for the request are increased system maintenance and improvement
costs, Clean Air Act related expenditures, and employee pension costs. A final
order from the MPSC on our electric rate case is expected in late 2005. If
approved as requested, the rate increase would go into effect in January 2006
and would apply to all retail electric customers. We cannot predict the amount
or timing of the rate increase, if any, which the MPSC will approve.

CE-26

BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of
Appeals upheld a lower court decision that requires Detroit Edison to obey a
municipal ordinance enacted by the City of Taylor, Michigan. The ordinance
requires Detroit Edison to bury a section of its overhead power lines at its own
expense. Detroit Edison has filed an appeal with the Michigan Supreme Court.
Unless overturned by the Michigan Supreme Court, the decision could encourage
other municipalities to adopt similar ordinances, as has occurred or is being
discussed in a few municipalities in Consumers' service territory. If incurred,
we would seek recovery of these costs from our customers, subject to MPSC
approval. This case has potentially broad ramifications for the electric utility
industry in Michigan; however, at this time, we cannot predict the outcome of
this matter.

OTHER ELECTRIC BUSINESS UNCERTAINTIES

NUCLEAR MATTERS:

Big Rock: Dismantlement of plant systems is essentially complete and
demolition of the remaining plant structures has begun. The restoration project
is on schedule to return approximately 530 acres of the site, including the area
formerly occupied by the nuclear plant, to a natural setting for unrestricted
use in mid-2006. An additional 30 acres, the area where seven transportable dry
casks loaded with spent nuclear fuel and an eighth cask loaded with high-level
radioactive waste material are stored, will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.

Palisades: In August 2004, the NRC completed its mid-cycle plant
performance assessment of Palisades. The assessment for Palisades covered the
first half of 2004. The NRC determined that Palisades was operated in a manner
that preserved public health and safety and fully met all cornerstone
objectives. As of December 2004, all inspection findings were classified as
having very low safety significance and all performance indicators show
performance at a level requiring no additional oversight. Based on the plant's
performance, only regularly scheduled inspections are planned through March
2006.

The amount of spent nuclear fuel at Palisades exceeds the plant's temporary
onsite storage pool capacity. We are using dry casks for temporary onsite
storage. As of December 31, 2004, we have loaded 22 dry casks with spent nuclear
fuel. For additional information on disposal of spent nuclear fuel, see Note 2,
Contingencies, "Other Electric Contingencies -- Nuclear Matters."

In September 2004, we announced that we will seek a license renewal for the
Palisades plant. The plant's current license from the NRC expires in 2011. NMC,
which operates the facility, will apply for a 20-year license renewal for the
plant on behalf of Consumers. The Palisades renewal application is scheduled to
be filed by the end of the first quarter of 2005.

We have authorized the purchase of a replacement reactor vessel closure
head. The replacement head is being manufactured and scheduled to be installed
in 2007. Palisades, like many other nuclear plants, has experienced cracking in
reactor head nozzle penetrations. Repairs to two nozzles were made in 2004. The
replacement head nozzles will be manufactured from materials less susceptible to
cracking and should minimize inspection and repair costs after replacement.

Spent nuclear fuel complaint: In March 2003, the Michigan Environmental
Council, the Public Interest Research Group in Michigan, and the Michigan
Consumer Federation filed a complaint with the MPSC, which was served on us by
the MPSC in April 2003. The complaint asks the MPSC to initiate a generic
investigation and contested case to review all facts and issues concerning costs
associated with spent nuclear fuel storage and disposal. The complaint seeks a
variety of relief with respect to Consumers, Detroit Edison, Indiana & Michigan
Electric Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear fuel storage and disposal should be placed in an independent
trust. The complaint also asks the MPSC to take additional actions. In May 2003,
Consumers and other named utilities each filed motions to dismiss the complaint.
We are unable to predict the outcome of this matter.

CE-27

GAS BUSINESS OUTLOOK

GROWTH: Over the next five years, we expect gas deliveries to grow at an
average rate of less than one percent per year. Actual gas deliveries in future
periods may be affected by:

- fluctuations in weather patterns,

- use by independent power producers,

- competition in sales and delivery,

- Michigan economic conditions,

- gas consumption per customer, and

- increases in gas commodity prices.

In February 2004, we filed an application with the MPSC for a Certificate
of Public Convenience and Necessity to construct a 25-mile gas transmission
pipeline in northern Oakland County. The project is necessary to meet estimated
peak load beginning in the winter of 2005 through 2006. In December 2004, the
MPSC approved a settlement agreement authorizing us to construct and operate the
pipeline. Construction is expected to begin late spring of 2005.

In October 2004, we filed an application with the MPSC for a Certificate of
Public Convenience and Necessity to construct a 10.8-mile gas transmission
pipeline in northwestern Wayne County. The project is necessary to meet the
projected capacity demands beginning in the winter of 2007. If we are unable to
construct the pipeline, we will need to pursue more costly alternatives or
curtail serving the system's load growth in that area.

GAS BUSINESS UNCERTAINTIES

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

Regulatory

- inadequate regulatory response to applications for requested rate
increases,

- response to increases in gas costs, including adverse regulatory response
and reduced gas use by customers, and

- proposed distribution pipeline integrity rules and mandates.

Environmental

- potential environmental remediation costs at a number of sites, including
sites formerly housing manufactured gas plant facilities.

Other

- transmission pipeline integrity mandates, maintenance and remediation
costs, and

- other pending litigation.

GAS TITLE TRACKING FEES AND SERVICES: On February 14, 2005, the FERC issued
its latest order involving Consumers' Gas Title Transfer Tracking Fees and
Services. In doing so, the FERC agreed with us that such orders only apply to a
title transfer tracking fee charged and collected in connection with the
Consumers' FERC blanket transportation service. Because of the newly stated
limits on what fees are subject to refund, we believe that if any such refunds
are ultimately required, they will not be material.

CE-28

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 for prudency in an annual
reconciliation proceeding.

The following table summarizes our GCR reconciliation filings with the
MPSC. For additional details, see Note 2, Contingencies, "Gas Rate Matters--Gas
Cost Recovery."

GAS COST RECOVERY RECONCILIATION

Net over-recovery amounts included in the table above include refunds that
we received from our suppliers that are required to be refunded to our
customers.

GCR Year 2003-2004: In February 2005, the MPSC approved a settlement
agreement that resulted in a credit to our GCR customers for a $28 million
over-recovery, plus $3 million interest, using a roll-in refund methodology. The
roll-in methodology incorporates a GCR over/under-recovery in the next GCR plan
year.

GCR Plan for Year 2004-2005: In December 2003, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2004
through March 2005. In June 2004, the MPSC issued a final Order in our GCR plan
approving a settlement. The settlement included a quarterly mechanism for
setting a GCR ceiling price. The current ceiling price is $6.57 per mcf. Actual
gas costs and revenues will be subject to an annual reconciliation proceeding.

GCR Plan for Year 2005-2006: In December 2004, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2005
through March 2006. Our request proposes using a GCR factor consisting of:

- a base GCR factor of $6.98 per mcf, plus

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

The GCR factor can be adjusted monthly, provided it remains at or below the
current ceiling price. The quarterly adjustment mechanism allows an increase in
the GCR ceiling price to reflect a portion of cost increases if the average
NYMEX price for a specified period is greater than that used in calculating the
base GCR factor. Actual gas costs and revenues will be subject to an annual
reconciliation proceeding.

2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC
for a gas rate increase in the annual amount of $156 million. In December 2003,
the MPSC granted an interim rate increase in the amount of $19 million annually.
The MPSC also ordered an annual $34 million reduction in our annual depreciation
expense and related taxes.

On October 14, 2004, the MPSC issued its Opinion and Order on final rate
relief. In the order, the MPSC authorized us to place into effect surcharges
that would increase annual gas revenues by $58 million. Further, the MPSC
rescinded the $19 million annual interim rate increase. The final rate relief
was contingent upon our agreement to:

- achieve a common equity level of at least $2.3 billion by year-end 2005
and propose a plan to improve the common equity level thereafter until
our target capital structure is reached,

CE-29

- make certain safety-related operation and maintenance, pension, retiree
health-care, employee health-care, and storage working capital
expenditures for which the surcharge is granted,

- refund surcharge revenues when our rate of return on common equity
exceeds its authorized 11.4 percent rate,

- prepare and file annual reports that address certain issues identified in
the order, and

- file a general rate case on or before the date that the surcharge expires
(which is two years after the surcharge goes into effect).

On October 15, 2004, we agreed to these commitments.

2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. On December 18,
2003, the MPSC ordered an annual $34 million reduction in our depreciation
expense and related taxes in an interim rate order issued in our 2003 gas rate
case.

In October and December 2004, the MPSC issued Opinions and Orders in our
gas depreciation case. The October 2004 order requires us to file an application
for new depreciation accrual rates for our natural gas utility plant on, or no
earlier than three months prior to, the date we file our next natural gas
general rate case. The MPSC also directed us to undertake a study to determine
why our removal costs are in excess of those of other regulated Michigan natural
gas utilities and file a report with the MPSC Staff on or before December 31,
2005.

In February 2005, we requested a delay in the filing date for the next
depreciation case until after the MPSC considers the removal cost study, and
after the MPSC issues an order in a pending case relating to asset retirement
obligation accounting.

GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. We expect to fund most of these costs through insurance
proceeds and through the MPSC approved rates charged to our customers. 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 remedial action costs.
For additional details, see Note 2, Contingencies, "Gas Contingencies -- Gas
Environmental Matters."

OTHER OUTLOOK

MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $10 million of interest. The Michigan Tax Tribunal
decision has been appealed to the Michigan Court of Appeals by the City of
Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court
of Appeals. The MCV Partnership also has a pending case with the Michigan Tax
Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the
outcome of these proceedings; therefore, the above refund (net of approximately
$16 million of deferred expenses) has not been recognized in 2004 earnings.

COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees
are represented by the Utility Workers of America Union. The Union represents
Consumers' operating, maintenance, and construction employees and our call
center employees. The collective bargaining agreement with the Union for our
operating, maintenance, and construction employees will expire on June 1, 2005
and negotiations for a new agreement is underway currently. The collective
bargaining agreement with the Union for our call center employees will expire on
August 1, 2005.

LITIGATION AND REGULATORY INVESTIGATION: CMS Energy is the subject of
various investigations as a result of round-trip trading transactions by CMS
MST, including an investigation by the DOJ. Additionally, CMS Energy and
Consumers are named as parties in various litigation matters including a
shareholder derivative

CE-30

lawsuit, a securities class action lawsuit, and a class action lawsuit alleging
ERISA violations. For additional details regarding these investigations and
litigation, see Note 2, Contingencies.

NEW ACCOUNTING STANDARDS

For a discussion of new pronouncements, see Note 13, Implementation of New
Accounting Standards.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to
expense the grant date fair value of employee stock options and similar awards.
The Statement also clarifies and expands SFAS No. 123's guidance in several
areas, including measuring fair value, classifying an award as equity or as a
liability, and attributing compensation cost to reporting periods.

In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to
require that excess tax benefits related to the excess of the tax deductible
amount over the compensation cost recognized be classified as a financing cash
inflow rather than as a reduction of taxes paid in operating activities.

This Statement is effective for us as of the beginning of third quarter
2005. We adopted the fair value method of accounting for share-based awards
effective December 2002, and therefore, expect this statement to have an
insignificant impact on our results of operations when it becomes effective.

CE-31

CONSUMERS ENERGY COMPANY

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Consumers' management is responsible for establishing and maintaining
adequate internal control over financial reporting, as such term is defined in
Rule 13a-15(f) under the Exchange Act. 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
based on 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, 2004.

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.

Consumers' management's assessment of the effectiveness of Consumers'
internal control over financial reporting as of December 31, 2004 has been
audited by Ernst & Young LLP, an independent registered public accounting firm,
who audited the consolidated financial statements of Consumers included in this
Form 10-K. Ernst & Young LLP's attestation report on Consumers' management's
assessment of internal control over financial reporting follows this report.

CE-32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder of Consumers Energy Company

We have audited management's assessment, included in MANAGEMENT'S REPORT ON
INTERNAL CONTROLS OVER FINANCIAL REPORTING, that Consumers Energy Company (a
Michigan Corporation and wholly-owned subsidiary of CMS Energy Corporation) and
subsidiaries maintained effective internal control over financial reporting as
of December 31, 2004, based on criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Consumers Energy
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the company's
internal control over financial reporting based on our audit. We did not examine
the effectiveness of internal control over financial reporting of Midland
Cogeneration Venture Limited Partnership, a 49% owned variable interest entity
which has been consolidated pursuant to Revised Financial Accounting Standards
Board Interpretation No. 46, "Consolidation of Variable Interest Entities",
whose financial statements reflect total assets and revenues constituting 15%
and 14%, respectively, of the related consolidated financial statement amounts
as of and for the year ended December 31, 2004. The effectiveness of Midland
Cogeneration Venture Limited Partnership's internal control over financial
reporting was audited by other auditors whose report has been furnished to us,
and our opinion, insofar as it relates to the effectiveness of Midland
Cogeneration Venture Limited Partnership's internal control over financial
reporting, is based solely on the report of the other auditors.

We conducted our audit in accordance with the standards of the Public
Company Accounting Oversight Board (United States). Those standards require that
we plan and perform the audit to obtain reasonable assurance about whether
effective internal control over financial reporting was maintained in all
material respects. Our audit included obtaining an understanding of internal
control over financial reporting, evaluating management's assessment, testing
and evaluating the design and operating effectiveness of internal control, and
performing such other procedures as we considered necessary in the
circumstances. We believe that our audit and the report of the other auditors
provide a reasonable basis for our opinion.

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 (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
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 (3) 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.

In our opinion, based on our audit and the report of the other auditors,
management's assessment that Consumers Energy Company maintained effective
internal control over financial reporting as of December 31, 2004, is fairly
stated, in all material respects, based on the COSO criteria. Also, in our
opinion, based on our audit and the report of the other auditors, Consumers
Energy Company maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2004, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Consumers Energy Company and subsidiaries as of December 31, 2004 and
2003, and the related consolidated statements of income, common stockholder's
equity, and cash flows for each of the three years in the period ended December
31, 2004 and our report dated March 7, 2005 expressed an unqualified opinion
thereon.

/s/ Ernst & Young LLP

Detroit, Michigan
March 7, 2005

CE-33

MCV MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

MCV's management is responsible for establishing and maintaining an
adequate system of internal control over financial reporting of MCV. This system
is designed to provide reasonable assurance regarding the reliability of
financial reporting and the preparation of financial statements for external
purposes in accordance with accounting principles generally accepted in the
United States of America.

MCV'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 MCV; (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
MCV are being made only in accordance with authorizations of management and the
Management Committee of MCV; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of MCV's assets that could have a material effect on the financial statements.

Because of its inherent limitations, a system of internal control over
financial reporting can provide only reasonable assurance and may not prevent or
detect misstatements. Further, because of changes in conditions, effectiveness
of internal controls over financial reporting may vary over time. Our system
contains self-monitoring mechanisms, and actions are taken to correct
deficiencies as they are identified.

MCV management conducted an evaluation of the effectiveness of the system
of internal control over financial reporting based on the framework in "Internal
Control -- Integrated Framework" issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this evaluation, management
concluded that MCV's system of internal control over financial reporting was
effective as of December 31, 2004. MCV management's assessment of the
effectiveness of MCV's internal control over financial reporting has been
audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which is included herein.

CE-34

CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME

The accompanying notes are an integral part of these statements.

CE-35

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

CE-36

The accompanying notes are an integral part of these statements.
CE-37

CONSUMERS ENERGY COMPANY

CONSOLIDATED BALANCE SHEETS

CE-38

The accompanying notes are an integral part of these statements.
CE-39

CONSUMERS ENERGY COMPANY

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

- -------------------------
(a) Number of shares of common stock outstanding was 84,108,789 for all periods
presented.

CE-40

(b) Disclosure of Other Comprehensive Income:

The accompanying notes are an integral part of these statements.
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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 that provides service
to customers in Michigan's Lower Peninsula. Our customer base includes a mix of
residential, commercial, and diversified industrial customers, the largest
segment of which is the automotive industry.

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 Revised FASB
Interpretation No. 46. The primary beneficiary of a variable interest entity is
the party that absorbs or receives a majority of the entity's expected losses or
expected residual returns or both as a result of holding variable interests,
which are ownership, contractual, or other economic interests. In 2004, we
consolidated the MCV Partnership and the FMLP in accordance with Revised FASB
Interpretation No. 46. For additional details, see Note 13, Implementation of
New Accounting Standards. These entities are reported as equity method
investments in our consolidated financial statements for all periods prior to
January 1, 2004. 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. Intercompany transactions and balances have been eliminated.

USE OF ESTIMATES: We prepare our consolidated financial statements in
conformity with U.S. generally accepted accounting principles. We are required
to make estimates using assumptions that may affect the reported amounts and
disclosures. Actual results could differ from those estimates.

We are required to record estimated liabilities in the consolidated
financial statements when it is probable that a loss will be incurred in the
future as a result of a current event, and when the amount can be reasonably
estimated. We have used this accounting principle to record estimated
liabilities as discussed in Note 2, Contingencies.

REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of
electricity and natural gas, and the storage of natural gas when services are
provided. Sales taxes are recorded as liabilities and are not included in
revenues.

CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred. Our regulated businesses are permitted to
capitalize an allowance for funds used during construction on regulated
construction projects and to include such amounts in plant in service.

CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an
original maturity of three months or less are considered cash equivalents.

At December 31, 2004, our restricted cash on hand was $21 million.
Restricted cash dedicated for repayment of Securitization bonds is classified as
a current asset as the payments on the related Securitization bonds occur within
one year.

FINANCIAL INSTRUMENTS: We account for investments in debt and equity
securities using SFAS No. 115. Debt and equity securities classified as
available-for-sale are reported at fair value determined from quoted market
prices. Debt and equity securities classified as held-to-maturity are reported
at cost. Unrealized gains or losses resulting from changes in fair value of
certain available-for-sale debt and equity securities are reported, net of tax,
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless the related changes in fair value are
determined to be other than temporary.

Unrealized gains or losses on our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets. Realized
gains or losses would not affect our earnings or cash flows.

For additional details regarding financial instruments, see Note 4,
Financial and Derivative Instruments.
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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

GAS INVENTORY: We use the weighted average cost method for valuing working
gas and recoverable cushion gas in underground storage facilities

GENERATING PLANT FUEL STOCK INVENTORY: We use the weighted average cost
method for valuing coal inventory and classify these costs as generating plant
fuel stock on our Consolidated Balance Sheets. The MCV Partnership's natural gas
inventory is also included in this category, stated at the lower of cost or
market and valued using the last-in, first-out ("LIFO") method.

IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate the potential
impairment of our investments in projects and other long-lived assets, other
than goodwill, based on various analyses, including the projection of
undiscounted cash flows, whenever events or changes in circumstances indicate
that the carrying amount of the assets may not be recoverable. If the carrying
amount of the investment or asset exceeds its estimated undiscounted future cash
flows, an impairment loss is recognized, and the investment or asset is written
down to its estimated fair value.

MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property
replacements to maintenance expense. We also 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 straight-line rates approved by the MPSC. The composite depreciation rates
for our properties are:

NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on
the quantity of heat produced for electric generation. For nuclear fuel used
after April 6, 1983, we charge certain disposal costs to nuclear fuel expense,
recover these costs through electric rates, and remit them to the DOE quarterly.
We elected to defer payment for disposal of spent nuclear fuel burned before
April 7, 1983. As of December 31, 2004, we have recorded a liability to the DOE
of $141 million, including interest, which is payable upon the first delivery of
spent nuclear fuel to the DOE. The amount of this liability, excluding a portion
of interest, was recovered through electric rates. For additional details on
disposal of spent nuclear fuel, see Note 2, Contingencies, "Other Electric
Contingencies -- Nuclear Matters."

OTHER INCOME AND OTHER EXPENSE: The following tables show the components of
Other income and Other expense:

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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, the original cost is
charged to accumulated depreciation. The cost of removal, less salvage, is
recorded as a regulatory liability. For additional details, see Note 6, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.

Property, plant, and equipment at December 31, 2004 and 2003, was as
follows:

- -------------------------
(a) Capital leases presented in this table are gross amounts. Accumulated
amortization of capital leases was $49 million at December 31, 2004 and $38
million at December 31, 2003.

(b) Includes unrecoverable base natural gas in underground storage of $26
million at December 31, 2004 and $23 million at December 31, 2003, which is
not subject to depreciation.

(c) As of December 31, 2004, accumulated depreciation, depletion, and
amortization is comprised of $4.601 billion from public utility plant,
$1.063 billion related to the consolidation of the MCV Facility, and $1
million from our non-utility plant assets. As of December 31, 2003,
accumulated depreciation, depletion,

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

and amortization included $4.416 billion from our public utility plant and
$1 million related to non-utility plant assets.

(d) Included in net property, plant and equipment are intangible assets
primarily related to software development costs, consents, leasehold
improvements, and rights of way. The estimated amortization life for
software development costs is seven years. The estimated amortization life
for leasehold improvements is over the life of the lease. Other intangible
amortization lives range from 50 to 105 years. Intangible assets at
December 31, 2004 and 2003 were as follows:

Pre-tax amortization expense related to these intangible assets was $19
million for the year ended December 31, 2004, $19 million for the year
ended December 31, 2003, and $17 million for the year ended December 31,
2002. Intangible assets amortization is forecasted to range from $8 million
to $19 million per year over the next five years.

(e) The following table illustrates the depreciable life for electric and gas
structures and improvements:

RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

RELATED PARTY TRANSACTIONS: We received income from related parties as
follows:

We recorded expense from related parties as follows:

- -------------------------
(a) In 2004, we consolidated the MCV Partnership and the FMLP into our
consolidated financial statements in accordance with Revised FASB
Interpretation No. 46. For additional details, see Note 13, Implementation
of New Accounting Standards.

(b) We issued Trust Preferred Securities through several Consumers' affiliated
companies. As of December 31, 2003, we deconsolidated the trusts that hold
the mandatorily redeemable Trust Preferred Securities. As a result of the
deconsolidation, we now record on the Consolidated Statements of Income,
Interest on Long-term debt -- related parties to the trusts holding the
Trust Preferred Securities. For additional information on Consumers'
affiliated Trust Preferred Securities companies, see Note 13,
Implementation of New Accounting Standards.

(c) We base our related party transactions on regulated prices, market prices,
or competitive bidding. In 2003, we paid overhead costs to CMS Energy based
on an industry allocation methodology, such as the Massachusetts Formula.
In 2004, we paid no overhead costs to CMS Energy.

(d) Panhandle was sold in June 2003.

We own 2.4 million shares of CMS Energy Common Stock with a fair value of
$25 million at December 31, 2004. For additional details on our investment in
CMS Energy Common Stock, see Note 4, Financial and Derivative Instruments.

TRADE RECEIVABLES: We record our accounts receivable at fair value.
Accounts deemed uncollectible are charged to operating expense.

UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums,
discounts, and expenses incurred in connection with the issuance of long-term
debt and amortize those costs ratably over the terms of the debt issues. Any
refinancing costs are charged to expenses 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 ratably over the
terms of the newly issued debt.

CE-47

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.

We reflect the following regulatory assets and liabilities, which include
both current and non-current amounts, on our Consolidated Balance Sheets. We
expect to recover these costs through rates over periods of up to 14 years. We
recognized an OPEB transition obligation in accordance with SFAS No. 106 and
established a regulatory asset for the amount that we expect to recover in rates
over the next eight years.

- -------------------------
(a) At December 31, 2004, we classified $19 million of regulatory assets as
current regulatory assets and we classified $1.677 billion of regulatory
assets as non-current regulatory assets. At December 31, 2003, we
classified $19 million of regulatory assets as current regulatory assets
and we classified $1.086 billion of regulatory assets as non-current
regulatory assets. At December 31, 2004 and December 31, 2003, all of our
regulatory liabilities represented non-current regulatory liabilities.

2: CONTINGENCIES

SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading
transactions by CMS MST, CMS Energy's Board of Directors established a Special
Committee to investigate matters surrounding the transactions and retained
outside counsel to assist in the investigation. The Special Committee completed
its investigation and reported its findings to the Board of Directors in October
2002. The Special Committee concluded, based on an extensive investigation, that
the round-trip trades were undertaken to raise CMS MST's profile as an energy
marketer with the goal of enhancing its ability to promote its services to new
customers. The Special Committee found no effort to manipulate the price of CMS
Energy Common Stock or affect energy prices. The Special Committee also made
recommendations designed to prevent any recurrence of this practice. Previously,
CMS Energy terminated its speculative trading business and revised its risk
management policy. The Board of Directors adopted, and CMS Energy implemented
the recommendations of the Special Committee.

CMS Energy is cooperating with an investigation by the DOJ concerning
round-trip trading. 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

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

related to round-trip trading. The order did not assess a fine and CMS Energy
neither admitted nor denied the order's findings. The settlement resolved the
SEC investigation involving CMS Energy and CMS MST.

SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. The complaints
were filed as purported class actions in the United States District Court for
the Eastern District of Michigan, by shareholders who allege that they purchased
CMS Energy's securities during a purported class period. These cases were later
consolidated by the court. The plaintiffs generally seek 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. CMS
Energy, Consumers, and the individual defendants filed motions to dismiss on
June 21, 2004. The judge issued an opinion and order dated January 7, 2005,
granting the motion to dismiss for Consumers and three of the individual
defendants, but denying the motions to dismiss for CMS Energy and the 13
remaining individual defendants. CMS Energy and the individual defendants will
defend themselves vigorously but cannot predict the outcome of this litigation.

ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS
MST, and certain named and unnamed officers and directors, in two lawsuits
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings and Incentive Plan (the "Plan"). The two cases
were filed in July 2002 in United States District Court for the Eastern District
of Michigan and were later consolidated by the court. Plaintiffs allege breaches
of fiduciary duties under ERISA and seek restitution on behalf of the Plan with
respect to a decline in value of the shares of CMS Energy Common Stock held in
the Plan. Plaintiffs also seek other equitable relief and legal fees. The judge
issued an opinion and order dated December 27, 2004, conditionally granting
plaintiffs' motion for class certification. A trial date has not been set, but
is expected to be no earlier than late in 2005. CMS Energy and Consumers will
defend themselves vigorously but cannot predict the outcome of this litigation.

ELECTRIC CONTINGENCIES

ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental
laws and regulations. Costs to operate our facilities in compliance with these
laws and regulations generally have been recovered in customer rates.

Clean Air: The EPA and the state regulations require us to make significant
capital expenditures estimated to be $802 million. As of December 31, 2004, we
have incurred $525 million in capital expenditures to comply with the EPA
regulations and anticipate that the remaining $277 million of capital
expenditures will be made between 2005 and 2011.

The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek modification permits
from the EPA. We have received and responded to information requests from the
EPA on this subject. We believe that we have properly interpreted the
requirements of "routine maintenance." If our interpretation is found to be
incorrect, we may be required to install additional pollution controls at some
or all of our coal-fired electric plants and potentially pay fines.
Additionally, the viability of certain plants remaining in operation could be
called into question.

In addition to modifying the coal-fired electric plants, we expect to
utilize nitrogen oxide emissions allowances for years 2005 through 2009, most of
which have been purchased. The cost of the allowances is estimated to average $8
million per year for 2005-2006. The need for allowances will decrease after year
2006 with the installation of emissions control technology.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Cleanup and Solid Waste: Under the Michigan Natural Resources and
Environmental Protection Act, we expect that we will ultimately incur
investigation and remedial action 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 several contaminated sites
administered under Superfund. Superfund liability is joint and several, meaning
that many other creditworthy parties with substantial assets are potentially
responsible with respect to the individual sites. Based on past experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $9 million. As of December 31, 2004, we have
recorded a liability for the minimum amount of our estimated Superfund
liability.

In October 1998, during routine maintenance activities, we identified PCB
as a component in certain paint, grout, and sealant materials at the Ludington
Pumped Storage facility. We removed and replaced part of the PCB material. We
have proposed a plan to deal with the remaining materials and are awaiting a
response from the EPA.

LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling power to us filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges that we incorrectly calculated the energy charge payments made pursuant
to power purchase agreements with qualifying facilities. In February 2004, the
Ingham County Circuit Court 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 eight
plaintiff qualifying facilities have appealed the dismissal of the circuit court
case to the Michigan Court of Appeals. We cannot predict the outcome of this
appeal.

ELECTRIC RESTRUCTURING MATTERS

ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates,
terms, and conditions under which retail customers are permitted to choose an
electric supplier. These revised tariffs allow ROA customers, upon as little as
30 days notice to us, to return to our generation service at current tariff
rates. If any class of customers' (residential, commercial, or industrial) ROA
load reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods. We cannot predict the total amount of electric supply load that may be
lost to alternative electric suppliers. As of March 2005, alternative electric
suppliers are providing 900 MW of generation supply to ROA customers. This
amount represents 12 percent of our distribution load and an increase of 23
percent compared to March 2004.

ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following chart summarizes our electric restructuring filings with the
MPSC:

- -------------------------
(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes recovery of Clean Air Act costs
through the Section 10d(4) Regulatory Asset case.

(b) Amount includes the cost of money through the year prior to the year filed.

Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act
allows us to recover certain regulatory assets through deferred recovery of
annual capital expenditures in excess of depreciation levels and certain other
expenses incurred prior to and throughout the rate freeze and rate cap periods,
including the cost of money. The section also allows deferred recovery of
expenses incurred during the rate freeze and rate cap periods that result from
changes in taxes, laws, or other state or federal governmental actions. In
October 2004, we filed an application with the MPSC seeking recovery of $628
million of Section 10d(4) Regulatory Assets for the period June 2000 through
December 2005 consisting of:

- capital expenditures in excess of depreciation,

- Clean Air Act costs,

- other expenses related to changes in law or governmental action incurred
during the rate freeze and rate cap periods, and

- the associated cost of money through the period of collection.

Of the $628 million, $152 million relates to the cost of money.

As allowed by the Customer Choice Act, in January 2004, we began accruing
and deferring for recovery the 2004 portion of our Section 10d(4) Regulatory
Assets. In November 2004, the MPSC issued an order in Detroit Edison's general
electric rate case which concluded that Detroit Edison's return of and on Clean
Air Act costs incurred from June 2000 through December 2003 are recoverable
under Section 10d(4). Based on the precedent set by this order, we recorded an
additional regulatory asset in November 2004 for our return of and on Clean Air
Act expenditures incurred from 2000 through 2003. Unless we receive an order
from the MPSC to the contrary, we will continue to record additional accruals.
However, certain aspects of Detroit Edison's electric rate case are different
from our Section 10d(4) Regulatory Asset filing. In March 2005, the MPSC Staff
filed testimony recommending the MPSC approve recovery of approximately $323
million. We cannot predict the amount, if any,

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

the MPSC will approve as recoverable. At December 31, 2004, total Section 10d(4)
Regulatory Assets totaled $141 million.

TRANSMISSION SALE: In May 2002, we sold our electric transmission system to
MTH, a non-affiliated limited partnership whose general partner is a subsidiary
of Trans-Elect, Inc. We are in arbitration with MTH regarding property tax items
used in establishing the selling price of our electric transmission system. An
unfavorable outcome could result in a reduction of sale proceeds previously
recognized of approximately $2 million to $3 million.

ELECTRIC RATE MATTERS

ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC
to increase our retail electric base rates. The electric rate case filing
requests an annual increase in revenues of approximately $320 million. The
primary reasons for the request are increased system maintenance and improvement
costs, Clean Air Act related expenditures, and employee pension costs. A final
order from the MPSC on our electric rate case is expected in late 2005. If
approved as requested, the rate increase would go into effect in January 2006
and would apply to all retail electric customers. We cannot predict the amount
or timing of the rate increase, if any, which the MPSC will approve.

POWER SUPPLY COSTS: To reduce the risk of high electric prices during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasing electric capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. We have purchased capacity and energy contracts partially covering the
estimated reserve margin requirements for 2005 through 2007. As a result, we
have recognized an asset of $12 million for unexpired capacity and energy
contracts as of December 31, 2004. The total premium costs of electric capacity
and energy contracts for 2004 were approximately $12 million.

PSCR: The PSCR process assures recovery of all reasonable and prudent power
supply costs actually incurred by us. In September 2004, we submitted our 2005
PSCR filing to the MPSC. The proposed PSCR charge would allow us to recover a
portion of our increased power supply costs from commercial and industrial
customers and, subject to the overall rate caps, from other customers. We
self-implemented the proposed 2005 PSCR charge in January 2005. We estimate the
increased recovery of power supply costs from commercial and industrial
customers to be approximately $49 million in 2005. The revenues from the PSCR
charges are subject to reconciliation at the end of the year after actual costs
have been reviewed for reasonableness and prudence. We cannot predict the
outcome of these PSCR proceedings.

OTHER ELECTRIC CONTINGENCIES

THE MIDLAND COGENERATION VENTURE: The MCV Partnership, which leases and
operates the MCV Facility, contracted to sell electricity to Consumers for a
35-year period beginning in 1990 and to supply electricity and steam to Dow. We
hold a 49 percent partnership interest in the MCV Partnership, and a 35 percent
lessor interest in the MCV Facility.

In 2004, we consolidated the MCV Partnership and the FMLP into our
consolidated financial statements in accordance with Revised FASB Interpretation
No. 46. For additional details, see Note 13, Implementation of New Accounting
Standards. Our consolidated retained earnings include undistributed earnings
from the MCV Partnership of $237 million at December 31, 2004 and $245 million
at December 31, 2003.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The cost that we incur under the MCV Partnership PPA exceeds the recovery
amount allowed by the MPSC. We expense all cash underrecoveries directly to
income. We estimate cash underrecoveries of capacity and fixed energy payments
as follows:

After September 15, 2007, we expect to claim relief under the regulatory
out provision in the PPA, limiting our capacity and fixed energy payments to the
MCV Partnership to the amount collected from our customers. The MCV Partnership
has indicated that it may take issue with our exercise of the regulatory out
clause after September 2007. We believe that the clause is valid and fully
effective, but cannot assure that it will prevail in the event of a dispute. The
MPSC's future actions on the capacity and fixed energy payments recoverable from
customers subsequent to September 15, 2007 may affect negatively the earnings of
the MCV Partnership and the value of our investment in the MCV Partnership.

Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned at our coal plants and our operation and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years and the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been impacted negatively. Even with the approved RCP, if gas prices continue at
present levels or increase, the economics of operating the MCV Facility may be
adverse enough to require us to recognize an impairment.

In January 2005, the MPSC issued an order approving the RCP, with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV Facility on the basis of natural gas market
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas by an
estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced
natural gas consumed by the MCV Facility will benefit our ownership interest in
the MCV Partnership.

The substantial MCV Facility fuel cost savings will be used first to offset
fully the cost of replacement power. Second, $5 million annually will be used to
fund a renewable energy program. Remaining savings will be split between the MCV
Partnership and Consumers. Consumers' direct savings will be shared 50 percent
with its customers in 2005 and 70 percent in 2006 and beyond. Consumers' direct
savings from the RCP, after a portion is allocated to customers, will be used to
offset our capacity and fixed energy underrecoveries expense. Since the MPSC has
excluded these underrecoveries from the rate making process, we anticipate that
our savings from the RCP will not affect our return on equity used in our base
rate filings.

In January 2005, Consumers and the MCV Partnership's general partners
accepted the terms of the order and implemented the RCP. The underlying
agreement for the RCP between Consumers and the MCV Partnership extends through
the term of the PPA. However, either party may terminate that agreement under
certain conditions. In February 2005, a group of intervenors in the RCP case
filed an application for rehearing of the MPSC order. The Attorney General also
filed a claim of appeal with the Michigan Court of Appeals. We cannot predict
the outcome of these appeals.

MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The MCV Partnership estimates that the
decision will result in a refund to the MCV Partnership of approximately $35
million in taxes plus $10 million of interest. The Michigan Tax Tribunal
decision has been appealed to the Michigan Court of Appeals by the City of
Midland and the MCV Partnership has filed a cross-appeal at the Michigan Court
of Appeals. The MCV Partnership also has a pending case with the Michigan Tax
Tribunal for tax years 2001 through 2004. The MCV Partnership cannot predict the
outcome of these proceedings; therefore,

CE-53

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

the above refund (net of approximately $16 million of deferred expenses) has not
been recognized in 2004 earnings.

NUCLEAR PLANT DECOMMISSIONING: Decommissioning funding practices approved
by the MPSC require us to file a report on the adequacy of funds for
decommissioning at three-year intervals. We prepared and filed updated cost
estimates for Big Rock and Palisades on March 31, 2004. Excluding additional
costs for spent nuclear fuel storage, due to the DOE's failure to accept this
spent nuclear fuel on schedule, these reports show a decommissioning cost of
$361 million for Big Rock and $868 million for Palisades. Since Big Rock is
currently in the process of being decommissioned, the estimated cost includes
historical expenditures in nominal dollars and future costs in 2003 dollars,
with all Palisades costs given in 2003 dollars.

In 1999, the MPSC orders for Big Rock and Palisades provided for fully
funding the decommissioning trust funds for both sites. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. The MPSC order set the
annual decommissioning surcharge for Palisades at $6 million through 2007.
Amounts collected from electric retail customers and deposited in trusts,
including trust earnings, are credited to a regulatory liability and asset
retirement obligation.

Big Rock: Excluding the additional nuclear fuel storage costs due to the
DOE's failure to accept this spent fuel on schedule, we are currently projecting
that the level of funds provided by the trust for Big Rock will fall short of
the amount needed to complete the decommissioning by $26 million. At this time,
we plan to provide the additional amounts needed from our corporate funds and,
subsequent to the completion of radiological decommissioning work, seek recovery
of such expenditures at the MPSC. We cannot predict how the MPSC will rule on
our request. The following table shows our Big Rock decommissioning activities:

- -------------------------

(a) Includes site restoration expenditures.

These activities had no material impact on net income. At December 31,
2004, we have an investment in nuclear decommissioning trust funds of $52
million for Big Rock. In addition, at December 31, 2004, we have charged $8
million to our FERC jurisdictional depreciation reserve for the decommissioning
of Big Rock.

Palisades: Excluding additional nuclear fuel storage costs due to the DOE's
failure to accept this spent fuel on schedule, we concluded that the existing
surcharge for Palisades needed to be increased to $25 million annually,
beginning January 1, 2006, and continue through 2011, our current license
expiration date. In June 2004, we filed an application with the MPSC seeking
approval to increase the surcharge for recovery of decommissioning costs related
to Palisades beginning in 2006. In September 2004, we announced that we will
seek a 20-year license renewal for Palisades. In January 2005, we filed a
settlement agreement with the MPSC that was agreed to by four of the six
parties. The settlement agreement provides for the continuation of the existing
$6 million annual decommissioning surcharge through 2011 and for the next
periodic review to be filed in March 2007. We are seeking MPSC approval of the
settlement, under a contested settlement proceeding, but cannot predict the
outcome.

At December 31, 2004, we have an investment in the MPSC nuclear
decommissioning trust funds of $513 million for Palisades. In addition, at
December 31, 2004, we have a FERC decommissioning trust fund with a balance of
$10 million. For additional details on decommissioning costs accounted for as
asset retirement obligations, see Note 6, Asset Retirement Obligations.

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NUCLEAR MATTERS:

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

There are two court decisions that 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. Over 60 utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. In July 2004, the DOE filed an amended answer and motion to
dismiss the complaint. In October 2004, we filed a response to the DOE's motion
and our motion for summary judgment on liability. Oral argument has been held,
and the motions are now before the Court for a decision. If our litigation
against the DOE is successful, we anticipate future recoveries from the DOE. We
plan to use recoveries to pay the cost of spent nuclear fuel storage until the
DOE takes possession as required by law. We can make no assurance that the
litigation against the DOE will be successful.

In July 2002, Congress approved and the President signed a bill designating
the site at Yucca Mountain, Nevada, for the development of a repository for the
disposal of high-level radioactive waste and spent nuclear fuel. We expect that
the DOE will submit an application to the NRC sometime in 2005 for a license to
begin construction of the repository. The application and review process is
estimated to take several years.

Insurance: We maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $27 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.

At Palisades, we maintain nuclear liability insurance for third-party
bodily injury and off-site property damage resulting from a nuclear hazard for
up to approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. Part of the Price-Anderson
Act's financial protection is a mandatory industry-wide program under which
owners of nuclear generating facilities could be assessed if a nuclear incident
occurs at any nuclear generating facility. The maximum assessment against us
could be $101 million per occurrence, limited to maximum annual installment
payments of $10 million.

We also maintain insurance under a program that covers tort claims for
bodily injury to nuclear workers caused by nuclear hazards. The policy contains
a $300 million nuclear industry aggregate limit. Under a previous insurance
program providing coverage for claims brought by nuclear workers, we remain
responsible for a maximum assessment of up to $6 million.

Big Rock remains insured for nuclear liability by a combination of
insurance and a NRC indemnity totaling $544 million, and a nuclear property
insurance policy from NEIL.

Insurance policy terms, limits, and conditions are subject to change during
the year as we renew our policies.

GAS CONTINGENCIES

GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remedial
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. We have completed initial
investigations at the
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23 sites. We will continue to implement remediation plans for sites where we
have received MDEQ remediation plan approval. We will also work toward resolving
environmental issues at sites as studies are completed.

We have estimated our costs for investigation and remedial action at all 23
sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost
Model. We expect our remaining costs to be between $37 million and $90 million.
The range reflects multiple alternatives with various assumptions for resolving
the environmental issues at each site. We base the estimates on discounted 2003
costs using a discount rate of three percent. The discount rate represents 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 insurance
proceeds and MPSC-approved rates. As of December 31, 2004, we have recorded a
liability of $38 million, net of $44 million of expenditures incurred to date,
and a regulatory asset of $65 million. 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 remedial action costs.

In its November 2002 gas distribution rate order, the MPSC authorized us to
continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.

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 for prudency in an annual
reconciliation proceeding.

The following table summarizes our GCR reconciliation filings with the
MPSC. Additional details related to these proceedings follow the table.

Gas Cost Recovery Reconciliation

- -------------------------
(a) Represents the weighted average interest rate at December 31, 2004 (5.097
percent at December 31, 2003).

(b) We consolidate the FMLP in accordance with Revised FASB Interpretation No.
46. The FMLP debt is essentially project debt secured by certain assets of
the MCV Partnership and the FMLP. The debt is non-recourse to other assets
of Consumers.

(c) Maturity date uncertain.

(d) Paid off in January 2005.
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FINANCINGS: The following is a summary of significant long-term debt
issuances and retirements during 2004:

Issuance costs associated with the issuances of FMBs totaled $7 million and
are being amortized ratably over the lives of the related debt. Call premiums
associated with the debt retirements totaled $20 million and are being amortized
ratably over the lives of the newly issued debt.

SUBSEQUENT FINANCING ACTIVITIES: In January 2005, we issued $250 million of
5.15 percent FMBs due 2017. We used the net proceeds of $247 million to pay off
our $60 million long-term bank loan, to redeem our $73 million 8.36 percent
subordinated deferrable interest notes, and to redeem our $124 million 8.20
percent subordinated deferrable interest notes. The subordinated deferrable
interest notes are classified as Long-term debt -- related parties on our
accompanying Consolidated Balance Sheets.

FIRST MORTGAGE BONDS: We secure our FMBs by a mortgage and lien on
substantially all of our property. Our ability to issue and sell securities is
restricted by certain provisions in the first mortgage bond indenture, our
articles of incorporation, and the need for regulatory approvals under federal
law.

SECURITIZATION BONDS: Securitization bonds are collateralized by certain
regulatory assets. 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 on the Securitization
bonds. Securitization surcharges totaled $50 million annually in 2003 and 2004.

LONG-TERM DEBT -- RELATED PARTIES: We formed various statutory wholly-owned
business trusts for the sole purpose of issuing preferred securities and lending
the gross proceeds to ourselves. The sole assets of the trusts consist of the
debentures described below. These debentures have terms similar to those of the
mandatorily redeemable preferred securities the trusts issued. We determined
that we do not hold the controlling financial interest in our trust preferred
security structures. Accordingly, those entities were deconsolidated as of
December 31, 2003 and are reflected in Long-term debt -- related parties. The
trust preferred securities were previously included in mezzanine equity.

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

- -------------------------
(a) Redeemed in February 2005.

(b) Redeemed in January 2005 with available cash.

In the event of default, holders of the trust preferred securities would be
entitled to exercise and enforce the trusts' 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 trusts' obligations under the preferred securities.

DEBT MATURITIES: At December 31, 2004, the aggregate annual maturities for
long-term debt for the next five years are:

REGULATORY AUTHORIZATION FOR FINANCINGS: We have FERC authorization to
issue or guarantee up to $1.1 billion of short-term securities and up to $1.1
billion of short-term FMBs as collateral for such short-term securities. We have
FERC authorization to issue up to $1 billion of long-term securities for
refinancing or refunding purposes, $1.5 billion of long-term securities for
general corporate purposes, and $2.5 billion of long-term FMBs to be issued
solely as collateral for other long-term securities.

REVOLVING CREDIT FACILITIES: The following secured revolving credit
facilities with banks are available as of December 31, 2004:

- -------------------------
(a) This facility expires in August 2005 and may be extended annually at
Consumers' option to July 31, 2007. The interest rate on borrowings under
this facility is LIBOR plus 125 basis points. Annual fees for letters-of-

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

credit are 125 basis points on the amount outstanding. A quarterly fee of 22.5
basis points is payable on the average daily unused balance.

SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently 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. We sold $304 million of receivables at December 31, 2004 and we
sold $297 million of receivables at December 31, 2003. These sold amounts are
excluded from accounts receivable on our Consolidated Balance Sheets. We
continue to service the receivables sold to the special purpose entity. The
purchaser of the receivables has no recourse against our other assets for
failure of a debtor to pay when due and the purchaser has no right to any
receivables not sold. No gain or loss has been recorded on the receivables sold
and we retain no interest in the receivables sold.

Certain cash flows under our accounts receivable sales program are shown in
the following table:

DIVIDEND RESTRICTIONS: Under the provisions of our articles of
incorporation, at December 31, 2004, we had $456 million of unrestricted
retained earnings available to pay common stock dividends. However, covenants in
our debt facilities cap common stock dividend payments at $300 million in a
calendar year. In October 2004, the MPSC rescinded its December 2003 interim gas
rate order, which included a $190 million annual dividend cap. For the year
ended December 31, 2004, we paid $190 million in common stock dividends to CMS
Energy.

PREFERRED STOCK: Our Preferred Stock outstanding follows:

FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE
REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF
OTHERS: This Interpretation became effective January 2003. It describes the
disclosure to be made by a guarantor about its obligations under certain
guarantees that it has issued. At the inception of a guarantee, it requires a
guarantor to recognize a liability for the fair value of the obligation
undertaken in issuing the guarantee. The initial recognition and measurement
provision of this Interpretation does not apply to some guarantee contracts,
such as warranties, derivatives, or guarantees between either parent and
subsidiaries or corporations under common control, although disclosure of these
guarantees is required. For contracts that are within the recognition and
measurement provision of this Interpretation, the provisions were to be applied
to guarantees issued or modified after December 31, 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table describes our guarantees at December 31, 2004:

- -------------------------
(a) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.

The following table provides additional information regarding our
guarantees:

4: 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 cost and fair value of our long-term financial instruments are as
follows:

- -------------------------
(a) Includes current maturities of $118 million at December 31, 2004 and $28
million at December 31, 2003. Settlement of long-term debt is generally not
expected until maturity.

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(b) Includes current maturities of $180 million at December 31, 2004.

(c) At December 31, 2004, we held 2.4 million shares of CMS Energy Common
Stock.

(d) Nuclear decommissioning investments include cash and equivalents and
accrued income totaling $11 million at December 31, 2004 and $11 million at
December 31, 2003. Unrealized gains and losses on nuclear decommissioning
investments are reflected as regulatory liabilities.

(e) The fair value of available-for-sale debt securities by contractual
maturity as of December 31, 2004 is as follows:

Our held-to-maturity investments consist of debt securities held by the MCV
Partnership totaling $139 million as of December 31, 2004. These securities
represent funds restricted primarily for future lease payments and are
classified as Other assets on our Consolidated Balance Sheets. These investments
have original maturity dates of approximately one year or less and, because of
their short maturities, their carrying amounts approximate their fair values.

DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, and equity security
prices. We manage these risks using established policies and procedures, under
the direction of both an executive oversight committee consisting of senior
management representatives and a risk committee consisting of business-unit
managers. We may use various contracts to manage these risks including swaps,
options, futures, and forward contracts.

We intend that any gains or losses on these contracts will be offset by an
opposite movement in the value of the item at risk. We enter into all risk
management contracts for purposes other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk through
established credit policies that include performing financial credit reviews of
our counterparties. Determination of our counterparties' credit quality is based
upon a number of factors, including credit ratings, disclosed financial
condition, and collateral requirements. Where contractual terms permit, we
employ standard agreements that allow for netting of positive and negative
exposures associated with a single counterparty. Based on these policies and our
current exposures, we do not anticipate a material adverse effect on our
financial position or earnings as a result of counterparty nonperformance.

Contracts used to manage market risks may be considered derivative
instruments that are subject to derivative and hedge accounting pursuant to SFAS
No. 133. If a contract is accounted for as a derivative instrument, it is
recorded in the financial statements as an asset or a liability, at the fair
value of the contract. The recorded fair value is then adjusted quarterly to
reflect any change in the market value of the contract, a practice known as
marking the contract to market. Changes in fair value (that is, gains or losses)
are reported either in earnings or accumulated other comprehensive income,
depending on whether the derivative qualifies for cash flow hedge accounting
treatment.

For derivative instruments to qualify for hedge accounting, the hedging
relationship must be formally documented at inception and be highly effective in
achieving offsetting cash flows or offsetting changes in fair value attributable
to the risk being hedged. If hedging a forecasted transaction, the forecasted
transaction must be probable. If a derivative instrument, used as a cash flow
hedge, is terminated early because it is probable that a forecasted transaction
will not occur, any gain or loss as of such date is recognized immediately in
earnings. If a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

derivative instrument, used as a cash flow hedge, is terminated early for other
economic reasons, any gain or loss as of the termination date is deferred and
recorded when the forecasted transaction affects earnings. The ineffective
portion, if any, of all hedges is recognized in earnings.

We use a combination of quoted market prices, prices obtained from external
sources, such as brokers, and mathematical valuation models to determine the
fair value of those contracts requiring derivative accounting. In certain
contracts, long-term commitments may extend beyond the period in which market
quotations for such contracts are available. Mathematical models are developed
to determine various inputs into the fair value calculation including price and
other variables that may be required to calculate fair value. Realized cash
returns on these commitments may vary, either positively or negatively, from the
results estimated through application of the mathematical model. In connection
with the market valuation of our derivative contracts, we maintain reserves, if
necessary, for credit risks based on the financial condition of counterparties.

The majority of our contracts are not subject to derivative accounting
under SFAS No. 133 because they qualify for the normal purchases and sales
exception, or because there is not an active market for the commodity. Our
electric capacity and energy contracts are not accounted for as derivatives due
to the lack of an active energy market in the state of Michigan and the
significant transportation costs that would be incurred to deliver the power
under the contracts to the closest active energy market at the Cinergy hub in
Ohio. Similarly, our coal purchase contracts are not accounted for as
derivatives due to the lack of an active market for the coal that we purchase.
If active markets for these commodities develop in the future, we may be
required to account for these contracts as derivatives, and the resulting
mark-to-market impact on earnings could be material to our financial statements.

The MISO is scheduled to begin the Midwest Energy Market on April 1, 2005,
which will include day-ahead and real-time energy market information and
centralized dispatch for market participants. At this time, we believe that the
commencement of this market will not constitute the development of an active
energy market in the state of Michigan. However, after having adequate
experience with the Midwest Energy Market, we will reevaluate whether or not the
activity level within this market leads to the conclusion that an active energy
market exists.

Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk. The following table reflects the fair value of
all contracts requiring derivative accounting:

- -------------------------
(a) The amount associated with derivative contracts held by the MCV Partnership
as of December 31, 2003 represents our proportionate share of the
unrealized gain on those contracts accounted for as cash flow hedges
included in Accumulated other comprehensive income. Our proportionate share
of the total fair value of all derivative instruments held by the MCV
Partnership as of December 31, 2003 was $51 million, and is included in
Investments -- Midland Cogeneration Venture Limited Partnership on our
Consolidated Balance Sheets.

The fair value of our derivative contracts is included in Derivative
instruments, Other assets, or Other liabilities on our Consolidated Balance
Sheets.

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GAS CONTRACTS: Our gas utility business uses fixed-priced weather-based gas
supply call options and fixed-priced gas supply call and put options to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of Other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or liability
as part of the GCR process. At December 31, 2004, we held fixed-priced weather-
based gas supply call options and had sold fixed-priced gas supply put options.

DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP:

Gas Fuel Contracts: The MCV Partnership uses natural gas fuel contracts to
buy gas as fuel for generation, and to manage gas fuel costs. The MCV
Partnership believes that certain of its long-term natural gas contracts qualify
as normal purchases under SFAS No. 133, and therefore, these contracts were not
recognized at fair value on the balance sheet as of December 31, 2004. The MCV
Partnership also held certain long-term gas contracts that did not qualify as
normal purchases as of December 31, 2004, because these contracts contained
volume optionality. Accordingly, these contracts were accounted for as
derivatives, with changes in fair value recorded in earnings each quarter. The
MCV Partnership expects future earnings volatility on these contracts, since
gains and losses will be recorded each quarter. For the year ended December 31,
2004, we recorded a $19 million net loss associated with these gas contracts in
Fuel for electric generation on our Consolidated Statements of Income. The fair
value of these contracts will reverse over the remaining life of the contracts
ranging from 2005 to 2007.

Due to the implementation of the RCP in January 2005, the MCV Partnership
has determined that a significant portion of its gas fuel contracts no longer
qualify as normal purchases because the contracted gas will not be consumed for
electric production. Accordingly, these contracts will be treated as derivatives
and will be marked-to-market through earnings each quarter, which could increase
earnings volatility. Based on market prices for natural gas as of January 31,
2005, the accounting for the MCV Partnership's long-term gas contracts,
including those affected by the implementation of the RCP, could result in an
estimated $100 million (pretax before minority interest) gain recorded to
earnings in the first quarter of 2005. This estimated gain will reverse in
subsequent quarters as the contracts settle. For further details on the RCP, see
Note 2, Contingencies, "Other Electric Contingencies -- The Midland Cogeneration
Venture." If there are further changes in the level of planned electric
production or gas consumption, the MCV Partnership may be required to account
for additional long-term gas contracts as derivatives, which could add to
earnings volatility.

Gas Fuel Futures and Swaps: The MCV Partnership enters into natural gas
futures contracts, option contracts, and over-the-counter swap transactions in
order to hedge against unfavorable changes in the market price of natural gas in
future months when gas is expected to be needed. These financial instruments are
used principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements. At December 31, 2004, the MCV
Partnership held gas fuel futures and swaps.

The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. The MCV Partnership also engages in cost mitigation
activities to offset the fixed charges the MCV Partnership incurs in operating
the MCV Facility. These cost mitigation activities include the use of futures
and options contracts to purchase and/or sell natural gas to maximize the use of
the transportation and storage contracts when it is determined that they will
not be needed for the MCV Facility operation. Although these cost mitigation
activities do serve to offset the fixed monthly charges, these cost mitigation
activities are not considered a normal course of business for the MCV
Partnership and do not qualify as hedges. Therefore, the mark-to-market gains
and losses from these cost mitigation activities are recorded in earnings each
quarter.

As of December 31, 2004, we have recorded a cumulative net gain of $21
million, net of tax, in Accumulated other comprehensive income relating to our
proportionate share of the contracts held by the MCV

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Partnership that qualify as cash flow hedges. This balance represents natural
gas futures, options, and swaps with maturities ranging from January 2005 to
December 2009, of which $11 million of this gain is expected to be reclassified
as an increase to earnings during the next 12 months. In addition, for the year
ended December 31, 2004, we recorded a net gain of $37 million in earnings from
hedging activities related to natural gas requirements for the MCV Facility
operations and a net gain of $2 million in earnings from the MCV Partnership's
cost mitigation activities.

5: RETIREMENT BENEFITS

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

- non-contributory, defined benefit Pension Plan,

- a cash balance pension plan for certain employees hired after June 30,
2003,

- benefits to certain management employees under SERP,

- a defined contribution 401(k) plan,

- benefits to a select group of management under EISP, and

- health care and life insurance benefits under OPEB.

Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including Panhandle. The Pension Plan's assets are not
distinguishable by company.

In June 2003, CMS Energy sold Panhandle to Southern Union Panhandle Corp.
No portion of the Pension Plan assets were transferred with the sale and
Panhandle employees are no longer eligible to accrue additional benefits. The
Pension Plan retained pension payment obligations for Panhandle employees that
were vested under the Pension Plan.

The sale of Panhandle resulted in a significant change in the makeup of the
Pension Plan. A remeasurement of the obligation was required at the date of
sale. The remeasurement further resulted in the following:

- an increase in OPEB expense of $4 million for 2003, and

- an additional charge to accumulated other comprehensive income of $31
million ($20 million after-tax) in 2003 as a result of the increase in
the additional minimum pension liability. As a result of company
contributions in 2003, the additional minimum pension liability was
eliminated as of December 31, 2003.

In 2003, a substantial number of retiring employees elected a lump sum
payment instead of receiving pension benefits as an annuity over time. Lump sum
payments constitute a settlement under SFAS No. 88. A settlement loss must be
recognized when the cost of all settlements paid during the year exceeds the sum
of the service and interest costs for that year. We recorded a settlement loss
of $48 million ($31 million after-tax) in December 2003.

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 consolidated assets. Trust assets were
$30 million at December 31, 2004, and $22 million at December 31, 2003. The
assets are classified as Other non-current assets. The Accumulated Benefit
Obligation for SERP was $30 million at December 31, 2004 and $19 million at
December 31, 2003.

401(k): Employer matching contributions to the 401(k) plan are invested in
CMS Energy common stock. The amount charged to expense for this plan was $8
million in 2002. The employer's match for the 401(k) plan was suspended on
September 1, 2002 and was resumed on January 1, 2005.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The MCV Partnership sponsors a defined contribution retirement plan
covering all employees. Under the terms of the plan, the MCV Partnership makes
contributions of either 5 or 10 percent of an employee's eligible annual
compensation dependent upon the employee's age. The MCV Partnership also
sponsors a 401(k) savings plan for employees. Contributions and costs for this
plan are based on matching an employee's savings up to a maximum level. Amounts
contributed under these plans were $1 million in 2004.

EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select 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 premium for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. As of December 31, 2004, the Accumulated Benefit Obligation
of the EISP was $4 million.

OPEB: Retiree health care costs at December 31, 2004 are based on the
assumption that costs would increase 7.5 percent in 2004. The rate of increase
is expected to be 10 percent for 2005. The rate of increase is expected to slow
to an estimated 5 percent by 2010 and thereafter.

The MCV Partnership sponsors defined cost postretirement health care plans
that cover all full-time employees, except key management. Participants in the
postretirement health care plans become eligible for the benefits if they retire
on or after the attainment of age 65 or upon a qualified disability retirement,
or if they have 10 or more years of service and retire at age 55 or older. The
accumulated benefit obligation of the MCV Partnership's postretirement plans was
$5 million at December 31, 2004. The MCV Partnership's net periodic
postretirement health care cost for 2004 was less than $1 million.

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:

We adopted SFAS No. 106, effective as of 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.

The measurement date for all of Consumers' plans is November 30 for 2004,
and December 31 for 2003 and 2002. We believe accelerating the measurement date
on our benefit plans by one month is preferable as it improves control
procedures and allows more time to review the completeness and accuracy of the
actuarial measurements. As a result of the measurement date change in 2004, we
recorded a $1 million cumulative effect of change in accounting, net of tax
benefit, as a decrease to earnings. We also increased the amount of accrued
benefit cost on our Consolidated Balance Sheets by $2 million. The effect of the
measurement date change was immaterial. The measurement date for the MCV
Partnership's plan is December 31, 2004.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Assumptions: The following table recaps the weighted-average assumptions
used in our retirement benefits plans to determine the benefit obligation and
net periodic benefit cost:

- -------------------------
(a) We determine our long-term rate of return by considering historical market
returns, the current and future economic environment, the capital market
principals of risk and return, and the expert opinions of individuals and
firms with financial market knowledge. We use the asset allocation of the
portfolio to forecast 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. The use of forecasted returns
for various classes of assets used to construct an expected return model is
reviewed periodically for reasonability and appropriateness.

Costs: The following table recaps the costs incurred in our retirement
benefits plans:

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

- -------------------------
(a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003
was signed into law in December 2003. The Act 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.

We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated, retroactively, the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No.
SFAS 106-2. We remeasured our obligation as of December 31, 2003 to
incorporate the impact of the Act, which resulted in a reduction to the
accumulated postretirement benefit obligation of $148 million. The
remeasurement resulted in a reduction of OPEB cost of $23 million for 2004.
The reduction of $23 million includes $7 million in capitalized OPEB costs.
For additional details, see Note 13, Implementation of New Accounting
Standards.

(b) The Pension Plan's Accumulated Benefit Obligation of $1.082 billion exceeded
the value of the Pension Plan assets and net balance sheet asset at December
31, 2004. As a result, we recorded an additional minimum liability of $419
million. Consistent with MPSC guidance, Consumers recognized the cost of
their additional minimum liability as a regulatory asset. Accordingly,
Consumers' additional minimum liability includes an intangible asset of $21
million, and a regulatory asset of $372 million. The Accumulated Benefit
Obligation for the Pension Plan was $1.019 billion at December 31, 2003.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

- -------------------------
(a) At November 30, 2004, there were 4,892,000 shares of CMS Energy Common
Stock in the Pension Plan assets with a fair value of $50 million, and
493,000 shares in the OPEB plan assets, with a fair value of $5 million. At
December 31, 2003, there were 4,970,000 shares of CMS Energy Common Stock
in the Pension Plan assets with a fair value of $42 million, and 414,000
shares in the OPEB plan assets, with a fair value of $4 million.

(b) The percentage of fixed income at December 31, 2003 is high because our
December contribution of $329 million was deposited temporarily into fixed
income securities.

We contributed $62 million to our OPEB plan in 2004. We plan to contribute
$62 million to our OPEB plan in 2005. We did not contribute to our Pension Plan
in 2004. We do not plan to contribute to our Pension Plan in 2005.

We have established a target asset allocation for our Pension Plan assets
of 65 percent equity and 35 percent fixed income 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
a lesser allocation to the Standard & Poor's Mid Cap and Small Cap Indexes and a
Foreign Equity Index Fund. Fixed income investments are diversified across
investment grade instruments of both government and corporate issuers. Annual
liability measurements, quarterly portfolio reviews, and periodic
asset/liability studies are used to evaluate the need for adjustments to the
portfolio allocation.

We have established union and non-union VEBA trusts to fund our future
retiree health and life insurance benefits. These trusts are funded through the
rate making process for Consumers, and through direct contributions from the
non-utility subsidiaries. The equity portions of the union and non-union health
care VEBA trusts are invested in a Standard & Poor's 500 Index fund. The fixed
income portion of the union health care VEBA trust is invested in domestic
investment grade taxable instruments. The fixed income portion of the non-union
health care VEBA trust is invested in a diversified mix of domestic tax-exempt
securities. The investment selections of each VEBA 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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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Benefit Payments: The expected benefit payments for each of the next five
years and the five-year period thereafter are as follows:

- -------------------------
(a) OPEB benefit payments are net of employee contributions and expected
Medicare Part D subsidy payments.

6: ASSET RETIREMENT OBLIGATIONS

SFAS NO. 143: This standard became effective January 2003. It requires
companies to record the fair value of the cost to remove assets at the end of
their useful life, if there is a legal obligation to remove them. We have legal
obligations to remove some of our assets, including our nuclear plants, at the
end of their useful lives. As required by SFAS No. 71, we accounted for the
implementation of this standard by recording regulatory assets and liabilities
instead of a cumulative effect of a change in accounting principle.

The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. 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 would increase by $22 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. Generally, gas transmission and electric and gas distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets. Also, no liability has been recorded for assets that have
insignificant cumulative disposal costs, such as substation batteries. The
measurement of the ARO liabilities for Palisades and Big Rock are based on
decommissioning studies that largely utilize third-party cost estimates.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:

The principal components of our deferred tax assets (liabilities)
recognized in the balance sheet are as follows:

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The actual income tax expense differs from the amount computed by applying
the statutory federal tax rate of 35 percent to income before income taxes as
follows:

8: EXECUTIVE INCENTIVE COMPENSATION

We provide a Performance Incentive Stock Plan (the Plan) to key employees
and non-employee Directors or consultants based on their contributions to the
successful management of the company. On May 28, 2004, shareholders approved an
amendment to the Plan, with an effective date of June 1, 2004. The amendment
established a 5-year term for the Plan. The Plan includes the following type of
awards:

- phantom shares,

- performance units,

- restricted stock,

- stock options,

- stock appreciation rights, and

- management stock purchases.

Phantom shares are valued at the fair market price of common stock when
granted. They give the holder the right to receive the appreciation value of
common stock on one or more valuation dates, according to a specified vesting
schedule determined at time of grant. These shares are subject to forfeiture if
employment terminates before vesting.

Performance units have an initial value established at the time of grant.
Performance criteria are established at the time of grant and, depending upon
the extent to which they are met, will determine the value of the payout, which
may be in the form of cash, common stock, or a combination of both. These units
are subject to forfeiture if employment terminates.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Restricted shares of common stock are outstanding shares with full voting
and dividend rights. These awards vest 100 percent after three years and are
subject to achievement of specified levels of total shareholder return including
a comparison to a peer group of companies. Some awards vest based solely on
continued employment. These awards are subject to forfeiture if employment
terminates before vesting. Restricted shares vest fully if control of CMS Energy
changes, as defined by the Plan.

Stock options give the holder the right to purchase common stock at a given
price over an extended period of time. Stock appreciation rights give the holder
the right to receive common stock appreciation, defined as the excess of the
market price of the stock at the date of exercise over the grant date price. All
stock options and stock appreciation rights are valued at fair market price when
granted. All options and rights may be exercised upon grant, and expire up to 10
years and one month from the date of grant.

Management stock purchases are the election of select participants in the
Officer's Incentive Compensation Plan to receive all or a portion of their
incentive payments in the form of shares of restricted common stock or shares of
restricted stock units. These participants may also receive awards of additional
restricted common stock or restricted stock units provided the total value of
these additional grants does not exceed $2.5 million for any fiscal year.

Under the revised Plan, shares awarded or subject to options, phantom
shares and performance units may not exceed 6 million shares from June 2004
through May 2009, nor may such grants or awards to any participant exceed
250,000 shares in any fiscal year.

Shares for which payment or exercise is in cash, as well as shares or
options that are forfeited, may be awarded or granted again under the Plan.

Awards of up to 5,482,690 shares of CMS Energy Common Stock may be issued
as of December 31, 2004. All grants awarded under this Plan in 2004 were in the
form of restricted stock.

The following table summarizes the restricted stock and stock options
granted to our key employees under the Performance Incentive Stock Plan:

At December 31, 2004, 316,312 of the 863,202 shares of CMS Energy
restricted common stock outstanding are subject to performance objectives.
Compensation expense for restricted stock was $2 million in 2004, $4 million in
2003, and less than $1 million in 2002.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table summarizes our stock options outstanding at December
31, 2004:

In December 2002, we adopted the fair value based method of accounting for
stock-based employee compensation, under SFAS No. 123, as amended by SFAS No.
148. We elected to adopt the prospective method recognition provisions of this
Statement, which applies the recognition provisions to all awards granted,
modified, or settled after the beginning of the fiscal year that the recognition
provisions are first applied.

The following table summarizes the weighted average fair value of stock
options granted:

- -------------------------
(a) There were no stock option grants during 2004.

(b) For 2002, there were two stock option grants totaling 490,600 options.

The stock options fair value is estimated using the Black-Scholes model, a
mathematical formula used to value options traded on securities exchanges. The
following assumptions were used in the Black-Scholes model:

- -------------------------
(a) There were no stock option grants during 2004.

(b) For 2002, there were two stock option grants totaling 490,600 options.

We recorded $3 million as stock-based employee compensation cost for 2003,
and $1 million for 2002. All stock options vest at date of grant.

9: LEASES

We lease various assets, including vehicles, railcars, construction
equipment, furniture, and buildings. We have both full-service and net leases. A
net lease requires us to pay for taxes, maintenance, operating costs, and
insurance. Most of our leases contain options at the end of the initial lease
term to:

- purchase the asset at fair value, or

- renew the lease at fair rental value.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Our capital leases are comprised mainly of leased service vehicles and
office furniture. As of December 31, 2004, capital lease obligations totaled $58
million. 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. Capital lease expenses were $13 million in 2004, $17 million in 2003,
and $20 million in 2002. In November 2003, we exercised our purchase option
under the capital lease agreement for our main headquarters building in Jackson,
Michigan. Operating lease charges were $13 million in 2004, $13 million in 2003,
and $13 million in 2002.

In order to obtain permanent financing for the MCV Facility, the MCV
Partnership entered into a sale and lease back agreement with a lessor group,
which includes the FMLP, for substantially all of the MCV Partnership's fixed
assets. In accordance with SFAS No. 98, the MCV Partnership accounts for the
transaction as a financing arrangement. As of December 31, 2004, finance lease
obligations totaled $286 million, which represents the third-party portion of
the MCV Partnership's finance lease obligation. Charges under the MCV
Partnership's finance lease obligation were $105 million in 2004. For additional
details on transactions with the MCV Partnership and the FMLP, see Note 2,
Contingencies, "Other Electric Contingencies -- The Midland Cogeneration
Venture."

Minimum annual rental commitments under our non-cancelable leases at
December 31, 2004 were:

10: SUMMARIZED FINANCIAL INFORMATION OF SIGNIFICANT RELATED ENERGY SUPPLIER

Under Revised FASB Interpretation No. 46, we are the primary beneficiary of
the MCV Partnership. We consolidated their assets, liabilities, and financial
activities into our financial statements as of and for the year ended December
31, 2004. As of December 31, 2004, the MCV Partnership had total assets of
$1.980 billion and a net loss of $24 million for the year. For 2003 and 2002,
the MCV Partnership was accounted for as an equity method investment and their
summarized financial information is shown below. Our 49 percent investment in
the MCV Partnership was $419 million at December 31, 2003 and our share of net
income was $29 million for the year ended December 31, 2003 and $65 million for
the year ended December 31, 2002.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Under the PPA with the MCV Partnership discussed in Note 2, Contingencies,
our 2003 obligation to purchase electric capacity from the MCV Partnership
provided 15 percent of our owned and contracted electric generating capacity.
Summarized financial information of the MCV Partnership for 2003 and 2002
follows:

STATEMENTS OF INCOME

BALANCE SHEET

- -------------------------
(a) Revenue from Consumers totaled $514 million in 2003 and $557 million in
2002.

(b) On April 1, 2002, the MCV Partnership implemented a new accounting standard
for derivatives. As a result, the MCV Partnership began accounting for
several natural gas contracts containing an option component at fair value.
The MCV Partnership recorded a $58 million cumulative effect adjustment for
the change in accounting principle as an increase to earnings. CMS
Midland's 49 percent ownership share was $28 million ($18 million
after-tax), which is reflected as a change in accounting principle on our
Consolidated Statements of Income.

(c) Receivables from Consumers totaled $40 million for December 31, 2003.

(d) The FMLP is the sole beneficiary of a trust that is the lessor in a
long-term direct finance lease with the MCV Partnership. CMS Holdings holds
a 46.4 percent ownership interest in the FMLP. The MCV Partnership's lease
obligations, assets, and operating revenues secure the FMLP's debt. The
following table summarizes obligation and payment information regarding the
direct finance lease:

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

(e) CMS Midland's recorded investment in the MCV Partnership includes
capitalized interest, which we are expensing over the life of our
investment in the MCV Partnership. The financing agreements prohibit the
MCV Partnership from distributing any cash to its owners until it meets
certain financial test requirements. We do not anticipate receiving a cash
distribution in the near future.

11: JOINTLY OWNED REGULATED UTILITY FACILITIES

We are required to provide only our share of financing for the jointly
owned utility facilities. The direct expenses of the jointly owned plants are
included in operating expenses. Operation, maintenance, and other expenses of
these jointly owned utility facilities are shared in proportion to each
participant's undivided ownership interest. The following table indicates the
extent of our investment in jointly owned regulated utility facilities:

12: REPORTABLE SEGMENTS

Our reportable segments are strategic business units organized and managed
by the nature of the products and services each provides. We evaluate
performance based upon the net income of each segment. We operate principally in
two segments, electric utility and gas utility.

The electric utility segment consists of regulated activities associated
with the generation and distribution of electricity in the state of Michigan.
The gas utility segment consists of regulated activities associated with the
transportation, storage, and distribution of natural gas in the state of
Michigan.

Accounting policies of the segments are the same as we describe in the
summary of significant accounting policies. Our financial statements reflect the
assets, liabilities, revenues, and expenses directly related to the electric and
gas segment where it is 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, other operation and maintenance expense,
construction expense, leased property, taxes or functional surveys. For example,
customer receivables are allocated based on revenue. Pension provisions are
allocated based on labor dollars.

We account for inter-segment sales and transfers at current market prices
and eliminate them in consolidated net income available to common stockholder by
segment. The "Other" segment includes our consolidated special purpose entity
for the sale of trade receivables, the MCV Partnership and the FMLP.

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

The following table shows our financial information by reportable segment:

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CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

- -------------------------
(a) 2002 excludes $28 million benefit due to the change in accounting for
derivative instruments.

(b) 2002 excludes $10 million tax expense due to the change in accounting for
derivative instruments.

(c) As of December 31, 2003, the trusts that hold the mandatorily redeemable
Trust Preferred Securities were deconsolidated. The trusts are now included
on our Consolidated Balance Sheets as Investments -Other.

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

(e) Amounts include electric restructuring implementation plan, purchase of
nuclear fuel, and other assets. Amounts also include a portion of capital
expenditures for plant and equipment attributable to both the electric and
gas utility businesses.

13: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST
ENTITIES: The FASB issued this Interpretation in January 2003. The objective of
the Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.

In December 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that had not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.

We determined that we are the primary beneficiary of both the MCV
Partnership and the FMLP. We have a 49 percent partnership interest in the MCV
Partnership and a 46.4 percent partnership interest in the FMLP. Consumers is
the primary purchaser of power from the MCV Partnership through a long-term
power purchase agreement. The FMLP holds a 75.5 percent lessor interest in the
MCV Facility, which results in Consumers holding a 35 percent lessor interest in
the MCV Facility. Collectively, these interests make us the primary beneficiary
of these entities. As such, we consolidated their assets, liabilities, and
activities into our financial statements as of and for the year ended December
31, 2004. These partnerships have third-party obligations totaling $582 million
at December 31, 2004. Property, plant, and equipment serving as collateral for
these obligations has a carrying value of $1.426 billion at December 31, 2004.
The creditors of these partnerships do not have recourse to the general credit
of Consumers.

We determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities were deconsolidated
as of December 31, 2003. Company Obligated Trust Preferred Securities totaling
$490 million that were previously included in mezzanine equity, were eliminated
due to deconsolidation. At December 31, 2004, we reflected Long-term
debt -- related parties of $326 million, current portion of Long-term
debt -- related parties of $180 million, and an investment in related parties of
$16 million.

We are not required to restate prior periods for the impact of this
accounting change.

CE-82

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

FASB STAFF POSITION, NO. SFAS 106-2, ACCOUNTING AND DISCLOSURE REQUIREMENTS
RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND MODERNIZATION ACT OF
2003: The Medicare Prescription Drug, Improvement, and Modernization Act of 2003
(the Act) was signed into law in December 2003. The Act establishes a
prescription drug benefit under Medicare (Medicare Part D) and a federal
subsidy, which is exempt from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D.

We believe our plan is actuarially equivalent to Medicare Part D and have
incorporated retroactively the effects of the subsidy into our financial
statements as of June 30, 2004, in accordance with FASB Staff Position, No. SFAS
106-2. We remeasured our obligation as of December 31, 2003 to incorporate the
impact of the Act, which resulted in a reduction to the accumulated
postretirement benefit obligation of $148 million. The remeasurement resulted in
a total OPEB cost reduction of $23 million for 2004. Consumers capitalizes a
portion of OPEB cost in accordance with regulatory accounting. As such, the
remeasurement resulted in a net reduction of OPEB expense of $16 million for
2004.

EITF ISSUE NO. 03-1, THE MEANING OF OTHER-THAN-TEMPORARY IMPAIRMENTS: The
Issue addresses the definition of an other-than-temporary impairment of certain
investments and provides additional disclosure requirements. The scope of EITF
Issue No. 03-1 includes debt and equity securities accounted for under SFAS No.
115, debt and equity securities held by non-profit organizations under SFAS No.
124, and cost method investments under APB No. 18. We analyzed our in-scope
investments under the guidance of this Issue and have provided additional
disclosures.

FSP 109-1, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE TAX DEDUCTION
PROVIDED TO U.S. BASED MANUFACTURERS BY THE AMERICAN JOBS CREATION ACT OF
2004: The American Jobs Creation Act of 2004 provides for a deduction, starting
in 2005, of a portion of the income from certain production activities,
including the production of electricity. FSP 109-1 indicates that the deduction
should be accounted for as a special deduction rather than a tax rate reduction
under SFAS No. 109. We are currently studying this act for its impact on us;
however, we do not anticipate a material amount of tax benefit from the domestic
production activities deduction in the near future.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

SFAS NO. 123R, SHARE-BASED PAYMENT: The Statement requires companies to
expense the grant date fair value of employee stock options and similar awards.
The Statement also clarifies and expands SFAS No. 123's guidance in several
areas, including measuring fair value, classifying an award as equity or as a
liability, and attributing compensation cost to reporting periods.

In addition, this Statement amends SFAS No. 95, Statement of Cash Flows, to
require that excess tax benefits related to the excess of the tax deductible
amount over the compensation cost recognized be classified as a financing cash
inflow rather than as a reduction of taxes paid in operating activities.

This Statement is effective for us as of the beginning of third quarter
2005. We adopted the fair value method of accounting for share-based awards
effective December 2002, and therefore, expect this statement to have an
insignificant impact on our results of operations when it becomes effective.

CE-83

CONSUMERS ENERGY COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

14: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)

CE-84

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, 2004 and 2003, and the related consolidated
statements of income, common stockholder's equity and cash flows for each of the
three years in the period ended December 31, 2004. Our audits also included the
financial statement schedule 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. The financial statements of Midland
Cogeneration Venture Limited Partnership, a 49% owned variable interest entity
which has been consolidated in 2004 pursuant to Revised Financial Accounting
Standards Board Interpretation No. 46, "Consolidation of Variable Interest
Entities" and accounted for under the equity method of accounting in 2003 and
2002, have been audited by other auditors whose report has been furnished to us;
insofar as our opinion on the consolidated financial statements relates to the
amounts included for Midland Cogeneration Venture Limited Partnership, it is
based solely on their report.

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
consolidated financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Consumers Energy
Company and subsidiaries at December 31, 2004 and 2003, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004 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 13 to the consolidated financial statements, in 2004,
the Company adopted Revised Financial Accounting Standards Board Interpretation
No. 46, "Consolidation of Variable Interest Entities". In addition, as discussed
in Note 5 to the consolidated financial statements, in 2004, the Company changed
its measurement date for all Consumers Energy Company pension and postretirement
benefit plans. As discussed in Notes 6 and 13 to the consolidated financial
statements, in 2003, the Company adopted the provisions of Statement of
Financial Accounting Standards No. 143, "Accounting for Asset Retirement
Obligations" and of FASB Interpretation No. 46, "Consolidation of Variable
Interest Entities".

We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of
Consumers Energy Company's internal control over financial reporting as of
December 31, 2004, based on criteria established in Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission and our report dated March 7, 2005 expressed an unqualified opinion
thereon.

/s/ Ernst & Young LLP

Detroit, Michigan
March 7, 2005

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:

We have completed an integrated audit of Midland Cogeneration Venture
Limited Partnership's 2004 consolidated financial statements and of its internal
control over financial reporting as of December 31, 2004 and audits of its 2003
and 2002 consolidated financial statements in accordance with the standards of
the Public Company Accounting Oversight Board (United States). Our opinions,
based on our audits, are presented below.

CONSOLIDATED FINANCIAL STATEMENTS

In our opinion, the accompanying consolidated balance sheets and the
related consolidated statements of operations, partners' equity and cash flows
(not presented herein) present fairly, in all material respects, the financial
position of Midland Cogeneration Limited Partnership (a Michigan limited
partnership) and its subsidiaries (MCV) at December 31, 2004 and 2003, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of MCV'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 of financial
statements 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.

As explained in Note 2 to the financial statements, effective April 1,
2002, Midland Cogeneration Venture Limited Partnership changed its method of
accounting for derivative and hedging activities in accordance with Derivative
Implementation Group ("DIG") Issue C-16.

INTERNAL CONTROL OVER FINANCIAL REPORTING

Also, in our opinion, management's assessment, included in Management's
Report on Internal Control Over Financial Reporting, that MCV maintained
effective internal control over financial reporting as of December 31, 2004
based on criteria established in Internal Control -- Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission (COSO),
is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, MCV maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2004, based on
criteria established in Internal Control -- Integrated Framework issued by COSO.
MCV's management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express opinions on
management's assessment and on the effectiveness of MCV's internal control over
financial reporting based on our audit. We conducted our audit of internal
control over financial reporting 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
effective internal control over financial reporting was maintained in all
material respects. An audit of internal control over financial reporting
includes obtaining an understanding of internal control over financial
reporting, evaluating management's assessment, testing and evaluating the design
and operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinions.

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,

CE-86

accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are recorded as
necessary to permit preparation of financial statements in accordance with
generally accepted accounting principles, and that receipts and expenditures of
the company are being made only in accordance with authorizations of management
and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition
of the company's assets that could have a material effect on the financial
statements.

Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Detroit, Michigan
February 25, 2005

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ON ACCOUNTING AND FINANCIAL DISCLOSURE.

CMS ENERGY

None.

CONSUMERS

None.

ITEM 9A. CONTROLS AND PROCEDURES.

CMS ENERGY

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 are effective
as of the end of the period covered by this annual report.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: CMS
Energy's management's assessment of internal control over financial reporting
appears in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS, and is
incorporated by reference herein.

CONSUMERS

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 are effective as
of the end of the period covered by this annual report.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING:
Consumers' management's assessment of internal control over financial reporting
appears in ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND ANALYSIS, and is
incorporated by reference herein.

ITEM 9B. OTHER INFORMATION.

CMS ENERGY

None.

CONSUMERS

None.

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PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.

CMS ENERGY

Information that is required in Item 10 regarding directors and executive
officers is included in CMS Energy's definitive proxy statement, which is
incorporated by reference herein.

CONSUMERS

Information that is required in Item 10 regarding Consumers' directors and
executive officers is included in CMS Energy's definitive proxy statement, which
is incorporated by reference herein.

ITEM 11. EXECUTIVE COMPENSATION.

CMS ENERGY

Information that is required in Item 11 regarding executive compensation is
included in CMS Energy's definitive proxy statement, which is incorporated by
reference herein.

CONSUMERS

Information that is required in Item 11 regarding executive compensation of
Consumers' executive officers is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT RELATED STOCKHOLDER MATTERS.

CMS ENERGY

Information that is required in Item 12 regarding securities authorized for
issuance under equity compensation plans and security ownership of certain
beneficial owners and management is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.

CONSUMERS

Information that is required in Item 12 regarding securities authorized for
issuance under equity compensation plans and security ownership of certain
beneficial owners and management of Consumers is included in CMS Energy's
definitive proxy statement, which is incorporated by reference herein.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

CMS ENERGY

Information that is required in Item 13 regarding certain relationships and
related transactions 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 regarding Consumers is included in CMS Energy's definitive
proxy statement, which is incorporated by reference herein.

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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) Financial Statement Schedules and Reports of Independent Public
Accountants for CMS Energy and Consumers are included after the
Exhibits to the Index to Financial Statement Schedules and are
incorporated by reference herein.

(a)(3) Exhibits for CMS Energy and Consumers are listed after Item 15(c)
below and are incorporated by reference herein.

(b) Exhibits, including those incorporated by reference (see also
Exhibit volume).

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CMS ENERGY'S AND CONSUMERS' EXHIBITS

CO-4

CO-5

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- -------------------------
* Obligations of only CMS Holdings and CMS Midland, second tier subsidiaries of
Consumers, and of CMS Energy but not of Consumers.

Exhibits listed above that have heretofore been filed with the Securities
and Exchange Commission 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-8

INDEX TO FINANCIAL STATEMENT SCHEDULES

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.

CO-9

CMS ENERGY CORPORATION

Schedule II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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CONSUMERS ENERGY COMPANY

SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
YEARS ENDED DECEMBER 31, 2004, 2003 AND 2002

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
10th day of March 2005.

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 and on the 10th day of March 2005.

CO-12

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 10th day of March 2005.

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 and on the 10th day of March
2005.

CO-14

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CMS ENERGY'S AND CONSUMERS' EXHIBIT INDEX

EXHIBITS DESCRIPTION
- -------- -----------

(4)(a)(i) -- 99th Supplemental Indenture dated as of 1/20/05, supplement
to Indenture dated as of September 1, 1945, between
Consumers and Chemical Bank (successor to Manufacturers
Hanover Trust Company), as Trustee
(4)(b)(i) -- 4th Supplemental Indenture dated as of May 31, 2001,
supplement to Indenture dated as of January 1, 1996
between Consumers and The Bank of New York, as Trustee
(4)(d)(i) -- 15th Supplemental Indenture dated as of 9/29/04, supplement
to Indenture dated as of September 15, 1992 between CMS
Energy and NBD Bank, as Trustee
(4)(d)(ii) -- 16th Supplemental Indenture dated as of 12/16/04,
supplement to Indenture dated as of September 15, 1992
between CMS Energy and NBD Bank, as Trustee
(4)(j) -- $300 million Fifth Amended and Restated Credit Agreement
dated as of August 3, 2004 among CMS Energy, CMS
Enterprises, the Banks, and the Administrative Agent and
Collection Agent, all defined therein
(4)(k) -- Reaffirmation of grant of a security interest dated as of
August 3, 2004 among CMS Energy, CMS Enterprises, and the
Administrative Agent and Collateral Agent, as defined
therein
(4)(l) -- Cash Collateral Agreement dated as of August 3, 2004 made
by CMS Energy to the Administrative Agent for the lenders
and Collateral Agent, as defined therein
(10)(f) -- Annual Officer Incentive Compensation Plan for CMS Energy
Corporation and its Subsidiaries effective January 1, 2004
(10)(w) -- Annual Management Incentive Compensation Plan for CMS
Energy Corporation and its Subsidiaries effective January
1, 2004
(10)(x) -- Annual Employee Incentive Compensation Plan for CMS Energy
Corporation and its Subsidiaries effective January 1, 2004
(12)(a) -- Statement regarding computation of CMS Energy's Ratio of
Earnings to Fixed Charges
(12)(b) -- Statement regarding computation of Consumers' Ratio of
Earnings to Fixed Charges and Preferred Securities
Dividends and Distributions
(18) -- Letter from Ernst & Young LLP to the Audit Committee of the
Boards of Directors for CMS Energy and Consumers regarding
the preferability of a change in accounting principle
(23)(a) -- Consent of Ernst & Young LLP for CMS Energy
(23)(b) -- Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV
(23)(c) -- Consent of Pricewaterhouse for CMS Energy re: Jorf Lasfar
(23)(d) -- Consent of Ernst & Young LLP for Consumers
(23)(e) -- Consent of PricewaterhouseCoopers LLP for Consumers 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

EXHIBITS DESCRIPTION
- -------- -----------

(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
(99)(a) -- Financial Statements for Midland Cogeneration Venture
Limited Partnership for the years ended December 31, 2001,
2002, and 2003
(99)(b) -- Financial Statements for Jorf Lasfar for the years ended
December 31, 2002, 2003, and 2004
(99)(c) -- Representation regarding Emirates CMS Power Company
financial statements for the years ended December 31, 2002,
2003 and 2004
(99)(d) -- Representation regarding SCP Investments (1) PTY. LTD.
financial statements for the years ended June 30, 2003,
2004 and 2005