CMS ENERGY CORP - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ____to

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

1-5611 CONSUMERS ENERGY COMPANY 38-0442310
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550

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

Indicate by check mark whether the Registrants are accelerated filers (as
defined in Rule 12b-2 of the Exchange Act).

CMS ENERGY CORPORATION: Yes [X] No [ ]
CONSUMERS ENERGY COMPANY: Yes [ ] No [X]

Number of shares outstanding of each of the issuer's classes of common stock at
October 31, 2004:

CMS ENERGY CORPORATION:
CMS Energy Common Stock, $.01 par value 194,725,703
CONSUMERS ENERGY COMPANY, $10 par value, privately held by CMS
Energy Corporation 84,108,789

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CMS ENERGY CORPORATION
AND
CONSUMERS ENERGY COMPANY

QUARTERLY REPORTS ON FORM 10-Q TO THE
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
FOR THE QUARTER ENDED SEPTEMBER 30, 2004

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

TABLE OF CONTENTS

Page
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Glossary.................................................................................................. 4

PART I: FINANCIAL INFORMATION

CMS Energy Corporation
Management's Discussion and Analysis
Executive Overview.............................................................................. CMS - 1
Restatement of 2003 Financial Statements........................................................ CMS - 2
Consolidation of Variable Interest Entities..................................................... CMS - 2
Forward-Looking Statements and Risk Factors..................................................... CMS - 2
Results of Operations........................................................................... CMS - 4
Critical Accounting Policies.................................................................... CMS - 13
Capital Resources and Liquidity................................................................. CMS - 25
Outlook......................................................................................... CMS - 28
New Accounting Standards........................................................................ CMS - 40
Consolidated Financial Statements
Consolidated Statements of Income (Loss)........................................................ CMS - 44
Consolidated Statements of Cash Flows........................................................... CMS - 46
Consolidated Balance Sheets..................................................................... CMS - 48
Consolidated Statements of Common Stockholders' Equity.......................................... CMS - 50
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies................................................ CMS - 51
2. Discontinued Operations, Other Asset Sales, Impairments, and Restructuring................. CMS - 54
3. Uncertainties.............................................................................. CMS - 59
4. Financings and Capitalization.............................................................. CMS - 85
5. Earnings Per Share......................................................................... CMS - 90
6. Financial and Derivative Instruments....................................................... CMS - 92
7. Retirement Benefits........................................................................ CMS - 98
8. Equity Method Investments.................................................................. CMS - 99
9. Reportable Segments........................................................................ CMS - 100
10. Asset Retirement Obligations............................................................... CMS - 102
11. Implementation of New Accounting Standards................................................. CMS - 104

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TABLE OF CONTENTS
(CONTINUED)

Page
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Consumers Energy Company
Management's Discussion and Analysis
Executive Overview.............................................................................. CE - 1
Consolidation of the MCV Partnership and the FLMP............................................... CE - 2
Forward-Looking Statements and Risk Factors..................................................... CE - 2
Results of Operations........................................................................... CE - 4
Critical Accounting Policies.................................................................... CE - 8
Capital Resources and Liquidity................................................................. CE - 17
Outlook......................................................................................... CE - 19
New Accounting Standards........................................................................ CE - 30
Consolidated Financial Statements
Consolidated Statements of Income............................................................... CE - 33
Consolidated Statements of Cash Flows........................................................... CE - 34
Consolidated Balance Sheets..................................................................... CE - 36
Consolidated Statements of Common Stockholder's Equity.......................................... CE - 38
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies................................................. CE - 41
2. Uncertainties............................................................................... CE - 44
3. Financings and Capitalization............................................................... CE - 65
4. Financial and Derivative Instruments........................................................ CE - 68
5. Retirement Benefits......................................................................... CE - 72
6. Asset Retirement Obligations................................................................ CE - 73
7. Implementation of New Accounting Standards.................................................. CE - 75

Quantitative and Qualitative Disclosures about Market Risk................................................ CO - 1
Controls and Procedures................................................................................... CO - 1

PART II: OTHER INFORMATION

Item 1. Legal Proceedings............................................................................ CO - 1
Item 5. Other Information............................................................................ CO - 6
Item 6. Exhibits and Reports on Form 8-K............................................................. CO - 6
Signatures........................................................................................... CO - 8

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GLOSSARY

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

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
ALJ............................................... Administrative Law Judge
Alliance RTO...................................... Alliance Regional Transmission Organization
Alstom............................................ Alstom Power Company
APB............................................... Accounting Principles Board
APB Opinion No. 18................................ APB Opinion No. 18, "The Equity Method of Accounting for Investments
in Common Stock"
APT............................................... Australian Pipeline Trust
ARO............................................... Asset retirement obligation
Articles.......................................... Articles of Incorporation
Attorney General.................................. Michigan Attorney General

bcf............................................... Billion cubic feet
Big Rock.......................................... Big Rock Point nuclear power plant, owned by Consumers
Board of Directors................................ Board of Directors of CMS Energy
Btu............................................... British thermal unit

CEO............................................... Chief Executive Officer
CFO............................................... Chief Financial Officer
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 subsidiary of Enterprises
CMS Generation.................................... CMS Generation Co., a subsidiary of Enterprises
CMS Holdings...................................... CMS Midland Holdings Company, a subsidiary of Consumers
CMS Midland....................................... CMS Midland Inc., a subsidiary of Consumers
CMS MST........................................... CMS Marketing, Services and Trading Company, a wholly owned subsidiary of
Enterprises, whose name was changed to CMS ERM effective January 2004

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CMS Oil and Gas................................... CMS Oil and Gas Company, formerly a subsidiary of Enterprises
CMS PEPS.......................................... CMS Energy Premium Equity Participating Security Units (CMS Energy Trust III)
CMS Pipeline Assets............................... CMS Enterprises pipeline assets in Michigan and Australia
CMS Viron......................................... CMS Viron Energy Services, 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
Consumers Funding................................. Consumers Funding LLC, a wholly owned special purpose subsidiary of Consumers
for the issuance of securitization bonds dated November 8, 2001
Consumers Receivables Funding II.................. Consumers Receivables Funding II LLC, a wholly owned subsidiary of Consumers
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 Generation
DOE............................................... U.S. Department of Energy
DOJ............................................... U.S. Department of Justice
Dow............................................... The Dow Chemical Company, a non-affiliated company

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
El Chocon ........................................ Hidroelectrica El Chocon, S.A., a 1,320 MW hydroelectric generating complex in
Argentina, in which CMS Energy 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

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Exchange Act...................................... Securities Exchange Act of 1934, as amended

FASB.............................................. Financial Accounting Standards Board
FASB Staff Position, No. 106-1.................... Accounting and Disclosure Requirements Related to the Medicare Prescription
Drug, Improvement and Modernization Act of 2003 (January 12, 2004)
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
FMB............................................... First Mortgage Bonds
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
GEII.............................................. General Electric International Inc.
Goldfields........................................ A pipeline business located in Australia, in which CMS Energy formerly held
a 39.7 percent ownership interest
Guardian.......................................... Guardian Pipeline, LLC, in which CMS Gas Transmission owned a one-third interest

Health Care Plan.................................. The medical, dental, and prescription drug programs offered to eligible
employees of Consumers and CMS Energy
HL Power.......................................... H.L. Power Company, a California Limited Partnership, owner of the Honey Lake
generation project in Wendel, California

Integrum.......................................... Integrum Energy Ventures, LLC
IPP............................................... Independent Power Production

JOATT............................................. Joint Open Access Transmission Tariff
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 held a 50 percent
ownership interest
LNG............................................... Liquefied natural gas

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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
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.............................................. Michigan Electric Transmission Company, formerly a subsidiary of Consumers
and now an indirect subsidiary of Trans-Elect
Michigan Power.................................... CMS Generation Michigan Power, LLC, owner of the Kalamazoo River Generating
Station and the Livingston Generating Station
MISO.............................................. Midwest Independent System Operator
Moody's........................................... Moody's Investors Service, Inc.
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

OATT.............................................. Open Access Transmission Tariff
OPEB.............................................. Postretirement benefit plans other than pensions for retired employees

Palisades......................................... Palisades nuclear power plant, which is owned by Consumers

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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 & 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, as amended, and as interpreted by the
Settlement Agreement dated as of January 1, 1999 between the MCV and Consumers.
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
Rouge............................................. Rouge Steel Industries

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
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

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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. 107...................................... SFAS No. 107, "Disclosures about Fair Value of Financial Instruments"
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. 128...................................... SFAS No. 128, "Earnings per Share"
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
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
Taweelah.......................................... Al Taweelah A2, a power and desalination plant of Emirates CMS Power Company,
in which CMS Generation holds a 40 percent interest
TEPPCO............................................ Texas Eastern Products Pipeline Company, LLC

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Toledo Power...................................... Toledo Power Company, the 135 MW coal and fuel oil power plant located on Cebu
Island, Phillipines, in which CMS Generation held a 47.5 percent interest.
Transition Costs.................................. Stranded Costs, as defined, plus the costs incurred in the transition to
competition
Trunkline......................................... Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle Holdings, LLC
Trunkline LNG..................................... 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

VEBA Trusts....................................... VEBA (voluntary employees' beneficiary association) trust accounts
established to specifically set aside employer contributed assets to pay for
future expenses of the OPEB plan

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11

CMS Energy Corporation

CMS ENERGY CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS

This MD&A is a combined 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
combined entity, except where it is made 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 and operate principally in three business segments: electric utility,
gas utility, and enterprises.

We earn our revenue and generate cash from operations by providing electric and
natural gas utility services, electric power generation, gas transmission,
storage, and processing. Our businesses are affected by weather, especially
during the traditional heating and cooling seasons, economic conditions,
particularly in Michigan, regulation and regulatory issues that primarily affect
our gas and electric utility operations, interest rates, our debt credit rating,
and energy commodity prices.

Our business strategy involves rebuilding 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. Much of our asset sales program is complete; we are engaged
in selling the remaining businesses that are not strategic to us. Over the next
few years, we expect this strategy to reduce our parent company debt
substantially, improve our debt ratings, grow earnings at a mid-single digit
rate, restore a meaningful dividend, and position the company to make new
investments consistent with our strengths. In the near term, our new investments
will focus on the utility.

We face important challenges in the future. We continue to lose industrial and
commercial customers to alternative electric suppliers without receiving
compensation for Stranded Costs caused by the lost sales. As of October 2004, we
have lost 877 MW or 11 percent of our electric load to these alternative
electric suppliers. Based on current trends, we predict load loss by year-end to
be in the range of 900 MW to 1,000 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, but the MPSC
has not yet authorized Stranded Cost recovery. We continue to seek resolution of
this issue through two pending Stranded Cost cases before the MPSC. In July
2004, several bills were introduced into the Michigan Senate that could change
Michigan's Customer Choice Act.

Further, higher natural gas prices have harmed the economics of the MCV
Partnership and we are seeking approval from the MPSC to change the way the
facility is used. Our proposal would reduce gas consumption by an estimated 30
to 40 bcf per year while improving the MCV Partnership's financial performance
with no change to customer rates. A portion of the benefits from the proposal
will support additional renewable resource development in Michigan. Resolving
the issue is important for our shareowners and customers.

CMS-1

CMS Energy Corporation

Our business plan is targeted at predictable earnings growth and debt reduction.
We are now over a year into our plan to reduce, by about half, the debt of CMS
Energy over a five-year period. In this regard, in August 2004, Consumers
completed an $800 million First Mortgage Bond financing at interest rates
ranging from 4.4 percent to 5.5 percent and used the proceeds to retire other
higher-interest rate long-term debt. Also in August 2004, we made a $150 million
investment in Consumers, providing additional liquidity and flexibility for our
utility operations. In October 2004, we issued 32.8 million shares of our common
stock, which included an option for an additional 4.3 million shares from the
original offering. We realized $288 million in net proceeds from this offering
and plan to use the cash to make additional capital infusions into Consumers. In
fact, on November 1, 2004, we invested $100 million of those proceeds into
Consumers. Pending further capital infusions, the proceeds will be used for
general corporate purposes, including temporary investments in short-term
securities. The result of these efforts, and others, will be a strong, reliable
energy company that will be poised to take advantage of opportunities for
further growth.

RESTATEMENT OF 2003 FINANCIAL STATEMENTS

Our financial statements as of and for the three and nine months ended September
30, 2003, as presented in this Form 10-Q, have been restated for the following
matters that were disclosed previously in Note 19, Quarterly Financial and
Common Stock Information (Unaudited), in our 2003 Form 10-K/A:

- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations," due to a change
in our expectations as to the timing of the sales,

- certain derivative accounting corrections at our equity
affiliates, and

- the net loss recorded in the second quarter of 2003 relating to
the sale of Panhandle, reflected as Discontinued Operations, was
understated by approximately $14 million, net of tax.

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 three and nine months ended September
30, 2004. These entities are reported as equity method investments in our
financial statements as of and for the three and nine months ended September 30,
2003. The consolidation of these entities had minimal impact on our consolidated
net income for the three and nine months ended September 30, 2004 versus the
same periods ended September 30, 2003. For additional details, see Note 11,
Implementation of New Accounting Standards.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

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CMS Energy Corporation

- capital and financial market conditions, including the current
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,

- adverse regulatory or legal decisions, including those related
to environmental laws and regulations,

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

- recovery of 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 energy
supply and oil 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, regulatory decisions concerning the
MCV Partnership RCP, and regulatory decisions that limit our
recovery of capacity and fixed energy payments,

- federal regulation of electric sales and transmission of
electricity including re-examination by federal regulators of
the market-based sales authorizations by 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,

- the GAAP requirement that we utilize mark-to-market accounting
on certain of our energy commodity contracts, and possibly
other types of contracts in the future, which may have a
negative effect on earnings 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

CMS-3

CMS Energy Corporation

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,

- 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 plan focuses on strengthening our balance sheet and improving
financial liquidity through debt reduction and aggressive cost management. The
sale of non-strategic and under-performing assets has generated cash to reduce
debt, reduced business risk, and provided for more predictable future earnings.

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CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS

For the three months ended September 30, 2004, our net income available to
common stock was $56 million, compared to a net loss available to common stock
of $69 million for the three months ended September 30, 2003. The $125 million
increase primarily reflects:

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

- a $24 million reduction in corporate interest expense,

- an $8 million increase in net income at our gas utility
primarily due to the 2004 annual unbilled gas revenue analysis
increase in gas revenues versus the 2003 analysis reduction in
gas revenues,

- a $7 million increase in net income at CMS ERM primarily due
to the absence of losses associated with wholesale gas and
power contracts sold in 2003,

- a $6 million reduction in funded benefits expense due to the
OPEB plans accounting for the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003 and the positive
impact of prior year pension plan contributions on pension
plan asset returns,

- the absence in 2004 of a $46 million net impairment charge
related to our international energy distribution business
recorded in 2003, and

- the absence in 2004 of a $19 million debt retirement charge
recorded in 2003.

These increases were offset partially by:

- a $10 million reduction in net income at our electric utility
primarily due to reduced tariff revenues equivalent to Big
Rock nuclear decommissioning surcharges, milder weather, and
decreased sales margins from deliveries to customers choosing
alternative electric suppliers,

- a $7 million reduction in earnings from our equity method
investments, and

- a $3 million declaration and payment of CMS Energy preferred
dividends.

For further information, see the individual results of operations for each CMS
Energy business segment within this MD&A.

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For the nine months ended September 30, 2004, our net income available to common
stock was $65 million, compared to a net loss available to common stock of $52
million for the nine months ended September 30, 2003. The $117 million increase
reflects:

- a $51 million reduction in corporate interest and other
expenses,

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

- a $20 million reduction in funded benefits expense primarily
due to the OPEB plans accounting for the Medicare Prescription
Drug, Improvement, and Modernization Act of 2003 and the
positive impact of prior year pension plan contributions on
pension plan asset returns,

- a $12 million increase in net income at CMS ERM primarily due
to the absence of losses associated with wholesale gas and
power contracts sold in 2003,

- a $6 million increase in net income at our gas utility
resulting from favorable impacts of the December 2003 rate
order outpacing reductions in gas deliveries resulting from
milder weather,

- the absence in 2004 of a $31 million deferred tax asset
valuation reserve established in 2003,

- the absence in 2004 of $24 million of charges related to
changes in accounting recorded in 2003,

- the absence in 2004 of $20 million of losses in Discontinued
Operations recorded in 2003, and

- the absence in 2004 of a $19 million debt retirement charge
recorded in 2003.

These increases were partially offset by:

- a $30 million increase in net asset impairment charges,

- a $21 million reduction in net income at our electric utility
primarily due to reduced tariff revenues equivalent to Big
Rock nuclear decommissioning surcharges, milder weather and
decreased sales margins from deliveries to customers choosing
alternative electric suppliers,

- an $11 million reduction in earnings from our equity method
investments,

- a $9 million declaration and payment of CMS Energy preferred
dividends, and

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

For further information, see the individual results of operations for each CMS
Energy business segment within this MD&A.

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ELECTRIC UTILITY RESULTS OF OPERATIONS

ELECTRIC DELIVERIES: Electric deliveries, including transactions with wholesale
marketers, other electric utilities, and customers choosing alternative
suppliers decreased 0.02 billion kWh or 0.2 percent, in the three months ended
September 30, 2004 versus the same period in 2003. For the nine months ended
September 30, 2004, electric deliveries increased 1.0 billion kWh or 3.5 percent
versus the same period in 2003. Electric delivery revenues benefited from the
recovery of deferred implementation costs. Recovery of these costs began July 1,
2004 and partially offset revenue reductions attributable to milder summer
temperatures, decreased revenues attributable to customers choosing alternative
electric suppliers, and tariff revenue reductions.

The tariff revenue reductions began January 1, 2004, and were equivalent to the
Big Rock nuclear decommissioning surcharge in effect when our electric retail
rates were frozen from September 2000 through December 31, 2003. The tariff
revenue reductions decreased electric delivery revenue by approximately $9
million in the three months ended September 30, 2004, and $27 million in the
nine months ended September 30, 2004 versus the same periods in 2003. The tariff
revenue reductions are expected to decrease electric delivery revenue by $35
million for the full year of 2004 versus the full year of 2003. On the positive
side, the tariff revenue reductions were reclassified for capped customers as
power supply revenue and helped reduce the underrecovery of power supply costs
for these customers.

POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost recovery
rate was a fixed amount per kWh, 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 underrecovery would have decreased
operating income. In 2004, our recovery of power supply costs is no longer
fixed, but is instead restricted to a pre-defined limit for certain customer
classes. The customer classes that have a pre-defined limit, or cap, on the
level of power supply costs they can be charged are primarily the residential
and small commercial customer classes. In 2004, to the extent our power
supply-related revenue exceeds actual power supply costs, this former benefit is
reserved for possible future refund. Prior to a refund, a reserve is decreased
for

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subsequent underrecoveries before possibly decreasing operating income. In the
three months ended September 30, 2004, we have been able to reverse revenues
previously reserved in the year and defer certain costs to reduce the impact of
underrecoveries on operating income. Consequently, in the three months ended
September 30, 2004, operating income increased versus the same period in 2003
due to a prior year underrecovery of power supply costs. Operating income
decreased for the nine months ended September 30, 2004 versus the same period in
2003 due to prior year power supply cost overrecoveries.

OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the three
months ended September 30, 2004, other operating expenses increased $8 million,
non-commodity revenue decreased $2 million, and other income increased $13
million versus the same period in 2003. The increase in other income relates
primarily to the accrual of interest income on capital expenditures in excess of
depreciation, as allowed by the Customer Choice Act. Higher operating expenses
reflect increased generating plant operating costs and amortization relating to
the recovery of deferred implementation costs, which began July 1, 2004.
Decreased non-commodity revenues primarily reflect a reduction in rent revenues.

In the nine months ended September 30, 2004, other operating expenses increased
$2 million, other income increased $33 million, and non-commodity revenue
decreased $2 million versus the same period in 2003. The increase in other
income relates primarily to the accrual of interest income on capital
expenditures in excess of depreciation, as allowed by the Customer Choice Act. A
decline in non-commodity revenues reflects reduced rent revenues in the nine
months ended September 30, 2004 versus the same period in 2003.

GENERAL TAXES: General taxes decreased in the three months ended September 30,
2004 versus the same period in 2003. This decrease reflects less MSBT expense
and reduced property tax expense.

General taxes increased in the nine months ended September 30, 2004 versus the
same period in 2003 primarily due to reductions in the MSBT expense in 2003. The
2003 reduction was primarily due to CMS Energy's receipt of approval to file
consolidated tax returns for the years 2000 and 2001. The taxable income for
these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003.

FIXED CHARGES: Fixed charges increased in the three and nine months ended
September 30, 2004 versus the same periods in 2003 due to higher average debt
levels, partially offset by a reduction in the average rate of interest. In the
three months ended September 30, 2004, the average rate of interest dropped 14
basis points and in the nine months ended September 30, 2004, the average rate
of interest dropped 45 basis points versus the same periods in 2003. This
decrease in the average rates incorporates the impact of an August 2004
refinancing of $800 million. This refinancing both extended the maturity of the
debt, and significantly decreased the long-term debt interest rates of the $800
million.

INCOME TAXES: In the three and nine months ended September 30, 2004, income
taxes decreased versus the same periods in 2003 primarily due to lower earnings
by the electric utility, and the OPEB Medicare Part D federal subsidy that is
exempt from federal taxation.

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CMS Energy Corporation

GAS UTILITY RESULTS OF OPERATIONS

Three Months Ended Nine Months Ended
September 30, September 30,
Reasons for the change: 2004 vs. 2003 2004 vs. 2003
- -----------------------------------------------------------------------------------------

Gas deliveries $10 $(11)
Gas rate increase 1 12
Gas wholesale and retail services and other gas
revenues - 3
Operation and maintenance (1) (3)
Depreciation 2 9
General taxes 2 (2)
Fixed charges (3) (9)
Income taxes (3) 7
- -----------------------------------------------------------------------------------------
Total change $ 8 $ 6
=========================================================================================

GAS DELIVERIES: For the three months ended September 30, 2004, the higher priced
non-transportation gas deliveries decreased 0.3 bcf or 1.7 percent versus the
same period in 2003. The lower priced transportation gas deliveries to end-use
customers decreased 0.6 bcf or 5.3 percent. Despite the decrease in gas
deliveries, gas delivery revenue increased in the three months ended September
30, 2004 versus the same period in 2003. This increase reflects the effect of
the annual unbilled gas volume analysis on accrued gas revenues versus the 2003
results. In 2004, this analysis supported an increase in unbilled gas volumes
that resulted in an increase of accrued gas revenues. In 2003, this annual
analysis led to a reduction in accrued gas revenues.

For the nine months ended September 30, 2004, gas deliveries, including
transportation to end-use customers, decreased 17.8 bcf or 7.5 percent versus
the same period in 2003 primarily due to milder weather.

GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. As a result of
this order, gas revenues increased for the three and nine months ended September
30, 2004 versus the same periods in 2003.

GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the nine months
ended September 30, 2004, wholesale and retail services and other gas revenues
increased primarily due to increased storage revenue versus the same period in
2003.

OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2004, increased expenditures on safety, reliability, and customer service were
offset partially by reduced benefit costs compared to the same periods in 2003.

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CMS Energy Corporation

DEPRECIATION: For the three and nine months ended September 30, 2004,
depreciation expense decreased versus the same periods in 2003. The decrease in
depreciation expense relates to a reduction in depreciation rates authorized by
the MPSC's December 2003 interim rate order.

GENERAL TAXES: General taxes decreased in the three months ended September 30,
2004 versus the same period in 2003. This decrease reflects less MSBT expense
and decreased property tax expense.

For the nine months ended September 30, 2004, general tax expense increased $2
million due to higher MSBT expense versus the same period in 2003. The increase
in MSBT expense is primarily due to CMS Energy's receipt of approval to file
consolidated tax returns for the years 2000 and 2001. The taxable income for
these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003.

FIXED CHARGES: Fixed charges increased in the three and nine months ended
September 30, 2004 versus the same periods in 2003 due to higher average debt
levels, partially offset by a reduction in the average rate of interest. In the
three months ended September 30, 2004, the average rate of interest dropped 14
basis points and in the nine months ended September 30, 2004, the average rate
of interest dropped 45 basis points versus the same periods in 2003. This
decrease in the average rates incorporates the impact of an August 2004
refinancing of $800 million. This refinancing both extended the maturity of the
debt, and significantly decreased the long-term debt interest rates of the $800
million.

INCOME TAXES: For the three months ended September 30, 2004, income taxes
increased primarily due to the increased earnings of the gas utility versus the
same period in 2003.

For the nine months ended September 30, 2004, income taxes decreased due to the
income tax treatment of items related to plant, property and equipment as
required by past MPSC rulings, the decreased earnings of the gas utility, and
the OPEB Medicare Part D federal subsidy that is exempt from federal taxation.

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CMS Energy Corporation

ENTERPRISES RESULTS OF OPERATIONS

FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: Due to
the implementation of FASB Interpretation No. 46, certain equity investments,
determined to be variable interest entities under this interpretation, which
were included in equity earnings during 2003 are included as fully consolidated
subsidiaries in the results of operations for 2004.

The net increase in earnings, due to the results of these entities, was $1
million for the three months ended September 30, 2004. This increase was
primarily from mark-to-market gains related to gas contracts, offset by
increased fuel and dispatch costs.

The net decrease in earnings, due to the results of these entities, was $10
million for the nine months ended September 30, 2004. This decrease was
primarily due to an increase in fuel and dispatch costs.

OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For the three months
ended September 30, 2004, operating revenues, net of related cost of gas and
purchased power, increased versus the same period in 2003 due to higher margins
from South American subsidiaries, partially offset by the termination of the
Michigan retail power and gas programs at CMS ERM.

For the nine months ended September 30, 2004, operating revenues, net of related
cost of gas and purchased power, increased versus the same period in 2003
primarily due to the sale of wholesale gas and power contracts at CMS ERM and
the termination of Michigan retail power and gas programs, also at CMS ERM.

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CMS Energy Corporation

EARNINGS FROM EQUITY METHOD INVESTEES: Equity earnings decreased for the three
months ended September 30, 2004 versus the same period in 2003 due to
mark-to-market losses related to interest rate swaps of $15 million.

Equity earnings decreased for the nine months ended September 30, 2004 versus
the same period in 2003 primarily due to the effects of the Argentine Government
natural gas export restrictions in 2004 on the results of GasAtacama, and less
favorable fixed charges.

OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2004, operation and maintenance expenses decreased versus the same period in
2003. Lower expenses in 2004 were primarily due to streamlining and business
reduction at CMS ERM and CMS Gas Transmission.

GENERAL TAXES, DEPRECIATION AND OTHER INCOME: For the three and nine months
ended September 30, 2004, the net of general tax expense, depreciation and other
income decreased operating income versus the same period in 2003 primarily as a
result of foreign exchange losses partially offset by lower depreciation and
general taxes due to streamlining and business reduction at CMS ERM.

GAIN ON SALE OF ASSETS: For the three months ended September 30, 2004, gains on
asset sales increased $44 million versus the same period in 2003. This is
primarily due to the $43 million gain on the sale of Goldfields in 2004.

For the nine months ended September 30, 2004, gains on asset sales increased $54
million versus the same period in 2003. This is primarily due to the 2004 gain
of $43 million on the sale of Goldfields, and the absence in 2004, of the net
loss on the sale of CMS ERM Wholesale Gas and Power contracts and a $4 million
loss on the sale of our interest in Guardian Pipeline, LLC recorded in 2003.

ASSET IMPAIRMENT: For the three months ended September 30, 2004, asset
impairment charges decreased versus the same period in 2003, due to the $61
million reduction in the fair value of our investment in CMS Electric and Gas'
Venezuelan distribution facility recorded in 2003.

For the nine months ended September 30, 2004, asset impairment charges increased
versus the same period in 2003, due to the $136 million reduction in the fair
value of Loy Yang recorded in 2004. This increase is partially offset by a $70
million reduction in the fair value of our investment in CMS Electric and Gas'
Venezuelan distribution facility and an impairment of two generators recorded in
2003.

FIXED CHARGES: For the three months ended September 30, 2004, fixed charges
increased versus the same period in 2003 due to the payment of preferred
dividends to the investor in our Michigan gas assets in 2004 and higher letter
of credit fees.

For the nine months ended September 30, 2004, fixed charges decreased versus the
same period in 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 CMS Enterprises during 2003, partially offset by the payment of
preferred dividends to the investor in our Michigan gas assets in 2004 and
higher letter of credit fees.

INCOME TAXES: For the three months ended September 30, 2004, income taxes
increased versus the same period in 2003 primarily due to higher earnings.

For the nine months ended September 30, 2004, income taxes decreased versus the
same period in 2003 due to the taxes related to the impairment charge for Loy
Yang.

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CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS

For the three months ended September 30, 2004, corporate interest expense and
other net expenses were $49 million, a decrease of $38 million versus the same
period in 2003. The decrease reflects the absence in 2004 of a $19 million
charge related to debt retired in 2003 and $22 million of lower interest and
other expenses. This decrease was partially offset by the declaration and
payment of $3 million of CMS Energy preferred dividends.

For the nine months ended September 30, 2004, corporate interest and other net
expenses were $147 million, a decrease of $51 million versus the same period in
2003. The decrease reflects the absence of a $24 million valuation allowance for
the possible loss of general business credits, a $19 million charge related to
debt retired in 2003, and $51 million of lower interest and other expenses. This
decrease was offset partially by the absence of $20 million of MSBT refunds
received in 2003, a $14 million reduction of interest expense allocated to
Discontinued Operations, and the declaration and payment of $9 million of CMS
Energy preferred dividends in 2004.

DISCONTINUED OPERATIONS: Net income from Discontinued Operations for the three
months ended September 30, 2004 was $8 million, an increase of $6 million versus
the same period in 2003. For the three months ended September 30, 2004, income
was primarily related to the gain on the sale of our Parmelia business, while
the income for the three months ended September 30, 2003 reflects post-sale
adjustments of previously recorded asset sale transactions.

Net income from Discontinued Operations for the nine months ended September 30,
2004 was $6 million, an increase of $26 million versus the same period in 2003.
In 2004, income from the sale of Parmelia was partially offset by losses from
other Discontinued Operations. In 2003, the loss included $14 million of
interest, after-tax, allocated from Corporate and a $12 million after-tax loss
related to the sale of Viron. The 2003 losses were partially offset by income
from other Discontinued Operations. For additional details, see Note 2,
Discontinued Operations, Other Asset Sales, Impairments, and Restructuring.

ACCOUNTING CHANGES: A $24 million loss for the cumulative effect of changes in
accounting principle was recognized in the first quarter of 2003; $23 million
was recognized in conjunction with the adoption of EITF Issue No. 02-03; $1
million was recognized in conjunction with the adoption of SFAS No. 143.

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 in accounting for long-lived assets,
contingencies, and equity method investments,

- accounting for the effects of industry regulation

- accounting for financial and derivative instruments,

- accounting for international operations and foreign currency,

- accounting for pension and postretirement benefits,

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CMS Energy Corporation

- 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 $15.377
billion at September 30, 2004, 61 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.

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We are still considering the sale of our remaining non-strategic and
under-performing assets, including some assets that were not determined to be
impaired. Upon the sale of these assets, the proceeds realized may be materially
different from the remaining carrying values. We cannot predict when, or make
any assurances that these asset sales will occur. Further, we cannot predict the
amount of cash or the value of consideration that may be received.

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 is probable and,
where determinable, an estimate of the liability amount. 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.

Under our PPA with the MCV Partnership, we pay a capacity charge based on the
availability of the MCV Facility whether or not electricity is actually
delivered to us; a variable energy charge for kWh delivered to us; and a fixed
energy charge based on availability up to 915 MW and based on delivery for the
remaining 325 MW of contract capacity. The cost that we incur under the MCV
Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we
estimate cash underrecoveries of capacity and fixed energy payments will
aggregate $206 million from 2004 through 2007. For capacity and fixed energy
payments billed by the MCV Partnership after September 15, 2007, and not
recovered from customers, we expect to claim relief under a regulatory out
provision under the MCV Partnership PPA. This provision obligates Consumers to
pay the MCV Partnership only those capacity and energy charges that the MPSC has
authorized for recovery from electric 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 for 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.

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.

As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV

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Facility's variable electricity production costs and its energy payment revenue
widens, the MCV Partnership's financial performance and our investment in the
MCV Partnership is and will be impacted negatively.

In February 2004, we filed the RCP with the MPSC that is intended to help
conserve natural gas and thereby improve our investment in the MCV Partnership,
without raising the costs paid by our electric customers. The plan's primary
objective is 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. This decrease in the quantity of high-priced natural gas
consumed by the MCV Facility will benefit Consumers' ownership interest in the
MCV Partnership. In August 2004, several qualifying facilities sought and
obtained a stay of the RCP proceeding from the Ingham County Circuit Court after
their previous attempt to intervene in the proceeding was denied by the MPSC. In
an attempt to resolve this intervention issue as quickly as possible, the MPSC
issued an order permitting the qualifying facilities to participate as
intervenors. As a result, the Ingham County Circuit Court stay was lifted and
hearings were completed in October 2004. The MPSC has decided to dispense with a
Proposal for Decision from the presiding ALJ and will issue a decision directly.
We cannot predict if or when the MPSC will approve the RCP.

The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Historically, natural gas prices have been
volatile. Presently, there is no consensus in the marketplace on the price or
range of future prices of natural gas. Even with an 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 of our
investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.

For additional details on the MCV Partnership, see Note 3, Uncertainties, "Other
Consumers' Electric Utility Uncertainties - 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, items that a non-regulated entity normally would expense, we may
record as regulatory assets if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, items that non-regulated
entities may normally recognize as revenues, we may record as regulatory
liabilities 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
September 30, 2004, we had $1.158 billion recorded as regulatory assets and
$1.512 billion recorded as regulatory liabilities.

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

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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 can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our debt
securities are classified as held-to-maturity securities and are reported at
cost. Our investments in equity securities are classified as available-for-sale
securities and are reported at fair value determined from quoted market prices.
Any unrealized gains or losses resulting from changes in fair value are reported
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless such changes in fair value are
determined to be other than temporary. Unrealized gains or losses resulting from
changes in the fair value of our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets.

DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended and
interpreted, to determine if certain contracts must be accounted for as
derivative instruments. The rules for determining whether a contract meets the
criteria for derivative accounting are numerous and complex. Moreover,
significant judgment is required to determine whether a contract requires
derivative accounting, and similar contracts can sometimes be accounted for
differently.

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 of the contract 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 the fair value of a derivative (that
is, gains or losses) are reported either in earnings or accumulated other
comprehensive income depending on whether the derivative qualifies for special
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 fuel futures and swaps, gas fuel options, gas fuel contracts containing
volume optionality, fixed priced weather-based gas supply call options, fixed
price gas supply call and put options, and gas and electric forward contracts
used for trading purposes. We generally do not account for electric capacity and
energy contracts, gas supply contracts, coal and nuclear fuel supply contracts,
or purchase orders for numerous supply items as derivatives.

The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives 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,
as defined by SFAS No. 133, 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, as
defined by SFAS No. 133, for the coal that we purchase. If active markets
develop in the future, we may be required to account for these contracts as
derivatives. The mark-to-market impact on earnings related to these contracts
could be material to our financial statements.

The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which
will include day-ahead and real-time energy market information for the MISO's
participants. We are presently evaluating what impacts, if any, this market
development will have on the determination of whether an active energy market
exists in the state of Michigan. For additional information, see Electric
Utility Business Uncertainties, "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 its
long-term natural gas contracts, which do not contain volume optionality,
qualify under SFAS No. 133 for the normal purchases and normal sales exception.
Therefore, these contracts are currently not recognized at fair value on the
balance sheet. Should significant changes in the level of the MCV Facility
operational dispatch or purchases of long-term gas occur, the MCV Partnership
would be required to re-evaluate its accounting treatment for these long-

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term gas contracts. This re-evaluation may result in recording mark-to-market
activity on some contracts, which could add to earnings volatility.

To determine the fair value of contracts that are accounted for as derivative
instruments, we use a combination of quoted market prices 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 September 30, 2004, we assumed a market-based
interest rate of 1 percent and monthly volatility rates ranging between 43
percent and 57 percent to calculate the fair value of our gas options. Also, at
September 30, 2004, we assumed a market-based interest rate of 1 percent and
daily volatility rates ranging between 56 percent and 108 percent to calculate
the fair value of our electric options. At September 30, 2004, we assumed
market-based interest rates ranging between 1.84 percent and 3.90 percent
(depending on the term of the contract) and monthly volatility rates ranging
between 34 percent and 63 percent to calculate the fair value of the gas fuel
derivative contracts held by the MCV Partnership.

TRADING ACTIVITIES: CMS ERM enters into and owns energy contracts that are
related to activities considered an integral part of CMS Energy's ongoing
operations. We use various financial instruments, including swaps, options,
futures, and forward contracts to manage commodity risks associated with
generation assets owned by CMS Energy or its subsidiaries and to fulfill our
contractual obligations. These contracts are classified as trading activities in
accordance with EITF Issue No. 02-03 and are accounted for using the criteria
defined in SFAS No. 133. Energy trading contracts that meet the definition of a
derivative 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. Energy trading contracts that do not meet the definition of a
derivative are accounted for as executory contracts (i.e., on an accrual basis).

The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. 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. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.

In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to 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 results of operations as a result of counterparty nonperformance.

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The following tables provide a summary of the fair value of our energy trading
contracts as of September 30, 2004:

In Millions
- --------------------------------------------------------------------------------------------------

Fair value of contracts outstanding as of December 31, 2003 $ 15
Fair value of new contracts when entered into during the period (a) (3)
Changes in fair value attributable to changes in valuation techniques and assumptions -
Contracts realized or otherwise settled during the period (17)
Other changes in fair value (b) 15
- -------------------------------------------------------------------------------------------------
Fair value of contracts outstanding as of September 30, 2004 $ 10
=================================================================================================

(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 contracts to manage
these risks, including swaps, options, futures, and forward contracts.

Contracts used to manage market risks may be considered derivative instruments
that are subject to derivative and hedge accounting pursuant to SFAS No. 133. 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 trading or 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 by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.

We perform sensitivity analyses to assess the potential loss in fair value, cash
flows, or future earnings based upon a hypothetical 10 percent adverse change in
market rates or prices. We do not believe that sensitivity analyses alone
provide an accurate or reliable method for monitoring and controlling risks.
Therefore, we use our experience and judgment to revise strategies and modify
assessments. Changes in excess of the amounts determined in sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity
Price Risk," "Trading Activity Commodity Price Risk," "Currency Exchange Risk,"
and "Investment Securities Price Risk" within this section.

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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 would only be realized if we repurchased all of our
fixed-rate financing.

Certain equity method investees have issued 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, fixed-priced weather-based gas supply call options, and
fixed-priced 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 September 30, 2004, we held
fixed-priced weather-based gas supply call options and fixed-price 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 contain volume
optionality and, therefore, are treated as derivative instruments. Also, 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 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. At September 30, 2004, the MCV Partnership held gas
fuel contracts with volume optionality, as well as gas fuel futures and swaps.

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

In Millions
- ---------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- ---------------------------------------------------------------------------------------------------

Potential reduction in fair value:
Gas supply option contracts $ 3 $1
Derivative contracts associated with Consumers' investment
in the MCV Partnership:
Gas fuel contracts 22 N/A
Gas fuel futures and swaps 48 N/A
===================================================================================================

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CMS Energy Corporation

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 March 31, 2004, as discussed in
Note 11, Implementation of New Accounting Standards.

Trading Activity Commodity Price Risk: We are exposed to market fluctuations in
the price of energy commodities. We employ established policies and procedures
to manage these risks and may use various commodity derivatives, including
futures, options, swaps, and forward contracts. The prices of these energy
commodities can fluctuate because of, among other things, changes in the supply
of and demand for the commodities.

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

In Millions
- ---------------------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- ---------------------------------------------------------------------------------------------------------------

Potential reduction in fair value:
Nuclear decommissioning investments $ 54 $ 57
Other available-for-sale investments 6 7
===============================================================================================================

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

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 in our Consolidated Balance Sheets as "Foreign Currency
Translation." As of September 30, 2004, cumulative foreign currency translation
decreased stockholders' equity by $325 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 an 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.

Argentina: At September 30, 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 3.02
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 not
subject us to 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

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certain employees hired after June 30, 2003. We use SFAS No. 87 to account for
pension costs.

401(k): In our efforts to reduce costs, the employer's match for the 401(k) plan
was suspended effective September 1, 2002. It is scheduled to resume 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 change significantly 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:

In Millions

Expected Costs Pension Cost OPEB Cost Contributions
- ---------------------------------------------------------------------------------

2004 $21 $30 $ 63
2005 52 38 80
2006 73 34 114
=================================================================================

Actual future pension cost and contributions will depend on future investment
performance, changes in future discount rates, and various other factors related
to the populations participating in the Pension Plan. As of September 30, 2004,
we have a prepaid pension asset of $392 million, $20 million of which is in
Prepayments and other current assets on our Consolidated Balance Sheets.

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 2004 by $2 million. Lowering the discount rate by 0.25 percent
(from 6.25 percent to 6.00 percent) would increase estimated pension cost for
2004 by $4 million.

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 $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months

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CMS Energy Corporation

ended September 30, 2004, $18 million for the nine months ended September 30,
2004, and an expected total reduction of $24 million for 2004.

For additional details on postretirement benefits, see Note 7, Retirement
Benefits and Note 11, Implementation of New Accounting Standards.

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 for regulated entities
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,
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, which largely
utilize third-party cost estimates. For additional details on ARO, see Note 10,
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.

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CMS Energy Corporation

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. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. 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 fully fund 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 will also
seek additional relief from the MPSC. For additional details on nuclear
decommissioning, see Note 3, Uncertainties, "Other Consumers' Electric Utility
Uncertainties - 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
advance payment 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, evaluating market conditions for financing opportunities,
and selling assets that are not consistent with our strategy. We believe our
current level of cash and borrowing capacity, along with anticipated cash flows
from operating and investing activities, will be sufficient to meet our
liquidity needs through 2005. We have not made a specific determination
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.

In October 2004, we issued 32.8 million shares of our common stock. We realized
$288 million in net proceeds from this offering. We will use the net proceeds to
make capital infusions into Consumers. Pending such capital infusions, the
proceeds will be used for general corporate purposes, including temporary
investments in short-term securities.

CASH POSITION, INVESTING, AND FINANCING

Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2004, $643 million consolidated cash was on hand, which
includes $83 million of restricted cash. For additional details on cash
equivalents and restricted cash, see Note 1, Corporate Structure and Accounting
Policies.

Our primary ongoing source of cash is dividends and other distributions from our
subsidiaries, including

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CMS Energy Corporation

proceeds from asset sales. For the first nine months of 2004, Consumers paid
$187 million in common stock dividends and Enterprises paid $157 million in
common stock dividends and other distributions to CMS Energy.

SUMMARY OF CASH FLOWS:

OPERATING ACTIVITIES:

For the nine months ended September 30, 2004, net cash provided by operating
activities increased $194 million versus the same period in 2003. The absence,
in 2004, of $210 million in pension contributions made in 2003, an increase in
accounts payable of $198 million, and a $124 million increase in accrued
expenses represent the majority of the increase. The accounts payable increase
is largely due to the purchase of natural gas at higher prices, fewer suppliers
requiring advanced payments for gas purchases, and the sale of CMS ERM wholesale
gas and power books in 2003. Increases in accrued expenses are primarily due to
a smaller decrease in accrued taxes in 2004 versus 2003. Collectively, these
increases more than offset the $311 million increase in accounts receivable and
accrued revenue primarily due to lower sales of accounts receivable resulting
from our improved liquidity.

INVESTING ACTIVITIES:

For the nine months ended September 30, 2004, net cash from investing activities
decreased $464 million versus the same period in 2003. This change was primarily
due to a decrease in asset sale proceeds of $633 million and an increase in
investments in unconsolidated subsidiaries of $70 million due to an infusion to
Shuweihat. This was partially offset by a decrease in the amount of cash
restricted of $285 million. In 2004, $118 million in restricted cash was no
longer required to be held as collateral for letters of credit. For additional
details on restricted cash, see Note 1, Corporate Structure and Accounting
Policies, "Cash Equivalents and Restricted Cash."

FINANCING ACTIVITIES:

For the nine months ended September 30, 2004, net cash from financing activities
decreased $192 million versus the same period in 2003 primarily due to a
decrease of $143 million in net proceeds from borrowings. For additional details
on long-term debt activity, see Note 4, Financings and Capitalization.

OBLIGATIONS AND COMMITMENTS

REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers issues short- and long-term
securities under the FERC's authorization. For additional details of Consumers'
existing authorization, see Note 4, Financings and Capitalization.

LONG-TERM DEBT: The components of long-term debt are presented in Note 4,
Financings and Capitalization.

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We will extinguish our $180 million, 7 percent extendible tenor rate adjusted
securities that were scheduled to mature in January 2005. Upon extinguishment,
we will record a charge of approximately $15 million, after-tax, for costs
associated with extinguishing this debt.

SHORT-TERM FINANCINGS: At September 30, 2004, CMS Energy had $208 million
available, Consumers had $475 million available, and the MCV Partnership had $50
million available in short-term credit facilities. The facilities are available
for general corporate purposes, working capital, and letters of credit.
Additional details on short-term financings are presented in Note 4, Financings
and Capitalization.

OFF-BALANCE SHEET ARRANGEMENTS:

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 $1.344 billion at September 30, 2004. The timing of the payments of
non-recourse debt only affects the cash flow and liquidity of the partnerships
and joint ventures.

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 4, Financings and Capitalization.

CONTINGENT COMMITMENTS: Our contingent 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 and approve these obligations and believe it
is unlikely that we would be required to perform or otherwise incur any material
losses associated with these guarantees. Our off-balance sheet commitments at
September 30, 2004, expire as follows:

Net overrecovery amounts included in the table above include refunds received by
us from our suppliers and required by the MPSC to be refunded to our customers.

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.
Recent increases in gas prices could cause us to incur costs in excess of what
can be recovered pursuant to the current ceiling price. We are permitted to
apply to the MPSC to modify the ceiling price, and will do so if necessary. In
addition, if actual, prudently incurred costs exceed the ceiling price, the
difference can be recovered through the reconciliation proceeding. Our GCR
factor for the billing month of November 2004 is $6.55 per mcf.

2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for
a gas rate increase in the annual amount of $156 million. On December 18, 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
receipt of a letter signed by the Chairman of Consumers and CMS Energy, which
agrees 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, Consumers' and CMS Energy's Chairman filed a letter with
the MPSC making the commitments required by the rate order.

CMS-37

CMS Energy Corporation

On October 19, 2004, we filed rehearing petitions with the MPSC, which seek
clarification of the method of computing our rate of return on common equity.

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.

On October 14, 2004, the MPSC issued its Opinion and Order in our gas
depreciation case. The order restores depreciation rates to the levels that were
in effect prior to the issuance of the December 18, 2003 interim gas rate order.
The final order further 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.

On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to
have book depreciation rates restored to the level set forth in the MPSC's prior
interim gas rate relief order.

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, Uncertainties, "Consumers' Gas Utility
Contingencies - Gas Environmental Matters."

OTHER CONSUMERS' OUTLOOK

CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that
applies to utilities and alternative electric suppliers. The code of conduct
seeks to prevent financial support, information sharing, and preferential
treatment between a utility's regulated and non-regulated services. The new code
of conduct is broadly written and could affect our:

- retail gas business energy related services,

- retail electric business energy related services,

- marketing of non-regulated services and equipment to Michigan
customers, and

- transfer pricing between our departments and affiliates.

We appealed the MPSC orders related to the code of conduct and sought a deferral
of the orders until the appeal was complete. We also sought waivers available
under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business.

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

CMS-38

CMS Energy Corporation

Partnership estimates that the decision will result in a refund to the MCV
Partnership of approximately $35 million in taxes plus $9 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 year-to-date 2004 earnings.

ENTERPRISES OUTLOOK

INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our IPP
business by narrowing the focus of our operations to primarily North 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.

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.

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., which is not included in our consolidated financial
statements. 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. The financial performance is dependent primarily
on the number of new wells connected and transportation volumes, with certain
EBITDA thresholds required to be achieved in order for us to receive payments on
the note. There may not be enough new wells connected in 2004 to achieve the
annual threshold and thus trigger a payment on the note for 2004.

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-39

CMS Energy Corporation

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

OTHER OUTLOOK

TAX BILL: In October 2004, Congress passed tax legislation, the "American Jobs
Creation Act of 2004," which the President signed into law. The bill contains
several provisions that could impact us, including a tax credit for the
production of electricity from biomass and a one-time reduction in the effective
tax rate (from 35 percent to 5.25 percent) on dividends repatriated in 2005 from
foreign subsidiaries. We are currently studying the tax bill's provisions for
its impact to us, which we believe will be positive in 2004 and following years.

SARBANES-OXLEY ACT OF 2002: We are in the process of implementing the internal
control requirements mandated by the Sarbanes-Oxley Act. Our evaluation and
testing of internal controls is continuing, but is incomplete as of the date of
this Form 10-Q. We are currently unaware of any material weaknesses in our
control over financial reporting. We plan to complete testing and finalize our
evaluation in the fourth quarter. Until this is completed, we cannot provide
assurance that our internal controls do not contain material weaknesses.

Our 2004 Form 10-K will contain a report by our management on the effectiveness
of our internal controls and a report by Ernst & Young, our Registered
Independent Auditors, that attests to and reports on our management's assessment
of internal control. These annual reports on internal control are now required
by Section 404 of the Sarbanes-Oxley Act for all public companies, effective
with our 2004 Form 10-K.

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 including a shareholder derivative
lawsuit, a securities class action lawsuit, a class action lawsuit alleging
ERISA violations, several lawsuits regarding alleged false natural gas price
reporting and price manipulation, and a lawsuit surrounding the possible sale of
CMS Pipeline Assets. For additional details regarding these investigations and
litigation, see Note 3, Uncertainties.

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 have 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

CMS-40

make us the primary beneficiary of these entities. As such, we consolidated
their assets, liabilities, and activities into our financial statements for the
first time as of and for the quarter ended March 31, 2004. These partnerships
have third-party obligations totaling $581 million at September 30, 2004.
Property, plant, and equipment serving as collateral for these obligations has a
carrying value of $1.440 billion at September 30, 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 for the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $116 million at September 30, 2004. Property,
plant, and equipment serving as collateral for these obligations has a carrying
value of $168 million as of September 30, 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 also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt-related parties
and reflected 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 September 30, 2004:

(a) At September 30, 2004, the balance includes our proportionate share of the
negative fair value of derivative instruments of $26 million.

CMS-41

CMS Energy Corporation

Our maximum exposure to loss through our interests in these variable interest
entities is limited to our investment balance of $128 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$59 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 from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.

The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.

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 $6 million for the three months ended September 30,
2004, $18 million for the nine months ended September 30, 2004, and an expected
total 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 $4 million, or $0.03 per share,
for the three months ended September 30, 2004, $13 million, or $0.08 per share,
for the nine months ended September 30, 2004, and an expected total net expense
reduction of $17 million for 2004.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

EITF ISSUE NO. 03-1, THE MEANING OF OTHER THAN TEMPORARY INVESTMENTS: The issue
addresses the definition of an other than temporary impairment of certain
investments and was scheduled to be effective as of September 30, 2004. 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.

The FASB issued a final FASB Staff Position, FSP EITF Issue 03-1-1 deferring
portions of EITF Issue No. 03-1 relating to guidance on such matters as to what
constitutes a minor impairment and the determination of "other than temporary."
The deferral extends until the Board issues a final FSP 03-1-a defining the
effective date and amending EITF Issue No. 03-1 as it is currently written. The
FASB expects to issue the FASB Staff Position in November. The deferral does not
apply to the disclosure requirements of EITF Issue No. 03-1, which are required
in our annual financial statements. We do not expect this issue to have an
impact on our results of operations when it becomes effective.

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

CMS-42

CMS Energy Corporation

market price trigger has been met.

We currently have a contingently convertible debt instrument and a contingently
convertible preferred stock instrument outstanding. Both securities include
similar contingent conversion provisions based on the market price of our common
stock. Including the dilutive effect of these instruments could reduce our
diluted earnings per share for 2004 by up to $0.10 per average common share. For
further information on these securities, refer to Note 4, Financings and
Capitalization, "Contingently Convertible Securities."

The effective date for this EITF Issue is for reporting periods ending after
December 15, 2004, and the guidance applies to contingently convertible
instruments outstanding at December 31, 2004. We plan to modify our contingently
convertible securities prior to the effective date, through exchange offers that
are intended to mitigate the earnings per share impact.

EITF ISSUE NO. 04-10, APPLYING PARAGRAPH 19 OF SFAS NO. 131, DISCLOSURES ABOUT
SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, IN DETERMINING WHETHER TO
AGGREGATE OPERATING SEGMENTS THAT DO NOT MEET THE QUANTITATIVE THRESHOLDS: This
issue addresses how to apply the operating segment aggregation criteria in SFAS
No. 131. At their September 2004 meeting, the EITF reached consensus on this
issue. The EITF concluded that operating segments that do not meet the
quantitative thresholds established in SFAS No. 131 could be aggregated only if
aggregation is consistent with the objective and basic principles of Statement
131 and the segments have similar economic characteristics. The consensus will
be effective as of December 31, 2004. We are currently assessing this issue and
have not determined whether it will impact our segment reporting disclosures.

CMS-43

CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(UNAUDITED)

THREE MONTHS ENDED NINE MONTHS ENDED
RESTATED RESTATED
SEPTEMBER 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------------
In Millions, Except Per Share Amounts

OPERATING REVENUE $ 1,063 $ 1,047 $ 3,910 $ 4,141
EARNINGS FROM EQUITY METHOD INVESTEES 18 28 78 125

OPERATING EXPENSES
Fuel for electric generation 215 104 571 310
Purchased and interchange power 100 118 257 459
Purchased power - related parties - 135 - 395
Cost of gas sold 142 166 1,166 1,301
Other operating expenses 225 215 667 630
Maintenance 63 50 185 169
Depreciation, depletion and amortization 114 90 366 308
General taxes 64 58 200 134
Asset impairment charges - 61 125 70
-------------------------------------------------
923 997 3,537 3,776
- -------------------------------------------------------------------------------------------------------------------------
OPERATING INCOME 158 78 451 490

OTHER INCOME (DEDUCTIONS)
Accretion expense (6) (7) (18) (23)
Gain (loss) on asset sales, net 46 - 49 (8)
Interest and dividends 8 10 22 21
Foreign currency gains (losses), net (1) - (7) 11
Other income 15 5 42 11
Other expense (1) (7) (5) (10)
-------------------------------------------------
61 1 83 2
- -------------------------------------------------------------------------------------------------------------------------
FIXED CHARGES
Interest on long-term debt 124 135 380 360
Interest on long-term debt - related parties 15 - 44 -
Other interest 6 31 18 49
Capitalized interest (2) (2) (5) (7)
Preferred dividends of subsidiaries 2 - 4 1
Preferred securities distributions - 16 - 52
-------------------------------------------------
145 180 441 455
- -------------------------------------------------------------------------------------------------------------------------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS 74 (101) 93 37

INCOME TAX EXPENSE (BENEFIT) 18 (25) 8 48
MINORITY INTERESTS 5 (5) 17 (3)
-------------------------------------------------
INCOME (LOSS) FROM CONTINUING OPERATIONS 51 (71) 68 (8)

GAIN (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $4 AND $3 TAX
EXPENSE IN 2004 AND $5 TAX BENEFIT AND $16 TAX EXPENSE IN 2003 8 2 6 (20)
-------------------------------------------------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING 59 (69) 74 (28)

CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13
TAX BENEFIT IN 2003:
DERIVATIVES (NOTE 6) - - - (23)
ASSET RETIREMENT OBLIGATIONS, SFAS NO. 143 (NOTE 10) - - - (1)
-------------------------------------------------
- - - (24)
-------------------------------------------------
NET INCOME (LOSS) 59 (69) 74 (52)
PREFERRED DIVIDENDS 3 - 9 -
-------------------------------------------------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCK $ 56 $ (69) $ 65 $ (52)
=================================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CMS-44

THREE MONTHS ENDED NINE MONTHS ENDED
RESTATED RESTATED
SEPTEMBER 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
In Millions, Except Per Share Amounts

CMS ENERGY
NET INCOME (LOSS)
Net Income (Loss) Available to Common Stock $ 56 $ (69) $ 65 $ (52)
======================================
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $0.30 $(0.47) $0.36 $(0.06)
Income (Loss) from Discontinued Operations 0.05 0.01 0.04 (0.14)
Loss from Changes in Accounting - - - (0.16)
--------------------------------------
Net Income (Loss) Attributable to Common Stock $0.35 $(0.46) $0.40 $(0.36)
======================================
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $0.29 $(0.47) $0.36 $(0.06)
Income (Loss) from Discontinued Operations 0.05 0.01 0.04 (0.14)
Loss from Changes in Accounting - - - (0.16)
--------------------------------------
Net Income (Loss) Attributable to Common Stock $0.34 $(0.46) $0.40 $(0.36)
======================================
DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ - $ -
- -------------------------------------------------------------------------------------------------------------------

THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CMS-45

CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

NINE MONTHS ENDED
RESTATED
SEPTEMBER 30 2004 2003
- -------------------------------------------------------------------------------------------------
In Millions

CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 74 $ (52)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear 366 308
decommissioning of $4 and $4, respectively)
Loss (gain) on disposal of discontinued operations (Note 2) (7) 46
Asset impairments (Note 2) 125 70
Capital lease and debt discount amortization 18 16
Accretion expense 18 23
Bad debt expense 11 17
Undistributed earnings from related parties (57) (45)
Loss (gain) on the sale of assets (Note 2) (49) 8
Cumulative effect of accounting changes - 24
Pension contribution - (210)
Changes in other assets and liabilities:
Decrease in accounts receivable and accrued revenues 16 327
Increase in inventories (273) (354)
Increase (decrease) in accounts payable 18 (180)
Decrease in accrued expenses (82) (206)
Deferred income taxes and investment tax credit 61 56
Decrease (increase) in other current and non-current assets (60) 461
Increase (decrease) in other current and non-current liabilities 15 (309)
------------------
Net cash provided by operating activities $ 194 $ -
- -------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $(377) $ (356)
Investments in partnerships and unconsolidated subsidiaries (70) -
Cost to retire property (53) (52)
Restricted cash (Note 1) 118 (167)
Investment in Electric Restructuring Implementation Plan (5) (5)
Investments in nuclear decommissioning trust funds (4) (4)
Proceeds from nuclear decommissioning trust funds 35 26
Maturity of MCV restricted investment securities held-to-maturity 592 -
Purchase of MCV restricted investment securities held-to-maturity (592) -
Proceeds from sale of assets 215 848
Other investing 9 42
------------------
Net cash provided by (used in) investing activities $(132) $ 332
- -------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds, and other long-term debt $ 839 $ 2,302
Issuance of common stock - 229
Retirement of bonds and other long-term debt (997) (1,830)
Retirement of trust preferred securities - (220)
Payment of preferred stock dividends (9) -
Decrease in notes payable - (487)
Payment of capital lease obligations (41) (10)
------------------
Net cash used in financing activities $(208) $ (16)
- -------------------------------------------------------------------------------------------------
EFFECT OF EXCHANGE RATES ON CASH - 2
- -------------------------------------------------------------------------------------------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $(146) $ 318
CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB
INTERPRETATION NO. 46 CONSOLIDATION 174 -
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 532 351
-----------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 560 $ 669
=================================================================================================

CMS-46

NINE MONTHS ENDED
RESTATED
SEPTEMBER 30 2004 2003
- ------------------------------------------------------------------------------------------------------
In Millions

OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $ 429 $ 405
Income taxes paid (net of refunds) - (33)
OPEB cash contribution 48 58
NON-CASH TRANSACTIONS
Other assets placed under capital leases $ 2 $ 11
======================================================================================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CMS-47

CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS

ASSETS
SEPTEMBER 30
SEPTEMBER 30 2003
2004 DECEMBER 31 RESTATED
(UNAUDITED) 2003 (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
In Millions

PLANT AND PROPERTY (AT COST)
Electric utility $ 7,860 $ 7,600 $ 7,583
Gas utility 2,929 2,875 2,841
Enterprises 3,400 895 680
Other 28 32 31
------------------------------------------
14,217 11,402 11,135
Less accumulated depreciation, depletion and amortization 6,035 4,846 4,882
------------------------------------------
8,182 6,556 6,253
Construction work-in-progress 418 388 371
------------------------------------------
8,600 6,944 6,624
- ---------------------------------------------------------------------------------------------------------------
INVESTMENTS
Enterprises 731 724 769
Midland Cogeneration Venture Limited Partnership - 419 404
First Midland Limited Partnership - 224 222
Other 24 23 2
------------------------------------------
755 1,390 1,397
- ---------------------------------------------------------------------------------------------------------------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 560 532 669
Restricted cash 83 201 205
Accounts receivable, notes receivable, and accrued revenue,
less allowances of $37, $40 and $33, respectively 392 378 264
Accounts receivable and notes receivable - related parties 57 73 164
Inventories at average cost:
Gas in underground storage 996 741 815
Materials and supplies 112 110 102
Generating plant fuel stock 78 41 44
Assets held for sale - 24 22
Price risk management assets 113 102 80
Regulatory assets 19 19 19
Derivative instruments 143 2 2
Prepayments and other 251 246 268
------------------------------------------
2,804 2,469 2,654
- ---------------------------------------------------------------------------------------------------------------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 616 648 659
Postretirement benefits 145 162 168
Abandoned Midland Project 10 10 10
Other 368 266 257
Assets held for sale - 2 52
Price risk management assets 229 177 179
Nuclear decommissioning trust funds 551 575 553
Prepaid pension costs 372 388 -
Goodwill 28 25 40
Notes receivable - related parties 219 242 129
Notes receivable 172 150 146
Other 508 390 366
------------------------------------------
3,218 3,035 2,559
------------------------------------------
TOTAL ASSETS $ 15,377 $ 13,838 $ 13,234
===============================================================================================================

CMS-48

STOCKHOLDERS' INVESTMENT AND LIABILITIES

ASSETS
SEPTEMBER 30
SEPTEMBER 30 2003
2004 DECEMBER 31 RESTATED
(UNAUDITED) 2003 (UNAUDITED)
- ---------------------------------------------------------------------------------------------------------------
In Millions

CAPITALIZATION
Common stockholders' equity
Common stock, authorized 350.0 shares; outstanding
161.9 shares, 161.1 shares and 161.1 shares, respectively $ 2 $ 2 $ 2
Other paid-in-capital 3,850 3,846 3,834
Accumulated other comprehensive loss (309) (419) (693)
Retained deficit (1,779) (1,844) (1,852)
-------------------------------------------
1,764 1,585 1,291
Preferred stock of subsidiary 44 44 44
Preferred stock 261 261 -
Company-obligated convertible Trust Preferred Securities
of subsidiaries - - 173
Company-obligated mandatorily redeemable Trust Preferred
Securities of Consumers' subsidiaries - - 490

Long-term debt 6,228 6,020 6,295
Long-term debt - related parties 684 684 -
Non-current portion of capital and finance lease obligations 318 58 116
-------------------------------------------
9,299 8,652 8,409
- ---------------------------------------------------------------------------------------------------------------
MINORITY INTERESTS 750 73 35
- ---------------------------------------------------------------------------------------------------------------

CURRENT LIABILITIES
Current portion of long-term debt, capital and finance leases 594 519 186
Notes payable - - 4
Accounts payable 338 317 361
Accounts payable - related parties 1 40 50
Accrued interest 128 130 112
Accrued taxes 192 285 151
Liabilities held for sale - 2 -
Price risk management liabilities 106 89 70
Current portion of purchase power contracts 6 27 26
Current portion of gas supply contract obligations 31 29 28
Deferred income taxes 30 27 16
Other 281 185 193
-------------------------------------------
1,707 1,650 1,197
- ---------------------------------------------------------------------------------------------------------------
NON-CURRENT LIABILITIES
Regulatory Liabilities
Cost of removal 1,026 983 962
Income taxes, net 326 312 309
Other 160 172 152
Postretirement benefits 247 265 590
Deferred income taxes 658 615 441
Deferred investment tax credit 81 85 86
Asset retirement obligation 438 359 363
Liabilities held for sale - - -
Price risk management liabilities 226 175 175
Gas supply contract obligations 186 208 218
Power purchase agreement - MCV Partnership - - 8
Other 273 289 289
-------------------------------------------
3,621 3,463 3,593
- ---------------------------------------------------------------------------------------------------------------
COMMITMENTS AND CONTINGENCIES (Notes 1, 3 and 4)

TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $ 15,377 $ 13,838 $ 13,234
===============================================================================================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CMS-49

CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)

THREE MONTHS ENDED NINE MONTHS ENDED
RESTATED RESTATED
SEPTEMBER 30 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------------------------
In Millions

COMMON STOCK
At beginning of period $ 2 $ 1 $ 2 $ 1
Common stock issued - 1 - 1
------------------------------------------
At end of period 2 2 2 2
- ---------------------------------------------------------------------------------------------------------------------------------
OTHER PAID-IN CAPITAL
At beginning of period 3,848 3,608 3,846 3,605
Common stock reacquired (4) (4) (5) (5)
Common stock reissued - 1 - 1
Common stock issued 6 229 9 233
------------------------------------------
At end of period 3,850 3,834 3,850 3,834
- ---------------------------------------------------------------------------------------------------------------------------------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period - (261) - (241)
Minimum pension liability adjustments (a) (1) (1) (1) (21)
------------------------------------------
At end of period (1) (262) (1) (262)
------------------------------------------
Investments
At beginning of period 8 5 8 2
Unrealized gain (loss) on investments (a) (1) 1 (1) 4
------------------------------------------
At end of period 7 6 7 6
------------------------------------------
Derivative Instruments
At beginning of period 6 (22) (8) (31)
Unrealized gain on derivative instruments (a) 5 9 24 2
Reclassification adjustments included in consolidated net income (loss) (a) (1) (5) (6) 11
------------------------------------------
At end of period 10 (18) 10 (18)
------------------------------------------
Foreign Currency Translation
At beginning of period (327) (412) (419) (458)
Change in foreign currency translation (a) 2 (7) 94 39
------------------------------------------
At end of period (325) (419) (325) (419)
------------------------------------------
At end of period (309) (693) (309) (693)
- ---------------------------------------------------------------------------------------------------------------------------------
RETAINED DEFICIT
At beginning of period (1,835) (1,783) (1,844) (1,800)
Net income (loss) (a) 59 (69) 74 (52)
Preferred stock dividends declared (3) - (9) -
Common stock dividends declared - - - -
------------------------------------------
At end of period (1,779) (1,852) (1,779) (1,852)
------------------------------------------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 1,764 $ 1,291 $ 1,764 $ 1,291
=================================================================================================================================
(A) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum Pension Liability
Minimum pension liability adjustments, net of tax benefit of
$(1), $(1), $(1) and $(11), respectively $ (1) $ (1) $ (1) $ (21)
Investments
Unrealized gain (loss) on investments, net of tax (tax benefit)
of $-, $1, $- and $2, respectively (1) 1 (1) 4
Derivative Instruments
Unrealized gain on derivative instruments, net of tax (tax benefit)
of $7, $-, $14 and $2, respectively 5 9 24 2
Reclassification adjustments included in consolidated net
income (loss), net of tax (tax benefit) of $-, $(4), $(3)
and $7, respectively (1) (5) (6) 11
Foreign currency translation, net 2 (7) 94 39
Net income (loss) 59 (69) 74 (52)
------------------------------------------
Total Other Comprehensive Income (Loss) $ 63 $ (72) $ 184 $ (17)
==========================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CMS-50

CMS Energy Corporation

CMS ENERGY CORPORATION
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

These interim Consolidated Financial Statements have been prepared by CMS Energy
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. Certain prior year amounts have been reclassified to
conform to the presentation in the current year. In management's opinion, the
unaudited information contained in this report reflects all adjustments of a
normal recurring nature necessary to assure the fair presentation of financial
position, results of operations and cash flows for the periods presented. The
Condensed Notes to Consolidated Financial Statements and the related
Consolidated Financial Statements should be read in conjunction with the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
contained in CMS Energy's Form 10-K/A for the year ended December 31, 2003. Due
to the seasonal nature of CMS Energy's operations, the results as presented for
this interim period are not necessarily indicative of results to be achieved for
the fiscal year.

RESTATEMENT OF 2003 FINANCIAL STATEMENTS

Our financial statements as of and for the three and nine months ended September
30, 2003, as presented in this Form 10-Q, have been restated for the following
matters that were disclosed previously in Note 19, Quarterly Financial and
Common Stock Information (Unaudited), in our 2003 Form 10-K/A:

- International Energy Distribution, which includes SENECA and
CPEE, is no longer considered "discontinued operations," due
to a change in our expectations as to the timing of the sales,

- certain derivative accounting corrections at our equity
affiliates, and

- the net loss recorded in the second quarter of 2003 relating
to the sale of Panhandle, reflected as Discontinued
Operations, was understated by approximately $14 million, net
of tax.

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,

CMS-51

CMS Energy Corporation

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 11, 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 financial statements in conformity with
accounting principles generally accepted in the United States. 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 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,
Uncertainties.

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.

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. At
September 30, 2004, our restricted cash on hand was $83 million. Restricted cash
primarily includes cash dedicated for repayment of bonds. It is classified as a
current asset as the payments on the related bonds occur within one year.

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 and Dividends.

FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our debt
securities are classified as held-to-maturity securities and are reported at
cost. Our investments in equity securities are classified as available-for-sale
securities and are reported at fair value determined from quoted market prices.
Any unrealized gains or losses resulting from changes in fair value are reported
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless such changes in fair value are
determined to

CMS-52

CMS Energy Corporation

be other than temporary. Unrealized gains or losses resulting from changes in
the fair value of our nuclear decommissioning investments are reflected as
regulatory liabilities on our Consolidated Balance Sheets. 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, and gains and losses on
intercompany foreign currency transactions that are long-term in nature that we
do not intend to settle in the foreseeable future, 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.

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

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 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 September 30, 2004, we have recorded a liability to the DOE for $140 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, Uncertainties, "Other Consumers' Electric
Utility Uncertainties - Nuclear Matters."

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

In Millions
- ----------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
-----------------------------------------
September 30 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------

Other income
Interest and dividends - related parties $ 2 $ 1 $ 4 $ 3
PA141 Return on capital expenditures 10 - 28 -
Electric restructuring return 2 1 5 4
Investment sale gain 1 - 2 -
All other - 3 3 4
- ----------------------------------------------------------------------------------------------------------------
Total other income $ 15 $ 5 $ 42 $ 11
================================================================================================================

CMS-53

CMS Energy Corporation

In Millions
- --------------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
-------------------------------------------
September 30 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------------

Other expense
Loss on SERP investment $ (1) $ (1) $ (2) $ (2)
CMS MST remediation costs - (4) - (4)
Civic and political expenditures (1) - (2) (1)
All other 1 (2) (1) (3)
- --------------------------------------------------------------------------------------------------------------------
Total other expense $ (1) $ (7) $ (5) $(10)
====================================================================================================================

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 10, 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.

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

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.

SFAS No. 144 imposes strict criteria for retention of regulatory-created assets
by requiring that such assets be probable of future recovery at each balance
sheet date. Management believes these assets are probable of future recovery.

2: DISCONTINUED OPERATIONS, OTHER ASSET SALES, IMPAIRMENTS, AND RESTRUCTURING

Our continued focus on financial improvement has led to discontinuing
operations, completing many asset sales, impairing some assets, and incurring
costs to restructure our business. Gross cash proceeds received from the sale of
assets totaled $215 million for the nine months ended September 30, 2004 and
$848 million for the nine months ended September 30, 2003.

CMS-54

CMS Energy Corporation

At September 30, 2004, we no longer have "Assets held for sale." At December 31,
2003, "Assets held for sale" included Parmelia, Bluewater Pipeline, and our
investment in the American Gas Index Fund. At September 30, 2003, "Assets held
for sale" included Marysville, Parmelia, and CMS Land. The major classes of
assets and liabilities held for sale on our Consolidated Balance Sheets are as
follows:

In Millions
- ----------------------------------------------------------------------------------------------------------------
September 30 December 31 September 30
2004 2003 2003
- ----------------------------------------------------------------------------------------------------------------

Assets
Cash $ - $ 7 $ 5
Accounts receivable - 2 1
Property, plant and equipment - net - 2 44
Other - 15 24
- ----------------------------------------------------------------------------------------------------------------
Total assets held for sale $ - $ 26 $ 74
================================================================================================================
Liabilities
Accounts payable $ - $ 2 $ -
- ----------------------------------------------------------------------------------------------------------------
Total liabilities held for sale $ - $ 2 $ -
================================================================================================================

DISCONTINUED OPERATIONS

We have discontinued the following operations:

In Millions
- ----------------------------------------------------------------------------------------------------------------
Pretax After-tax
Business/Project Discontinued Gain(Loss) Gain(Loss) Status
- ----------------------------------------------------------------------------------------------------------------

CMS Field Services December 2002 $ (5) $ (1) Sold July 2003
Marysville June 2003 2 1 Sold November 2003
Parmelia (a) December 2003 10 6 Sold August 2004
================================================================================================================

(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 proceeds are
subject to normal post closing adjustments. 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-55

CMS Energy Corporation

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

In Millions
- -------------------------------------------------------------------------------
Three months ended September 30 2004 2003
- -------------------------------------------------------------------------------

Revenues $ 1 $ 5
===============================================================================
Discontinued operations:
Pretax loss from discontinued operations $ - $ (1)
Income tax expense - -
-----------------------
Loss from discontinued operations - (1)
Pretax gain (loss) from disposal of discontinued
operations 12 (2)
Income tax expense (benefit) 4 (5)
-----------------------
Gain from disposal of discontinued operations 8 3
- -------------------------------------------------------------------------------
Gain from discontinued operations $ 8 $ 2
================================================================================

In Millions
- -------------------------------------------------------------------------------
Nine months ended September 30 2004 2003
- -------------------------------------------------------------------------------

Revenues $ 11 $501
===============================================================================
Discontinued operations:
Pretax gain (loss) from discontinued operations $ (1) $ 45
Income tax expense - 19
-----------------------
Gain (loss) from discontinued operations (1) 26
Pretax gain (loss) from disposal of discontinued
operations 10 (49)
Income tax expense (benefit) 3 (3)
-----------------------
Gain (loss) from disposal of discontinued
operations 7 (46)
- --------------------------------------------------------------------------------
Gain (loss) from discontinued operations $ 6 $(20)
================================================================================

The 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 the nine months ended
September 30, 2004 and $22 million for the nine months ended September 30, 2003
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 non-strategic and under-performing
assets. The impacts of these sales are included in "Gain (loss) on asset sales,
net" in the Consolidated Statements of Income (Loss).

For the nine months ended September 30, 2004, we sold the following assets that
did not meet the definition of, and therefore were not reported as, discontinued
operations:

CMS-56

CMS Energy Corporation

(a) Bluewater Pipeline is a 24.9-mile pipeline that extends from Marysville,
Michigan to Armada, Michigan.

(b) 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.

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

(d) 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 proceeds are subject to normal post
closing adjustments. The $45 million ($29 million after-tax) gain on the
sale of Goldfields includes a $9 million ($6 million after-tax) foreign
currency translation gain.

For the nine months ended September 30, 2003, 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.

CMS-57

In addition, we have written off the carrying value of projects under
development that will no longer be pursued.

The table below summarizes our asset impairments:

In Millions
- -------------------------------------------------------------------------------------------------------------
Nine months ended September 30 Pretax 2004 After-tax 2004 Pretax 2003 After-tax 2003
- -------------------------------------------------------------------------------------------------------------

Asset impairments:
Enterprises:
Loy Yang (a) $ 125 $ 81 $ - $ -
International Energy Distribution (b) - - 63 47
Other (c) - - 7 4
- -------------------------------------------------------------------------------------------------------------
Total asset impairments $ 125 $ 81 $ 70 $ 51
=============================================================================================================

(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) Primarily represents an impairment recorded to reflect the fair value of two
generators.

RESTRUCTURING AND OTHER COSTS

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

The following tables show the amount charged to expense for restructuring costs,
the payments made, and the unpaid balance of accrued costs for the nine months
ended September 30, 2004 and September 30, 2003:

In Millions
- -------------------------------------------------------------------------------------------------------------
Involuntary Lease
Termination Termination Total
- -------------------------------------------------------------------------------------------------------------

Beginning accrual balance, January 1, 2003 $ 12 $ 8 $ 20
Expense 4 - 4
Payments (11) (1) (12)
----------------------------------------
Ending accrual balance at September 30, 2003 $ 5 $ 7 $ 12
=============================================================================================================

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CMS Energy Corporation

3: UNCERTAINTIES

Several 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 net sales, revenues, or income from continuing
operations. Such trends and uncertainties are discussed in detail below.

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 has 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. 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. A hearing on those motions
occurred on August 2, 2004 and the judge has taken the matter under advisement.
CMS Energy, Consumers, and the individual defendants will defend themselves
vigorously but cannot predict the outcome of this litigation.

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

CMS-59

CMS Energy Corporation

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. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to December 1, 2004,
subject to such further extensions as may be mutually agreed upon by the parties
and authorized by the Court. 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, 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. 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, this investigation will have on
its business.

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. 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, Inc. but
is required to indemnify Cantera Natural Gas, Inc. with respect to this action.)

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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 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 conspiracy by engaging
in activities to manipulate the price of natural gas in California. The
complaint contains counts alleging violations of the Sherman Act, Cartwright Act
(a California statute), and the California Business and Profession Code relating
to unlawful, unfair, and deceptive business practices. There is currently
pending in the Nevada federal district court a multi district court litigation
(MDL) matter involving 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 Sherman Act
claim and some of the defendants in the MDL matter are also defendants in the
Texas-Ohio case. Those defendants successfully argued to have the Texas-Ohio
case transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case
agreed to extend the time for all defendants to answer or otherwise respond
until May 28, 2004 and on that date a number of defendants filed motions to
dismiss. In order to negotiate possible dismissal and/or substitution of
defendants, CMS Energy and two other parent holding company defendants were
given further extensions to answer or otherwise respond to the complaint until
November 16, 2004.

Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint
containing allegations similar to those made in the Texas-Ohio case, albeit
limited to California state law claims, was filed in California state court in
February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed
a notice to remove this action to California federal district court, which was
granted, and had it transferred to the MDL proceeding in Nevada. However, the
plaintiff is seeking to have the case remanded back to California and until the
issue is resolved, no further action will be taken. Another putative class
action lawsuit, Fairhaven Power Company v. Encana Power Corporation, containing
allegations similar to those made in the Texas-Ohio case, was filed in
California federal court in September 2004. CMS Energy, Enterprises, and CMS MST
are named as defendants.

Three new, virtually identical actions were filed in San Diego Superior Court in
July 2004, one by the County of Santa Clara, one by the County of San Diego and
one by the City of and County of San Francisco and the San Francisco City
Attorney (collectively the Municipal Lawsuits). Defendants, consisting of a
number of energy companies including CMS Energy, CMS MST, Cantera Natural Gas,
and Cantera Gas Company, are alleged to have engaged in false reporting of
natural gas price and volume information and sham sales to artificially inflate
natural gas retail prices in California. All three complaints allege claims for
unjust enrichment and violations of the Cartwright Act, and the San Francisco
action also alleges a claim for violation of the California Business and
Profession Code relating to unlawful, unfair, and deceptive business practices.
The Municipal Lawsuits were removed to federal district court, and conditional
transfer orders were issued transferring the cases to the Nevada MDL proceeding.
Plaintiffs in each of the Municipal Lawsuits intend to seek to have the cases
remanded back to San Diego Superior Court, and they have agreed to extend the
time to answer or otherwise respond to the complaints to thirty days from the
date an order on the motion to remand is issued. Two new lawsuits were filed in
California, one a putative class action in San Diego Superior Court on behalf of
retail consumers of natural gas, and one in Alameda Superior Court on behalf of
a cooperative of public agencies engaged in the retail purchase of natural gas.
The actions are virtually identical to the Municipal Lawsuits, and the
defendants include CMS Energy, CMS MST, Cantera Natural Gas, and Cantera Gas
Company. More of such "copycat" actions may follow.

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

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CONSUMERS' UNCERTAINTIES

Several 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 and gas
operations. Such trends and uncertainties include:

Environmental

- increased capital expenditures and operating expenses for Clean
Air Act compliance, and

- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability
or expense relating to the Michigan Natural Resources and
Environmental Protection Acts, Superfund, and at former
manufactured gas plant facilities.

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,

- ability to recover any of our net Stranded Costs under the
regulatory policies set by the MPSC,

- 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

- recovery of nuclear decommissioning costs,

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

- regulatory decisions concerning the RCP,

- 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 integrity rules and mandates.

Other

- pending litigation regarding PURPA qualifying facilities,

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

- other pending litigation.

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 September 30, 2004, we
have incurred $500 million in capital expenditures to comply with the EPA
regulations and anticipate that the remaining $302 million of capital
expenditures will be made between 2004 and 2011. These expenditures include
installing catalytic reduction technology at some of our coal-fired electric
plants. Based on the Customer Choice Act, beginning January 2004, an annual
return of and on these types of capital expenditures, to the extent

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they are above depreciation levels, is expected to be recoverable from
customers, subject to the MPSC prudency hearing.

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 purchase
nitrogen oxide emissions allowances for years 2004 through 2009. The cost of the
allowances is estimated to average $7 million per year for 2004-2006; the cost
will decrease after year 2006 with the installation of plant control technology.
The cost of the allowances is accounted for as inventory. The allowance
inventory is expensed as the coal-fired electric plants generate electricity.
The price for nitrogen oxide emissions allowances is volatile and could change
substantially.

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 would potentially 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 and nickel from
coal-fired and 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 fuel has resulted in reduced plant emissions,
lower operating costs, and flexibility in meeting future regulatory compliance
requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide
allowances optimizes our overall cost of regulatory compliance by delaying
capital expenditures and minimizing regulatory uncertainty. Western coal has
reduced our overall cost of fuel and reduced the impact on us from the recent
increases in eastern coal prices.

Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.

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 United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. 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 changed the 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 by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.

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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 September 30, 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. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants.

We believe we have been performing the calculation in the manner prescribed by
the power purchase agreements, and have filed a request with the MPSC (as a
supplement to the 2004 PSCR plan case) that asks the MPSC to review this issue
and to confirm that our method of performing the calculation is correct. We
filed a motion to dismiss the lawsuit in the Ingham County Circuit Court due to
the pending request at the MPSC concerning the PSCR plan case. In February 2004,
the judge ruled on the motion and deferred to the primary jurisdiction of the
MPSC. This ruling resulted in a dismissal of the circuit court case without
prejudice. In October 2004, the ALJ in the PSCR plan case issued a Proposal for
Decision concluding that we have been correctly administering the energy charge
calculation methodology that is specified in the power purchase agreements.
Although only eight qualifying facilities have raised the issue, the same energy
charge methodology is used in the PPA with the MCV Partnership and in
approximately 20 additional power purchase agreements with us, representing a
total of 1,670 MW of electric capacity. 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 matter.

CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS

ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, the Michigan legislature
passed electric utility restructuring legislation known as the Customer Choice
Act. This Act:

- allows all customers to choose their electric generation supplier
effective January 1, 2002,

- provides for a one-time five percent residential electric rate
reduction,

- froze all electric rates through December 31, 2003, and
established a rate cap for residential customers through at least
December 31, 2005, and a rate cap for small commercial and
industrial customers through at least December 31, 2004,

- allows deferred recovery of annual capital expenditures in excess
of depreciation levels and certain other expenses incurred prior
to and during the rate freeze-cap period, including the cost of
money,

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- allows for the use of Securitization bonds to refinance qualified
costs,

- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the Act,

- requires Michigan utilities to join a FERC-approved RTO or sell
their interest in transmission facilities to an independent
transmission owner,

- requires Consumers, Detroit Edison, and AEP to expand jointly
their available transmission capability by at least 2,000 MW, and

- establishes a market power supply test that, if not met, may
require transferring control of generation resources in excess of
that required to serve retail sales requirements.

The following summarizes our status under the last three provisions of the
Customer Choice Act. First, we chose to sell our interest in our transmission
facilities to an independent transmission owner to comply with the Customer
Choice Act. For additional details regarding the sale of the transmission
facility, see "Transmission Sale" within this Note. Second, in July 2002, the
MPSC issued an order approving our plan to achieve the increased transmission
capacity required under the Customer Choice Act. We have completed the
transmission capacity projects identified in the plan and have submitted
verification of this fact to the MPSC. We believe we are in full compliance.
Lastly, in September 2003, the MPSC issued an order finding that we are in
compliance with the market power supply test set forth in the Customer Choice
Act.

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 October 2004, alternative electric
suppliers are providing 877 MW of load. This amount represents 11 percent of the
total distribution load and an increase of 45 percent compared to October 2003.

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

- Securitization,

- Stranded Costs,

- implementation costs,

- security costs,

- Section 10d(4) Regulatory Assets, and

- transmission rates.

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The following chart summarizes our filings with the MPSC. For additional details
related to these proceedings, see the related sections within this Note.

Year(s) Years Requested
Proceeding Filed Covered Amount Status
- -----------------------------------------------------------------------------------------------------------------------------

Securitization 2003 N/A $1.083 billion MPSC denied our request to issue additional
Securitization bonds.

Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced zero Stranded Costs
for 2000 through 2001, which we are appealing.
Filings for 2002 and 2003 in the amount of $116
million are pending MPSC
approval.

Implementation 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the years
Costs 1997-2001, plus $20 million for the cost of
money through 2003. Implementation cost
filings for 2002 and 2003 in the amount of
$8 million, which includes the cost of money
through 2003, are still pending MPSC approval.

Security Costs 2004 2001-2005 $25 million MPSC approved the $25 million requested for
recovery. As of September 30, 2004, we have
recorded $21 million of costs incurred as a
regulatory asset.

Section 10d(4) 2004 2001-2005 $628 million Filed with the MPSC in October 2004.
Regulatory
Assets
=============================================================================================================================

(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. If Clean Air Act costs are not
recovered through the Section 10d(4) Regulatory Asset case, Stranded Costs
requested would total $304 million.

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

Securitization: The Customer Choice Act allows for the use of Securitization
bonds to refinance certain qualified costs. Since Securitization involves
issuing bonds secured by a revenue stream from rates collected directly from
customers to service the bonds, Securitization bonds typically have a higher
credit rating than conventional utility corporate financing. In 2000 and 2001,
the MPSC issued orders authorizing us to issue Securitization bonds. We issued
our first Securitization bonds in late 2001. Securitization resulted in:

- lower interest costs, and

- longer amortization periods for the securitized assets.

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We will recover the repayment of principal, interest, and other expenses
relating to the bond issuance through a Securitization charge and a tax charge
that began in December 2001. These charges are subject to an annual true up
until one year before the last scheduled bond maturity date, and no more than
quarterly thereafter. The December 2004 true up filed with the MPSC in October
2004, is expected to modify the total Securitization and related tax charges
from 1.718 mills per kWh to 1.735 mills per kWh. There will be no impact on
customer bills from Securitization for most of our electric customers until the
Customer Choice Act rate cap period expires, and an electric rate case is
processed. Securitization charge collections, $38 million for the nine months
ended September 30, 2004, and $37 million for the nine months ended September
30, 2003, are remitted to a trustee. Securitization charge collections are
restricted to the repayment of the principal and interest on the Securitization
bonds and payment of the ongoing expenses of Consumers Funding. Consumers
Funding is legally separate from Consumers. The assets and income of Consumers
Funding, including the securitized property, are not available to creditors of
Consumers or CMS Energy.

In March 2003, we filed an application with the MPSC seeking approval to issue
additional Securitization bonds. In June 2003, the MPSC issued a financing order
authorizing the issuance of Securitization bonds in the amount of $554 million.
We filed for rehearing and clarification on a number of features in the
financing order. In October 2004, the MPSC issued an order that reversed the
June 2003 financing order and denied our request to issue additional
Securitization bonds. Clean Air Act costs, originally included in our Stranded
Cost filings, were also part of this Securitization request that was denied. The
MPSC order, however, also gave us the option to file for recovery of these costs
through a Section 10d(4) Regulatory Asset case, which we filed in October 2004.

Stranded Costs: The Customer Choice Act allows electric utilities to recover
their net Stranded Costs, without defining the term. In December 2001, the MPSC
Staff recommended a methodology, which calculated net Stranded Costs as the
shortfall between:

- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and

- the revenues received from customers under existing rates
available to cover the revenue requirement.

The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost recovery
charge. However, the MPSC has not yet approved such a charge. The MPSC has
declined to resolve numerous issues regarding the net Stranded Cost recovery
methodology in a way that would allow a reliable prediction of the level of
Stranded Costs. As a result, we have not recorded regulatory assets to recognize
the future recovery of such costs.

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The following table outlines our applications filed with the MPSC and the status
of recovery for these costs:

In Millions
- -----------------------------------------------------------------------------------------------------------------
Requested, without recovery of Requested, with recovery of
Clean Air Act costs through the Clean Air Act costs through the MPSC
approval of Section 10d(4) approval of Section 10d(4) ordered
Year Year Regulatory Assets, including Regulatory Assets, recoverable
Filed Incurred cost of money including cost of money amount
- -----------------------------------------------------------------------------------------------------------------

2002 2000 $ 26 $12 $ -
2002 2001 46 9 -
2003 2002 104 47 Pending
2004 2003 128 69 Pending
=================================================================================================================

We are currently in the process of appealing the MPSC orders regarding Stranded
Costs for 2000 and 2001 with the Michigan Court of Appeals and the Michigan
Supreme Court. In June 2004, the MPSC conducted hearings for our 2002 Stranded
Cost application. In July 2004, the ALJ issued a Proposal for Decision in our
2002 net Stranded Cost case, which recommended that the MPSC find that we
incurred net Stranded Costs of $12 million. This recommendation includes the
cost of money through July 2004 and excludes Clean Air Act costs.

Hearings for our 2003 Stranded Cost application were conducted in August 2004.
The MPSC Staff issued a position on our 2003 net Stranded Cost application,
which resulted in a Stranded Cost calculation of $52 million. This amount
includes the cost of money, but excludes Clean Air Act costs. We cannot predict
how the MPSC will rule on our requests for recoverability of 2002 and 2003
Stranded Costs or whether the MPSC will adopt a Stranded Cost recovery method
that will offset fully any associated margin loss from ROA.

Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines our
applications filed with the MPSC and the status of recovery for these costs:

In Millions
- -----------------------------------------------------------------------------------------------------------------
Recoverable, including
(b) cost of money through
Year Filed Year Incurred Requested Disallowed Allowed 2003
- -----------------------------------------------------------------------------------------------------------------

1999 1997 & 1998 $ 20 $ 5 $ 15 $22
2000 1999 30 5 25 33
2001 2000 25 5 20 24
2002 2001 8 - 8 9
2003 & 2004 (a) 2002 7 Pending Pending Pending
2004 2003 1 Pending Pending Pending
=================================================================================================================

(a) On March 31, 2004, we requested additional 2002 implementation cost recovery
of $5 million related to our former participation in the development of the
Alliance RTO. This cost has been expensed; therefore, the amount is not included
as a regulatory asset.

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(b) Amounts include the cost of money through the year prior to the year filed.

In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million for implementation costs related to our former participation in the
development of the Alliance RTO. Included in this amount is $5 million pending
approval by the MPSC as part of 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. We cannot
predict the outcome of the appeal process or the amount, if any, we will collect
for Alliance RTO development costs.

The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. As of
September 30, 2004, we incurred and deferred as a regulatory asset $92 million
of implementation costs, which includes $25 million associated with the cost of
money. We believe the implementation costs and associated cost of money are
fully recoverable in accordance with the Customer Choice Act.

In June 2004, following an appeal and remand of initial MPSC orders relating to
1999 implementation costs, the MPSC authorized the recovery of all previously
approved implementation costs for the years 1997 through 2001 totaling $88
million. This total includes the cost of money through 2003. Additional carrying
costs will be added until collection occurs. The implementation costs will be
recovered through surcharges over 36-month collection periods and phased in as
applicable rate caps expire. In September 2004, the ALJ issued a Proposal for
Decision recommending full recovery of the requested 2002 and 2003
implementation costs. We cannot predict the amount, if any, the MPSC will
approve as recoverable costs for these years.

Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs as a result of federal and state regulatory security
requirements incurred before January 1, 2006. In August 2004, the MPSC approved
a settlement agreement that authorizes full recovery of $25 million in requested
security costs over a five-year period beginning in September 2004. The amount
includes reasonable and prudent security enhancements through December 31, 2005.
All retail customers, except customers of alternative electric suppliers, will
pay these charges. As a result, in August 2004, we recorded total approved
security costs incurred to date, including the cost of money. As of September
30, 2004, we have recorded $21 million in security costs as a regulatory asset.
The following table outlines our application filed with the MPSC and the status
of recovery for these costs:

In Millions
- ----------------------------------------------------------------------------------------
Regulatory asset as of
Year Filed Years Covered Requested September 30, 2004 Allowed
- ----------------------------------------------------------------------------------------

2004 2001-2005 $ 25 $21 $25
========================================================================================

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-cap periods, including
the cost of money. The section also allows deferred recovery of expenses
incurred during the rate freeze-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 in costs from 2000
through 2005 under section 10d(4). The request includes capital expenditures in
excess of depreciation, Clean Air Act costs, and other expenses related to
changes in law or governmental action incurred during the rate freeze-cap
period. Of the $628 million, $152 million

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relates to the cost of money. Also included in this application is $74 million
of costs that were also incorporated in our Stranded Costs filings. We cannot
predict the amount, if any, the MPSC will approve as recoverable. The following
table outlines our application filed with the MPSC and the status of recovery
for these costs:

In Millions
- -----------------------------------------------------------------------------------
Year Filed Years Covered Requested Allowed
- -----------------------------------------------------------------------------------

2004 2000-2005 $628 Pending
===================================================================================

Transmission Rates: Our application of JOATT transmission rates to customers
during past periods is under FERC review. The rates included in these tariffs
were applied to certain transmission transactions affecting both Detroit
Edison's and our transmission systems between 1997 and 2002. We believe our
reserve is sufficient to satisfy our refund obligation to any of our former
transmission customers under our former JOATT.

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 currently 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.

Under an agreement with MTH, our transmission rates are fixed by contract at
current levels through December 31, 2005, and are subject to FERC ratemaking
thereafter. However, we are subject to certain additional MISO surcharges, which
we estimate to be $10 million in 2004.

CONSUMERS' ELECTRIC UTILITY RATE MATTERS

PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of September 2004, we are in
compliance with the acceptable level of performance. We are a member of an
industry coalition that has appealed the customer credit portion of the
performance standards to the Michigan Court of Appeals. We cannot predict the
likely effects of the financial penalties, if any, nor can we predict the
outcome of the appeal. Likewise, we cannot predict our ability to meet the
standards in the future or the cost of future compliance.

POWER SUPPLY COSTS: We were required to provide backup service to ROA customers
on a best efforts basis. In October 2003, we provided notice to the MPSC that we
would terminate the provision of backup service in accordance with the Customer
Choice Act, effective January 1, 2004.

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. As we did in
2004, 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, approximately 101
percent is expected to be met from owned electric generating plants and
long-term power purchase contracts, and approximately 10 percent from short-term
contracts, options for physical deliveries, and other agreements. As of
September 30, 2004, we have purchased

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capacity and energy contracts partially covering the estimated reserve margin
requirements for 2004 through 2007. As a result, we have recognized an asset of
$13 million for unexpired capacity and energy contracts. As of October 2004, the
total premium costs of electric capacity and energy contracts for 2004 is
expected to be approximately $12 million.

PSCR: As a result of meeting the transmission capability expansion requirements
and the market power test, as discussed within this Note, we have met the
requirements under the Customer Choice Act to return to the PSCR process. The
PSCR process provides for the reconciliation of actual power supply costs with
power supply revenues. This process assures recovery of all reasonable and
prudent power supply costs actually incurred by us. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. In October 2004,
the ALJ issued a Proposal for Decision, which recommended approval of our 2004
PSCR factor, with minor adjustments. The PSCR factor recommended for approval
includes nitrogen oxide emissions allowance costs and requested transmission
costs, less a minor adjustment. We estimate the recovery of increased power
supply costs from large commercial and industrial customers to be approximately
$32 million in 2004.

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 all other customers. Unless we receive an order from the MPSC, we
expect to self-implement this 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.

OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES

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,
through two wholly owned subsidiaries, the following assets related to the MCV
Partnership and the MCV Facility:

- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and

- CMS Holdings holds, through the FMLP, 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 11, Implementation of New Accounting Standards.

Our consolidated retained earnings include undistributed earnings from the MCV
Partnership of $244 million at September 30, 2004 and $238 million at September
30, 2003.

Power Supply Purchases from the MCV Partnership: Our annual obligation to
purchase capacity from the MCV Partnership is 1,240 MW through the term of the
PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's
availability, a levelized average capacity charge of 3.77 cents per kWh,

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and a fixed energy charge. We also pay a variable energy charge based on our
average cost of coal consumed for all kWh delivered. Effective January 1999, we
reached a settlement agreement with the MCV Partnership that capped capacity
payments made on the basis of availability that may be billed by the MCV
Partnership at a maximum 98.5 percent availability level.

Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.

In 1992, we recognized a loss and established a liability for the present value
of the estimated future underrecoveries of power supply costs under the PPA
based on the MPSC cost recovery orders. We estimate that 51 percent of the
actual cash underrecoveries for 2004 will be charged to the PPA liability, with
the remaining portion charged to operating expense as a result of our 49 percent
ownership in the MCV Partnership. The remaining liability associated with the
loss totaled $6 million at September 30, 2004. We will expense all cash
underrecoveries directly to income once the PPA liability is depleted. We expect
the PPA liability to be depleted in late 2004.

If the MCV Facility's generating availability remains at the maximum 98.5
percent level, our cash underrecoveries associated with the PPA could be as
follows:

In Millions
- -------------------------------------------------------------------------------
2004 2005 2006 2007
- -------------------------------------------------------------------------------

Estimated cash underrecoveries at 98.5% $56 $56 $55 $39
Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
===============================================================================

Beginning January 1, 2004, the rate freeze for large industrial customers was no
longer in effect and we returned to the PSCR process. Under the PSCR process, we
will recover from our customers the approved capacity and fixed energy charges
based on availability, up to an availability cap of 88.7 percent as established
in previous MPSC orders.

Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility:
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be impacted negatively.

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

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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.

Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges based on the MCV Facility's actual
availability up to the 98.5 percent cap. After September 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 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. 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.

Resource Conservation Plan: In February 2004, we filed the RCP with the MPSC
that is intended to help conserve natural gas and thereby improve our investment
in the MCV Partnership. This plan seeks approval to:

- dispatch the MCV Facility based on natural gas market prices
without increased costs to electric customers,

- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and

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

The RCP 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. This decrease in the quantity of high-priced natural gas consumed
by the MCV Facility will benefit Consumers' ownership interest in the MCV
Partnership. The amount of PPA capacity and fixed energy payments recovered from
retail electric customers would remain capped at 88.7 percent. Therefore,
customers will not be charged for any increased power supply costs, if they
occur. Consumers and the MCV Partnership have reached an agreement that the MCV
Partnership will reimburse Consumers for any incremental power costs incurred to
replace the reduction in power dispatched from the MCV Facility. In August 2004,
several qualifying facilities sought and obtained a stay of the RCP proceeding
from the Ingham County Circuit Court after their previous attempt to intervene
in the proceeding was denied by the MPSC. In an attempt to resolve this
intervention issue as quickly as possible, the MPSC issued an order permitting
the qualifying facilities to participate as intervenors. As a result, the Ingham
County Circuit Court stay was lifted and hearings were completed in October
2004. The MPSC has decided to dispense with a Proposal for Decision from the
presiding ALJ and will issue a decision directly. We cannot predict if or when
the MPSC will approve the RCP.

The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Historically, natural gas prices have been
volatile. Presently, there is no consensus in the marketplace on the price or
range of future prices of natural gas. Even with an 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 of our
investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.

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

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approximately $35 million in taxes plus $9 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
year-to-date 2004 earnings.

NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates
for Big Rock and Palisades assume that each plant site will eventually be
restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
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 each plant 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.
The Palisades cost estimate assumes the plant will be safely stored and
subsequently decommissioned.

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.

However, based on current projections, the current level of funds provided by
the trusts is not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation, as discussed
below in "Nuclear Matters" within this Note. We will also seek additional relief
from the MPSC.

In the case of 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 will fall short of the
amount needed to complete the decommissioning by $26 million. At this point in
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.

In the case of Palisades, excluding additional nuclear fuel storage costs due to
the DOE's failure to accept this spent fuel on schedule, we have concluded that
the existing surcharge needs 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. We cannot predict what effect the application and
announcement may have on the MPSC request.

NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor
vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. The restoration project is on
schedule to

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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.

The NRC and the MDEQ continue to find all decommissioning activities at Big Rock
are being performed in accordance with applicable regulations including license
requirements.

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
September 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.

Our Palisades plant is currently undergoing a regularly scheduled refueling
outage. In conjunction with this scheduled outage, we have completed inspection
of all 54 nuclear reactor vessel head penetrations. Small cracks were identified
in the welds on two of the 45 control rod drive penetration nozzles. No external
primary coolant system leakage or damage to the reactor head material was noted.
Sections of the two penetrations have been removed and replaced. Post-weld
testing, restoration of the support attachments, and reactor head installation
on the vessel are in progress and are expected to be complete by mid-November.
The total outage extension caused by the weld cracks will be approximately four
weeks. The plant is expected to return to service by the end of November.

We expect to have sufficient power at all times to meet our load requirements
from our other plants or purchase arrangements. These replacement power
requirements could increase the cost of power by an estimated $1.6 million
(pretax) per week during an extended refueling outage. Of this estimated amount,
approximately $0.6 million per week is not recoverable from our customers. The
preliminary estimate of the cost of repair to the reactor vessel is $5 million.

Our ability to make off-system sales may also be affected by an extension of the
refueling outage. However, until all repairs are made, there can be no assurance
of the length and effect of the outage on our operations and consolidated
earnings.

The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage
pool capacity. We are using dry casks for temporary onsite storage. As of
September 30, 2004, we have loaded 22 dry casks with spent nuclear fuel.

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 in the first quarter of 2005.

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.

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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. The motions are expected to be
heard in late 2004 or early 2005. 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, by December 2004, an application to the NRC for a license
to begin construction of the repository. The application and review process is
estimated to take several years.

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.

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 where 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.

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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.

COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
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 our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.

Coal Supply and Transportation: We have entered into coal supply contracts with
various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements, we are
obligated to take physical delivery of the coal and make payment based upon the
contract terms. Our coal supply contracts expire through 2006, and total an
estimated $154 million. Our coal transportation contracts expire through 2007,
and total an estimated $92 million. Long-term coal supply contracts have
accounted for approximately 60 to 90 percent of our annual coal requirements
over the last 10 years. Although future contract coverage is not finalized at
this time, we believe that it will be within the historic 60 to 90 percent
range.

Power Supply, Capacity, and Transmission: As of September 30, 2004, we had
future unrecognized commitments to purchase power transmission services under
fixed price forward contracts for 2004 and 2005 totaling $6 million. We 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 2004 through 2030 total an estimated $3.004 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant were not available to deliver electricity to us, then we would not be
obligated to make the capacity payment until the plant could deliver.

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 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. The estimates are based on discounted
2003 costs using a discount rate of three percent. The discount rate represents
a ten-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 through the MPSC approved rates charged to our customers. As of
September 30, 2004, we have recorded a regulatory liability of $40 million, net
of $41 million of

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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 MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our prudently incurred gas costs. 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
GCR Year Date Filed Order Date Recovery Status
- ------------------------------------------------------------------------------------------------------------------

2001-2002 June 2002 May 2004 $3 million $2 million has been refunded;
$1 million is included in our 2003-2004
GCR reconciliation filing

2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest accrued
through March 2003, and an $11 million
disallowance settlement agreement

2003-2004 June 2004 Pending $28 million Filing includes the $1 million and
$5 million GCR net overrecovery above
==================================================================================================================

Net overrecovery amounts included in the table above include refunds received by
us from our suppliers and required by the MPSC to be refunded to our customers.

GCR year 2001-2002: In June 2002, we filed a reconciliation of GCR costs and
revenues for the 12-months ended March 2002. In May 2004, the MPSC issued an
order directing us to refund a net overrecovery of $3 million, plus interest. Of
this, $2 million has been refunded and the remaining $1 million is included in
our 2003-2004 GCR year reconciliation filing.

GCR year 2002-2003: In June 2003, we filed a reconciliation of GCR costs and
revenues for the 12-months ended March 2003. We proposed to recover from our
customers approximately $6 million of under recovered gas costs, including
interest through March 2003, using a roll-in methodology. The roll-in
methodology incorporates a GCR over/underrecovery in the next GCR plan year. The
approach was approved by the MPSC in a November 2002 order.

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In January 2004, intervenors filed their positions in our 2002-2003 GCR
reconciliation case. Their positions were that not all of our gas purchasing
decisions were prudent from April 2002 through March 2003 and they proposed
disallowances. In 2003, we reserved $11 million for a 2002-2003 GCR
disallowance. Interest on this amount from April 2003 through February 2004, at
our authorized rate of return, increased this amount by $1 million. The interest
was recorded as an expense in 2003. In March 2004, the parties in the case
reached a settlement agreement that resulted in a GCR disallowance of $11
million for the GCR period. The settlement agreement was approved by the MPSC in
March 2004. The prior year $6 million underrecovery and $11 million disallowance
are included in our 2003-2004 GCR year filing using the roll-in methodology. The
roll-in methodology incorporates the GCR underrecovery in the next GCR plan
year. The approach was approved by the MPSC in a November 2002 order.

GCR year 2003-2004: In June 2004, we filed a reconciliation of GCR costs and
revenues for the 12-months ended March 2004. We proposed to refund to our
customers $28 million of overrecovered gas cost, plus interest. We proposed that
the refund be included in the 2004-2005 GCR plan year. The overrecovery includes
the $1 million refund for the 2001-2002 GCR reconciliation case, the $11 million
refund settlement for the 2002-2003 GCR reconciliation case, as well as refunds
received by us from our suppliers and required by the MPSC to be refunded to our
customers.

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.
Recent increases in gas prices could cause us to incur costs in excess of what
can be recovered pursuant to the current ceiling price. We are permitted to
apply to the MPSC to modify the ceiling price, and will do so if necessary. In
addition, if actual, prudently incurred costs exceed the ceiling price, the
difference can be recovered through the reconciliation proceeding. Our GCR
factor for the billing month of November 2004 is $6.55 per mcf.

2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for
a gas rate increase in the annual amount of $156 million. On December 18, 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
receipt of a letter signed by the Chairman of Consumers and CMS Energy which
agrees 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, Consumers' and CMS Energy's Chairman filed a letter with
the MPSC making the

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commitments required by the rate order.

On October 19, 2004, we filed rehearing petitions with the MPSC, which seek
clarification of the method of computing our rate of return on common equity.

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.

On October 14, 2004, the MPSC issued its Opinion and Order in our gas
depreciation case. The order restores depreciation rates to the levels that were
in effect prior to the issuance of the December 18, 2003 interim gas rate order.
The final order further 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.

On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to
have book depreciation rates restored to the level set forth in the MPSC's prior
interim gas rate relief order.

GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an
order rejecting our filing to assess certain rates for non-physical gas title
tracking services we provide. In December 2003, the FERC ruled that no refunds
were at issue and we reversed a $4 million reserve related to this matter. In
January 2004, three companies filed with the FERC for clarification or rehearing
of the FERC's December 2003 order. In April 2004, the FERC issued its Order
Granting Clarification. In that Order, the FERC indicated that its December 2003
order was in error. It directed us to file within 30 days a fair and equitable
title-tracking fee and to make refunds, with interest, to customers based on the
difference between the accepted fee and the fee paid. In response to the FERC's
April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued
an Order Granting Rehearing for Further Consideration in June 2004. We expect
the FERC to issue an order on the merits of this proceeding. We believe that
with respect to the FERC jurisdictional transportation, we have not charged any
customers title transfer fees, so no refunds are due. At this time, we cannot
predict the outcome of this proceeding.

OTHER UNCERTAINTIES

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.

BAY HARBOR: Certain of CMS Energy's subsidiaries participated in the development
of Bay Harbor, a residential development near Petoskey, Michigan. CMS Energy has
since sold its interests in Bay Harbor but on September 3, 2004, the MDEQ issued
a Notice of Noncompliance (NON) directed to certain CMS Energy subsidiaries and
other parties that participated in Bay Harbor regarding cement kiln dust (CKD)
pile seep water contaminated with high levels of pH in Little Traverse Bay of
Lake Michigan.

In the various agreements to develop Bay Harbor, CMS Land Company, a subsidiary
of CMS Energy (CMS Land) and CMS Energy made certain indemnifications to various
parties for environmental

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conditions. In a settlement agreement, CMS Land abandoned all interests and
rights in Bay Harbor but retained the responsibilities it and CMS Energy had
under the previous environmental indemnifications. One such responsibility deals
with the construction, operation and maintenance of a pH-lowering treatment
facility at Bay Harbor that treats "seep water" collected after the water seeps
over underground CKD piles. The "seep water" has a high pH level that requires
treatment before the water can be discharged into the City of Petoskey sewer
system. While the pH treatment facility was out of service for a number of
months to address maintenance issues, and to resolve issues with the City of
Petoskey, MDEQ found the high levels of pH in Little Traverse Bay and issued the
NON. In addition, the EPA has become involved and has sent a representative to
obtain samples and information concerning the site. CMS Energy is engaging in a
study of the treatment facility in order to address maintenance issues over the
chemical composition of the liquid being delivered to the City of Petoskey. CMS
Energy has also presented plans to the MDEQ to undertake a study concerning a
separate "seep" that is not currently subject to a water collection and
treatment facility.

Several parties have issued demand letters to CMS Land and CMS Energy claiming
breach of the indemnification provisions and requesting payment of their
expenses related to the NON. CMS Energy responded by stating that it had not
breached its indemnity obligations; it will comply with the indemnities; it has
restarted the pH treatment facility; and it has responded to the NON.

CMS Energy cannot predict the outcome of this matter.

INTEGRUM LAWSUIT: Integrum filed a complaint in Wayne County, Michigan Circuit
Court in July 2003 against CMS Energy, Enterprises, and APT. Integrum alleges
several causes of action against APT, CMS Energy, and Enterprises in connection
with an offer by Integrum to purchase the CMS Pipeline Assets. In addition to
seeking unspecified money damages, Integrum is seeking an order enjoining CMS
Energy and Enterprises from selling, and APT from purchasing, the CMS Pipeline
Assets and an order of specific performance mandating that CMS Energy,
Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT and
Integrum. A certain officer and director of Integrum is a former officer and
director of CMS Energy, Consumers, and their subsidiaries. The individual was
not employed by CMS Energy, Consumers, or their subsidiaries when Integrum made
the offer to purchase the CMS Pipeline Assets. CMS Energy and Enterprises filed
a motion to change the venue from Wayne County to Jackson County, which was
granted. The case was then dismissed with prejudice based upon the plaintiff's
failure to file a transfer fee within the requisite time. The plaintiff has
stated it intends to file a motion to have the case reinstated. CMS Energy and
Enterprises believe that Integrum's claims are without merit. CMS Energy and
Enterprises intend to defend vigorously against this action but they cannot
predict the outcome of this litigation.

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 in the matter of
Ahmed, et al v. Dearborn Industrial Generation, LLC. The complaint sought
damages "in excess of $25,000" and injunctive relief based upon allegations of
excessive noise and vibration created by operation of the power plant. The first

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amended complaint was filed on behalf of six named plaintiffs, all alleged to be
adjacent or nearby residents or property owners. The damages alleged were injury
to persons and property of the landowners. Certification of a class of
"potentially thousands" who have been similarly affected was requested. The
parties entered into a settlement agreement on June 25, 2004, whereby DIG will
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. Remediation will take approximately 280 days. DIG cannot
predict the final cost associated with the settlement of this matter at this
time.

MCV EXPANSION, LLC: Under an agreement entered into with General Electric
Company (GE) in October 2002, MCV Expansion, LLC has a remaining contingent
obligation to GE in the amount of $2.2 million that may become payable in the
fourth quarter of 2004. The agreement provides that this contingent obligation
is subject to a pro rata reduction under a formula based upon certain purchase
orders being entered into with GE by June 30, 2003. MCV Expansion, LLC
anticipates but cannot assure that purchase orders will be executed with GE
sufficient to eliminate contingent obligations of $2.2 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 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.

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. On April 21, 2004, Argentina
and Bolivia signed an agreement in which Bolivian gas producers agreed to supply
up to 4 million cubic feet of natural gas per day to Argentina. This gas began
flowing to Argentina in mid-June and will continue to flow through November
2004. With these imports, 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.

In addition, the government of Argentina and Argentine gas producers entered
into an agreement to allow Argentine gas producers to raise their prices, the
effect of which should help to ease Argentina's long-term gas shortage problems.
Argentina and Bolivia are also currently in discussions to further extend the
term and increase the volume of gas flowing to Argentina from Bolivia under the
gas supply agreement, which expires in November 2004. At this point it is not
possible to predict the outcome of, or the impact on GasAtacama from, these
discussions or an extension of the Argentina/Bolivian gas supply agreement.

Currently, management of GasAtacama is working with government officials of
Chile and Argentina, as well as meeting with its electricity customers and gas
producers, to attempt to mitigate the impact of a continuing gas shortage in
Argentina. At this point it is not possible to predict the outcome of these
events and their effect on the earnings of GasAtacama.

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ARGENTINA ECONOMIC SITUATION: 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.

While we cannot predict future peso-to-U.S. dollar exchange rates, we do expect
that these non-cash charges reduce substantially the risk of further material
balance sheet impacts when combined with anticipated proceeds from international
arbitration currently in progress and political risk insurance. At September 30,
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 3.02 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.

LEONARD FIELD DISPUTE: Pursuant to a Consent Judgment entered in Oakland County,
Michigan Circuit Court in September 2001, CMS Gas Transmission had 18 months to
extract approximately one bcf of pipeline quality natural gas held in the
Leonard Field in Addison Township. The Consent Judgment provided for an
extension of that period upon certain circumstances. CMS Gas Transmission has
complied with the requirements of the Consent Judgment. Addison Township filed a
lawsuit in Oakland County Circuit Court against CMS Gas Transmission in February
2004 alleging the Leonard Field was discharging odors in violation of the
Consent Judgment. Pursuant to a Stipulated Order entered April 1, 2004, CMS Gas
Transmission agreed to certain undertakings to address the odor complaints and
further agreed to temporarily cease operations at the Leonard Field during the
month of April 2004, the last month provided for in the Consent Judgment. Also,
Addison Township was required to grant CMS Gas Transmission an extension to
withdraw its natural gas if certain conditions were met. Addison Township denied
CMS Gas Transmission's request for an extension on April 5, 2004. CMS Gas
Transmission is pursuing its legal remedies and filed a complaint against
Addison Township in June 2004. Addison Township has filed a counterclaim
alleging CMS Gas Transmission has failed to remove certain equipment from the
Leonard Field and that odor discharges have resulted in a diminution in
surrounding property values and consequently a loss in property tax revenues.
CMS Gas Transmission cannot predict the outcome of this matter, and unless an
extension is provided, it will be unable to extract approximately 500,000 mcf of
gas remaining in the Leonard Field.

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 Overseas Private Investment Corporation
(OPIC). Enterprises is party to a Sponsor Support Agreement pursuant to which
Enterprises has guaranteed CMS Ensenada's debt service payments to the OPIC up
to an amount which is in dispute, but which Enterprises estimated to be

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approximately $9 million at June 30, 2004. Following a payment made to the OPIC
in July 2004, Enterprises now believes this amount to be approximately $7
million.

An interim arrangement, which provided CMS Ensenada with payments under the
power purchase agreement that covered most, but not all, of CMS Ensenada's
operating costs, was agreed to with YPF Repsol in 2002 but expired on December
31, 2003. Efforts to negotiate a new agreement with YPF Repsol have been
unsuccessful.

As a result, CMS Ensenada initiated two legal actions: (1) an ex parte action in
the Argentine commercial courts, requesting injunctive relief in the form of a
temporary increase in the payments by YPF Repsol under the power purchase
agreement that would allow CMS Ensenada to continue to operate while seeking a
final and permanent resolution; and (2) an arbitration administered by the
International Chamber of Commerce seeking a ruling that the application of the
Emergency Laws to the power purchase agreement is unconstitutional, or,
alternatively, that the arbitral panel reestablish the economic equilibrium of
the power purchase agreement, as required by the Emergency Laws taking into
account that a significant portion of CMS Ensenada's operating costs are payable
in U.S. dollars. In April 2004, the injunctive relief was granted on appeal, but
in an amount lower than requested by CMS Ensenada. The injunctive relief expired
at the end of May, but the court recently extended the term of relief until the
end of the arbitration.

OTHER: Certain CMS Gas Transmission and CMS Generation affiliates in Argentina
received notice from various Argentine provinces claiming stamp taxes and
associated penalties and interest arising from various gas transportation
transactions. Although these claims total approximately $24 million, we believe
the claims are without merit and will continue to contest them vigorously.

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 is summarized as follows:

In Millions
- --------------------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- --------------------------------------------------------------------------------------------------------------

CMS ENERGY CORPORATION
Senior notes $ 2,063 $ 2,063
General term notes 227 496
Extendible tenor rate adjusted securities and other 186 187
-------------- --------------
Total - CMS Energy Corporation 2,476 2,746
-------------- --------------
CONSUMERS ENERGY COMPANY
First mortgage bonds 2,283 1,483
Senior notes 813 1,254
Bank debt and other 356 469
Securitization bonds 406 426
FMLP debt 296 --
-------------- --------------
Total - Consumers Energy Company 4,154 3,632
-------------- --------------
OTHER SUBSIDIARIES 199 191
-------------- --------------
Principal amounts outstanding 6,829 6,569
Current amounts (565) (509)
Net unamortized discount (36) (40)
- -----------------------------------------------------------------------------------------------------------
Total Long-term debt $ 6,228 $ 6,020
===========================================================================================================

FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB
Interpretation No. 46. At September 30, 2004, long-term debt of the FMLP
consists of:

In Millions
- ---------------------------------------------------------------------------
Maturity 2004
- ---------------------------------------------------------------------------

11.75% subordinated secured notes 2005 $ 70
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
- ---------------------------------------------------------------------------
Total amount outstanding $296
===========================================================================

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.

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

Principal Issue/Retirement
(In millions) Interest Rate Date Maturity Date
- ----------------------------------------------------------------------------------------------------------------

DEBT ISSUANCES

CONSUMERS ENERGY
FMB $ 150 4.40% August 2004 August 2009
FMB 300 5.00% August 2004 February 2012
FMB 350 5.50% August 2004 August 2016
- ----------------------------------------------------------------------------------------------------------------
Total debt issuances $ 800
================================================================================================================
DEBT RETIREMENTS

CONSUMERS ENERGY
FMLP debt $ 115 11.75% July 2004 July 2004
Long-term bank debt 140 Variable August 2004 March 2009
Senior notes 141 6.50% September 2004 June 2018
Senior notes 300 6.00% September 2004 March 2005
- ----------------------------------------------------------------------------------------------------------------
Total debt retirements $ 696
================================================================================================================

Issuance costs associated with the 2004 FMB issuances total $5 million and are
being amortized ratably over the lives of the related debt. Call premiums
associated with the debt retirements totaled $13 million and are being amortized
ratably over the lives of the newly issued debt.

In September 2004, Consumers issued $30 million of 3.375 percent Limited
Obligation Revenue Bonds. Consequently, Consumers redeemed $30 million of 5.8
percent Limited Obligation Revenue Bonds in October 2004.

In October 2004, we issued 32.8 million shares of our common stock. We realized
$288 million in net proceeds from this offering. We will use the net proceeds to
make capital infusions into Consumers. Pending such capital infusions, the
proceeds will be used for general corporate purposes, including temporary
investments in short-term securities.

DEBT MATURITIES: At September 30, 2004, the aggregate annual maturities for
long-term debt for the three months ending December 31, 2004 and the next four
years are:

In Millions
- ----------------------------------------------------------------------------------------------------------------
Payments Due
-----------------------------------------------------------------
2004 2005 2006 2007 2008
- ----------------------------------------------------------------------------------------------------------------

Long-term debt $ 228 $355 $ 551 $ 554 $ 1,053
================================================================================================================

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 first mortgage bonds 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 first mortgage bonds to be issued solely as collateral for other
long-term securities.

SHORT-TERM FINANCINGS: At September 30, 2004, CMS Energy had a $300 million
secured revolving credit facility with banks, which expires August 3, 2007. At
September 30, 2004, $92 million of letters

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of credit are issued and outstanding under this facility and $208 million is
available for general corporate purposes, working capital, and letters of
credit. At September 30, 2004, Consumers had a $500 million secured revolving
credit facility with banks, which expires July 31, 2007. At September 30, 2004,
$25 million of letters of credit are issued and outstanding under this facility
and $475 million is available for general corporate purposes, working capital,
and letters of credit. The MCV Partnership had a $50 million working capital
facility available.

FIRST MORTGAGE BONDS: Consumers secures its first mortgage bonds 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.

CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly
of leased service vehicles and office furniture. As of September 30, 2004,
capital lease obligations totaled $62 million. 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 September 30, 2004, finance lease obligations totaled $285
million, which represents the third-party portion of the MCV Partnership's
finance lease obligation.

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 $50 million of receivables at September 30, 2004 and we
sold $254 million at September 30, 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:

In Millions
- -------------------------------------------------------------------------------
Nine Months Ended September 30 2004 2003
- -------------------------------------------------------------------------------

Net cash flow as a result of A/R financing $ (247) $ (71)
Collections from customers $ 3,542 $3,379
===============================================================================

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 September 30, 2004,
Consumers had $348 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 order, which included a $190
million annual dividend cap imposed on Consumers. For the nine months ended
September 30, 2004, CMS Energy received $187 million of common stock dividends
from Consumers.

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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 beginning 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 September 30, 2004:

In Millions
- ----------------------------------------------------------------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount(b) Provision(c)
- ----------------------------------------------------------------------------------------------------------------------

Indemnifications from asset sales and
other agreements(a) Various Various $ 1,147 $ 2 $ -
Letters of credit Various Various 163 - -
Surety bonds and other indemnifications Various Various 24 - -
Other guarantees Various Various 197 - -
Nuclear insurance retrospective premiums Various Various 134 - -
======================================================================================================================

(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.

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The following table provides additional information regarding our guarantees:

- ---------------------------------------------------------------------------------------------------------------------
Events That Would Require
Guarantee Description How Guarantee Arose Performance
- ---------------------------------------------------------------------------------------------------------------------

Indemnifications from asset sales and Stock and asset sales agreements Findings of misrepresentation,
other agreements breach of warranties, and other
specific events or circumstances

Letters of credit Normal operations of coal power Noncompliance with environmental
plants regulations

Natural gas transportation Nonperformance

Self-insurance requirement Nonperformance

Nuclear plant closure Nonperformance

Surety bonds and other indemnifications Normal operating activity, permits Nonperformance
and license

Other guarantees Normal operating activity Nonperformance or non-payment by a
subsidiary under a related contract

Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price-Anderson Act
for nuclear incident
======================================================================================================================

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 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 $384 million as of September 30, 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: At September 30, 2004, we had contingently
convertible debt and equity securities outstanding. The significant terms of
these securities are as follows:

Convertible Senior Notes: Our $150 million 3.375 percent convertible senior
notes are putable to CMS Energy by the note holders at par on July 15, 2008,
July 15, 2013 and July 15, 2018. The notes are convertible to Common Stock at
the option of the holder if the price of our Common Stock remains at or above
$12.81 per share for 20 of 30 consecutive trading days ending on the last
trading day of a quarter. The $12.81 price per share may be adjusted if there is
a payment or distribution to our Common Stockholders. If conversion were to
occur, the notes would be converted into 14.1 million shares of Common Stock
based on the initial conversion rate.

Convertible Preferred Stock: Our $250 million 4.50 percent cumulative
convertible perpetual preferred stock has a liquidation value of $50.00 per
share. The security is convertible to Common Stock at the option of the holder
if the price of our Common Stock remains at or above $11.87 per share for 20 of
30 consecutive trading days ending on the last trading day of a quarter. On or
after December 5, 2008, we may cause the Preferred Stock to convert into Common
Stock if the closing price of our Common Stock remains at or above $12.86 for 20
of any 30 consecutive trading days. The $11.87 and $12.86 prices per share may
be adjusted if there is a payment or distribution to our Common Stockholders. If
conversion were to occur, the securities would be converted into 25.3 million
shares of Common Stock based on the

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initial conversion rate.

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. Including the dilutive effect of these instruments could
reduce our diluted earnings per share for 2004 by up to $0.10 per average common
share. The effective date for this EITF Issue is for reporting periods ending
after December 15, 2004, and the guidance applies to contingently convertible
instruments outstanding at December 31, 2004. We plan to modify our contingently
convertible securities prior to the effective date, through exchange offers that
are intended to mitigate the earnings per share impact.

5: EARNINGS PER SHARE

The following tables present the basic and diluted earnings per share
computations:

In Millions, Except Per Share Amounts
- ---------------------------------------------------------------------------------------------

Three Months Ended September 30 2004 2003
- ---------------------------------------------------------------------------------------------

EARNINGS ATTRIBUTABLE TO COMMON STOCK:
Income (Loss) from Continuing Operations $ 51 $ (71)
Less Preferred Dividends (3) -
----------------------------
Income (Loss) from Continuing Operations attributable
to Common Stock - Basic and Diluted $ 48 $ (71)
============================
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.5 152.2
Add dilutive Stock Options and Warrants 0.5(a) -(a)
----------------------------
Average Shares - Diluted 162.0 152.2
============================

EARNINGS (LOSS) PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO COMMON STOCK
Basic $ 0.30 $ (0.47)
Diluted $ 0.29 $ (0.47)
=============================================================================================

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CMS Energy Corporation

In Millions, Except Per Share Amounts
- -----------------------------------------------------------------------------------------------
Nine Months Ended September 30 2004 2003
- -----------------------------------------------------------------------------------------------

EARNINGS ATTRIBUTABLE TO COMMON STOCK:
Income (Loss) from Continuing Operations $ 68 $ (8)
Less Preferred Dividends (9) -
------------------------------
Income (Loss) from Continuing Operations attributable
to Common Stock - Basic and Diluted $ 59 $ (8)
==============================
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.3 146.8
Add dilutive Stock Options and Warrants 0.5(a) -(a)
------------------------------
Average Shares - Diluted 161.8 146.8
==============================

EARNINGS (LOSS) PER AVERAGE COMMON SHARE
ATTRIBUTABLE TO COMMON STOCK
Basic $ 0.36 $ (0.06)
Diluted $ 0.36 $ (0.06)
===============================================================================================

(a) Since the exercise price was greater than the average market price of the
Common Stock, options and warrants to purchase 4.7 million shares of Common
Stock were excluded from the computation of diluted EPS for the three and nine
months ended September 30, 2004, compared to 5.9 million shares of Common Stock
for the three months ended September 30, 2003 and 6.0 million shares of Common
Stock for the nine months ended September 30, 2003.

Contingently Convertible Securities: Computation of diluted earnings per share
for the three months and the nine months ended September 30, 2004 excluded
conversion of our $150 million 3.375 percent convertible senior notes and our 5
million shares of 4.50 percent cumulative convertible preferred stock. Both are
"contingently convertible" securities and, as of September 30, 2004, none of the
stated contingencies have been met. 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 a $2.2 million reduction of interest
expense, net of tax, for the three months ended September 30, 2004 and the three
months ended September 30, 2003, and a $6.5 million reduction of interest
expense, net of tax, for the nine months ended September 30, 2004 and the nine
months ended September 30, 2003. 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.

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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 carrying
amount of all long-term financial instruments, except as shown below,
approximates fair value. Our held-to-maturity investments consist of debt
securities held by the MCV Partnership totaling $140 million as of September 30,
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. For additional details, see Note 1, Corporate Structure and
Accounting Policies.

In Millions
- ----------------------------------------------------------------------------------------------------------------------
September 30 2004 2003
- ----------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain(Loss) Cost Value Gain(Loss)
- ----------------------------------------------------------------------------------------------------------------------

Long-term debt (a) $6,793 $7,111 $(318) $6,469 $6,640 $(171)
Long-term debt - related parties (b) 684 647 37 - - -
Trust Preferred Securities (b) - - - 663 603 60
Available-for-sale securities:
Nuclear decommissioning (c) 431 551 120 450 553 103
SERP 54 65 11 55 62 7
Southern Union Stock - - - 54 54 -
======================================================================================================================

(a) Includes current maturities of $565 million at September 30, 2004 and $174
million at September 30, 2003. Settlement of long-term debt is generally not
expected until maturity.

(b) We determined that we are not the primary beneficiary of our trust preferred
security structures. Accordingly, those entities have been deconsolidated as of
December 31, 2003 and are reflected in Long-term debt - related parties on our
Consolidated Balance Sheets. For additional details, see Note 11, Implementation
of New Accounting Standards.

(c) Our unrealized gains and losses on nuclear decommissioning investments are
reflected as regulatory liabilities.

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 trading or 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 by
performing financial credit

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reviews using, among other things, publicly available credit ratings of such
counterparties.

Contracts used to manage interest rate, foreign currency, and commodity price
risk 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 of the
contract 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 the
fair value of a derivative (that is, gains or losses) are reported either in
earnings or accumulated other comprehensive income depending on whether the
derivative qualifies for special hedge accounting treatment.

For derivative instruments to qualify for hedge accounting under SFAS No. 133,
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 immediately
recognized 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. We use a combination of quoted market prices and mathematical
valuation models to determine fair value of those contracts requiring derivative
accounting. The ineffective portion, if any, of all hedges is recognized in
earnings.

The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives 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,
as defined by SFAS No. 133, 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, as
defined by SFAS No. 133, for the coal that we purchase. If active markets
develop in the future, we may be required to account for these contracts as
derivatives. The mark-to-market impact on earnings related to these contracts
could be material to the financial statements.

The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which
will include day-ahead and real-time energy market information for the MISO's
participants. We are presently evaluating what impacts, if any, this market
development will have on the determination of whether an active energy market
exists in the state of Michigan.

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

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In Millions
- ----------------------------------------------------------------------------------------------------------------------------
September 30 2004 2003
- ----------------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- ----------------------------------------------------------------------------------------------------------------------------

Other than trading
Gas contracts $2 $5 $3 $3 $- $(3)
Interest rate risk contracts - (1) (1) - - -
Derivative contracts associated with
Consumers' investment in the MCV Partnership:
Prior to consolidation - - - - 10 10
After consolidation:
Gas fuel contracts - 80 80 - - -
Gas fuel futures and swaps - 92 92 - - -
Trading
Electric / gas contracts (2) 10 12 - 14 14
Derivative contracts associated with equity
investments in:
Shuweihat - (26) (26) - (32) (32)
Taweelah (35) (29) 6 - (29) (29)
Jorf Lasfar - (10) (10) - (10) (10)
Other - - - - (4) (4)
===========================================================================================================================

The fair value of our other than trading derivative contracts is included in
Derivative instruments, Other assets, or Other liabilities on our Consolidated
Balance Sheets. The fair value of our trading derivative contracts is included
in either Price risk management assets or Price risk management liabilities on
our Consolidated Balance Sheets. The fair value of derivative contracts
associated with our equity investments is included in Enterprises Investments on
our Consolidated Balance Sheets. The fair value of derivative contracts
associated with our investment in the MCV Partnership for 2003 is included in
Investments - Midland Cogeneration Venture Limited Partnership on our
Consolidated Balance Sheets.

ELECTRIC CONTRACTS: Our electric utility business may use purchased electric
call option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods. As of September 30, 2004 and September 30, 2003, we did not
have any purchased electric call options outstanding that were accounted for as
derivatives.

GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, 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 September 30, 2004, we held fixed-priced
weather-based gas supply call options and fixed-price gas supply put options.

INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk
associated with forecasted interest payments on variable-rate debt and to reduce
the impact of interest rate fluctuations. Most of our interest rate swaps are
designated as cash flow hedges. As such, we record changes in the fair value of

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these contracts in accumulated other comprehensive income unless the swaps are
sold. For interest rate swaps that did not qualify for hedge accounting
treatment, we record changes in the fair value of these contracts in Other
income.

The following table reflects the outstanding floating-to-fixed interest rates
swaps:

In Millions
- ----------------------------------------------------------------------------------
Floating to Fixed Notional Maturity Fair
Interest Rate Swaps Amount Date Value
- ----------------------------------------------------------------------------------

September 30, 2004 $ 25 2005-2006 $ (1)
September 30, 2003 3 2006 -
==================================================================================

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 7.3 percent at September 30, 2004 and 9.0 percent at September 30,
2003.

There was no ineffectiveness associated with any of the interest rate swaps that
qualified for hedge accounting treatment. As of September 30, 2004, we have
recorded an unrealized loss of $1 million, net of tax, in accumulated other
comprehensive income related to interest rate risk contracts accounted for as
cash flow hedges. We expect to reclassify $1 million of this amount as a
decrease to earnings during the next 12 months primarily to offset the
variable-rate interest expense on hedged debt.

Certain equity method investees have issued interest rate swaps to hedge the
risk associated with variable-rate debt, as listed in the table under
"Derivative Instruments" within this Note. 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 income.

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 its long-term natural gas contracts, which do not
contain volume optionality, qualify under SFAS No. 133 for the normal purchases
and normal sales exception. Therefore, these contracts are currently not
recognized at fair value on the balance sheet. Should significant changes in the
level of the MCV Facility operational dispatch or purchases of long-term gas
occur, the MCV Partnership would be required to re-evaluate its accounting
treatment for these long-term gas contracts. This re-evaluation may result in
recording mark-to-market activity on some contracts, which could add to earnings
volatility.

At September 30, 2004, the MCV Partnership had six long-term gas contracts that
contained both an option and forward component. Because of the option component,
these contracts do not qualify for the normal purchases and sales exception and
are 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 or losses will be recorded each quarter. At
September 30, 2004, the MCV Partnership also held three long-term gas contracts
that were previously accounted for as derivatives but

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qualified for the normal purchases and sales exception starting in the fourth
quarter of 2002. At that time, the fair value of these contracts was frozen and
is being amortized over the remaining life of the contracts. For the nine months
ended September 30, 2004, we recorded a $5 million net gain associated with the
MCV Partnership's long-term gas fuel contracts in Fuel for electric generation
on our Consolidated Statements of Income (Loss). The fair value of these
contracts will reverse over the remaining life of the contracts ranging from
2004 to 2007.

Gas Fuel Futures and Swaps: To manage market risks associated with the
volatility of natural gas prices, the MCV Partnership maintains a gas hedging
program. 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 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. At September 30, 2004, the MCV Partnership held gas
fuel futures and swaps.

These financial instruments are accounted for as derivatives under SFAS No. 133.
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 under SFAS No. 133. Therefore, the
mark-to-market gains and losses from these cost mitigation activities are
recorded in earnings each quarter.

As of September 30, 2004, we have recorded a cumulative net gain of $30 million,
net of tax, in accumulated other comprehensive income 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 October 2004 to December 2009, of which $17
million of this gain is expected to be reclassified as an increase to earnings
during the next 12 months. In addition, for the nine months ended September 30,
2004, we recorded a net gain of $21 million in earnings from hedging activities
related to natural gas requirements for the MCV Facility operations and a net
gain of $1 million in earnings from the MCV Partnership's cost mitigation
activities.

TRADING ACTIVITIES: 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 significantly reduced. 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. We use
various financial

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instruments, including swaps, options, futures, and forward contracts to manage
commodity risks associated with generation assets owned by CMS Energy or its
subsidiaries and to fulfill our contractual obligations. These contracts are
classified as trading activities in accordance with EITF No. 02-03 and are
accounted for using the criteria defined in SFAS No. 133. Energy trading
contracts that meet the definition of a derivative 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 in earnings as a component of operating revenues in the period in
which the changes occur. Energy trading contracts that do not meet the
definition of a derivative are accounted for as executory contracts (i.e., on an
accrual basis).

The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. 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. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.

In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to 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 results of operations as a result of counterparty nonperformance.

FOREIGN EXCHANGE DERIVATIVES: 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 not subject us to risk from exchange rate movements because
gains and losses on such contracts offset losses and gains, respectively, on
assets and liabilities being hedged. At September 30, 2004 and September 30,
2003, we had no outstanding foreign exchange contracts.

As of September 30, 2004, 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.

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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,

- health care and life insurance benefits under OPEB,

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

- a defined contribution 401(k) plan.

Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.

As of September 30, 2004, we have recorded a prepaid pension asset of $392
million, $20 million of which is in Prepayments and other current assets on our
Consolidated Balance Sheet.

OPEB: 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." In 1994, the MPSC authorized recovery of the electric
utility portion of these costs over 18 years and in 1996, the MPSC authorized
recovery of the gas utility portion of these costs over 16 years. We have made
contributions of $48 million to our 401(h) and VEBA trust funds in 2004. We plan
to make additional contributions of $15 million in 2004.

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

In Millions
- -----------------------------------------------------------------------------------------------------------------
Pension
Three Months Ended Nine Months Ended
- -----------------------------------------------------------------------------------------------------------------
September 30 2004 2003 2004 2003
- -----------------------------------------------------------------------------------------------------------------

Service cost $10 $ 10 $29 $ 29
Interest expense 17 18 53 55
Expected return on plan assets (26) (20) (80) (61)
Amortization of:
Net loss 3 2 10 7
Prior service cost 1 1 4 5
----------------------------------------------
Net periodic pension cost $5 $ 11 $16 $ 35
=================================================================================================================

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In Millions
- --------------------------------------------------------------------------------------------------------------
OPEB
Three Months Ended Nine Months Ended
- --------------------------------------------------------------------------------------------------------------
September 30 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------

Service cost $ 5 $ 5 $ 15 $ 16
Interest expense 14 17 43 50
Expected return on plan assets (12) (11) (36) (32)

Amortization of:
Net loss 3 4 8 14

Prior service cost (2) (1) (7) (5)
---------------------------------------------
Net periodic postretirement benefit cost $ 8 $ 14 $ 23 $ 43
==============================================================================================================

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 $158 million. The remeasurement resulted in
a reduction of OPEB cost of $6 million for the three months ended September 30,
2004, $18 million for the nine months ended September 30, 2004, and an expected
total reduction of $24 million for 2004. The reduction of $24 million includes
$7 million in capitalized OPEB costs. For additional details, see Note 11,
Implementation of New Accounting Standards.

8: 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. In 2004, net
income from these investments included undistributed earnings of $13 million for
the three months ended September 30, 2004 and $57 million for the nine months
ended September 30, 2004. In 2003, net income from these investments included
distributions in excess of earnings of $24 million for the three months ended
September 30, 2003 and undistributed earnings of $45 million for the nine months
ended September 30, 2003. The most significant of these investments is our:

- 50 percent interest in Jorf Lasfar,

- 45 percent interest in SCP, and

- 40 percent interest in Taweelah.

In August 2004, we sold our investment in SCP. Summarized income statement
information for these equity method investments is as follows:

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Income Statement Data

In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf (a)
Three Months Ended September 30, 2004 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------

Operating revenue $ 120 $ 7 $ 26 $ 153
Operating expenses (82) (2) (8) (92)
-----------------------------------------------
Operating income 38 5 18 61
Other income (expense), net (13) (2) (28) (43)
-----------------------------------------------
Net income (loss) $ 25 $ 3 $ (10) $ 18
=========================================================================================================

In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf
Three Months Ended September 30, 2003 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------

Operating revenue $ 89 $ 15 $ 24 $ 128
Operating expenses (52) (5) (9) (66)
-----------------------------------------------
Operating income 37 10 15 62
Other income (expense), net (17) (5) 14 (8)
-----------------------------------------------
Net income $ 20 $ 5 $ 29 $ 54
=========================================================================================================

Income Statement Data

In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf (a)
Nine Months Ended September 30, 2004 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------

Operating revenue $ 332 $ 44 $ 74 $ 450
Operating expenses (203) (12) (30) (245)
-----------------------------------------------
Operating income 129 32 44 205
Other expense, net (42) (14) (20) (76)
-----------------------------------------------
Net income $ 87 $ 18 $ 24 $ 129
=========================================================================================================

In Millions
- ---------------------------------------------------------------------------------------------------------
Jorf
Nine Months Ended September 30, 2003 Lasfar SCP Taweelah Total
- ---------------------------------------------------------------------------------------------------------

Operating revenue $ 270 $ 40 $ 72 $ 382
Operating expenses (138) (13) (27) (178)
-----------------------------------------------
Operating income 132 27 45 204
Other expense, net (41) (14) (12) (67)
-----------------------------------------------
Net income $ 91 $ 13 $ 33 $ 137
=========================================================================================================

(a) Includes results through the respective date of sale.

9: 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 the generation and distribution of
electricity in the state of

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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.

The following tables show our financial information by reportable segment. The
"Other" net income segment includes corporate interest and other, discontinued
operations, and the cumulative effect of accounting changes.

REVENUES In Millions
- ------------------------------------------------------------------------------------------------
Three Months Ended September 30 2004 2003
- ------------------------------------------------------------------------------------------------

Electric utility $ 704 $ 714
Gas utility 171 164
Enterprises 188 169
--------------------------
$ 1,063 $ 1,047
================================================================================================

NET INCOME (LOSS) AVAILABLE TO COMMON STOCK In Millions
- ------------------------------------------------------------------------------------------------
Three Months Ended September 30 2004 2003
- ------------------------------------------------------------------------------------------------

Electric utility $ 49 $ 59
Gas utility (11) (19)
Enterprises 59 (24)
Other (41) (85)
--------------------------
$ 56 $ (69)
================================================================================================

REVENUES In Millions
- ------------------------------------------------------------------------------------------------
Nine Months Ended September 30 2004 2003
- ------------------------------------------------------------------------------------------------

Electric utility $ 1,945 $ 1,966
Gas utility 1,376 1,252
Enterprises 589 923
--------------------------
$ 3,910 $ 4,141
================================================================================================

NET INCOME (LOSS) AVAILABLE TO COMMON STOCK In Millions
- ------------------------------------------------------------------------------------------------
Nine Months Ended September 30 2004 2003
- ------------------------------------------------------------------------------------------------

Electric utility $ 124 $ 145
Gas utility 46 40
Enterprises 36 5
Other (141) (242)
--------------------------
$ 65 $ (52)
================================================================================================

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TOTAL ASSETS In Millions
- ------------------------------------------------------------------------------------------------
September 30 2004 2003
- ------------------------------------------------------------------------------------------------

Electric utility $ 6,972 $ 6,551
Gas utility 3,230 2,952
Enterprises 4,815 3,561
Other 360 170
--------------------------
$ 15,377 $ 13,234
================================================================================================

10: 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 do so. We have legal obligations to
remove some of our assets, including our nuclear plants, at the end of their
useful lives.

Before adopting this standard, we classified the removal cost of assets included
in the scope of SFAS No. 143 as part of the reserve for accumulated
depreciation. For these assets, the removal cost of $448 million that was
classified as part of the reserve at December 31, 2002, was reclassified in
January 2003, in part, as a:

- $364 million ARO liability,

- $134 million regulatory liability,

- $42 million regulatory asset, and

- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.

We are reflecting a regulatory asset and liability as required by SFAS No. 71
for regulated entities 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 current 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, 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.

In addition, in 2003, we recorded an ARO liability for certain pipelines and
non-utility generating plants and a $1 million, net of tax, cumulative effect of
change in accounting for accretion and depreciation expense for ARO liabilities
incurred prior to 2003.

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

September 30, 2004 In Millions
- ---------------------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- ---------------------------------------------------------------------------------------------------------------------

Palisades-decommission plant site 1972 Palisades nuclear plant $500
Big Rock-decommission plant site 1962 Big Rock nuclear plant 51
JHCampbell intake/discharge water line 1980 Plant intake/discharge water line -
Closure of coal ash disposal areas Various Generating plants coal ash areas -
Closure of wells at gas storage fields Various Gas storage fields -
Indoor gas services equipment relocations Various Gas meters located inside structures -
Closure of gas pipelines Various Gas transmission pipelines -
Dismantle natural gas-fired power plant 1997 Gas fueled power plant -
=====================================================================================================================

September 30, 2004 In Millions
- ----------------------------------------------------------------- --------------------------------------------------------------
ARO Liability ARO
------------------- Cash Flow Liability
ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 9/30/04
- ---------------------------------------------------------------------------------------------------------------------------------

Palisades-decommission $249 $268 $ - $ - $16 $60 $344
Big Rock-decommission 61 35 - (32) 10 22 35
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - (2) 4 - 54
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
Closure of gas pipelines (a) 8 - - - - - -
Natural gas-fired power plant 1 1 - - 1 - 2
-------------------------------------------------------------------------------------
Total $373 $359 $ - $(34) $31 $82 $438
=================================================================================================================================

(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, Uncertainties, "Other Consumers' Electric Utility
Uncertainties - Nuclear Plant Decommissioning."

Reclassification of certain types of Cost of Removal: Beginning in December
2003, the SEC requires the quantification and reclassification of the estimated
cost of removal obligations arising from other than legal obligations. These
cost of removal obligations have been accrued through depreciation charges. We
estimate that we had $1.026 billion at September 30, 2004 and $962 million at
September 30, 2003 of previously accrued asset removal costs related to our
regulated obligations arising from other than legal operations. These
obligations, which were previously classified as a component of accumulated
depreciation, are now classified as regulatory liabilities in the accompanying
Consolidated Balance Sheets.

CMS-103

CMS Energy Corporation

11: 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 have 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 for the first time as of and for the quarter ended
March 31, 2004. These partnerships have third-party obligations totaling $581
million at September 30, 2004. Property, plant, and equipment serving as
collateral for these obligations has a carrying value of $1.440 billion at
September 30, 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 for the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $116 million at September 30, 2004. Property,
plant, and equipment serving as collateral for these obligations has a carrying
value of $168 million as of September 30, 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 also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected 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

CMS-104

CMS Energy Corporation

details our involvement in these entities at September 30, 2004:

- ----------------------------------------------------------------------------------------------------------------------------------
Name (Ownership Nature of the Involvement Investment Balance Operating Agreement Total Generating
Interest) Entity Country Date (In Millions) with CMS Energy Capacity
- ----------------------------------------------------------------------------------------------------------------------------------

United Arab 1999 $ 77 Yes 777 MW
Taweelah (40%) Generator Emirates

Generator -
Under
Jubail (25%) Construction Saudi Arabia 2001 $ - Yes 250 MW

United Arab 2001 $ 51 (a) Yes 1,500 MW
Shuweihat (20%) Generator Emirates
- ----------------------------------------------------------------------------------------------------------------------------------
Total $ 128 2,527 MW
==================================================================================================================================

(a) At September 30, 2004, the balance includes our proportionate share of the
negative fair value of derivative instruments of $26 million.

Our maximum exposure to loss through our interests in these variable interest
entities is limited to our investment balance of $128 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$59 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 from federal taxation, to sponsors of retiree health
care benefit plans that provide a benefit that is actuarially equivalent to
Medicare Part D. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.

The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.

CMS-105

CMS Energy Corporation

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 $6 million for the three months ended September 30,
2004, $18 million for the nine months ended September 30, 2004, and an expected
total 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 $4 million for the three months
ended September 30, 2004, $13 million for the nine months ended September 30,
2004, and an expected total net expense reduction of $17 million for 2004.

CMS-106

Consumers Energy Company

CONSUMERS ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS

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

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 and services each provides and operate
principally in two business segments: electric utility and gas utility. Our
electric utility operations include the generation, purchase, distribution, and
sale of electricity. Our gas utility operations include the purchase,
transportation, storage, distribution, and sale of natural gas.

We earn our revenue and generate cash from operations by providing electric and
natural gas services, electric power generation, gas transmission and storage,
and other energy related services. Our businesses are affected 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 strategy involves rebuilding our balance sheet and maintaining focus on our
core strength: superior utility operation and service. Over the next few years,
we expect this strategy to improve our debt ratings, grow earnings at a
mid-single digit rate, and position the company 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 without receiving compensation for
Stranded Costs caused by the lost sales. As of October 2004, we have lost 877
MW, or 11 percent, of our electric load to these alternative electric suppliers.
Based on current trends, we predict load loss by year-end to be in the range of
900 MW to 1,000 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, but the MPSC has not yet authorized
Stranded Cost recovery. We continue to seek resolution of this issue through two
pending Stranded Cost cases before the MPSC. In July 2004, several bills were
introduced into the Michigan Senate that could change Michigan's Customer Choice
Act.

Further, higher natural gas prices have harmed the economics of the MCV
Partnership and we are seeking approval from the MPSC to change the way the
facility is used. Our proposal would reduce gas consumption by an estimated 30
to 40 bcf per year while improving the MCV Partnership's financial performance
with no change to customer rates. A portion of the benefits from the proposal
will support additional renewable resource development in Michigan. Resolving
the issue is important for our shareowners and customers.

We are focused on further reducing our business, financial, and regulatory
risks, while growing the equity base of our company. In this regard, in August
2004, we completed an $800 million First Mortgage Bond financing at interest
rates ranging from 4.4 percent to 5.5 percent and used the proceeds to retire
other higher-interest rate long-term debt. Also in August 2004, we received a
$150 million contribution from

CE-1

Consumers Energy Company

CMS Energy, providing additional liquidity and flexibility for our operations.
The result of these efforts, and others, will 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 three and nine months ended September 30, 2004. These entities
are reported as equity method investments in our financial statements as of and
for the three and nine months ended September 30, 2003. The consolidation of
these entities had no impact on our consolidated net income for the three and
nine months ended September 30, 2004 versus the same periods ended September 30,
2003. For additional details, see Note 7, Implementation of New Accounting
Standards.

FORWARD-LOOKING STATEMENTS AND RISK FACTORS

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

- capital and financial market conditions, including the current 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,

CE-2

Consumers Energy Company

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

- recovery of 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 energy supply and
oil 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, regulatory decisions concerning the MCV Partnership RCP,
and regulatory decisions that limit our recovery of capacity and fixed
energy payments,

- federal regulation of electric sales and transmission of electricity
including 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,

- the GAAP requirement that we utilize mark-to-market accounting on
certain of our energy commodity contracts, and possibly other types of
contracts in the future, which may have a negative effect on earnings
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.

CE-3

Consumers Energy Company

RESULTS OF OPERATIONS

NET INCOME AVAILABLE TO COMMON STOCKHOLDER

In Millions
- -------------------------------------------------------------------------------------------------------------
September 30 2004 2003 Change
- -------------------------------------------------------------------------------------------------------------

Three months ended $ 34 $ 33 $ 1
Nine months ended 162 172 (10)
=============================================================================================================

2004 COMPARED TO 2003: For the three months ended September 30, 2004, our net
income increased $1 million versus the same period in 2003 primarily due to
increases in gas revenues, electric fuel recovery revenues, earnings from the
MCV Partnership, reductions in general tax expense, and increased interest
income. The annual unbilled gas volume analysis led to an increase in accrued
gas revenues of $7 million versus the 2003 results. In addition, gas revenues
increased net income $1 million due to the interim MPSC gas rate order issued in
December 2003. The Customer Choice Act authorized us to recognize interest
income on the excess of capital expenditures over our depreciation base. The
increase in interest income offset higher operating expenses, benefiting net
income $4 million. Net income also increased $1 million versus the same period
in 2003 due to the absence of a prior year underrecovery of PSCR revenue versus
cost. Further, net income increased $3 million due to a decrease in general
taxes from decreased property tax expense. Finally, net income increased $2
million due to higher earnings from the MCV Partnership reflecting increases in
the fair value of certain long-term gas contracts.

Decreased electric delivery revenues and increased interest charges
substantially offset these increases to net income. Decreased electric delivery
revenues reduced net income by $13 million, primarily due to milder summer
temperatures, tariff revenue reductions, and the continued loss of commercial
and industrial customers switching to alternative electric suppliers, as allowed
by the Customer Choice Act. An increase in interest expense decreased net income
$4 million due to greater average borrowings, partially offset by a reduction in
the average rate of interest.

For the nine months ended September 30, 2004, our net income decreased $10
million versus the same period in 2003. Electric delivery revenues decreased net
income $28 million due to milder summer weather, tariff revenue reductions, and
the continued loss of customers to alternative electric suppliers, as allowed by
the Customer Choice Act. The milder weather lowered gas delivery revenues,
decreasing net income by $7 million. Earnings from the MCV Partnership declined
$6 million primarily due to increases in non-recoverable fuel costs incurred at
the MCV Facility. In addition, net income was decreased $12 million due to
higher interest expense from greater average borrowings, partially offset by a
reduction in our average interest rate. Higher general taxes decreased net
income $7 million due to a 2003 reduction in MSBT expense to reflect the benefit
of CMS Energy's receipt of approval to file consolidated tax returns for the
years 2000 and 2001. Further, in 2003, under provisions of the Customer Choice
Act, the excess or recovery of PSCR revenues over PSCR costs benefited net
income. In contrast, in 2004, PSCR overrecoveries must be reserved for possible
future refund and consequently, do not benefit net income. This change in the
treatment of PSCR overrecoveries reduced net income $2 million.

Partially offsetting these reductions to net income were $31 million in benefits
relating primarily to reduced depreciation expense and increases in interest
income. The Customer Choice Act authorized us to defer electric depreciation on
the excess of capital expenditures over our depreciation base and recognize
interest income on the excess capital expenditures. Gas depreciation expense
also declined in the nine months ended September 30, 2004 versus the same period
in 2003 due to the interim MPSC gas rate order

CE-4

Consumers Energy Company

issued in December 2003. This interim order also authorized a gas rate increase
that benefited net income by $8 million. Finally, net income benefited from the
absence of a $12 million charge taken in 2003. The 2003 charge reflected a
decline in the market value of CMS Energy stock held by us.

For additional details, see "Electric Utility Results of Operations" and "Gas
Utility Results of Operations" within this section and Note 2, Uncertainties.

ELECTRIC UTILITY RESULTS OF OPERATIONS

In Millions
- ----------------------------------------------------------------------------------------------------------------
September 30 2004 2003 Change
- ----------------------------------------------------------------------------------------------------------------

Three months ended $ 49 $ 59 $ (10)
Nine months ended 124 145 (21)
================================================================================================================

Three Months Ended Nine Months Ended
Reasons for the change: September 30, 2004 vs. 2003 September 30, 2004 vs. 2003
- ----------------------------------------------------------------------------------------------------------------

Electric deliveries $(20) $(43)
Power supply costs and related revenue 2 (3)
Other operating expenses, non-commodity
revenue and other income 3 29
General taxes 2 (8)
Fixed charges (3) (9)
Income taxes 6 13
-----------------------------------------------------------
Total change $(10) $(21)
================================================================================================================

ELECTRIC DELIVERIES: Electric deliveries, including transactions with wholesale
marketers, other electric utilities, and customers choosing alternative
suppliers decreased 0.02 billion kWh or 0.2 percent, in the three months ended
September 30, 2004 versus the same period in 2003. For the nine months ended
September 30, 2004, electric deliveries increased 1.0 billion kWh or 3.5 percent
versus the same period in 2003. Electric delivery revenues benefited from the
recovery of deferred implementation costs. Recovery of these costs began July 1,
2004 and partially offset revenue reductions attributable to milder summer
temperatures, decreased revenues attributable to customers choosing alternative
electric suppliers, and tariff revenue reductions.

The tariff revenue reductions began January 1, 2004, and were equivalent to the
Big Rock nuclear decommissioning surcharge in effect when our electric retail
rates were frozen from September 2000 through December 31, 2003. The tariff
revenue reductions decreased electric delivery revenue by approximately $9
million in the three months ended September 30, 2004, and $27 million in the
nine months ended September 30, 2004 versus the same periods in 2003. The tariff
revenue reductions are expected to decrease electric delivery revenue by $35
million for the full year of 2004 versus the full year of 2003. On the positive
side, the tariff revenue reductions were reclassified for capped customers as
power supply revenue and helped reduce the underrecovery of power supply costs
for these customers.

CE-5

Consumers Energy Company

POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost recovery
rate was a fixed amount per kWh, 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 underrecovery would have decreased
operating income. In 2004, our recovery of power supply costs is no longer
fixed, but is instead restricted to a pre-defined limit for certain customer
classes. The customer classes that have a pre-defined limit, or cap, on the
level of power supply costs they can be charged are primarily the residential
and small commercial customer classes. In 2004, to the extent our power
supply-related revenue exceeds actual power supply costs, this former benefit is
reserved for possible future refund. Prior to a refund, a reserve is decreased
for subsequent underrecoveries before possibly decreasing operating income. In
the three months ended September 30, 2004, we have been able to reverse revenues
previously reserved in the year and defer certain costs to reduce the impact of
underrecoveries on operating income. Consequently, in the three months ended
September 30, 2004, operating income increased versus the same period in 2003
due to a prior year underrecovery of power supply costs. Operating income
decreased for the nine months ended September 30, 2004 versus the same period in
2003 due to prior year power supply cost overrecoveries.

OTHER OPERATING EXPENSES, NON-COMMODITY REVENUE AND OTHER INCOME: In the three
months ended September 30, 2004, other operating expenses increased $8 million,
non-commodity revenue decreased $2 million, and other income increased $13
million versus the same period in 2003. The increase in other income relates
primarily to the accrual of interest income on capital expenditures in excess of
depreciation, as allowed by the Customer Choice Act. Higher operating expenses
reflect increased generating plant operating costs and amortization relating to
the recovery of deferred implementation costs, which began July 1, 2004.
Decreased non-commodity revenues primarily reflect a reduction in rent revenues.

In the nine months ended September 30, 2004, other operating expenses increased
$2 million, other income increased $33 million, and non-commodity revenue
decreased $2 million versus the same period in 2003. The increase in other
income relates primarily to the accrual of interest income on capital
expenditures in excess of depreciation, as allowed by the Customer Choice Act. A
decline in non-commodity revenues reflects reduced rent revenues in the nine
months ended September 30, 2004 versus the same period in 2003.

GENERAL TAXES: General taxes decreased in the three months ended September 30,
2004 versus the same period in 2003. This decrease reflects less MSBT expense
and reduced property tax expense.

General taxes increased in the nine months ended September 30, 2004 versus the
same period in 2003 primarily due to reductions in the MSBT expense in 2003. The
2003 reduction was primarily due to CMS Energy's receipt of approval to file
consolidated tax returns for the years 2000 and 2001. The taxable income for
these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003.

FIXED CHARGES: Fixed charges increased in the three and nine months ended
September 30, 2004 versus the same periods in 2003 due to higher average debt
levels, partially offset by a reduction in the average rate of interest. In the
three months ended September 30, 2004, the average rate of interest dropped 14
basis points and in the nine months ended September 30, 2004, the average rate
of interest dropped 45 basis points versus the same periods in 2003. This
decrease in the average rates incorporates the impact of an August 2004
refinancing of $800 million. This refinancing both extended the maturity of the
debt, and significantly decreased the long-term debt interest rates of the $800
million.

CE-6

Consumers Energy Company

INCOME TAXES: In the three and nine months ended September 30, 2004, income
taxes decreased versus the same periods in 2003 primarily due to lower earnings
by the electric utility, and the OPEB Medicare Part D federal subsidy that is
exempt from federal taxation.

GAS UTILITY RESULTS OF OPERATIONS

In Millions
- -------------------------------------------------------------------------------------------------------------
September 30 2004 2003 Change
- -------------------------------------------------------------------------------------------------------------

Three months ended $ (11) $(19) $8
Nine months ended 46 40 6
=============================================================================================================

Three Months Ended Nine Months Ended
Reasons for the change: September 30, 2004 vs. 2003 September 30, 2004 vs.2003
- -------------------------------------------------------------------------------------------------------------

Gas deliveries $10 $(11)
Gas rate increase 1 12
Gas wholesale and retail services and other gas
revenues - 3
Operation and maintenance (1) (3)
Depreciation 2 9
General taxes 2 (2)
Fixed charges (3) (9)
Income taxes (3) 7
-----------------------------------------------------------
Total change $ 8 $ 6
=============================================================================================================

GAS DELIVERIES: For the three months ended September 30, 2004, the higher priced
non-transportation gas deliveries decreased 0.3 bcf or 1.7 percent versus the
same period in 2003. The lower priced transportation gas deliveries to end-use
customers decreased 0.6 bcf or 5.3 percent. Despite the decrease in gas
deliveries, gas delivery revenue increased in the three months ended September
30, 2004 versus the same period in 2003. This increase reflects the effect of
the annual unbilled gas volume analysis on accrued gas revenues versus the 2003
results. In 2004, this analysis supported an increase in unbilled gas volumes
that resulted in an increase of accrued gas revenues. In 2003, this annual
analysis led to a reduction in accrued gas revenues.

For the nine months ended September 30, 2004, gas deliveries, including
transportation to end-use customers, decreased 17.8 bcf or 7.5 percent versus
the same period in 2003 primarily due to milder weather.

GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. As a result of
this order, gas revenues increased for the three and nine months ended September
30, 2004 versus the same periods in 2003.

GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: For the nine months
ended September 30, 2004, wholesale and retail services and other gas revenues
increased primarily due to increased storage revenue versus the same period in
2003.

CE-7

Consumers Energy Company

OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2004, increased expenditures on safety, reliability, and customer service were
offset partially by reduced benefit costs compared to the same periods in 2003.

DEPRECIATION: For the three and nine months ended September 30, 2004,
depreciation expense decreased versus the same periods in 2003. The decrease in
depreciation expense relates to a reduction in depreciation rates authorized by
the MPSC's December 2003 interim rate order.

GENERAL TAXES: General taxes decreased in the three months ended September 30,
2004 versus the same period in 2003. This decrease reflects less MSBT expense
and decreased property tax expense.

For the nine months ended September 30, 2004, general tax expense increased $2
million due to higher MSBT expense versus the same period in 2003. The increase
in MSBT expense is primarily due to CMS Energy's receipt of approval to file
consolidated tax returns for the years 2000 and 2001. The taxable income for
these years was lower than the amount used to make estimated MSBT payments.
These returns were filed in the second quarter of 2003.

FIXED CHARGES: Fixed charges increased in the three and nine months ended
September 30, 2004 versus the same periods in 2003 due to higher average debt
levels, partially offset by a reduction in the average rate of interest. In the
three months ended September 30, 2004, the average rate of interest dropped 14
basis points and in the nine months ended September 30, 2004, the average rate
of interest dropped 45 basis points versus the same periods in 2003. This
decrease in the average rates incorporates the impact of an August 2004
refinancing of $800 million. This refinancing both extended the maturity of the
debt, and significantly decreased the long-term debt interest rates of the $800
million.

INCOME TAXES: For the three months ended September 30, 2004, income taxes
increased primarily due to the increased earnings of the gas utility versus the
same period in 2003.

For the nine months ended September 30, 2004, income taxes decreased due to the
income tax treatment of items related to plant, property and equipment as
required by past MPSC rulings, the decreased earnings of the gas utility, and
the OPEB Medicare Part D federal subsidy that is exempt from federal taxation.

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 in accounting for contingencies and equity method
investments,

- accounting for the effects of industry regulation,

- accounting for financial and derivative instruments,

- accounting for pension and postretirement benefits,

- 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.

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Consumers Energy Company

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 is probable and,
where determinable, an estimate of the liability amount. 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.

Under our PPA with the MCV Partnership, we pay a capacity charge based on the
availability of the MCV Facility whether or not electricity is actually
delivered to us; a variable energy charge for kWh delivered to us; and a fixed
energy charge based on availability up to 915 MW and based on delivery for the
remaining 325 MW of contract capacity. The cost that we incur under the MCV
Partnership PPA exceeds the recovery amount allowed by the MPSC. As a result, we
estimate cash underrecoveries of capacity and fixed energy payments will
aggregate $206 million from 2004 through 2007. For capacity and fixed energy
payments billed by the MCV Partnership after September 15, 2007, and not
recovered from customers, we expect to claim relief under a regulatory out
provision under the MCV Partnership PPA. This provision obligates Consumers to
pay the MCV Partnership only those capacity and energy charges that the MPSC has
authorized for recovery from electric 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 for 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.

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.

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Consumers Energy Company

As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be impacted negatively.

In February 2004, we filed the RCP with the MPSC that is intended to help
conserve natural gas and thereby improve our investment in the MCV Partnership,
without raising the costs paid by our electric customers. The plan's primary
objective is 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. This decrease in the quantity of high-priced natural gas
consumed by the MCV Facility will benefit Consumers' ownership interest in the
MCV Partnership. In August 2004, several qualifying facilities sought and
obtained a stay of the RCP proceeding from the Ingham County Circuit Court after
their previous attempt to intervene in the proceeding was denied by the MPSC. In
an attempt to resolve this intervention issue as quickly as possible, the MPSC
issued an order permitting the qualifying facilities to participate as
intervenors. As a result, the Ingham County Circuit Court stay was lifted and
hearings were completed in October 2004. The MPSC has decided to dispense with a
Proposal for Decision from the presiding ALJ and will issue a decision directly.
We cannot predict if or when the MPSC will approve the RCP.

The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Historically, natural gas prices have been
volatile. Presently, there is no consensus in the marketplace on the price or
range of future prices of natural gas. Even with an 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 of our
investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.

For additional details on the MCV Partnership, see Note 2, Uncertainties, "Other
Electric Uncertainties - 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, items that a non-regulated entity normally would expense, we may
record as regulatory assets if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, items that non-regulated
entities may normally recognize as revenues, we may record as regulatory
liabilities 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
September 30, 2004, we had $1.158 billion recorded as regulatory assets and
$1.512 billion recorded as regulatory liabilities.

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

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Consumers Energy Company

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 can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our debt
securities are classified as held-to-maturity securities and are reported at
cost. Our investments in equity securities are classified as available-for-sale
securities and are reported at fair value determined from quoted market prices.
Any unrealized gains and losses resulting from changes in fair value are
reported in equity as part of accumulated other comprehensive income. Unrealized
gains and losses are excluded from earnings unless such changes in fair value
are determined to be other than temporary. Unrealized gains or losses resulting
from changes in the fair value of our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets.

DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended and
interpreted, to determine if certain contracts must be accounted for as
derivative instruments. The rules for determining whether a contract meets the
criteria for derivative accounting are numerous and complex. Moreover,
significant judgment is required to determine whether a contract requires
derivative accounting, and similar contracts can sometimes be accounted for
differently.

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 of the contract 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 the fair value of a derivative (that
is, gains or losses) are reported either in earnings or accumulated other
comprehensive income, depending on whether the derivative qualifies for special
hedge accounting treatment.

The types of contracts we typically classify as derivative instruments are
interest rate swaps, electric call options, gas fuel futures and swaps, gas fuel
options, gas fuel contracts containing volume optionality, fixed priced
weather-based gas supply call options, and fixed price gas supply call and put
options. We generally do not account for electric capacity and energy contracts,
gas supply contracts, coal and nuclear fuel supply contracts, or purchase orders
for numerous supply items as derivatives.

The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives 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, as defined by
SFAS No. 133, 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, as defined by SFAS No.
133, for the coal that we purchase. If active markets develop in the future, we
may be required to account for these contracts as derivatives. The
mark-to-market impact on earnings related to these contracts could be material
to our financial statements.

The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which
will include day-ahead and real-time energy market information for the MISO's
participants. We are presently evaluating what impacts, if any, this market
development will have on the determination of whether an active energy market
exists in the state of Michigan. For additional information, see Electric
Business Uncertainties, "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 its
long-term natural gas contracts, which do not contain volume optionality,
qualify under SFAS No. 133 for the normal purchases and normal sales exception.
Therefore, these contracts are currently not recognized at fair value on the
balance sheet. Should significant changes in the level of the MCV Facility
operational dispatch or purchases of long-term gas occur, the MCV Partnership
would be required to re-evaluate its accounting treatment for these long-term
gas contracts. This re-evaluation may result in recording mark-to-market
activity on some contracts, which could add to earnings volatility.

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Consumers Energy Company

To determine the fair value of contracts that are accounted for as derivative
instruments, we use a combination of quoted market prices 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 September 30, 2004, we assumed a market-based
interest rate of 1 percent and monthly volatility rates ranging between 43
percent and 57 percent to calculate the fair value of our gas options. At
September 30, 2004, we assumed market-based interest rates ranging between 1.84
percent and 3.90 percent (depending on the term of the contract) and monthly
volatility rates ranging between 34 percent and 63 percent to calculate the fair
value of the gas fuel derivative contracts held by the MCV Partnership.

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 contracts to manage these risks, including swaps,
options, futures, and forward contracts.

Contracts used to manage market risks may be considered derivative instruments
that are subject to derivative and hedge accounting pursuant to SFAS No. 133. 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 by performing
financial credit reviews using, among other things, publicly available credit
ratings of such counterparties.

We perform sensitivity analyses to assess the potential loss in fair value, cash
flows, or future earnings based upon a hypothetical 10 percent adverse change in
market rates or prices. We do not believe that sensitivity analyses alone
provide an accurate or reliable method for monitoring and controlling risks.
Therefore, we use our experience and judgment to revise strategies and modify
assessments. Changes in excess of the amounts determined in sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity
Price Risk," and "Investment Securities Price Risk" within this section.

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):

In Millions
- ----------------------------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- ----------------------------------------------------------------------------------------------------------------------

Variable-rate financing - before tax annual earnings exposure $ 1 $ 1
Fixed-rate financing - potential loss in fair value (a) 168 154
======================================================================================================================

(a) Fair value exposure would 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, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. Electric call

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Consumers Energy Company

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 September 30, 2004, we
held fixed-priced weather-based gas supply call options and fixed-price 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 contain volume
optionality and, therefore, are treated as derivative instruments. Also, 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 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. At September 30, 2004, the MCV Partnership held gas
fuel contracts with volume optionality, as well as gas fuel futures and swaps.

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

In Millions
- --------------------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- --------------------------------------------------------------------------------------------------------------

Potential reduction in fair value:
Gas supply option contracts $ 3 $ 1
Derivative contracts associated with Consumers' investment
in the MCV Partnership:
Gas fuel contracts 22 N/A
Gas fuel futures and swaps 48 N/A
==============================================================================================================

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 March 31, 2004, as discussed in
Note 7, Implementation of New Accounting Standards.

Investment Securities Price Risk: We are exposed to price risk associated with
investments in equity securities. As discussed in "Financial Instruments" within
this section, our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income. Unrealized gains and
losses are excluded from earnings unless such changes in fair value are
determined to be other than temporary. Unrealized gains or losses resulting from
changes in the fair value of our nuclear decommissioning investments are
reflected as regulatory liabilities in our Consolidated Balance Sheets. Our debt
securities are classified as held-to-maturity securities and have original
maturity dates of approximately one year or less. Because of the short maturity
of these instruments, their carrying amounts approximate their fair values.

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Consumers Energy Company

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

In Millions
- -------------------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- -------------------------------------------------------------------------------------------------------------

Potential reduction in fair value:
Nuclear decommissioning investments $ 54 $ 57
Other available-for-sale investments 4 4
=============================================================================================================

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. It is scheduled to resume 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 change significantly 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. As of September 30, 2004,
we have a prepaid pension asset of $369 million, $20 million of which is in
Other current assets on our Consolidated Balance Sheets.

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Consumers Energy Company

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 2004 by $2 million. Lowering the discount rate by 0.25 percent
(from 6.25 percent to 6.00 percent) would increase estimated pension cost for
2004 by $4 million.

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 reduction of OPEB cost of $6 million for the three months ended September 30,
2004, $17 million for the nine months ended September 30, 2004, and an expected
total reduction of $23 million for 2004.

For additional details on postretirement benefits, see Note 5, Retirement
Benefits, and Note 7, Implementation of New Accounting Standards.

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,
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, which largely
utilize third-party cost estimates. For additional details on ARO, see Note 6,
Asset Retirement Obligations.

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Consumers Energy Company

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. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. 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 fully fund 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 will also
seek additional relief from the MPSC. For additional details on nuclear
decommissioning, see Note 2, Uncertainties, "Other Electric Uncertainties -
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 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 are generally based on
regulated prices, market prices, or competitive bidding. Transactions involving
the power supply purchases from certain affiliates

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Consumers Energy Company

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.

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
advance payment 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 borrowing capacity,
along with anticipated cash flows from operating and investing activities, will
be sufficient to meet our liquidity needs through 2005.

CASH POSITION, INVESTING, AND FINANCING

SUMMARY OF CASH FLOWS:

In Millions
- -------------------------------------------------------------------------------
Nine Months Ended September 30 2004 2003
- -------------------------------------------------------------------------------

Net cash provided by (used in):
Operating activities $ 330 $ 143
Investing activities (427) (327)
Financing activities 10 100
-----------------------------
Net Decrease in Cash and Cash Equivalents $ (87) $ (84)
================================================================================

OPERATING ACTIVITIES:

For the nine months ended September 30, 2004, net cash provided by operating
activities increased $187 million versus the same period in 2003. The absence,
in 2004, of $172 million in pension contributions made in 2003, increases in
inventory due to decreased economic demand for gas, and increases in other
liabilities resulting from the consolidation of the MCV Partnership and the
FMLP, and other timing differences represent the majority of the increase. These
increases more than offset the $157 million increase in accounts receivable
primarily due to lower sales of accounts receivable resulting from our improved
liquidity.

INVESTING ACTIVITIES:

For the nine months ended September 30, 2004, net cash from investing activities
decreased $100 million versus the same period in 2003 due to an increase in
capital expenditures of $62 million and an increase in the amount of cash
restricted of $33 million. For additional details on restricted cash, see Note
1, Corporate Structure and Accounting Policies, "Cash Equivalents and Restricted
Cash."

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Consumers Energy Company

FINANCING ACTIVITIES:

For the nine months ended September 30, 2004, net cash provided by financing
activities decreased $90 million versus the same period in 2003 primarily due to
a decrease of $216 million in net proceeds from borrowings. This decrease was
offset by a $150 million stockholder's contribution from the parent. For
additional details on long-term debt activity, see Note 3, Financings and
Capitalization.

OBLIGATIONS AND COMMITMENTS

REGULATORY AUTHORIZATION FOR FINANCINGS: We issue short- and long-term
securities under the FERC's authorization. For additional details of our
existing authorization, see Note 3, Financings and Capitalization.

LONG-TERM DEBT: The components of long-term debt are presented in Note 3,
Financings and Capitalization.

SHORT-TERM FINANCINGS: At September 30, 2004, we had $475 million available and
the MCV Partnership had $50 million available in short-term credit facilities.
The facilities are available for general corporate purposes, working capital,
and letters of credit. Additional details on short-term financings are presented
in Note 3, Financings and Capitalization.

OFF-BALANCE SHEET ARRANGEMENTS:

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.

CONTINGENT COMMITMENTS: Our 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 and approve these obligations and believe it is unlikely that we
would be required to perform or otherwise incur any material losses associated
with these guarantees. Our off-balance sheet commitments at September 30, 2004
will expire as follows:

Contingent Commitments In Millions
- ---------------------------------------------------------------------------------------------------------------
Commitment Expiration
--------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 beyond
- ---------------------------------------------------------------------------------------------------------------

Off-balance sheet:
Surety bonds and
other indemnifications (a) $ 5 $ - $ - $ - $ - $ - $ 5
Letters of credit (b) 25 - 18 - - - 7
===============================================================================================================

(a) The surety bonds are continuous in nature. The need for the bonds is
determined on an annual basis. In the third quarter of 2004, $3 million in
surety bonds were not renewed.

(b) The $2 million letter of credit for workers compensation self insurance and
$5 million of MDEQ letters of credit are renewed annually.

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Consumers Energy Company

DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
September 30, 2004, we had $348 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 order, which
included a $190 million annual dividend cap. For the nine months ended September
30, 2004, we paid $187 million in common stock dividends to CMS Energy.

OUTLOOK

ELECTRIC BUSINESS OUTLOOK

GROWTH: 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. We experienced less
growth than expected in 2003 as a result of cooler than normal summer weather
and a decline in manufacturing activity in Michigan. In 2004, we have again
experienced cooler than normal summer weather. As a result, electric deliveries
growth for 2004 is expected to be less than one percent.

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

- 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,

- ability to recover any of our net Stranded Costs under the
regulatory policies set by the MPSC,

- 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

- effects of recommendations as a result of the August 14, 2003
blackout, including increased regulatory requirements and new
legislation,

- regulatory decisions concerning the RCP,

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- effects of the FERC market power test requirements for electric
market-based rate authority,

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

- recovery of nuclear decommissioning costs. For additional details,
see "Accounting for Nuclear Decommissioning Costs" 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,
Uncertainties.

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.

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 September 30, 2004, we have
incurred $500 million in capital expenditures to comply with these regulations
and anticipate that the remaining $302 million of capital expenditures will be
made between 2004 and 2011. These expenditures include installing catalytic
reduction technology at some of our coal-fired electric plants. In addition to
modifying the coal-fired electric plants, we expect to purchase nitrogen oxide
emissions allowances for years 2004 through 2009. The cost of the allowances is
estimated to average $7 million per year for 2004-2006; the cost will decrease
after year 2006 with the installation of plant control technology. The cost of
the allowances is accounted for as inventory.

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 would potentially 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 and nickel from
coal-fired and

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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 fuel has resulted in reduced plant emissions,
lower operating costs, and flexibility in meeting future regulatory compliance
requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide
allowances optimizes our overall cost of regulatory compliance by delaying
capital expenditures and minimizing regulatory uncertainty. Western coal has
reduced our overall cost of fuel and reduced the impact on us from the recent
increases in eastern coal prices.

Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.

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 United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. 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.

In March 2004, the EPA changed the 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 by
2006. We are studying the rules to determine the most cost-effective solutions
for compliance.

For additional details on electric environmental matters, see Note 2,
Uncertainties, "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. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of October 2004, alternative electric suppliers are providing 877 MW
of generation supply to ROA customers. This amount represents 11 percent of our
distribution load and an increase of 45 percent compared to October 2003. Based
on current trends, we predict load loss by year-end to be in the range of 900 MW
to 1,000 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 rates 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,

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- 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.

In September 2004, the Chair of the Senate Technology and Energy Committee
formed a workgroup to analyze the merits of the proposed legislation. Workgroup
activities have since concluded and their impact on the proposed legislation is
still uncertain. In October 2004, a substitute to one of the bills was
introduced, but has not yet been adopted by the Michigan Senate.

Securitization: In March 2003, we filed an application with the MPSC seeking
approval to issue additional Securitization bonds. In June 2003, the MPSC issued
a financing order authorizing the issuance of Securitization bonds in the amount
of $554 million. We filed for rehearing and clarification on a number of
features in the financing order. In October 2004, the MPSC issued an order that
reversed the June 2003 financing order and denied our request to issue
additional Securitization bonds. Clean Air Act costs, originally included in our
Stranded Cost filings, were also part of this Securitization request that was
denied. The MPSC order, however, also gave us the option to file for recovery of
these costs through a Section 10d(4) Regulatory Asset case, which we filed in
October 2004.

Stranded Costs: To the extent we experience net Stranded Costs as determined by
the MPSC, the Customer Choice Act allows us to recover such costs by collecting
a transition surcharge from customers who switch to an alternative electric
supplier. We cannot predict whether the Stranded Cost recovery method ultimately
adopted by the MPSC will be applied in a manner that will offset fully any
associated margin loss.

In July 2004, the ALJ issued a Proposal for Decision in our 2002 net Stranded
Cost case, which recommended that the MPSC find that we incurred net Stranded
Costs of $12 million. This recommendation includes the cost of money through
July 2004 and excludes Clean Air Act costs. In July 2004, the MPSC Staff filed a
position on our 2003 net Stranded Cost application, which resulted in a Stranded
Cost calculation of $52 million. This amount includes the cost of money, but
excludes Clean Air Act costs. We cannot predict how the MPSC will rule on these
requests for the recovery of Stranded Costs. Therefore, we have not recorded
regulatory assets to recognize the future recovery of such costs.

Implementation Costs: Following an appeal and remand of initial MPSC orders
relating to 1999 implementation costs, the MPSC authorized the recovery of all
previously approved implementation costs for the years 1997 through 2001 by
surcharges on all customers' bills phased in as rate caps expire. Authorized
recoverable implementation costs totaled $88 million. This total includes the
cost of money through 2003. Additional carrying costs will be added until
collection occurs. For additional information on rate caps, see "Rate Caps"
within this section.

Our applications for recovery of $7 million of implementation costs for 2002 and
$1 million for 2003 are presently pending approval by the MPSC. In September
2004, the ALJ issued a Proposal for Decision recommending full recovery of these
costs. Included in the 2002 request is $5 million related to our former
participation in the development of the Alliance RTO. Although we believe these
implementation costs and associated cost of money are fully recoverable in
accordance with the Customer Choice Act, we cannot predict the amount, if any,
the MPSC will approve as recoverable.

In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million for implementation costs related to our former participation in the
development of the Alliance RTO. Included in this amount is $5 million pending

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approval by the MPSC as part of the 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. We
cannot predict the outcome of the appeal process or the amount, if any,
we will collect for Alliance RTO development costs.

Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs as a result of federal and state regulatory security
requirements incurred before January 1, 2006. In August 2004, the MPSC approved
a settlement agreement that authorizes full recovery of $25 million in requested
security costs over a five-year period beginning in September 2004. The amount
includes reasonable and prudent security enhancements through December 31, 2005.
All retail customers, except customers of alternative electric suppliers, will
pay these charges. As a result, in August 2004, we recorded total approved
security costs incurred to date, including the cost of money. As of September
30, 2004, we have recorded $21 million in security costs as a regulatory asset.

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-cap periods, including
the cost of money. In October 2004, we filed an application with the MPSC
seeking recovery of $628 million of capital expenditures in excess of
depreciation, Clean Air Act costs, and other expenses for the period June 2000
through December 2005. Of the $628 million, $152 million relates to the cost of
money. Also included in this application is $74 million of costs that were also
incorporated in our Stranded Costs filings. 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 us being unable to collect our full cost of conducting
business from electric customers. Such limitations include:

- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and

- rate caps 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 periods. 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.

PSCR: The PSCR process provides for the reconciliation of actual power supply
costs with power supply revenues. This process provides for recovery of all
reasonable and prudent power supply costs actually incurred by us, including the
actual cost for fuel, and purchased and interchange power. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. In October 2004,
the ALJ issued a Proposal for Decision, which recommended approval of our 2004
PSCR factor with minor adjustments. The PSCR factor recommended for approval
includes nitrogen oxide emissions allowance costs and requested transmission
costs, less a minor adjustment. We estimate the recovery of increased power
supply costs from large commercial and industrial customers to be approximately
$32 million in 2004.

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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 all other customers. Unless we receive an order from the MPSC, we
expect to self-implement this 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 October 2004, special contracts for
approximately 630 MW of load are in place, most of which are in effect through
2005.

Transmission Costs: In May 2002, we sold our electric transmission system for
$290 million to MTH. We are currently 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 rulemakings could affect significantly:

- transmission cost trends,

- delivered power costs to us, and

- delivered power costs to our retail electric customers.

As part of the ongoing development of regional transmission systems, the issue
of the appropriate level of "through and out" rates has been raised by the FERC
in recent orders. Through and out rates occur when a utility purchases
electricity that travels through the service territory of other utilities. These
utilities charge a rate for the energy going through and out of their service
territory. In March 2004, the FERC accepted a settlement whereby, effective
December 1, 2004, regional through and out rates for transactions in PJM and
MISO would be eliminated. In October 2004, two pricing proposals designed to
replace the elimination of through and out rates were submitted to the FERC for
approval. One of the pricing proposals could cause us to incur higher
transmission costs. We are unable to determine if the FERC will accept either
proposal, or will adopt a proposal of its own. The financial impact of such
proceedings, rulemaking, and trends are not quantifiable currently.

Transmission Market Developments: The MISO is scheduled to begin the Midwest
energy market on March 1, 2005. At that time, the MISO will begin providing
day-ahead and real-time energy market information for the MISO's participants.
These services 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.

We are also 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 effective May 1,
2004 and American Electric Power Service Corporation joined the PJM RTO
effective October 1, 2004. These integrations could create different patterns of
flow and power within the Midwest area and could affect adversely our ability to
provide reliable service to our customers.

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We are presently evaluating what financial impacts, if any, these market
developments will have on our operations.

August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid
serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
As a result, federal and state investigations regarding the cause of the
blackout were conducted. These investigations resulted in the NERC and the U.S.
and Canadian Power System Outage Task Force releasing electric operations
recommendations. 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. The
financial impacts of these recommendations are not quantifiable currently.

For additional details and material changes relating to the restructuring of the
electric utility industry and electric rate matters, see Note 2, Uncertainties,
"Electric Restructuring Matters," and "Electric Rate Matters."

PALISADES PLANT OUTAGE: Our Palisades plant is currently undergoing a regularly
scheduled refueling outage. In conjunction with this scheduled outage, we have
completed inspection of all 54 nuclear reactor vessel head penetrations. Small
cracks were identified in the welds on two of the 45 control rod drive
penetration nozzles. No external primary coolant system leakage or damage to the
reactor head material was noted. Sections of the two penetrations have been
removed and replaced. Post-weld testing, restoration of the support attachments,
and reactor head installation on the vessel are in progress and are expected to
be complete by mid-November. The total outage extension caused by the weld
cracks will be approximately four weeks. The plant is expected to return to
service by the end of November. For additional details on the Palisades outage,
see Note 2, Uncertainties, "Other Electric Uncertainties - Nuclear Matters."

UNIT OUTAGE: In June 2004, our 638 MW Karn Unit 4 facility located in
Essexville, Michigan experienced a failure on the exciter. The exciter is a
device that provides the magnetic field to the main electric generator. We
rented a temporary replacement from Detroit Edison. In October 2004, we decided
to extend our rental of the temporary replacement until December 2004 during the
refueling outage at our Palisades plant, as discussed in "Palisades Plant
Outage" within this section.

FERC REVISED MARKET POWER TEST: In April 2004, the FERC adopted two new
generation market power screen tests and modified measures that can be taken to
mitigate market power where it is found. The screens will apply to all initial
market-based rate applications and will be reviewed every three years. Based on
our filing with the FERC in August 2004, we determined that Consumers passed the
established screens, enabling us to sell power at market-based rates. Subsequent
to this filing, the FERC staff informally requested a revised market power
analysis based on the consolidated figures of Consumers and CMS Energy's
Michigan subsidiaries. On October 1, 2004, we submitted the revised market power
analysis, which we believe demonstrates that we passed the established screens
on a consolidated basis. On October 29, 2004, the FERC staff requested us to
provide additional support information and respond to several clarification
requests. The FERC also issued similar letters to ten other companies that had
made contemporaneous market power filings with the FERC. We are in the process
of preparing our response, which is due November 19, 2004.

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.
Consumers and other interested parties are considering appeals to the Michigan
Supreme Court. Unless overturned by the Michigan Supreme Court, the decision
could encourage other municipalities to adopt similar ordinances. This case has
potentially broad ramifications for the electric utility and telephone
industries in Michigan; however, at this time, we cannot predict the outcome of
this matter.

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PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of September 2004, we are in
compliance with the acceptable level of performance. We are a member of an
industry coalition that has appealed the customer credit portion of the
performance standards to the Michigan Court of Appeals. We cannot predict the
likely effects of the financial penalties, if any, nor can we predict the
outcome of the appeal. Likewise, we cannot predict our ability to meet the
standards in the future or the cost of future compliance.

For additional details on performance standards, see Note 2, Uncertainties,
"Electric Rate Matters - Performance Standards."

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 for the construction of a 25-mile gas
transmission pipeline in northern Oakland County. The project is necessary to
meet peak load beginning in the winter of 2005 through 2006. If we are unable to
construct the pipeline due to local opposition, we will need to pursue more
costly alternatives or possibly curtail serving the system's load growth in that
area. We are currently involved in settlement discussions with several
intervenors. At this time, we cannot predict the outcome of our negotiations.

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
net sales, 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 integrity rules and mandates.

Environmental

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

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Other

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

- other pending litigation.

GAS BTU CONTENT: We sell gas to retail customers under tariffs approved by the
MPSC. These tariffs measure the volume of gas delivered to customers (i.e. mcf).
However, we purchase gas for resale on a heating value (i.e. Btu) basis. The Btu
content of the gas purchased fluctuates and may result in customers using less
gas for the same heating requirement. We fully recover our cost to purchase gas
through the approved GCR. However, since the customer may use less gas on a
volumetric basis, the revenue from the distribution charge (the non-gas cost
portion of the customer bill) could be reduced. This could adversely affect our
gas utility earnings. The amount of any possible earnings loss due to
fluctuating Btu content in future periods cannot be estimated at this time.

GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an
order rejecting our filing to assess certain rates for non-physical gas title
tracking services we provide. In December 2003, the FERC ruled that no refunds
were at issue and we reversed a $4 million reserve related to this matter. In
January 2004, three companies filed with the FERC for clarification or rehearing
of the FERC's December 2003 order. In April 2004, the FERC issued its Order
Granting Clarification. In that order, the FERC indicated that its December 2003
order was in error. It directed us to file within 30 days a fair and equitable
title-tracking fee and to make refunds, with interest, to customers based on the
difference between the accepted fee and the fee paid. In response to the FERC's
April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued
an Order Granting Rehearing for Further Consideration in June 2004. We expect
the FERC to issue an order on the merits of this proceeding. We believe that
with respect to the FERC jurisdictional transportation, we have not charged any
customers title transfer fees, so no refunds are due. At this time, we cannot
predict the outcome of this proceeding.

GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our prudently incurred gas costs. 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, Uncertainties, "Gas Rate Matters - Gas Cost
Recovery."

Gas Cost Recovery Reconciliation

- --------------------------------------------------------------------------------------------------------------------
Net Over
GCR Year Date Filed Order Date Recovery Status
- --------------------------------------------------------------------------------------------------------------------

2001-2002 June 2002 May 2004 $3 million $2 million has been refunded;
$1 million is included in our 2003-2004
GCR reconciliation filing

2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest accrued
through March 2003, and an $11 million
disallowance settlement agreement

2003-2004 June 2004 Pending $28 million Filing includes the $1 million and
$5 million GCR net overrecovery above
=====================================================================================================================

Net overrecovery amounts included in the table above include refunds received by
us from our suppliers and required by the MPSC to be refunded to our customers.

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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.
Recent increases in gas prices could cause us to incur costs in excess of what
can be recovered pursuant to the current ceiling price. We are permitted to
apply to the MPSC to modify the ceiling price, and will do so if necessary. In
addition, if actual, prudently incurred costs exceed the ceiling price, the
difference can be recovered through the reconciliation proceeding. Our GCR
factor for the billing month of November 2004 is $6.55 per mcf.

2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for
a gas rate increase in the annual amount of $156 million. On December 18, 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
receipt of a letter signed by the Chairman of Consumers and CMS Energy, which
agrees 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, Consumers' and CMS Energy's Chairman filed a letter with
the MPSC making the commitments required by the rate order.

On October 19, 2004, we filed rehearing petitions with the MPSC, which seek
clarification of the method of computing our rate of return on common equity.

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.

On October 14, 2004, the MPSC issued its Opinion and Order in our gas
depreciation case. The order restores depreciation rates to the levels that were
in effect prior to the issuance of the December 18, 2003 interim gas rate order.
The final order further 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.

On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to
have book depreciation rates restored to the level set forth in the MPSC's prior
interim gas rate relief order.

GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number

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Consumers Energy Company

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, Uncertainties, "Gas Contingencies - Gas Environmental
Matters."

OTHER OUTLOOK

CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that
applies to utilities and alternative electric suppliers. The code of conduct
seeks to prevent financial support, information sharing, and preferential
treatment between a utility's regulated and non-regulated services. The new code
of conduct is broadly written and could affect our:

- retail gas business energy related services,

- retail electric business energy related services,

- marketing of non-regulated services and equipment to Michigan
customers, and

- transfer pricing between our departments and affiliates.

We appealed the MPSC orders related to the code of conduct and sought a deferral
of the orders until the appeal was complete. We also sought waivers available
under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business.

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 $9 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 year-to-date 2004 earnings.

TAX BILL: In October 2004, Congress passed tax legislation, the "American Jobs
Creation Act of 2004," which the President signed into law. We are currently
studying the tax bill's provisions for its impact, if any, upon Consumers.

SARBANES-OXLEY ACT OF 2002: We are in the process of implementing the internal
control requirements mandated by the Sarbanes-Oxley Act. Our evaluation and
testing of internal controls is continuing, but is incomplete as of the date of
this Form 10-Q. We are currently unaware of any material weaknesses in our
control over financial reporting. We plan to complete testing and finalize our
evaluation in the fourth quarter. Until this is completed, we cannot provide
assurance that our internal controls do not contain material weaknesses.

CE-29

Consumers Energy Company

Our 2004 Form 10-K will contain a report by our management on the effectiveness
of our internal controls and a report by Ernst & Young, our Registered
Independent Auditors, that attests to and reports on our management's assessment
of internal control. These annual reports on internal control are now required
by Section 404 of the Sarbanes-Oxley Act for all public companies, effective
with our 2004 Form 10-K.

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 including a shareholder derivative
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, Uncertainties.

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 have 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 for the first time as of and for the quarter ended
March 31, 2004. These partnerships have third-party obligations totaling $581
million at September 30, 2004. Property, plant, and equipment serving as
collateral for these obligations has a carrying value of $1.440 billion at
September 30, 2004. The creditors of these partnerships do not have recourse to
the general credit of CMS Energy.

We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $490 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $506 million of long-term debt - related parties
and reflected an investment in related parties of $16 million.

We are not required to restate prior periods for the impact of this accounting
change.

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

CE-30

Consumers Energy Company

that is actuarially equivalent to Medicare Part D. At December 31, 2003, we
elected a one-time deferral of the accounting for the Act, as permitted by FASB
Staff Position, No. SFAS 106-1.

The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.

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 $6 million for the three months ended September 30,
2004, $17 million for the nine months ended September 30, 2004, and an expected
total 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 $4 million for the three months
ended September 30, 2004, $12 million for the nine months ended September 30,
2004, and an expected total net expense reduction of $16 million for 2004.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

EITF ISSUE NO. 03-1, THE MEANING OF OTHER THAN TEMPORARY INVESTMENTS: This issue
addresses the definition of an other than temporary impairment of certain
investments and was scheduled to be effective as of September 30, 2004. 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 Opinion No. 18.

The FASB issued a final FASB Staff Position, FSP EITF Issue 03-1-1 deferring
portions of EITF Issue No. 03-1 relating to guidance on such matters as to what
constitutes a minor impairment and the determination of "other than temporary."
The deferral extends until the Board issues a final FSP 03-1-a defining the
effective date and amending EITF Issue No. 03-1 as it is currently written. The
FASB expects to issue the FASB Staff Position in November. The deferral does not
apply to the disclosure requirements of EITF Issue No. 03-1, which are required
in our annual financial statements. We do not expect this issue to have an
impact on our results of operations when it becomes effective.

EITF ISSUE NO. 04-10, APPLYING PARAGRAPH 19 OF SFAS NO. 131, DISCLOSURES ABOUT
SEGMENTS OF AN ENTERPRISE AND RELATED INFORMATION, IN DETERMINING WHETHER TO
AGGREGATE OPERATING SEGMENTS THAT DO NOT MEET THE QUANTITATIVE THRESHOLDS: This
issue addresses how to apply the operating segment aggregation criteria in SFAS
No. 131. At their September 2004 meeting, the EITF reached consensus on this
issue. The EITF concluded that operating segments that do not meet the
quantitative thresholds established in SFAS No. 131 could be aggregated only if
aggregation is consistent with the objective and basic principles of Statement
131 and the segments have similar economic characteristics. The consensus will
be effective as of December 31, 2004. We do not expect this issue to have an
impact on our segment reporting under SFAS No. 131 when it becomes effective.

CE-31

Consumers Energy Company

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CE-32

CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)

THREE MONTHS ENDED NINE MONTHS ENDED
SEPTEMBER 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------
In Millions

OPERATING REVENUE $ 885 $ 879 $ 3,355 $ 3,223

EARNINGS (LOSS) FROM EQUITY METHOD INVESTEES 1 (3) 1 31

OPERATING EXPENSES
Fuel for electric generation 194 89 518 245
Purchased and interchange power 71 103 171 260
Purchased power - related parties 18 131 49 383
Cost of gas sold 89 90 947 793
Cost of gas sold - related parties - 2 1 27
Other operating expenses 181 178 529 505
Maintenance 56 41 163 149
Depreciation, depletion and amortization 104 80 335 275
General taxes 51 47 163 130
--------------------------------------
764 761 2,876 2,767
- -------------------------------------------------------------------------------------------

OPERATING INCOME 122 115 480 487

OTHER INCOME (DEDUCTIONS)
Accretion expense (1) (1) (3) (5)
Interest and dividends 4 1 11 6
Gain on asset sales, net 1 - 1 -
Other income 13 2 35 6
Other expense (2) (1) (4) (15)
--------------------------------------
15 1 40 (8)
- -------------------------------------------------------------------------------------------

INTEREST CHARGES
Interest on long-term debt 70 51 215 144
Interest on long-term debt - related parties 11 - 33 -
Other interest 4 2 11 10
Capitalized interest (2) (2) (5) (7)
--------------------------------------
83 51 254 147
- -------------------------------------------------------------------------------------------

INCOME BEFORE INCOME TAXES AND MINORITY INTERESTS 54 65 266 332

INCOME TAXES 19 21 91 126

MINORITY INTERESTS 1 - 12 -
--------------------------------------

NET INCOME 34 44 163 206
PREFERRED STOCK DIVIDENDS - - 1 1
PREFERRED SECURITIES DISTRIBUTIONS - 11 - 33
--------------------------------------

NET INCOME AVAILABLE TO COMMON STOCKHOLDER $ 34 $ 33 $ 162 $ 172
===========================================================================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CE-33

CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)

Nine Months Ended
September 30 2004 2003
- -----------------------------------------------------------------------------------------------
In Millions

CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 163 $ 206
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $4 and $4, respectively) 335 275
Gain on sale of assets (1) -
Capital lease and other amortization 20 20
Loss on CMS Energy stock - 12
Distributions from related parties less than earnings - 14
Pension contribution - (172)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenue (1) 156
Increase (decrease) in accounts payable 27 (26)
Decrease in accrued expenses (130) (132)
Increase in inventories (273) (335)
Deferred income taxes and investment tax credit 91 72
Decrease in other current and non-current assets 54 96
Increase (decrease) in other current and non-current liabilities 45 (43)
-----------------

Net cash provided by operating activities $ 330 $ 143
- -----------------------------------------------------------------------------------------------

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $(368) $ (306)
Cost to retire property (53) (52)
Restricted cash on hand (Note 1) (34) (1)
Investments in Electric Restructuring Implementation Plan (5) (5)
Investments in nuclear decommissioning trust funds (4) (4)
Proceeds from nuclear decommissioning trust funds 35 26
Maturity of MCV restricted investment securities held-to-maturity 592 -
Purchase of MCV restricted investment securities held-to-maturity (592) -
Cash proceeds from sale of assets 2 15
----------------

Net cash used in investing activities $(427) $ (327)
- -----------------------------------------------------------------------------------------------

CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long term debt $ 817 $ 1,543
Retirement of long-term debt (727) (780)
Payment of common stock dividends (187) (162)
Preferred securities distributions - (33)
Payment of preferred stock dividends (2) (1)
Payment of capital and finance lease obligations (41) (10)
Decrease in notes payable, net - (457)
Stockholder's contribution, net 150 -
-----------------

Net cash provided by financing activities $ 10 $ 100
- -----------------------------------------------------------------------------------------------

Net Decrease in Cash and Cash Equivalents $ (87) $ (84)

Cash and Cash Equivalents from Effect of Revised FASB
Interpretation No. 46 Consolidation 174 -

Cash and Cash Equivalents, Beginning of Period 46 244
----------------
Cash and Cash Equivalents, End of Period $ 133 $ 160
===============================================================================================

CE-34

OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:

In Millions
September 30 Nine Months Ended
2004 2003
- -------------------------------------------------------------------

CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $ 237 $156
Income taxes paid 7 32
OPEB cash contribution 47 53

NON-CASH TRANSACTIONS
Other assets placed under capital lease 2 11
==================================================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CE-35

CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS

ASSETS

SEPTEMBER 30 SEPTEMBER 30
2004 DECEMBER 31 2003
(UNAUDITED) 2003 (UNAUDITED)
- -----------------------------------------------------------------------------------------------------------------------------
In Millions

PLANT (AT ORIGINAL COST)
Electric $ 7,860 $ 7,600 $ 7,583
Gas 2,929 2,875 2,841
Other
2,523 15 15
----------------------------------------------
13,312 10,490 10,439
Less accumulated depreciation, depletion and amortization 5,589 4,417 4,403
----------------------------------------------
7,723 6,073 6,036
Construction work-in-progress 405 375 359
----------------------------------------------
8,128 6,448 6,395
- -----------------------------------------------------------------------------------------------------------------------------

INVESTMENTS
Stock of affiliates 23 20 17
First Midland Limited Partnership - 224 222
Midland Cogeneration Venture Limited Partnership - 419 404
Other 19 18 2
----------------------------------------------
42 681 645
- -----------------------------------------------------------------------------------------------------------------------------

CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 133 46 160
Restricted cash 52 18 19
Accounts receivable, notes receivable and accrued revenue, less allowances of
$8, $8 and $7 respectively 289 257 81
Accounts receivable - related parties 12 4 7
Inventories at average cost
Gas in underground storage 995 739 813
Materials and supplies 71 70 72
Generating plant fuel stock 77 41 44
Deferred property taxes 111 143 88
Regulatory assets 19 19 19
Derivative instruments 143 2 2
Other 79 78 92
----------------------------------------------
1,981 1,417 1,397
- -----------------------------------------------------------------------------------------------------------------------------

NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 616 648 659
Postretirement benefits 145 162 168
Abandoned Midland Project 10 10 10
Other 368 266 257
Nuclear decommissioning trust funds 551 575 553
Prepaid pension costs 349 364 -
Other 311 174 147
----------------------------------------------
2,350 2,199 1,794
----------------------------------------------
TOTAL ASSETS $ 12,501 $ 10,745 $ 10,231
=============================================================================================================================

CE-36

STOCKHOLDER'S EQUITY AND LIABILITIES

SEPTEMBER 30 SEPTEMBER 30
2004 DECEMBER 31 2003
(UNAUDITED) 2003 (UNAUDITED)
- ----------------------------------------------------------------------------------------------------------------------
In Millions

CAPITALIZATION
Common stockholder's equity
Common stock, authorized 125.0 shares; outstanding
84.1 shares for all periods $ 841 $ 841 $ 841
Paid-in capital 832 682 682
Accumulated other comprehensive income (loss) 38 17 (191)
Retained earnings since December 31, 1992 496 521 555
---------------------------------------
2,207 2,061 1,887

Preferred stock 44 44 44
Company-obligated mandatorily redeemable preferred securities
of subsidiaries - - 490

Long-term debt 3,986 3,583 3,531
Long-term debt - related parties 506 506 -
Non-current portion of capital and finance lease obligations 318 58 116
---------------------------------------
7,061 6,252 6,068
- ---------------------------------------------------------------------------------------------------------------

MINORITY INTERESTS 675 - -
- ---------------------------------------------------------------------------------------------------------------

CURRENT LIABILITIES
Current portion of long-term debt, capital leases and finance leases 177 38 39
Notes payable - related parties 200 200 -
Accounts payable 253 200 245
Accrued taxes 61 209 84
Accounts payable - related parties 12 75 65
Current portion of purchase power contract 6 27 26
Deferred income taxes 30 33 23
Other 300 185 168
---------------------------------------
1,039 967 650
- ---------------------------------------------------------------------------------------------------------------

NON-CURRENT LIABILITIES
Deferred income taxes 1,328 1,233 1,009
Regulatory Liabilities
Cost of removal 1,026 983 962
Income taxes, net 326 312 309
Other 160 172 152
Postretirement benefits 172 190 431
Asset retirement obligations 436 358 362
Deferred investment tax credit 81 85 86
Power purchase agreement - MCV Partnership - - 8
Other 197 193 194
---------------------------------------
3,726 3,526 3,513
- ---------------------------------------------------------------------------------------------------------------

COMMITMENTS AND CONTINGENCIES (Notes 1, 2, and 5)

TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES $ 12,501 $ 10,745 $ 10,231
===============================================================================================================

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CE-37

CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(UNAUDITED)

Three Months Ended Nine Months Ended
SEPTEMBER 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------
In Millions

COMMON STOCK
At beginning and end of period (a) $ 841 $ 841 $ 841 $ 841
-----------------------------------------------------------------------------------------------------------------

OTHER PAID-IN CAPITAL
At beginning of period 682 682 682 682
Stockholder's contribution 150 - 150 -
----------------------------------------
At end of period 832 682 832 682
- --------------------------------------------------------------------------------------------------------------------

ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period - (202) - (185)
Minimum liability pension adjustments (b) (1) - (1) (17)
----------------------------------------
At end of period (1) (202) (1) (202)
----------------------------------------

Investments
At beginning of period 10 8 9 1
Unrealized gain (loss) on investments (c) - (2) 1 5
----------------------------------------
At end of period 10 6 10 6
----------------------------------------
Derivative Instruments
At beginning of period 16 11 8 5
Unrealized gain (loss) on derivative instruments (c) 14 (4) 27 9
Reclassification adjustments included in consolidated net (loss) (c) (1) (2) (6) (9)
----------------------------------------
At end of period 29 5 29 5
- -------------------------------------------------------------------------------------------------------------------

Total Accumulated Other Comprehensive Income (Loss) 38 (191) 38 (191)
- --------------------------------------------------------------------------------------------------------------------

RETAINED EARNINGS
At beginning of period 544 522 521 545
Net Income 34 44 163 206
Cash dividends declared - Common Stock (82) - (187) (162)
Cash dividends declared - Preferred Stock - - (1) (1)
Preferred securities distributions - (11) - (33)
----------------------------------------
At end of period 496 555 496 555
- --------------------------------------------------------------------------------------------------------------------

TOTAL COMMON STOCKHOLDER'S EQUITY $ 2,207 $ 1,887 $ 2,207 $ 1,887
===================================================================================================================

CE-38

THREE MONTHS ENDED NINE MONTHS ENDED
September 30 2004 2003 2004 2003
- ------------------------------------------------------------------------------ --------- --------- --------- ---------

(a) Number of shares of common stock outstanding was 84,108,789 for all
periods presented.

(b) Because of the significant change in the makeup of the pension plan due
to the sale of Panhandle, SFAS No. 87 required a remeasurement of the
obligation at the date of sale. The remeasurement resulted in an
additional charge to Accumulated Other Comprehensive Income of
approximately $27 million ($17 million, net of tax) in 2003 as a result of
the increase in the additional minimum pension liability.

(c) Disclosure of Comprehensive Income:

Minimum pension liability adjustments, net of tax (tax benefit) of
$(1), $-, $(1) and $-, respectively (b) $ (1) $ - $ (1) $ (17)
Investments
Unrealized gain (loss) on investments, net of tax (tax benefit) of
$-, $-, $1 and $(3), respectively - (2) 1 5
Derivative Instruments
Unrealized gain (loss) on derivative instruments, net of tax (tax
benefit) of $7, $2, $14, and $(4), respectively 14 (4) 27 9
Reclassification adjustments included in consolidated net income, net
of tax (tax benefit) of $(1), $1, $(3) and $5, respectively (1) (2) (6) (9)
Net income 34 44 163 206
-------- --------- --------- --------
Total Comprehensive Income $ 46 $ 36 $ 184 $ 194
======== ========= ========= ========

THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.

CE-39

Consumers Energy Company

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CE-40

Consumers Energy Company

CONSUMERS ENERGY COMPANY
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

These interim Consolidated Financial Statements have been prepared by Consumers
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in financial statements prepared in accordance
with accounting principles generally accepted in the United States have been
condensed or omitted. Certain prior year amounts have been reclassified to
conform to the presentation in the current year. In management's opinion, the
unaudited information contained in this report reflects all adjustments of a
normal recurring nature necessary to assure the fair presentation of financial
position, results of operations and cash flows for the periods presented. The
Condensed Notes to Consolidated Financial Statements and the related
Consolidated Financial Statements should be read in conjunction with the
Consolidated Financial Statements and Notes to Consolidated Financial Statements
contained in the Consumers' Form 10-K for the year ended December 31, 2003. Due
to the seasonal nature of Consumers' operations, the results as presented for
this interim period are not necessarily indicative of results to be achieved for
the fiscal year.

1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES

CORPORATE STRUCTURE: Consumers, a subsidiary of CMS Energy, a holding company,
is a combination electric and gas utility company 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 7, 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 financial statements in conformity with
accounting principles generally accepted in the United States. 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 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, Uncertainties.

CE-41

Consumers Energy Company

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
September 30, 2004, our restricted cash on hand was $52 million. Restricted cash
primarily includes cash dedicated for repayment of bonds. It is classified as a
current asset as the payments on the related bonds occur within one year.

FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our debt
securities are classified as held-to-maturity securities and are reported at
cost. Our investments in equity securities are classified as available-for-sale
securities and are reported at fair value determined from quoted market prices.
Any unrealized gains or losses resulting from changes in fair value are reported
in equity as part of accumulated other comprehensive income. Unrealized gains or
losses are excluded from earnings unless such changes in fair value are
determined to be other than temporary. Unrealized gains or losses resulting from
changes in the fair value of our nuclear decommissioning investments are
reflected as regulatory liabilities on our Consolidated Balance Sheets. For
additional details regarding financial instruments, see Note 4, Financial and
Derivative Instruments.

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 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 September 30, 2004, we have recorded a liability to the DOE for $140 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, Uncertainties, "Other Electric Uncertainties -
Nuclear Matters."

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

In Millions
- ----------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
------------------------------------------------
September 30 2004 2003 2004 2003
- ----------------------------------------------------------------------------------------------------------------

Other income
PA 141 Return on Capital Expenditures $ 10 $ - $ 28 $ -
Electric restructuring return 2 1 5 4
All other 1 1 2 2
- ----------------------------------------------------------------------------------------------------------------
Total other income $ 13 $ 2 $ 35 $ 6
================================================================================================================

CE-42

Consumers Energy Company

In Millions
- ------------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
-------------------------------------------------
September 30 2004 2003 2004 2003
- ------------------------------------------------------------------------------------------------------------------

Other expense
Loss on CMS Energy stock $ -- $ -- $ -- $ (12)
Civic and political expenditures (1) -- (2) (1)
All other (1) (1) (2) (2)
- ------------------------------------------------------------------------------------------------------------------
Total other expense $ (2) $ (1) $ (4) $ (15)
==================================================================================================================

PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, 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.

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

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 available to the common
stockholder 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 this Note.
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 and our variable interest entities.

The following table shows our financial information by reportable segment:

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Consumers Energy Company

In Millions
- ---------------------------------------------------------------------------------------------------------------
Three Months Ended Nine Months Ended
------------------------------------------------------
September 30 2004 2003 2004 2003
- ---------------------------------------------------------------------------------------------------------------

Operating revenue
Electric $ 704 $ 714 $ 1,947 $ 1,970
Gas 171 164 1,376 1,252
Other 10 1 32 1
- ---------------------------------------------------------------------------------------------------------------
Total Operating Revenue $ 885 $ 879 $ 3,355 $ 3,223
===============================================================================================================
Net income available to common stockholder
Electric $ 49 $ 59 $ 124 $ 145
Gas (11) (19) 46 40
Other (4) (7) (8) (13)
- ---------------------------------------------------------------------------------------------------------------
Total Net Income $ 34 $ 33 $ 162 $ 172
===============================================================================================================

In Millions
- ---------------------------------------------------------------------------------------------------------------
September 30 2004 2003
- ---------------------------------------------------------------------------------------------------------------

Assets
Electric (a) $ 6,972 $ 6,551
Gas (a) 3,230 2,952
Other 2,299 728
- ----------------------------------------------------------------------------------------------------------------
Total Assets $ 12,501 $ 10,231
===============================================================================================================

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

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.

SFAS No. 144 imposes strict criteria for retention of regulatory-created assets
by requiring that such assets be probable of future recovery at each balance
sheet date. Management believes these assets are probable of future recovery.

2: UNCERTAINTIES

Several 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 and gas
operations. Such trends and uncertainties include:

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Consumers Energy Company

Environmental

- increased capital expenditures and operating expenses for Clean
Air Act compliance, and

- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability
or expense relating to the Michigan Natural Resources and
Environmental Protection Acts, Superfund, and at former
manufactured gas plant facilities.

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,

- ability to recover any of our net Stranded Costs under the
regulatory policies set by the MPSC,

- 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

- recovery of nuclear decommissioning costs,

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

- regulatory decisions concerning the RCP,

- 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 integrity rules and mandates.

Other

- pending litigation regarding PURPA qualifying facilities,

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

- other pending litigation.

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 has 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 nor denied the order's findings. The settlement
resolved the SEC investigation involving CMS Energy and CMS MST.

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Consumers Energy Company

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. A hearing on those motions
occurred on August 2, 2004 and the judge has taken the matter under advisement.
CMS Energy, Consumers, 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, 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. 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 September 30, 2004, we
have incurred $500 million in capital expenditures to comply with the EPA
regulations and anticipate that the remaining $302 million of capital
expenditures will be made between 2004 and 2011. These expenditures include
installing catalytic reduction technology at some of our coal-fired electric
plants. Based on the Customer Choice Act, beginning January 2004, an annual
return of and on these types of capital expenditures, to the extent

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Consumers Energy Company

they are above depreciation levels, is expected to be recoverable from
customers, subject to the MPSC prudency hearing.

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 purchase
nitrogen oxide emissions allowances for years 2004 through 2009. The cost of the
allowances is estimated to average $7 million per year for 2004-2006; the cost
will decrease after year 2006 with the installation of plant control technology.
The cost of the allowances is accounted for as inventory. The allowance
inventory is expensed as the coal-fired electric plants generate electricity.
The price for nitrogen oxide emissions allowances is volatile and could change
substantially.

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 would potentially 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 and nickel from
coal-fired and 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 fuel has resulted in reduced plant emissions,
lower operating costs, and flexibility in meeting future regulatory compliance
requirements. Trading our excess sulfur dioxide allowances for nitrogen oxide
allowances optimizes our overall cost of regulatory compliance by delaying
capital expenditures and minimizing regulatory uncertainty. Western coal has
reduced our overall cost of fuel and reduced the impact on us from the recent
increases in eastern coal prices.

Several bills have been introduced in the United States Congress that would
require reductions in emissions of greenhouse gases. We cannot predict whether
any federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.

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 United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. 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 changed the 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 by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.

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Consumers Energy Company

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 September 30, 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. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants.

We believe we have been performing the calculation in the manner prescribed by
the power purchase agreements, and have filed a request with the MPSC (as a
supplement to the 2004 PSCR plan case) that asks the MPSC to review this issue
and to confirm that our method of performing the calculation is correct. We
filed a motion to dismiss the lawsuit in the Ingham County Circuit Court due to
the pending request at the MPSC concerning the PSCR plan case. In February 2004,
the judge ruled on the motion and deferred to the primary jurisdiction of the
MPSC. This ruling resulted in a dismissal of the circuit court case without
prejudice. In October 2004, the ALJ in the PSCR plan case issued a Proposal for
Decision concluding that we have been correctly administering the energy charge
calculation methodology that is specified in the power purchase agreements.
Although only eight qualifying facilities have raised the issue, the same energy
charge methodology is used in the PPA with the MCV Partnership and in
approximately 20 additional power purchase agreements with us, representing a
total of 1,670 MW of electric capacity. 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 matter.

ELECTRIC RESTRUCTURING MATTERS

ELECTRIC RESTRUCTURING LEGISLATION: In June 2000, the Michigan legislature
passed electric utility restructuring legislation known as the Customer Choice
Act. This Act:

- allows all customers to choose their electric generation supplier
effective January 1, 2002,

- provides for a one-time five percent residential electric rate
reduction,

- froze all electric rates through December 31, 2003, and
established a rate cap for residential customers through at least
December 31, 2005, and a rate cap for small commercial and
industrial customers through at least December 31, 2004,

- allows deferred recovery of annual capital expenditures in excess
of depreciation levels and certain other expenses incurred prior
to and during the rate freeze-cap period, including the cost of
money,

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Consumers Energy Company

- allows for the use of Securitization bonds to refinance qualified
costs,

- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the Act,

- requires Michigan utilities to join a FERC-approved RTO or sell
their interest in transmission facilities to an independent
transmission owner,

- requires Consumers, Detroit Edison, and AEP to expand jointly
their available transmission capability by at least 2,000 MW, and

- establishes a market power supply test that, if not met, may
require transferring control of generation resources in excess of
that required to serve retail sales requirements.

The following summarizes our status under the last three provisions of the
Customer Choice Act. First, we chose to sell our interest in our transmission
facilities to an independent transmission owner to comply with the Customer
Choice Act. For additional details regarding the sale of the transmission
facility, see "Transmission Sale" within this Note. Second, in July 2002, the
MPSC issued an order approving our plan to achieve the increased transmission
capacity required under the Customer Choice Act. We have completed the
transmission capacity projects identified in the plan and have submitted
verification of this fact to the MPSC. We believe we are in full compliance.
Lastly, in September 2003, the MPSC issued an order finding that we are in
compliance with the market power supply test set forth in the Customer Choice
Act.

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 October 2004, alternative electric
suppliers are providing 877 MW of load. This amount represents 11 percent of the
total distribution load and an increase of 45 percent compared to October 2003.

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

- Securitization,

- Stranded Costs,

- implementation costs,

- security costs,

- Section 10d(4) Regulatory Assets, and

- transmission rates.

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Consumers Energy Company

The following chart summarizes our filings with the MPSC. For additional details
related to these proceedings, see the related sections within this Note.

- -----------------------------------------------------------------------------------------------------------------
Year(s) Years Requested
Proceeding Filed Covered Amount Status
- -----------------------------------------------------------------------------------------------------------------

Securitization 2003 N/A $1.083 billion MPSC denied our request to issue
additional Securitization bonds.

Stranded Costs 2002-2004 2000-2003 $137 million (a) MPSC ruled that we experienced zero
Stranded Costs for 2000 through 2001,
which we are appealing. Filings for
2002 and 2003 in the amount of $116
million are pending MPSC approval.

Implementation Costs 1999-2004 1997-2003 $91 million (b) MPSC allowed $68 million for the
years 1997-2001, plus $20 million for
the cost of money through 2003.
Implementation cost filings for 2002
and 2003 in the amount of $8 million,
which includes the cost of money
through 2003, are still pending MPSC
approval.

Security Costs 2004 2001-2005 $25 million MPSC approved the $25 million
requested for recovery. As of
September 30, 2004, we have recorded
$21 million of costs incurred as a
regulatory asset.

Section 10d(4) 2004 2001-2005 $628 million Filed with the MPSC in October 2004.
Regulatory Assets
===================================================================================================================

(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. If Clean Air Act costs are not
recovered through the Section 10d(4) Regulatory Asset case, Stranded Costs
requested would total $304 million.

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

Securitization: The Customer Choice Act allows for the use of Securitization
bonds to refinance certain qualified costs. Since Securitization involves
issuing bonds secured by a revenue stream from rates collected directly from
customers to service the bonds, Securitization bonds typically have a higher
credit rating than conventional utility corporate financing. In 2000 and 2001,
the MPSC issued orders authorizing us to issue Securitization bonds. We issued
our first Securitization bonds in late 2001. Securitization resulted in:

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Consumers Energy Company

- lower interest costs, and

- longer amortization periods for the securitized assets.

We will recover the repayment of principal, interest, and other expenses
relating to the bond issuance through a Securitization charge and a tax charge
that began in December 2001. These charges are subject to an annual true up
until one year before the last scheduled bond maturity date, and no more than
quarterly thereafter. The December 2004 true up filed with the MPSC in October
2004, is expected to modify the total Securitization and related tax charges
from 1.718 mills per kWh to 1.735 mills per kWh. There will be no impact on
customer bills from Securitization for most of our electric customers until the
Customer Choice Act rate cap period expires, and an electric rate case is
processed. Securitization charge collections, $38 million for the nine months
ended September 30, 2004, and $37 million for the nine months ended September
30, 2003, are remitted to a trustee. Securitization charge collections are
restricted to the repayment of the principal and interest on the Securitization
bonds and payment of the ongoing expenses of Consumers Funding. Consumers
Funding is legally separate from Consumers. The assets and income of Consumers
Funding, including the securitized property, are not available to creditors of
Consumers or CMS Energy.

In March 2003, we filed an application with the MPSC seeking approval to issue
additional Securitization bonds. In June 2003, the MPSC issued a financing order
authorizing the issuance of Securitization bonds in the amount of $554 million.
We filed for rehearing and clarification on a number of features in the
financing order. In October 2004, the MPSC issued an order that reversed the
June 2003 financing order and denied our request to issue additional
Securitization bonds. Clean Air Act costs, originally included in our Stranded
Cost filings, were also part of this Securitization request that was denied. The
MPSC order, however, also gave us the option to file for recovery of these costs
through a Section 10d(4) Regulatory Asset case, which we filed in October 2004.

Stranded Costs: The Customer Choice Act allows electric utilities to recover
their net Stranded Costs, without defining the term. In December 2001, the MPSC
Staff recommended a methodology, which calculated net Stranded Costs as the
shortfall between:

- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and

- the revenues received from customers under existing rates
available to cover the revenue requirement.

The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost recovery
charge. However, the MPSC has not yet approved such a charge. The MPSC has
declined to resolve numerous issues regarding the net Stranded Cost recovery
methodology in a way that would allow a reliable prediction of the level of
Stranded Costs. As a result, we have not recorded regulatory assets to recognize
the future recovery of such costs.

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Consumers Energy Company

The following table outlines our applications filed with the MPSC and the status
of recovery for these costs:

In Millions
- ------------------------------------------------------------------------------------------------------------------
Requested, without recovery of Requested, with recovery of
Clean Air Act costs through the Clean Air Act costs through the
approval of Section 10d(4) approval of Section 10d(4) MPSC ordered
Year Year Regulatory Assets, including cost Regulatory Assets, including recoverable
Filed Incurred of money cost of money amount
- ------------------------------------------------------------------------------------------------------------------

2002 2000 $ 26 $12 $ -
2002 2001 46 9 -
2003 2002 104 47 Pending
2004 2003 128 69 Pending
==================================================================================================================

We are currently in the process of appealing the MPSC orders regarding Stranded
Costs for 2000 and 2001 with the Michigan Court of Appeals and the Michigan
Supreme Court. In June 2004, the MPSC conducted hearings for our 2002 Stranded
Cost application. In July 2004, the ALJ issued a Proposal for Decision in our
2002 net Stranded Cost case, which recommended that the MPSC find that we
incurred net Stranded Costs of $12 million. This recommendation includes the
cost of money through July 2004 and excludes Clean Air Act costs.

Hearings for our 2003 Stranded Cost application were conducted in August 2004.
The MPSC Staff issued a position on our 2003 net Stranded Cost application,
which resulted in a Stranded Cost calculation of $52 million. This amount
includes the cost of money, but excludes Clean Air Act costs. We cannot predict
how the MPSC will rule on our requests for recoverability of 2002 and 2003
Stranded Costs or whether the MPSC will adopt a Stranded Cost recovery method
that will offset fully any associated margin loss from ROA.

Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines our
applications filed with the MPSC and the status of recovery for these costs:

In Millions
- -------------------------------------------------------------------------------------------------------------------
Recoverable, including
(b) cost of money through
Year Filed Year Incurred Requested Disallowed Allowed 2003
- -------------------------------------------------------------------------------------------------------------------

1999 1997 & 1998 $20 $5 $15 $22
2000 1999 30 5 25 33
2001 2000 25 5 20 24
2002 2001 8 - 8 9
2003 & 2004 (a) 2002 7 Pending Pending Pending
2004 2003 1 Pending Pending Pending
===================================================================================================================

(a) On March 31, 2004, we requested additional 2002 implementation cost recovery
of $5 million related to our former participation in the development of the
Alliance RTO. This cost has been expensed; therefore, the amount is not included
as a regulatory asset.

(b) Amounts include the cost of money through the year prior to the year filed.

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Consumers Energy Company

In addition to seeking MPSC approval for these costs, we are pursuing
authorization at the FERC for the MISO to reimburse us for approximately $8
million for implementation costs related to our former participation in the
development of the Alliance RTO. Included in this amount is $5 million pending
approval by the MPSC as part of 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. We cannot
predict the outcome of the appeal process or the amount, if any, we will collect
for Alliance RTO development costs.

The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. As of
September 30, 2004, we incurred and deferred as a regulatory asset $92 million
of implementation costs, which includes $25 million associated with the cost of
money. We believe the implementation costs and associated cost of money are
fully recoverable in accordance with the Customer Choice Act.

In June 2004, following an appeal and remand of initial MPSC orders relating to
1999 implementation costs, the MPSC authorized the recovery of all previously
approved implementation costs for the years 1997 through 2001 totaling $88
million. This total includes the cost of money through 2003. Additional carrying
costs will be added until collection occurs. The implementation costs will be
recovered through surcharges over 36-month collection periods and phased in as
applicable rate caps expire. In September 2004, the ALJ issued a Proposal for
Decision recommending full recovery of the requested 2002 and 2003
implementation costs. We cannot predict the amount, if any, the MPSC will
approve as recoverable costs for these years.

Security Costs: The Customer Choice Act, as amended, allows for recovery of new
and enhanced security costs as a result of federal and state regulatory security
requirements incurred before January 1, 2006. In August 2004, the MPSC approved
a settlement agreement that authorizes full recovery of $25 million in requested
security costs over a five-year period beginning in September 2004. The amount
includes reasonable and prudent security enhancements through December 31, 2005.
All retail customers, except customers of alternative electric suppliers, will
pay these charges. As a result, in August 2004, we recorded total approved
security costs incurred to date, including the cost of money. As of September
30, 2004, we have recorded $21 million in security costs as a regulatory asset.
The following table outlines our application filed with the MPSC and the status
of recovery for these costs:

In Millions
- ---------------------------------------------------------------------------------------
Year Years Regulatory asset as of
Filed Covered Requested September 30, 2004 Allowed
- ---------------------------------------------------------------------------------------

2004 2001-2005 $25 $21 $25
=======================================================================================

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-cap periods, including
the cost of money. The section also allows deferred recovery of expenses
incurred during the rate freeze-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 in costs from 2000
through 2005 under section 10d(4). The request includes capital expenditures in
excess of depreciation, Clean Air Act costs, and other expenses related to
changes in law or governmental action incurred during the rate freeze-cap
period. Of the $628 million, $152 million relates to the cost of money. Also
included in this application is $74 million of costs that were also incorporated
in our Stranded Costs filings. We cannot predict the amount, if any, the MPSC
will

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approve as recoverable. The following table outlines our application filed with
the MPSC and the status of recovery for these costs:

In Millions
- --------------------------------------------------------------------------------
Year Years
Filed Covered Requested Allowed
- --------------------------------------------------------------------------------

2004 2000-2005 $628 Pending
================================================================================

Transmission Rates: Our application of JOATT transmission rates to customers
during past periods is under FERC review. The rates included in these tariffs
were applied to certain transmission transactions affecting both Detroit
Edison's and our transmission systems between 1997 and 2002. We believe our
reserve is sufficient to satisfy our refund obligation to any of our former
transmission customers under our former JOATT.

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 currently 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.

Under an agreement with MTH, our transmission rates are fixed by contract at
current levels through December 31, 2005, and are subject to FERC ratemaking
thereafter. However, we are subject to certain additional MISO surcharges, which
we estimate to be $10 million in 2004.

ELECTRIC RATE MATTERS

PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after outages, safety, and customer services. The MPSC order calls for financial
penalties in the form of customer credits if the standards for the duration and
frequency of outages are not met. We met or exceeded all approved standards for
year-end results for both 2002 and 2003. As of September 2004, we are in
compliance with the acceptable level of performance. We are a member of an
industry coalition that has appealed the customer credit portion of the
performance standards to the Michigan Court of Appeals. We cannot predict the
likely effects of the financial penalties, if any, nor can we predict the
outcome of the appeal. Likewise, we cannot predict our ability to meet the
standards in the future or the cost of future compliance.

POWER SUPPLY COSTS: We were required to provide backup service to ROA customers
on a best efforts basis. In October 2003, we provided notice to the MPSC that we
would terminate the provision of backup service in accordance with the Customer
Choice Act, effective January 1, 2004.

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. As we did in
2004, 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, approximately 101
percent is expected to be met from owned electric generating plants and
long-term power purchase contracts, and approximately 10 percent from short-term
contracts, options for physical deliveries, and other agreements. As of
September 30, 2004, we have purchased capacity and energy contracts partially
covering the estimated reserve margin requirements for 2004 through 2007. As a
result, we have recognized an asset of $13 million for unexpired capacity and
energy

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contracts. As of October 2004, the total premium costs of electric capacity and
energy contracts for 2004 is expected to be approximately $12 million.

PSCR: As a result of meeting the transmission capability expansion requirements
and the market power test, as discussed within this Note, we have met the
requirements under the Customer Choice Act to return to the PSCR process. The
PSCR process provides for the reconciliation of actual power supply costs with
power supply revenues. This process assures recovery of all reasonable and
prudent power supply costs actually incurred by us. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. In October 2004,
the ALJ issued a Proposal for Decision, which recommended approval of our 2004
PSCR factor, with minor adjustments. The PSCR factor recommended for approval
includes nitrogen oxide emissions allowance costs and requested transmission
costs, less a minor adjustment. We estimate the recovery of increased power
supply costs from large commercial and industrial customers to be approximately
$32 million in 2004.

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 all other customers. Unless we receive an order from the MPSC, we
expect to self-implement this 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.

OTHER ELECTRIC UNCERTAINTIES

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,
through two wholly owned subsidiaries, the following assets related to the MCV
Partnership and the MCV Facility:

- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and

- CMS Holdings holds, through the FMLP, 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 7, Implementation of New Accounting Standards.

Our consolidated retained earnings include undistributed earnings from the MCV
Partnership of $244 million at September 30, 2004 and $238 million at September
30, 2003.

Power Supply Purchases from the MCV Partnership: Our annual obligation to
purchase capacity from the MCV Partnership is 1,240 MW through the term of the
PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's
availability, a levelized average capacity charge of 3.77 cents per kWh, and a
fixed energy charge. We also pay a variable energy charge based on our average
cost of coal consumed for all kWh delivered. Effective January 1999, we reached
a settlement agreement with the

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MCV Partnership that capped capacity payments made on the basis of availability
that may be billed by the MCV Partnership at a maximum 98.5 percent availability
level.

Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.

In 1992, we recognized a loss and established a liability for the present value
of the estimated future underrecoveries of power supply costs under the PPA
based on the MPSC cost recovery orders. We estimate that 51 percent of the
actual cash underrecoveries for 2004 will be charged to the PPA liability, with
the remaining portion charged to operating expense as a result of our 49 percent
ownership in the MCV Partnership. The remaining liability associated with the
loss totaled $6 million at September 30, 2004. We will expense all cash
underrecoveries directly to income once the PPA liability is depleted. We expect
the PPA liability to be depleted in late 2004.

If the MCV Facility's generating availability remains at the maximum 98.5
percent level, our cash underrecoveries associated with the PPA could be as
follows:

In Millions
- -----------------------------------------------------------------------------------------
2004 2005 2006 2007
- -----------------------------------------------------------------------------------------

Estimated cash underrecoveries at 98.5% $ 56 $ 56 $ 55 $ 39

Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
=========================================================================================

Beginning January 1, 2004, the rate freeze for large industrial customers was no
longer in effect and we returned to the PSCR process. Under the PSCR process, we
will recover from our customers the approved capacity and fixed energy charges
based on availability, up to an availability cap of 88.7 percent as established
in previous MPSC orders.

Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility:
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be impacted negatively.

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.

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Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges based on the MCV Facility's actual
availability up to the 98.5 percent cap. After September 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 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. 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.

Resource Conservation Plan: In February 2004, we filed the RCP with the MPSC
that is intended to help conserve natural gas and thereby improve our investment
in the MCV Partnership. This plan seeks approval to:

- dispatch the MCV Facility based on natural gas market prices
without increased costs to electric customers,

- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and

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

The RCP 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. This decrease in the quantity of high-priced natural gas consumed
by the MCV Facility will benefit Consumers' ownership interest in the MCV
Partnership. The amount of PPA capacity and fixed energy payments recovered from
retail electric customers would remain capped at 88.7 percent. Therefore,
customers will not be charged for any increased power supply costs, if they
occur. Consumers and the MCV Partnership have reached an agreement that the MCV
Partnership will reimburse Consumers for any incremental power costs incurred to
replace the reduction in power dispatched from the MCV Facility. In August 2004,
several qualifying facilities sought and obtained a stay of the RCP proceeding
from the Ingham County Circuit Court after their previous attempt to intervene
in the proceeding was denied by the MPSC. In an attempt to resolve this
intervention issue as quickly as possible, the MPSC issued an order permitting
the qualifying facilities to participate as intervenors. As a result, the Ingham
County Circuit Court stay was lifted and hearings were completed in October
2004. The MPSC has decided to dispense with a Proposal for Decision from the
presiding ALJ and will issue a decision directly. We cannot predict if or when
the MPSC will approve the RCP.

The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
20 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Historically, natural gas prices have been
volatile. Presently, there is no consensus in the marketplace on the price or
range of future prices of natural gas. Even with an 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 of our
investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.

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 $9 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

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the outcome of these proceedings; therefore, the above refund (net of
approximately $16 million of deferred expenses) has not been recognized in
year-to-date 2004 earnings.

NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates
for Big Rock and Palisades assume that each plant site will eventually be
restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
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 each plant 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.
The Palisades cost estimate assumes the plant will be safely stored and
subsequently decommissioned.

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.

However, based on current projections, the current level of funds provided by
the trusts is not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation, as discussed
below in "Nuclear Matters" within this Note. We will also seek additional relief
from the MPSC.

In the case of 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 will fall short of the
amount needed to complete the decommissioning by $26 million. At this point in
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.

In the case of Palisades, excluding additional nuclear fuel storage costs due to
the DOE's failure to accept this spent fuel on schedule, we have concluded that
the existing surcharge needs 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. We cannot predict what effect the application and
announcement may have on the MPSC request.

NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor
vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. 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

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begins removing the spent nuclear fuel by 2010.

The NRC and the MDEQ continue to find all decommissioning activities at Big Rock
are being performed in accordance with applicable regulations including license
requirements.

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
September 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.

Our Palisades plant is currently undergoing a regularly scheduled refueling
outage. In conjunction with this scheduled outage, we have completed inspection
of all 54 nuclear reactor vessel head penetrations. Small cracks were identified
in the welds on two of the 45 control rod drive penetration nozzles. No external
primary coolant system leakage or damage to the reactor head material was noted.
Sections of the two penetrations have been removed and replaced. Post-weld
testing, restoration of the support attachments, and reactor head installation
on the vessel are in progress and are expected to be complete by mid-November.
The total outage extension caused by the weld cracks will be approximately four
weeks. The plant is expected to return to service by the end of November.

We expect to have sufficient power at all times to meet our load requirements
from our other plants or purchase arrangements. These replacement power
requirements could increase the cost of power by an estimated $1.6 million
(pretax) per week during an extended refueling outage. Of this estimated amount,
approximately $0.6 million per week is not recoverable from our customers. The
preliminary estimate of the cost of repair to the reactor vessel is $5 million.

Our ability to make off-system sales may also be affected by an extension of the
refueling outage. However, until all repairs are made, there can be no assurance
of the length and effect of the outage on our operations and consolidated
earnings.

The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage
pool capacity. We are using dry casks for temporary onsite storage. As of
September 30, 2004, we have loaded 22 dry casks with spent nuclear fuel.

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 in the first quarter of 2005.

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.

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In October 2004, we filed a response to the DOE's motion and our motion for
summary judgment on liability. The motions are expected to be heard in late 2004
or early 2005. 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, by December 2004, an application to the NRC for a license
to begin construction of the repository. The application and review process is
estimated to take several years.

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.

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 where 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.

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COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
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 our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.

Coal Supply and Transportation: We have entered into coal supply contracts with
various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements, we are
obligated to take physical delivery of the coal and make payment based upon the
contract terms. Our coal supply contracts expire through 2006, and total an
estimated $154 million. Our coal transportation contracts expire through 2007,
and total an estimated $92 million. Long-term coal supply contracts have
accounted for approximately 60 to 90 percent of our annual coal requirements
over the last 10 years. Although future contract coverage is not finalized at
this time, we believe that it will be within the historic 60 to 90 percent
range.

Power Supply, Capacity, and Transmission: As of September 30, 2004, we had
future unrecognized commitments to purchase power transmission services under
fixed price forward contracts for 2004 and 2005 totaling $6 million. We 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 2004 through 2030 total an estimated $4.496 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant were not available to deliver electricity to us, then we would not be
obligated to make the capacity payment until the plant could deliver.

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 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. The estimates are based on discounted
2003 costs using a discount rate of three percent. The discount rate represents
a ten-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 through the MPSC approved rates charged to our customers. As of
September 30, 2004, we have recorded a regulatory liability of $40 million, net
of $41 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.

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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 MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our prudently incurred gas costs. 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
GCR Year Date Filed Order Date Recovery Status
- ----------------------------------------------------------------------------------------------------------------

2001-2002 June 2002 May 2004 $3 million $2 million has been refunded;
$1 million is included in our 2003-2004
GCR reconciliation filing

2002-2003 June 2003 March 2004 $5 million Net overrecovery includes interest
accrued through March 2003, and an
$11 million disallowance settlement
agreement.

2003-2004 June 2004 Pending $28 million Filing includes the $1 million and
$5 million GCR net overrecovery above
================================================================================================================

Net overrecovery amounts included in the table above include refunds received by
us from our suppliers and required by the MPSC to be refunded to our customers.

GCR year 2001-2002: In June 2002, we filed a reconciliation of GCR costs and
revenues for the 12-months ended March 2002. In May 2004, the MPSC issued an
order directing us to refund a net overrecovery of $3 million, plus interest. Of
this, $2 million has been refunded and the remaining $1 million is included in
our 2003-2004 GCR year reconciliation filing.

GCR year 2002-2003: In June 2003, we filed a reconciliation of GCR costs and
revenues for the 12-months ended March 2003. We proposed to recover from our
customers approximately $6 million of underrecovered gas costs, including
interest through March 2003, using a roll-in methodology. The roll-in
methodology incorporates a GCR over/underrecovery in the next GCR plan year. The
approach was approved by the MPSC in a November 2002 order.

In January 2004, intervenors filed their positions in our 2002-2003 GCR
reconciliation case. Their positions were that not all of our gas purchasing
decisions were prudent from April 2002 through March 2003 and they proposed
disallowances. In 2003, we reserved $11 million for a 2002-2003 GCR
disallowance. Interest on this amount from April 2003 through February 2004, at
our authorized rate of return, increased this amount by $1 million. The interest
was recorded as an expense in 2003. In March 2004, the parties in the case
reached a settlement agreement that resulted in a GCR disallowance of $11
million for the GCR period. The settlement agreement was approved by the MPSC in
March 2004. The prior year $6 million underrecovery and $11 million disallowance
are included in our 2003-2004 GCR year filing using the roll-in methodology. The
roll-in methodology incorporates the

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GCR underrecovery in the next GCR plan year. The approach was approved by the
MPSC in a November 2002 order.

GCR year 2003-2004: In June 2004, we filed a reconciliation of GCR costs and
revenues for the 12-months ended March 2004. We proposed to refund to our
customers $28 million of overrecovered gas cost, plus interest. We proposed that
the refund be included in the 2004-2005 GCR plan year. The overrecovery includes
the $1 million refund for the 2001-2002 GCR reconciliation case, the $11 million
refund settlement for the 2002-2003 GCR reconciliation case, as well as refunds
received by us from our suppliers and required by the MPSC to be refunded to our
customers.

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.
Recent increases in gas prices could cause us to incur costs in excess of what
can be recovered pursuant to the current ceiling price. We are permitted to
apply to the MPSC to modify the ceiling price, and will do so if necessary. In
addition, if actual, prudently incurred costs exceed the ceiling price, the
difference can be recovered through the reconciliation proceeding. Our GCR
factor for the billing month of November 2004 is $6.55 per mcf.

2003 GAS RATE CASE: On March 14, 2003, we filed an application with the MPSC for
a gas rate increase in the annual amount of $156 million. On December 18, 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
receipt of a letter signed by the Chairman of Consumers and CMS Energy which
agrees 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, Consumers' and CMS Energy's Chairman filed a letter with
the MPSC making the commitments required by the rate order.

On October 19, 2004, we filed rehearing petitions with the MPSC, which seek
clarification of the method of computing our rate of return on common equity.

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.

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Consumers Energy Company

On October 14, 2004, the MPSC issued its Opinion and Order in our gas
depreciation case. The order restores depreciation rates to the levels that were
in effect prior to the issuance of the December 18, 2003 interim gas rate order.
The final order further 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.

On October 19, 2004, we filed a rehearing petition with the MPSC, which seeks to
have book depreciation rates restored to the level set forth in the MPSC's prior
interim gas rate relief order.

GAS TITLE TRACKING FEES AND SERVICES: In September 2002, the FERC issued an
order rejecting our filing to assess certain rates for non-physical gas title
tracking services we provide. In December 2003, the FERC ruled that no refunds
were at issue and we reversed a $4 million reserve related to this matter. In
January 2004, three companies filed with the FERC for clarification or rehearing
of the FERC's December 2003 order. In April 2004, the FERC issued its Order
Granting Clarification. In that Order, the FERC indicated that its December 2003
order was in error. It directed us to file within 30 days a fair and equitable
title-tracking fee and to make refunds, with interest, to customers based on the
difference between the accepted fee and the fee paid. In response to the FERC's
April 2004 order, we filed a Request for Rehearing in May 2004. The FERC issued
an Order Granting Rehearing for Further Consideration in June 2004. We expect
the FERC to issue an order on the merits of this proceeding. We believe that
with respect to the FERC jurisdictional transportation, we have not charged any
customers title transfer fees, so no refunds are due. At this time, we cannot
predict the outcome of this proceeding.

OTHER UNCERTAINTIES

In addition to the matters disclosed within this Note, we 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.

CE-64

Consumers Energy Company

3: FINANCINGS AND CAPITALIZATION

Long-term debt is summarized as follows:

In Millions
- ------------------------------------------------------------------------------------------------------------
September 30, 2004 December 31, 2003
- ------------------------------------------------------------------------------------------------------------

First mortgage bonds $ 2,283 $ 1,483
Senior notes 813 1,254
Bank debt and other 356 469
Securitization bonds 406 426
FMLP debt 296 -
----------------------------------------------
Principal amounts outstanding 4,154 3,632
Current amounts (148) (28)
Net unamortized discount (20) (21)
- ------------------------------------------------------------------------------------------------------------
Total Long-term debt $ 3,986 $ 3,583
============================================================================================================

FMLP DEBT: We consolidate the FMLP in accordance with Revised FASB
Interpretation No. 46. At September 30, 2004, long-term debt of the FMLP
consists of:

In Millions
- ------------------------------------------------------------------------------------------------------------
Maturity 2004
- ------------------------------------------------------------------------------------------------------------

11.75% subordinated secured notes 2005 $ 70
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
- ------------------------------------------------------------------------------------------------------------
Total amount outstanding $ 296
============================================================================================================

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.

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

Principal Issue/Retirement
(In millions) Interest Rate Date Maturity Date
- ------------------------------------------------------------------------------------------------------------

DEBT ISSUANCES
FMB $ 150 4.40% August 2004 August 2009
FMB 300 5.00% August 2004 February 2012
FMB 350 5.50% August 2004 August 2016
- ------------------------------------------------------------------------------------------------------------
Total debt issuances $ 800
============================================================================================================
DEBT RETIREMENTS
FMLP debt $ 115 11.75% July 2004 July 2004
Long-term bank debt 140 Variable August 2004 March 2009
Senior notes 141 6.50% September 2004 June 2018
Senior notes 300 6.00% September 2004 March 2005
- ------------------------------------------------------------------------------------------------------------
Total debt retirements $ 696
============================================================================================================

Issuance costs associated with the 2004 FMB issuances total $5 million and are
being amortized ratably over the lives of the related debt. Call premiums
associated with 2004 debt retirements totaled

CE-65

Consumers Energy Company

$13 million and are being amortized ratably over the lives of the newly issued
debt.

In September 2004, we issued $30 million of 3.375 percent Limited Obligation
Revenue Bonds. Consequently, we redeemed $30 million of 5.8 percent Limited
Obligation Revenue Bonds in October 2004.

DEBT MATURITIES: At September 30, 2004, the aggregate annual maturities for
long-term debt for the three months ending December 31, 2004 and the next four
years are:

In Millions
- --------------------------------------------------------------------------------
Payments Due
- --------------------------------------------------------------------------------
December 31 2004 2005 2006 2007 2008
- --------------------------------------------------------------------------------

Long-term debt $ 38 $ 118 $ 478 $ 59 $ 504
================================================================================

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 first mortgage bonds 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 first mortgage bonds
to be issued solely as collateral for other long-term securities.

SHORT-TERM FINANCINGS: At September 30, 2004, we had a $500 million secured
revolving credit facility with banks, which expires July 31, 2007. At September
30, 2004, $25 million of letters of credit were issued and outstanding under
this facility and $475 million was available for general corporate purposes,
working capital, and letters of credit. The MCV Partnership had a $50 million
working capital facility available.

FIRST MORTGAGE BONDS: We secure our first mortgage bonds 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.

CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly
of leased service vehicles and office furniture. As of September 30, 2004,
capital lease obligations totaled $62 million. 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 September 30, 2004, finance lease obligations totaled $285
million, which represents the third-party portion of the MCV Partnership's
finance lease obligation.

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 $50 million of receivables at September 30, 2004 and we
sold $254 million at September 30, 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.

CE-66

Consumer Energy Company

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

In Millions
- --------------------------------------------------------------------------------
Nine Months Ended September 30 2004 2003
- --------------------------------------------------------------------------------

Net cash flow as a result of A/R financing $ (247) $ (71)
Collections from customers $ 3,542 $ 3,379
================================================================================

DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
September 30, 2004, we had $348 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 order, which
included a $190 million annual dividend cap. For the nine months ended September
30, 2004, we paid $187 million in common stock dividends to CMS Energy.

FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENT
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 beginning 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 tables describe our guarantees at September 30, 2004:

In Millions
- ---------------------------------------------------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount Provision (a)
- ---------------------------------------------------------------------------------------------------------

Standby letters of credit Various Various $ 25 $ - $ -
Surety bonds Various Various 5 - -
Nuclear insurance retrospective premiums Various Various 134 - -
=========================================================================================================

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

Events That Would Require
Guarantee Description How Guarantee Arose Performance
- -------------------------------------------------------------------------------------------------------------

Standby letters of credit Normal operations of coal power Noncompliance with
plants environmental regulations

Natural gas transportation Nonperformance

Self-insurance requirement Nonperformance

Nuclear plant closure Nonperformance

Surety bonds Normal operating activity, permits Nonperformance
and license

Nuclear insurance retrospective Normal operations of nuclear plants Call by NEIL and Price-Anderson
premiums Act for nuclear incident
=============================================================================================================

CE-67

Consumer Energy Company

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 carrying
amount of all long-term financial instruments, except as shown below,
approximates fair value. Our held-to-maturity investments consist of debt
securities held by the MCV Partnership totaling $140 million as of September 30,
2004. These securities represent funds restricted primarily for future lease
payments and are classified as Other Assets on the 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. For additional details, see Note 1, Corporate Structure and
Accounting Policies.

In Millions
- ------------------------------------------------------------------------------------------------------------------
September 30 2004 2003
- ------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain (Loss) Cost Value Gain (Loss)
- ------------------------------------------------------------------------------------------------------------------

Long-term debt (a) $ 4,134 $ 4,267 $ (133) $ 3,559 $ 3,677 $ (118)
Long-term debt - related parties (b) 506 515 (9) - - -
Trust Preferred Securities (b) - - - 490 497 (7)
Available-for-sale securities:
Common stock of CMS Energy (c) 10 22 12 10 17 7
SERP 17 21 4 17 20 3
Nuclear decommissioning
investments (d) 431 551 120 450 553 103
==================================================================================================================

(a) Includes current maturities of $148 million at September 30, 2004 and $28
million at September 30, 2003. Settlement of long-term debt is generally not
expected until maturity.

(b) We determined that we are not the primary beneficiary of our trust preferred
security structures. Accordingly, those entities have been deconsolidated as of
December 31, 2003 and are reflected in Long-term debt - related parties on the
Consolidated Balance Sheets. For additional details, see Note 7, Implementation
of New Accounting Standards.

(c) As of September 30, 2004, we held 2.4 million shares of CMS Energy Common
Stock.

(d) Our unrealized gains and losses on nuclear decommissioning investments are
reflected as regulatory liabilities.

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,

CE-68

Consumer Energy Company

fail to perform under the agreements. We minimize such risk by performing
financial credit reviews using, among other things, publicly available credit
ratings of such counterparties.

Contracts used to manage interest rate and commodity price risk 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 of the
contract 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 the
fair value of a derivative (that is, gains or losses) are reported either in
earnings or accumulated other comprehensive income depending on whether the
derivative qualifies for special hedge accounting treatment.

For derivative instruments to qualify for hedge accounting under SFAS No. 133,
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 immediately
recognized 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. We use a combination of quoted market prices and mathematical
valuation models to determine fair value of those contracts requiring derivative
accounting. The ineffective portion, if any, of all hedges is recognized in
earnings.

The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives 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, as defined by
SFAS No. 133, 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, as defined by SFAS No.
133, for the coal that we purchase. If active markets develop in the future, we
may be required to account for these contracts as derivatives. The
mark-to-market impact on earnings related to these contracts could be material
to the financial statements.

The MISO is scheduled to begin the Midwest energy market on March 1, 2005, which
will include day-ahead and real-time energy market information for the MISO's
participants. We are presently evaluating what impacts, if any, this market
development will have on the determination of whether an active energy market
exists in the state of Michigan.

CE-69

Consumers Energy Company

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

In Millions
- ---------------------------------------------------------------------------------------------------------------------

September 30 2004 2003
- ---------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain Cost Value Gain (Loss)
- ---------------------------------------------------------------------------------------------------------------------

Gas contracts $ 2 $ 5 $ 3 $ 3 $ - $ (3)
Derivative contracts associated with
Consumers' investment in the MCV Partnership:
Prior to consolidation - - - - 10 10
After consolidation:
Gas fuel contracts - 80 80 - - -
Gas fuel futures and swaps - 92 92 - - -
======================================================================================================================

The fair value of our derivative contracts is included in Derivative
Instruments, Other Assets, or Other Liabilities on our Consolidated Balance
Sheets. The fair value of derivative contracts associated with our investment in
the MCV Partnership for 2003 is included in Investments - Midland Cogeneration
Venture Limited Partnership on our Consolidated Balance Sheets.

ELECTRIC CONTRACTS: Our electric utility business may use purchased electric
call option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods. As of September 30, 2004 and September 30, 2003, we did not
have any purchased electric call options outstanding that were accounted for as
derivatives.

GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, 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 September 30, 2004, we held fixed-priced
weather-based gas supply call options and fixed-price gas supply put options.

INTEREST RATE RISK CONTRACTS: We frequently use interest rate swaps to hedge the
risk associated with forecasted interest payments on variable-rate debt and to
reduce the impact of interest rate fluctuations. These interest rate swaps are
generally designated as cash flow hedges. As such, we record changes in the fair
value of these contracts in accumulated other comprehensive income unless the
swaps are sold. As of September 30, 2004 and September 30, 2003, we did not have
any interest rate swaps outstanding.

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 its long-term natural gas contracts, which do not
contain volume optionality, qualify under SFAS No. 133 for the normal purchases
and normal sales exception. Therefore, these contracts are currently not
recognized at fair value on the balance sheet. Should significant changes in the
level of the MCV Facility operational dispatch or purchases of long-term gas
occur, the MCV Partnership would be required to re-evaluate its

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Consumers Energy Company

accounting treatment for these long-term gas contracts. This re-evaluation may
result in recording mark-to-market activity on some contracts, which could add
to earnings volatility.

At September 30, 2004, the MCV Partnership had six long-term gas contracts that
contained both an option and forward component. Because of the option component,
these contracts do not qualify for the normal purchases and sales exception and
are 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 or losses will be recorded each quarter. At
September 30, 2004, the MCV Partnership also held three long-term gas contracts
that were previously accounted for as derivatives but qualified for the normal
purchases and sales exception starting in the fourth quarter of 2002. At that
time, the fair value of these contracts was frozen and is being amortized over
the remaining life of the contracts. For the nine months ended September 30,
2004, we recorded a $5 million net gain associated with the MCV Partnership's
long-term gas fuel 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 2004 to 2007.

Gas Fuel Futures and Swaps: To manage market risks associated with the
volatility of natural gas prices, the MCV Partnership maintains a gas hedging
program. 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 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. At September 30, 2004, the MCV Partnership held gas
fuel futures and swaps.

These financial instruments are accounted for as derivatives under SFAS No. 133.
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 under SFAS No. 133. Therefore, the
mark-to-market gains and losses from these cost mitigation activities are
recorded in earnings each quarter.

As of September 30, 2004, we have recorded a cumulative net gain of $30 million,
net of tax, in accumulated other comprehensive income 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 October 2004 to December 2009, of which $17
million of this gain is expected to be reclassified as an increase to earnings
during the next 12 months. In addition, for the nine months ended September 30,
2004, we recorded a net gain of $21 million in earnings from hedging activities
related to natural gas requirements for the MCV Facility operations and a net
gain of $1 million in earnings from the MCV Partnership's cost mitigation
activities.

CE-71

Consumers Energy Company

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,

- health care and life insurance benefits under OPEB,

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

- a defined contribution 401(k) plan.

Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.

As of September 30, 2004, we have recorded a prepaid pension asset of $369
million, $20 million of which is in Other current assets on our Consolidated
Balance Sheets.

OPEB: 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." In 1994, the MPSC authorized recovery of the electric
utility portion of these costs over 18 years and in 1996, the MPSC authorized
recovery of the gas utility portion of these costs over 16 years. We have made
contributions of $47 million to our 401(h) and VEBA trust funds in 2004. We plan
to make additional contributions of $15 million in 2004.

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

In Millions
- -------------------------------------------------------------------------------
Pension
Three Months Ended Nine Months Ended
- -------------------------------------------------------------------------------
September 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------

Service cost $ 10 $ 10 $ 29 $ 29
Interest expense 17 18 53 55
Expected return on plan assets (26) (20) (80) (61)
Amortization of:
Net loss 3 2 10 7
Prior service cost 1 1 4 5
-------------------------------------
Net periodic pension cost $ 5 $ 11 $ 16 $ 35
===============================================================================

CE-72

Consumers Energy Company

In Millions
- -------------------------------------------------------------------------------
OPEB
Three Months Ended Nine Months Ended
- -------------------------------------------------------------------------------
September 30 2004 2003 2004 2003
- -------------------------------------------------------------------------------

Service cost $ 4 $ 5 $ 13 $ 14
Interest expense 14 15 41 46
Expected return on plan assets (11) (10) (34) (30)
Amortization of:
Net loss 3 5 9 14
Prior service cost (2) (2) (6) (5)
----------------------------------
Net periodic postretirement benefit cost $ 8 $ 13 $ 23 $ 39
===============================================================================

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 reduction of OPEB cost of $6 million for the three months ended September 30,
2004, $17 million for the nine months ended September 30, 2004, and an expected
total reduction of $23 million for 2004. The reduction of $23 million includes
$7 million in capitalized OPEB costs. For additional details, see Note 7,
Implementation of New Accounting Standards.

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 do so. We have legal obligations to
remove some of our assets, including our nuclear plants, at the end of their
useful lives.

Before adopting this standard, we classified the removal cost of assets included
in the scope of SFAS No. 143 as part of the reserve for accumulated
depreciation. For these assets, the removal cost of $448 million that was
classified as part of the reserve at December 31, 2002, was reclassified in
January 2003, in part, as a:

- $364 million ARO liability,

- $134 million regulatory liability,

- $42 million regulatory asset, and

- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.

We are reflecting a regulatory asset and liability as required by SFAS No. 71
for regulated entities 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

CE-73

Consumers Energy Company

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, 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.

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

September 30, 2004 In Millions
- ---------------------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- ---------------------------------------------------------------------------------------------------------------------

Palisades - decommission plant site 1972 Palisades nuclear plant $500
Big Rock - decommission plant site 1962 Big Rock nuclear plant 51
JHCampbell intake/discharge water line 1980 Plant intake/discharge water line -
Closure of coal ash disposal areas Various Generating plants coal ash areas -
Closure of wells at gas storage fields Various Gas storage fields -
Indoor gas services equipment relocations Various Gas meters located inside structures -
=====================================================================================================================

September 30, 2004 In Millions
- -------------------------------------------------------------------------------------------------------------------------
ARO Liability ARO
------------- Cash flow Liability
ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 9/30/04
- -------------------------------------------------------------------------------------------------------------------------

Palisades - decommission $249 $268 $ - $ - $16 $60 $344
Big Rock - decommission 61 35 - (32) 10 22 35
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - (2) 4 - 54
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
-----------------------------------------------------------------------------------

Total $364 $358 $ - $(34) $30 $82 $436
=========================================================================================================================

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 2, Uncertainties, "Other Electric Uncertainties - Nuclear
Plant Decommissioning."

Reclassification of certain types of Cost of Removal: Beginning in December
2003, the SEC requires the quantification and reclassification of the estimated
cost of removal obligations arising from other than legal obligations. These
cost of removal obligations have been accrued through depreciation

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Consumers Energy Company

charges. We estimate that we had $1.026 billion at September 30, 2004 and $962
million at September 30, 2003 of previously accrued asset removal costs related
to our regulated operations arising from other than legal obligations. These
obligations, which were previously classified as a component of accumulated
depreciation, are now classified as regulatory liabilities in the accompanying
Consolidated Balance Sheets.

7: 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 have 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 for the first time as of and for the quarter ended
March 31, 2004. These partnerships have third-party obligations totaling $581
million at September 30, 2004. Property, plant, and equipment serving as
collateral for these obligations has a carrying value of $1.440 billion at
September 30, 2004. The creditors of these partnerships do not have recourse to
the general credit of CMS Energy.

We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company Obligated Trust Preferred
Securities totaling $490 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $506 million of long-term debt - related parties
and reflected an investment in related parties of $16 million.

We are not required to restate prior periods for the impact of this accounting
change.

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. At December 31, 2003, we elected a one-time deferral of the
accounting for the Act, as permitted by FASB Staff Position, No. SFAS 106-1.

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Consumers Energy Company

The final FASB Staff Position, No. SFAS 106-2 supersedes FASB Staff Position,
No. SFAS 106-1 and provides further accounting guidance. FASB Staff Position,
No. SFAS 106-2 states that for plans that are actuarially equivalent to Medicare
Part D, employers' measures of accumulated postretirement benefit obligations
and postretirement benefit costs should reflect the effects of the Act.

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 $6 million for the three months ended September 30,
2004, $17 million for the nine months ended September 30, 2004, and an expected
total 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 $4 million for the three months
ended September 30, 2004, $12 million for the nine months ended September 30,
2004, and an expected total net expense reduction of $16 million for 2004.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

CMS ENERGY

Quantitative and Qualitative Disclosures about Market Risk is contained in PART
I: CMS Energy Corporation's Management's Discussion and Analysis, which is
incorporated by reference herein.

CONSUMERS

Quantitative and Qualitative Disclosures about Market Risk is contained in PART
I: Consumers Energy Company's Management's Discussion and Analysis, which is
incorporated by reference herein.

ITEM 4. CONTROLS AND PROCEDURES

CMS ENERGY

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

Internal Control Over Financial Reporting: There have not been any changes in
CMS Energy's internal control over financial reporting (as such term is defined
in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.

CONSUMERS

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

Internal Control Over Financial Reporting: There have not been any changes in
Consumers' internal control over financial reporting (as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

The discussion below is limited to an update of developments that have occurred
in various judicial and administrative proceedings, many of which are more fully
described in CMS Energy's and Consumers' Forms 10-K/A for the year ended
December 31, 2003. Reference is also made to the Condensed Notes to the
Consolidated Financial Statements, in particular, Note 3, Uncertainties for CMS
Energy and Note 2, Uncertainties for Consumers, included herein for additional
information regarding various pending administrative and judicial proceedings
involving rate, operating, regulatory and environmental matters.

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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. CMS Energy will fully cooperate with the SEC in its inquiry. From 1991
through January 3, 2002, subsidiaries of CMS Energy held interests 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 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. CMS Energy provided the SEC
with a list of documents that may be responsive to its request but the SEC has
yet to indicate which documents it wishes to review.

SEC INVESTIGATION

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 nor denied the
order's findings. The settlement resolved the SEC investigation involving CMS
Energy and CMS MST. In March 2004, the SEC also filed an action against three
former employees related to round-trip trading by CMS MST. One of the
individuals has settled with the SEC. CMS Energy is currently advancing legal
defense costs for the remaining two individuals in accordance with existing
indemnification policies.

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. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to December 1, 2004,
subject to such further extensions as may be mutually agreed upon by the parties
and authorized by the Court. CMS Energy cannot predict the outcome of this
matter.

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INTEGRUM LAWSUIT

Integrum filed a complaint in Wayne County, Michigan Circuit Court in July 2003
against CMS Energy, Enterprises and APT. Integrum alleges several causes of
action against APT, CMS Energy, and Enterprises in connection with an offer by
Integrum to purchase the CMS Pipeline Assets. In addition to seeking unspecified
money damages, Integrum is seeking an order enjoining CMS Energy and Enterprises
from selling, and APT from purchasing, the CMS Pipeline Assets and an order of
specific performance mandating that CMS Energy, Enterprises, and APT complete
the sale of the CMS Pipeline Assets to APT and Integrum. A certain officer and
director of Integrum is a former officer and director of CMS Energy, Consumers,
and their subsidiaries. The individual was not employed by CMS Energy,
Consumers, or their subsidiaries when Integrum made the offer to purchase the
CMS Pipeline Assets. CMS Energy and Enterprises filed a motion to change venue
from Wayne County to Jackson County, which was granted. The case was then
dismissed with prejudice based upon plaintiff's failure to file a transfer fee
within the requisite time. Plaintiff has stated it intends to file a motion to
have the case reinstated. CMS Energy and Enterprises believe that Integrum's
claims are without merit. CMS Energy and Enterprises intend to defend vigorously
against this action but they cannot predict the outcome of this litigation.

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. 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, Inc. but is required to
indemnify Cantera Natural Gas, Inc. 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 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 conspiracy by engaging
in activities to manipulate the price of natural gas in California. The
complaint contains counts alleging violations of the Sherman Act, Cartwright Act
(a California statute), and the California Business and Profession Code relating
to unlawful, unfair and deceptive business practices. There is currently pending
in the Nevada federal district court a multi district court litigation (MDL)
matter involving 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 Sherman Act claim and
some of the defendants in the MDL matter are also defendants in the Texas-Ohio
case. Those defendants successfully argued to have the Texas-Ohio case
transferred to the MDL proceeding. The plaintiff in the Texas-Ohio case agreed
to extend the time for all defendants to answer or otherwise respond until May
28, 2004 and on that date a number of defendants filed motions to dismiss. In
order to negotiate possible dismissal and/or substitution of defendants, CMS
Energy and two other parent holding company defendants were given further
extensions to answer or otherwise respond to the complaint until November 16,
2004.

Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint
containing allegations similar to those made in the Texas-Ohio case, albeit
limited to California state law claims, was filed in California state court in
February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed
a notice to remove this action to California federal district court, which was
granted, and

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had it transferred to the MDL proceeding in Nevada. However, the
plaintiff is seeking to have the case remanded back to California and until the
issue is resolved, no further action will be taken. Another putative class
action lawsuit, Fairhaven Power Company v. Encana Power Corporation, containing
allegations similar to those made in the Texas-Ohio case, was filed in
California federal court in September 2004. CMS Energy, Enterprises, and CMS MST
are named as defendants.

Three new, virtually identical actions were filed in San Diego Superior Court in
July 2004, one by the County of Santa Clara, one by the County of San Diego and
one by the City of and County of San Francisco and the San Francisco City
Attorney (collectively the Municipal Lawsuits). Defendants, consisting of a
number of energy companies including CMS Energy, CMS MST, Cantera Natural Gas,
and Cantera Gas Company, are alleged to have engaged in false reporting of
natural gas price and volume information and sham sales to artificially inflate
natural gas retail prices in California. All three complaints allege claims for
unjust enrichment and violations of the Cartwright Act, and the San Francisco
action also alleges a claim for violation of the California Business and
Profession Code relating to unlawful, unfair and deceptive business practices.
The Municipal Lawsuits were removed to federal district court, and conditional
transfer orders were issued transferring the cases to the Nevada MDL proceeding.
Plaintiffs in each of the Municipal Lawsuits intend to seek to have the cases
remanded back to San Diego Superior Court, and they have agreed to extend the
time to answer or otherwise respond to the complaints to thirty days from the
date an order on the motion to remand is issued. Two new lawsuits were filed in
California, one a putative class action in San Diego Superior Court on behalf of
retail consumers of natural gas, and one in Alameda Superior Court on behalf of
a cooperative of public agencies engaged in the retail purchase of natural gas.
The actions are virtually identical to the Municipal Lawsuits, and the
defendants include CMS Energy, CMS MST, Cantera Natural Gas, and Cantera Gas
Company. More of such "copycat" actions may follow.

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

LEONARD FIELD DISPUTE

Pursuant to a Consent Judgment entered in Oakland County, Michigan Circuit Court
in September 2001, CMS Gas Transmission had 18 months to extract approximately
one bcf of pipeline quality natural gas held in the Leonard Field in Addison
Township. The Consent Judgment provided for an extension of that period upon
certain circumstances. CMS Gas Transmission has complied with the requirements
of the Consent Judgment. Addison Township filed a lawsuit in Oakland County
Circuit Court against CMS Gas Transmission in February 2004 alleging the Leonard
Field was discharging odors in violation of the Consent Judgment. Pursuant to a
Stipulated Order entered April 1, 2004, CMS Gas Transmission agreed to certain
undertakings to address the odor complaints and further agreed to temporarily
cease operations at the Leonard Field during the month of April 2004, the last
month provided for in the Consent Judgment. Also, Addison Township was required
to grant CMS Gas Transmission an extension to withdraw its natural gas if
certain conditions were met. Addison Township denied CMS Gas Transmission's
request for an extension on April 5, 2004. CMS Gas Transmission is pursuing its
legal remedies and filed a complaint against Addison Township in June 2004.
Addison Township has filed a counterclaim alleging CMS Gas Transmission has
failed to remove certain equipment from the Leonard Field and that odor
discharges have resulted in a diminution in surrounding property values and
consequently a loss in property tax revenues. CMS Gas Transmission cannot
predict the outcome of this matter, and unless an extension is provided, it will
be unable to extract approximately 500,000 mcf of gas remaining in the Leonard
Field.

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CMS ENERGY AND CONSUMERS

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, 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. 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. A hearing
on those motions occurred on August 2, 2004 and the judge has taken the matter
under advisement. CMS Energy, Consumers, and the individual defendants will
defend themselves vigorously but cannot predict the outcome of this litigation.

ENVIRONMENTAL MATTERS

CMS Energy, Consumers and 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, CMS Energy and Consumers
believe that it is unlikely that these actions, individually or in total, will
have a material adverse effect on their financial condition. See CMS

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Energy's and Consumers' MANAGEMENT'S DISCUSSION AND ANALYSIS and CMS Energy's
and Consumers' CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

ITEM 5. OTHER INFORMATION

A shareholder who wishes to submit a proposal for consideration at the CMS
Energy 2005 Annual Meeting pursuant to the applicable rules of the SEC must send
the proposal to reach CMS Energy's Corporate Secretary on or before December 24,
2004. In any event if CMS Energy has not received written notice of any matter
to be proposed at that meeting by March 9, 2005, the holders of the proxies may
use their discretionary voting authority on any such matter. The proposals
should be addressed to:
Corporate Secretary, CMS Energy, One Energy Plaza, Jackson, Michigan 49201.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) LIST OF EXHIBITS

(31)(a) CMS Energy Corporation's certification of the CEO pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002

(31)(b) CMS Energy Corporation's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

(31)(c) Consumers Energy Company's certification of the CEO pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002

(31)(d) Consumers Energy Company's certification of the CFO pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002

(32)(a) CMS Energy Corporation's certifications pursuant to Section
906 of the Sarbanes-Oxley Act of 2002

(32)(b) Consumers Energy Company's certifications pursuant to Section
906 of the Sarbanes-Oxley Act of 2002

(b) REPORTS ON FORM 8-K

CMS ENERGY

During the third quarter of 2004, CMS Energy filed or furnished the
following Current Reports on Form 8-K:

- 8-K furnished on August 5, 2004 covering matters pursuant to
Item 12, Results of Operations and Financial Condition
(including a Summary of Consolidated Earnings, Summarized
Comparative Balance Sheets, Summarized Statements of Cash
Flows, and a Summary of Consolidated Earnings -
Reconciliations of GAAP Net Income (Loss) to Non-GAAP
Ongoing Net Income);
- 8-K filed on August 20, 2004 covering matters pursuant to
Item 5, Other Events;
- 8-K filed on August 31, 2004 covering matters pursuant to
Item 2.01, Completion of Acquisition or Disposition of
Assets; and

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- 8-K filed on September 1, 2004 covering matters pursuant to
Item 5.02, Departure of Directors of Principal Officers;
Election of Directors; Appointment of Principal Officers

CONSUMERS

During the third quarter of 2004, Consumers filed or furnished the
following Current Reports on Form 8-K:

- 8-K furnished on August 5, 2004 covering matters pursuant to
Item 12, Results of Operations and Financial Condition
(including a Summary of Consolidated Earnings, Summarized
Comparative Balance Sheets, Summarized Statements of Cash
Flows, and a Summary of Consolidated Earnings -
Reconciliations of GAAP Net Income (Loss) to Non-GAAP
Ongoing Net Income);
- 8-K filed on August 20, 2004 covering matters pursuant to
Item 5, Other Events; and
- 8-K filed on September 1, 2004 covering matters pursuant to
Item 5.02, Departure of Directors of Principal Officers;
Election of Directors; Appointment of Principal Officers

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company or its subsidiary.

CMS ENERGY CORPORATION
(Registrant)

Dated: November 4, 2004 By: /s/ Thomas J. Webb
----------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer

CONSUMERS ENERGY COMPANY
(Registrant)

Dated: November 4, 2004 By: /s/ Thomas J. Webb
-----------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer

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EXHIBIT INDEX

EX. NO. DESCRIPTION
- ------ -----------

(31)(a) CMS Energy Corporation's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

(31)(b) CMS Energy Corporation's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002

(31)(c) Consumers Energy Company's certification of the CEO pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002

(31)(d) Consumers Energy Company's certification of the CFO pursuant
to Section 302 of the Sarbanes-Oxley Act of 2002

(32)(a) CMS Energy Corporation's certifications pursuant to Section
906 of the Sarbanes-Oxley Act of 2002

(32)(b) Consumers Energy Company's certifications pursuant to Section
906 of the Sarbanes-Oxley Act of 2002