<PAGE>

================================================================================

                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                              WASHINGTON, DC 20549

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

                                    FORM 10-K

[X]             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   FOR THE FISCAL YEAR ENDED DECEMBER 31, 2006
                                       OR
[ ]           TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
              FOR THE TRANSITION PERIOD FROM           TO


<Table>
<Caption>
COMMISSION         REGISTRANT; STATE OF INCORPORATION;                IRS EMPLOYER
FILE NUMBER        ADDRESS; AND TELEPHONE NUMBER                      IDENTIFICATION NO.
-----------        -----------------------------------                ------------------
<S>                <C>                                                <C>
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
</Table>


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


<Table>
<Caption>
                                                        NAME OF EACH EXCHANGE
REGISTRANT              TITLE OF CLASS                  ON WHICH REGISTERED
----------              --------------                  ---------------------
<S>                     <C>                             <C>
CMS Energy Corporation  Common Stock, $.01 par value    New York Stock Exchange
CMS ENERGY TRUST I      7.75% Quarterly Income          New York Stock Exchange
                        Preferred Securities
CONSUMERS ENERGY        Preferred Stocks, $100 par      New York Stock Exchange
  COMPANY               value: $4.16 Series, $4.50
                        Series
</Table>


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

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

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

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

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

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

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

Indicate by check mark whether the Registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer (as defined in Exchange Act Rule
12b-2).

CMS ENERGY CORPORATION:  Large accelerated filer [X] Accelerated filer [ ]
Non-accelerated filer [ ]

CONSUMERS ENERGY COMPANY:  Large accelerated filer [ ] Accelerated filer [ ]
Non-accelerated filer [X]

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

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

The aggregate market value of CMS Energy voting and non-voting common equity
held by non-affiliates was $2.853 billion for the 220,508,564 CMS Energy Common
Stock shares outstanding on June 30, 2006 based on the closing sale price of
$12.94 for CMS Energy Common Stock, as reported by the New York Stock Exchange
on such date.

There were 223,255,864 shares of CMS Energy Common Stock outstanding on February
20, 2007. On February 20, 2007, CMS Energy held all voting and non-voting common
equity of Consumers.

Documents incorporated by reference: CMS Energy's proxy statement and Consumers'
information statement relating to the 2007 annual meeting of shareholders to be
held May 18, 2007, is incorporated by reference in Part III, except for the
compensation and human resources committee report and audit committee report
contained therein.

================================================================================

<PAGE>

                             CMS Energy Corporation
                                       And
                            Consumers Energy Company

                       Annual Reports on Form 10-K to the
                       Securities and Exchange Commission
                               For the Year Ended
                                December 31, 2006

This combined Form 10-K is separately filed by CMS Energy Corporation and
Consumers Energy Company. Information in this combined Form 10-K relating to
each individual registrant is filed by such registrant on its own behalf.
Consumers Energy Company makes no representation regarding information relating
to any other companies affiliated with CMS Energy Corporation other than its own
subsidiaries.

                                TABLE OF CONTENTS


<Table>
<Caption>
                                                                             PAGE
                                                                             ----
<S>        <C>                                                               <C>
Glossary   ...............................................................      3


PART I:


Item 1.    Business.......................................................      9
Item 1A.   Risk Factors...................................................     26
Item 1B.   Unresolved Staff Comments......................................     33
Item 2.    Properties.....................................................     33
Item 3.    Legal Proceedings..............................................     33
Item 4.    Submission of Matters to a Vote of Security Holders............     37


PART II:


Item 5.    Market for Registrant's Common Equity, Related Stockholder          38
           Matters and Issuer Purchases of Equity Securities..............
Item 6.    Selected Financial Data........................................     38
Item 7.    Management's Discussion and Analysis of Financial Condition and     38
           Results of Operations..........................................
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk.....     39
Item 8.    Financial Statements and Supplementary Data....................     40
Item 9.    Changes in and Disagreements With Accountants on Accounting and   CO-1
           Financial Disclosure...........................................
Item 9A.   Controls and Procedures........................................   CO-1
Item 9B.   Other Information..............................................   CO-6


PART III:


Item 10.   Directors, Executive Officers and Corporate Governance.........   CO-7
Item 11.   Executive Compensation.........................................   CO-7
Item 12.   Security Ownership of Certain Beneficial Owners and Management    CO-8
           Related Stockholder Matters....................................
Item 13.   Certain Relationships and Related Transactions, and Director      CO-8
           Independence...................................................
Item 14.   Principal Accountant Fees and Services.........................   CO-8


PART IV:


Item 15.   Exhibits, Financial Statement Schedules........................   CO-8
</Table>




                                        2

<PAGE>

                                    GLOSSARY

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



<Table>
<S>                        <C>

ABATE....................  Association of Businesses Advocating Tariff
                           Equity
ABO......................  Accumulated Benefit Obligation. The liabilities
                           of a pension plan based on service and pay to
                           date. This differs from the Projected Benefit
                           Obligation that is typically disclosed in that it
                           does not reflect expected future salary
                           increases.
AFUDC....................  Allowance for Funds Used During Construction
ALJ......................  Administrative Law Judge
AMT......................  Alternative minimum tax
AOCI.....................  Accumulated Other Comprehensive Income
AOCL.....................  Accumulated Other Comprehensive Loss
APB......................  Accounting Principles Board
APB Opinion No. 18.......  APB Opinion No. 18, "The Equity Method of
                           Accounting for Investments in Common Stock"
APT......................  Australian Pipeline Trust
ARO......................  Asset retirement obligation
Attorney General.........  Michigan Attorney General
Bay Harbor...............  a residential/commercial real estate area located
                           near Petoskey, Michigan. In 2002, CMS Energy sold
                           its interest in Bay Harbor.
bcf......................  One billion cubic feet of gas
Big Rock.................  Big Rock Point nuclear power plant, owned by
                           Consumers
Bluewater Pipeline.......  Bluewater Pipeline, a 24.9-mile pipeline that
                           extends from Marysville, Michigan to Armada,
                           Michigan
Board of Directors.......  Board of Directors of CMS Energy
Btu......................  British thermal unit
CEO......................  Chief Executive Officer
CFO......................  Chief Financial Officer
CFTC.....................  Commodity Futures Trading Commission
CKD......................  Cement Kiln Dust
Clean Air Act............  Federal Clean Air Act, as amended
CMS Energy...............  CMS Energy Corporation, the parent of Consumers
                           and Enterprises
CMS Energy Common Stock
  or common stock........  Common stock of CMS Energy, par value $.01 per
                           share
CMS Electric and Gas.....  CMS Electric and Gas Company, a subsidiary of
                           Enterprises
CMS ERM..................  CMS Energy Resource Management Company, formerly
                           CMS MST, a subsidiary of Enterprises
CMS Field Services.......  CMS Field Services, Inc., formerly a wholly owned
                           subsidiary of CMS Gas Transmission. The sale of
                           this subsidiary closed in July 2003.
CMS Gas Transmission.....  CMS Gas Transmission Company, a wholly owned
                           subsidiary of Enterprises
CMS Generation...........  CMS Generation Co., a wholly owned subsidiary of
                           Enterprises
CMS Holdings.............  CMS Midland Holdings Company, a subsidiary of
                           Consumers
CMS International
  Ventures...............  CMS International Ventures LLC, a subsidiary of
                           Enterprises
CMS Midland..............  Midland Cogeneration Venture Group II, LLC,
                           successor to CMS Midland Inc., formerly a
                           subsidiary of Consumers that had a 49 percent
                           ownership interest in the MCV Partnership
</Table>

                                        3

<PAGE>

<Table>
<S>                        <C>
CMS Midland Holdings
  Company................  CMS Midland Holdings Company, a subsidiary of
                           Consumers that has a 46 percent ownership
                           interest in First Midland Limited Partnership and
                           a 35 percent lessor interest in the MCV Facility
CMS MST..................  CMS Marketing, Services and Trading Company, a
                           wholly owned subsidiary of Enterprises, whose
                           name was changed to CMS ERM effective January
                           2004
CMS Oil and Gas..........  CMS Oil and Gas Company, formerly a subsidiary of
                           Enterprises
Consumers................  Consumers Energy Company, a subsidiary of CMS
                           Energy
Court of Appeals.........  Michigan Court of Appeals
CPEE.....................  Companhia Paulista de Energia Eletrica, in which
                           CMS International Ventures owns a 94 percent
                           interest
CT Mendoza...............  The 540 MW natural gas-fired power plant located
                           in Argentina, in which CMS International Ventures
                           owns a 92.6 percent interest
Customer Choice Act......  Customer Choice and Electricity Reliability Act,
                           a Michigan statute enacted in June 2000
DCCP.....................  Defined Company Contribution Plan
Detroit Edison...........  The Detroit Edison Company, a non-affiliated
                           company
DIG......................  Dearborn Industrial Generation, LLC, an indirect
                           wholly owned subsidiary of CMS Energy
DOE......................  U.S. Department of Energy
DOJ......................  U.S. Department of Justice
Dow......................  The Dow Chemical Company, a non-affiliated
                           company
DTE Energy...............  DTE Energy Company, a non-affiliated company
EISP.....................  Executive Incentive Separation Plan
EITF.....................  Emerging Issues Task Force
EITF Issue 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................  The 1,200 MW hydro power plant located in
                           Argentina, in which CMS Generation holds a 17.2
                           percent ownership interest
Ensenada.................  The 128 MW natural gas-fired power plant located
                           in Argentina, in which CMS International Ventures
                           owns 100 percent interest
Entergy..................  Entergy Corporation, a non-affiliated company
Enterprises..............  CMS Enterprises Company, a subsidiary of CMS
                           Energy
EPA......................  U.S. Environmental Protection Agency
EPS......................  Earnings per share
Exchange Act.............  Securities Exchange Act of 1934, as amended
FASB.....................  Financial Accounting Standards Board
FASB Interpretation No.
  46(R)..................  Revised FASB Interpretation No. 46, Consolidation
                           of Variable Interest Entities
FERC.....................  Federal Energy Regulatory Commission
FIN 47...................  FASB Interpretation No. 47, Accounting for
                           Conditional Asset Retirement Obligations
FIN 48...................  FASB Interpretation No. 48, Uncertainty in Income
                           Taxes
First Mortgage Bond
  Indenture..............  The indenture dated as of September 1, 1945
                           between Consumers and JPMorgan Chase Bank, N.A.
                           (ultimate successor to City Bank Farmers Trust
                           Company), as Trustee, and as amended and
                           supplemented
FMB......................  First Mortgage Bonds
FMLP.....................  First Midland Limited Partnership, a partnership
                           that holds a lessor interest in the MCV Facility
                           and an indirect subsidiary of Consumers
</Table>

                                        4

<PAGE>

<Table>
<S>                        <C>
FSP......................  FASB Staff Position
FTR......................  Financial transmission right
GAAP.....................  Generally Accepted Accounting Principles
GasAtacama...............  GasAtacama Holding Limited, a limited liability
                           partnership that manages GasAtacama S.A., which
                           includes an integrated natural gas pipeline and
                           electric generating plant located in Argentina
                           and Chile and Atacama Finance Company, in which
                           CMS International Ventures owns a 50 percent
                           interest
GCR......................  Gas cost recovery
Goldfields...............  A pipeline business located in Australia, in
                           which CMS Energy formerly held a 39.7 percent
                           ownership interest
GVK......................  GVK Facility, a 250 MW gas fired power plant
                           located in South Central India, in which CMS
                           Generation formerly held a 33 percent interest
GWh......................  Gigawatt-hour
IPP......................  Independent Power Producer
IRS......................  Internal Revenue Service
ISFSI....................  Independent Spent Fuel Storage Installation
ITC......................  Income tax credit
Jorf Lasfar..............  The 1,356 MW coal-fueled power plant in Morocco,
                           jointly owned by CMS Generation and ABB Energy
                           Ventures, Inc., in which CMS Generation owns a 50
                           percent interest
Jubail...................  A 240 MW natural gas cogeneration power plant
                           located in Saudi Arabia, in which CMS Generation
                           owns a 25 percent interest
kWh......................  Kilowatt-hour (a unit of energy equal to one
                           thousand watt hours)
Loy Yang.................  The 2,000 MW brown coal fueled Loy Yang A power
                           plant and an associated coal mine in Victoria,
                           Australia, in which CMS Generation formerly held
                           a 50 percent ownership interest
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......................  One thousand cubic feet of gas
MCV Facility.............  A natural gas-fueled, combined-cycle cogeneration
                           facility operated by the MCV Partnership
MCV GP II................  Midland Cogeneration Venture Group II, LLC which
                           is the successor of CMS Midland, Inc.
MCV Partnership..........  Midland Cogeneration Venture Limited Partnership
                           in which Consumers has a 49 percent interest
                           through CMS Midland, Inc.
MCV PPA..................  The Power Purchase Agreement between Consumers
                           and the MCV Partnership with a 35-year term
                           commencing in March 1990, as amended, and as
                           interpreted by the Settlement Agreement dated as
                           of January 1, 1999 between the MCV Partnership
                           and Consumers.
MD&A.....................  Management's Discussion and Analysis
MDEQ.....................  Michigan Department of Environmental Quality
METC.....................  Michigan Electric Transmission Company, LLC which
                           is owned by ITC Holding Corporation, a company
                           that operates electric transmission facilities
                           through a wholly owned subsidiary, including the
                           transmission system within Detroit Edison's
                           territory
</Table>

                                        5

<PAGE>

<Table>
<S>                        <C>
Midwest Energy Market....  An energy market developed by the MISO to provide
                           day-ahead and real-time market information and
                           centralized dispatch for market participants
MISO.....................  Midwest Independent Transmission System Operator,
                           Inc.
MMBtu....................  Million British thermal unit
Moody's..................  Moody's Investors Service, Inc.
MPSC.....................  Michigan Public Service Commission
MRV......................  Market-Related Value of Plan assets
MSBT.....................  Michigan Single Business Tax
MW.......................  Megawatt (a unit of power equal to one million
                           watts)
MWh......................  Megawatt-hour (a unit of energy equal to one
                           million watt hours)
NEIL.....................  Nuclear Electric Insurance Limited, an industry
                           mutual insurance company owned by member utility
                           companies
Neyveli..................  CMS Generation Neyveli Ltd, a 250 MW lignite-
                           fired power station located in Neyveli, Tamil
                           Nadu, India, in which CMS International Ventures
                           holds a 50 percent interest
NMC......................  Nuclear Management Company LLC, formed in 1999 by
                           Northern States Power Company (now Xcel Energy
                           Inc.), Alliant Energy, Wisconsin Electric Power
                           Company, and Wisconsin Public Service Company to
                           operate and manage nuclear generating facilities
                           owned by the four utilities
NOL......................  Net Operating Loss
NRC......................  Nuclear Regulatory Commission
NYMEX....................  New York Mercantile Exchange
OCI......................  Other Comprehensive Income
OPEB.....................  Postretirement benefit plans other than pensions
                           for retired employees
Palisades................  Palisades nuclear power plant, which is owned by
                           Consumers
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
Peabody Energy...........  Peabody Energy Corporation, a non-affiliated
                           company
Pension Plan.............  The trusteed, non-contributory, defined benefit
                           pension plan of Panhandle, Consumers and CMS
                           Energy
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
PURPA....................  Public Utility Regulatory Policies Act of 1978
RCP......................  Resource Conservation Plan
ROA......................  Retail Open Access
S&P......................  Standard & Poor's Ratings Group, a division of
                           The McGraw-Hill Companies, Inc.
SAB No. 107..............  Staff Accounting Bulletin No. 107, Share-Based
                           Payment
</Table>

                                        6

<PAGE>

<Table>
<S>                        <C>
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
SFAS No. 5...............  SFAS No. 5, "Accounting for Contingencies"
SFAS No. 13..............  SFAS No. 13, "Accounting for Leases"
SFAS No. 71..............  SFAS No. 71, "Accounting for the Effects of
                           Certain Types of Regulation"
SFAS No. 87..............  SFAS No. 87, "Employers' Accounting for Pensions"
SFAS No. 88..............  SFAS No. 88, "Employers' Accounting for
                           Settlements and Curtailments of Defined Benefit
                           Pension Plans and for Termination Benefits"
SFAS No. 98..............  SFAS No. 98, "Accounting for Leases"
SFAS No. 106.............  SFAS No. 106, "Employers' Accounting for
                           Postretirement Benefits Other Than Pensions"
SFAS No. 109.............  SFAS No. 109, "Accounting for Income Taxes"
SFAS No. 115.............  SFAS No. 115, "Accounting for Certain Investments
                           in Debt and Equity Securities"
SFAS No. 123(R)..........  SFAS No. 123 (revised 2004), "Share-Based
                           Payment"
SFAS No. 132(R)..........  SFAS No. 132 (revised 2003), "Employers'
                           Disclosures about Pensions and Other
                           Postretirement Benefits"
SFAS No. 133.............  SFAS No. 133, "Accounting for Derivative
                           Instruments and Hedging Activities, as amended
                           and interpreted"
SFAS No. 143.............  SFAS No. 143, "Accounting for Asset Retirement
                           Obligations"
SFAS No. 144.............  SFAS No. 144, "Accounting for the Impairment or
                           Disposal of Long-Lived Assets"
SFAS No. 157.............  SFAS No. 157, "Fair Value Measurement"
SFAS No. 158.............  SFAS No. 158, "Employers' Accounting for Defined
                           Benefit Pension and Other Postretirement
                           Plans -- an amendment of FASB Statements No. 87,
                           88, 106, and 132(R)"
Shuweihat................  A power and desalination plant of Shuweihat CMS
                           International Power Company, in which CMS
                           Generation holds a 20 percent interest
SLAP.....................  Scudder Latin American Power Fund
Southern Union...........  Southern Union Company, a non-affiliated company
SRLY.....................  Separate Return Limitation Year
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
</Table>

                                        7

<PAGE>

<Table>
<S>                        <C>
Takoradi.................  A 200 MW open-cycle combustion turbine crude oil
                           power plant located in Ghana, in which CMS
                           Generation owns a 90 percent interest
TAQA.....................  Abu Dhabi National Energy Company, a subsidiary
                           of Abu Dhabi Water and Electricity Authority, CMS
                           Generation's partner in the Taweelah and
                           Shuweihat projects
Taweelah.................  Al Taweelah A2, a power and desalination plant of
                           Emirates CMS Power Company, in which CMS
                           Generation holds a 40 percent interest
TGM......................  A natural gas transportation and pipeline
                           business located in Argentina, in which CMS
                           International Ventures owns a 20 percent interest
TGN......................  A natural gas transportation and pipeline
                           business located in Argentina, in which CMS Gas
                           Transmission owns a 23.54 percent interest
TRAC.....................  Terminal Rental Adjustment Clause, a provision of
                           a leasing agreement which permits or requires the
                           rental price to be adjusted upward or downward by
                           reference to the amount realized by the lessor
                           under the agreement upon sale or other
                           disposition of formerly leased property
Trunkline................  CMS Trunkline Gas Company, LLC, formerly a
                           subsidiary of CMS Panhandle Holdings, LLC
Trust Preferred
  Securities.............  Securities representing an undivided beneficial
                           interest in the assets of statutory business
                           trusts, the interests of which have a preference
                           with respect to certain trust distributions over
                           the interests of either CMS Energy or Consumers,
                           as applicable, as owner of the common beneficial
                           interests of the trusts
Union....................  Utility Workers Union of America, AFL-CIO
VEBA Trusts..............  VEBA employees' beneficiary association trusts
                           accounts established to specifically set aside
                           employer contributed assets to pay for future
                           expenses of the OPEB plan
</Table>




                                        8

<PAGE>

                                     PART I
                                ITEM 1. BUSINESS

GENERAL

CMS ENERGY

     CMS Energy was formed in Michigan in 1987 and is an energy holding company
operating through subsidiaries in the United States and in selected markets
around the world. Its two principal subsidiaries are Consumers and Enterprises.
Consumers is a public utility that provides natural gas and/or electricity to
almost 6.5 million of Michigan's 10 million residents and serves customers in
all 68 of the state's Lower Peninsula counties. Enterprises, through various
subsidiaries and affiliates, is engaged in diversified energy businesses in the
United States and in selected markets around the world. See ITEM 7. CMS ENERGY'S
MANAGEMENT'S DISCUSSION AND ANALYSIS -- EXECUTIVE OVERVIEW.

     CMS Energy's consolidated operating revenue was $6.810 billion in 2006,
$6.288 billion in 2005 and $5.472 billion in 2004. CMS Energy operates in three
business segments -- electric utility, gas utility, and enterprises. See
BUSINESS SEGMENTS later in this Item 1 for further discussion of each segment.

CONSUMERS

     Consumers was formed in Michigan in 1968 and is the successor to a
corporation organized in Maine in 1910 that conducted business in Michigan from
1915 to 1968. Consumers serves companies operating in the automotive, metal,
chemical and food products industries as well as a diversified group of other
industries. In 2006, Consumers served 1.8 million electric customers and 1.7
million gas customers.

     Consumers' consolidated operations account for a majority of CMS Energy's
total assets and income, as well as a substantial portion of its operating
revenue. Consumers' consolidated operating revenue was $5.721 billion in 2006,
$5.232 billion in 2005 and $4.711 billion in 2004.

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

     CONSUMERS' PROPERTIES -- GENERAL:  Consumers owns its principal properties
in fee, except that most electric lines and gas mains are located in public
roads or on land owned by others and are accessed by Consumers pursuant to
easements and other rights. Almost all of Consumers' properties are subject to
the lien of its First Mortgage Bond Indenture. For additional information on
Consumers' properties see BUSINESS SEGMENTS -- Consumers Electric
Utility -- Electric Utility Properties, and -- Consumers Gas Utility -- Gas
Utility Properties, below.

BUSINESS SEGMENTS

CMS ENERGY FINANCIAL INFORMATION

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

CONSUMERS FINANCIAL INFORMATION

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


                                        9

<PAGE>

CONSUMERS ELECTRIC UTILITY

  ELECTRIC UTILITY OPERATIONS

     Consumers' electric utility operating revenue was $3.302 billion in 2006,
$2.701 billion in 2005 and $2.586 billion in 2004. Consumers' electric utility
operations include the generation, purchase, distribution and sale of
electricity. At year-end 2006, it was authorized to provide service in 60 of the
68 counties of Michigan's Lower Peninsula. Principal cities served include
Battle Creek, Flint, Grand Rapids, Jackson, Kalamazoo, Midland, Muskegon and
Saginaw. Consumers' electric utility customer base includes a mix of
residential, commercial and diversified industrial customers, the largest
segment of which is the automotive industry (which comprises 5 percent of CMS
Energy's revenues). Consumers' electric utility operations are not dependent
upon a single customer, or even a few customers, and the loss of any one or even
a few of such customers is not reasonably likely to have a material adverse
effect on its financial condition.

     Consumers' electric utility operations are seasonal. The summer months
usually increase demand for electric energy, principally due to the use of air
conditioners and other cooling equipment, thereby affecting revenues. In 2006,
Consumers' electric sales were 37 billion kWh and retail open access deliveries
were 1 billion kWh, for total electric deliveries of 38 billion kWh. In 2005,
Consumers' electric sales were 35 billion kWh and retail open access deliveries
were 4 billion kWh, for total electric deliveries of 39 billion kWh.

     Consumers' 2006 summer peak demand was 8,657 MW excluding retail open
access loads and 8,883 MW including retail open access loads. For the 2005-06
winter period, Consumers' peak demand was 5,752 MW excluding retail open access
loads and 6,123 MW including retail open access loads. Based on its summer 2006
forecast, Consumers carried an 11 percent reserve margin target. However, as a
result of higher than forecasted peak loads, Consumers' ultimate reserve margin
was 6 percent compared to 15 percent in 2005. Currently, Consumers owns or
controls capacity necessary to supply approximately 108 percent of projected
firm summer peak load for summer 2007 and is in the process of securing the
additional capacity needed to meet its summer 2007 reserve margin target of 11
percent (111 percent of projected firm summer peak load). The ultimate use of
the reserve margin will depend primarily on summer weather conditions, the level
of retail open access requirements being served by others during the summer, and
any unscheduled plant outages.


                                       10

<PAGE>

  ELECTRIC UTILITY PROPERTIES

     GENERATION: At December 31, 2006, Consumers' electric generating system
consisted of the following:


<Table>
<Caption>
                                                                          2006         2006 NET
                                                                       SUMMER NET     GENERATION
                                                SIZE AND YEAR         DEMONSTRATED     (MILLIONS
NAME AND LOCATION (MICHIGAN)                   ENTERING SERVICE     CAPABILITY (MW)     OF KWH)
----------------------------                ---------------------   ---------------   ----------

<S>                                         <C>                     <C>               <C>

COAL GENERATION
  J H Campbell 1 & 2 -- West Olive........  2 Units, 1962-1967             615           4,358
  J H Campbell 3 -- West Olive............  1 Unit, 1980                   765(a)        3,712
  D E Karn -- Essexville..................  2 Units, 1959-1961             515           3,587
  B C Cobb -- Muskegon....................  2 Units, 1956-1957             312           1,844
  J R Whiting -- Erie.....................  3 Units, 1952-1953             328           2,378
  J C Weadock -- Essexville...............  2 Units, 1955-1958             306           1,865
                                                                         -----          ------
Total coal generation.....................                               2,841          17,744
                                                                         -----          ------
OIL/GAS GENERATION
  B C Cobb -- Muskegon....................  3 Units, 1999-2000(b)          183              14
  D E Karn -- Essexville..................  2 Units, 1975-1977           1,276             179
                                                                         -----          ------
Total oil/gas generation..................                               1,459             193
                                                                         -----          ------
HYDROELECTRIC
  Conventional Hydro Generation...........  13 Plants, 1906-1949            74             485
  Ludington Pumped Storage................  6 Units, 1973                  955(c)         (426)(d)
                                                                         -----          ------
Total hydroelectric.......................                               1,029              59
                                                                         -----          ------
NUCLEAR GENERATION
  Palisades -- South Haven................  1 Unit, 1971                   778           5,904
                                                                         -----          ------
GAS/OIL COMBUSTION TURBINE
  Generation..............................  7 Plants, 1966-1971            345              16
                                                                         -----          ------
Total owned generation....................                               6,452          23,916
PURCHASED AND INTERCHANGE POWER
  Capacity................................                               2,762(e)
                                                                         -----
Total.....................................                               9,214
                                                                         =====

</Table>


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

(a) Represents Consumers' share of the capacity of the J H Campbell 3 unit, net
    of 6.69 percent (ownership interests of the Michigan Public Power Agency and
    Wolverine Power Supply Cooperative, Inc.).

     (b) Cobb 1-3 are retired coal-fired units that were converted to gas-fired.
         Units were placed back into service in the years indicated.

     (c) Represents Consumers' share of the capacity of Ludington. Consumers and
              Detroit Edison have 51 percent and 49 percent undivided ownership,
         respectively, in the plant.

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

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

     In 2006, through the Midwest Energy Market, long-term purchase contracts,
options, spot market and other seasonal purchases, Consumers purchased up to
2,762 MW of net capacity from others, which amounted to 32 percent of Consumers'
total system requirements.

     DISTRIBUTION: Consumers' distribution system includes:

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


                                       11

<PAGE>

     - 4,197 miles of high-voltage distribution overhead lines operating at 23
       kilovolts and 46 kilovolts;

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

     - 55,525 miles of electric distribution overhead lines;

     - 9,586 subsurface miles of underground distribution lines; and

     - substations having an aggregate transformer capacity of 22,705,360
       kilovoltamperes.

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

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


<Table>
<Caption>
                                                             MILLIONS OF KWH
                                               ------------------------------------------
POWER GENERATED                                 2006     2005     2004     2003     2002
---------------                                ------   ------   ------   ------   ------

<S>                                            <C>      <C>      <C>      <C>      <C>

Coal.........................................  17,744   19,711   18,810   20,091   19,361
Nuclear......................................   5,904    6,636    5,346    6,151    6,358
Oil..........................................      48      225      193      242      347
Gas..........................................     161      356       38      129      354
Hydro........................................     485      387      445      335      387
Net pumped storage...........................    (426)    (516)    (538)    (517)    (486)
                                               ------   ------   ------   ------   ------
Total net generation.........................  23,916   26,799   24,294   26,431   26,321
                                               ======   ======   ======   ======   ======

</Table>


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


<Table>
<Caption>
                                                           COST PER MILLION BTU
                                                  --------------------------------------
FUEL CONSUMED                                      2006    2005    2004     2003    2002
-------------                                     -----   -----   ------   -----   -----

<S>                                               <C>     <C>     <C>      <C>     <C>

Coal............................................  $2.09   $1.78   $ 1.43   $1.33   $1.34
Oil.............................................   8.68    5.98     4.68    3.92    3.49
Gas.............................................   8.92    9.76    10.07    7.62    3.98
Nuclear.........................................   0.24    0.34     0.33    0.34    0.35
All Fuels(a)....................................   1.72    1.64     1.26    1.16    1.19
</Table>


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

(a) Weighted average fuel costs.

     Consumers has four generating plant sites that burn coal. In 2006, these
plants produced a combined total of 17,744 million kWh of electricity, which
represents 75 percent of Consumers' 23,648 million kWh baseload supply, the
capacity used to serve a constant level of customer demand. These plants burned
8.9 million tons of coal in 2006. On December 31, 2006, Consumers had on hand a
53-day supply of coal.

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

     Consumers has entered into coal supply contracts with various suppliers and
associated rail transportation contracts for its coal-fired generating stations.
Under the terms of these agreements, Consumers is obligated to take physical
delivery of the coal and make payment based upon the contract terms. Consumers'
coal supply contracts expire through 2010, and total an estimated $515 million.
Its coal transportation contracts expire through 2009, and total an estimated
$214 million. Long-term coal supply contracts have accounted for approximately
60 to 90 percent of Consumers' annual coal requirements over the last 10 years.
Consumers believes that, at present, it will be within the historic 60 to 90
percent range.

     At December 31, 2006, Consumers had future unrecognized commitments to
purchase capacity and energy under long-term power purchase agreements with
various generating plants. These contracts require monthly capacity payments
based on the plants' availability or deliverability. These payments for 2007
through 2030 total an

                                       12

<PAGE>

estimated $15.815 billion. This amount may vary depending upon plant
availability and fuel costs. Consumers is obligated to pay capacity charges
based only on the amount of capacity available at a given time, whether or not
power is delivered to Consumers.

     Consumers owns Palisades, an operating nuclear power plant located near
South Haven, Michigan. In May 2001, with the approval of the NRC, Consumers
transferred its authority to operate Palisades to NMC. During 2006, Palisades'
net generation was 5,904 million kWh, constituting 25 percent of Consumers'
baseload supply. Palisades' nuclear fuel supply responsibilities are under NMC's
control as agent for Consumers. New fuel contracts are being written as NMC
agreements. Consumers/NMC currently have sufficient contracts in place to supply
100 percent of the uranium concentrates and conversion services and 100 percent
of the enrichment services requirements for the 2007 reload. A contract for
uranium concentrates is in place to supply approximately 6 percent of the 2008
reload requirements. Two contracts for conversion services are in place to
supply approximately 39 percent of the 2008 reload requirements and a contract
for enrichment services is in place to supply approximately 32 percent of the
2008 reload requirements. Consumers has a contract for nuclear fuel fabrication
services in place for reloads in 2007 through 2013.

     In July 2006, Consumers reached an agreement to sell Palisades to Entergy
and for Entergy to assume ownership and responsibility for the Big Rock ISFSI.
As part of the transaction, Entergy will sell Consumers 100 percent of
Palisades' output up to its current capacity of 798 MW under a 15-year power
purchase agreement. The sale is subject to various regulatory approvals,
including but not limited to the MPSC's approval of the power purchase
agreement, the FERC's approval for Entergy to sell power to Consumers under the
power purchase agreement and the NRC's approval of the transfer of the operating
license to Entergy. Consumers expects to complete the sale in 2007.

     The Nuclear Waste Policy Act of 1982 made the federal government
responsible for the permanent disposal of spent nuclear fuel and high-level
radioactive waste by 1998. The DOE has not arranged for storage facilities and
it does not expect to receive spent nuclear fuel for storage in 2007 or the near
term. Palisades currently has spent nuclear fuel that exceeds its temporary on-
site storage pool capacity. Therefore, Consumers is storing spent nuclear fuel
in NRC-approved steel and concrete vaults known as "dry casks." For additional
information on disposal of nuclear fuel and Consumers' use of dry casks, see
ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER
ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC
UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 7. CONSUMERS' MANAGEMENT'S
DISCUSSION AND ANALYSIS -- OUTLOOK -- OTHER ELECTRIC BUSINESS
UNCERTAINTIES -- NUCLEAR MATTERS AND ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS.

CONSUMERS GAS UTILITY

  GAS UTILITY OPERATIONS

     Consumers' gas utility operating revenue was $2.374 billion in 2006, $2.483
billion in 2005 and $2.081 billion in 2004. Consumers' gas utility operations
purchase, transport, store, distribute and sell natural gas. As of December 31,
2006, it was authorized to provide service in 47 of the 68 counties in
Michigan's Lower Peninsula. Principal cities served include Bay City, Flint,
Jackson, Kalamazoo, Lansing, Pontiac and Saginaw, as well as the suburban
Detroit area, where nearly 900,000 of Consumers' gas customers are located.
Consumers' gas utility operations are not dependent upon a single customer, or
even a few customers, and the loss of any one or even a few of such customers is
not reasonably likely to have a material adverse effect on its financial
condition.

     Consumers' gas utility operations are seasonal. Consumers injects natural
gas into storage during the summer months for use during the winter months when
the demand for natural gas is higher. Peak demand usually occurs in the winter
due to colder temperatures and the resulting increased demand for heating fuels.
In 2006, deliveries of natural gas sold by Consumers and by other sellers who
deliver natural gas to customers (including the MCV Partnership) through
Consumers' pipeline and distribution network totaled 313 bcf.


                                       13

<PAGE>

     GAS UTILITY PROPERTIES: Consumers' gas distribution and transmission system
located throughout Michigan's Lower Peninsula consists of:

     - 26,295 miles of distribution mains;

     - 1,671 miles of transmission lines;

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

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

     GAS SUPPLY: In 2006, Consumers purchased 67 percent of the gas it delivered
from United States producers and 26 percent from Canadian producers. Authorized
suppliers in the gas customer choice program supplied the remaining 7 percent of
gas that Consumers delivered.

     Consumers' firm gas transportation agreements are with ANR Pipeline
Company, Great Lakes Gas Transmission, L.P., Trunkline Gas Co., Panhandle
Eastern Pipe Line Company, and Vector Pipeline. Consumers uses these agreements
to deliver gas to Michigan for ultimate deliveries to market. Consumers' firm
transportation and city gate arrangements are capable of delivering over 95
percent of Consumers' total gas supply requirements. As of December 31, 2006,
Consumers' portfolio of firm transportation from pipelines to Michigan is as
follows:



<Table>
<Caption>
                                                             VOLUME
                                                        (DEKATHERMS/DAY)    EXPIRATION
                                                        ----------------    ----------

<S>                                                     <C>               <C>      <C>

ANR Pipeline Company..................................        50,000      March    2017
Great Lakes Gas Transmission, L.P. ...................       100,000      March    2007
Great Lakes Gas Transmission, L.P (starting
  04/01/07)...........................................       100,000      March    2011
Great Lakes Gas Transmission, L.P. ...................        50,000      March    2017
Trunkline Gas Co. ....................................       290,000      October  2008
Panhandle Eastern Pipe Line Company (starting
  04/01/07)...........................................        50,000      October  2007
Panhandle Eastern Pipe Line Company (starting
  04/01/08)...........................................        50,000      October  2008
Panhandle Eastern Pipe Line Company...................        50,000      October  2008
Vector Pipeline.......................................        50,000      March    2007
Vector Pipeline (starting 04/01/07)...................        50,000      March    2012
</Table>



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

ENTERPRISES

     Enterprises, through various subsidiaries and equity investments, is
engaged in domestic and international energy businesses including independent
power production, electric distribution, and natural gas transmission, storage
and processing. Enterprises' operating revenue was $1.135 billion in 2006,
$1.110 billion in 2005 and $808 million in 2004. See ITEM 7. CMS ENERGY'S
MANAGEMENT'S DISCUSSION AND ANALYSIS -- EXECUTIVE OVERVIEW.

NATURAL GAS TRANSMISSION

     CMS Gas Transmission was formed in 1988 and owns, develops and manages
domestic and international natural gas facilities. In 2006, CMS Gas
Transmission's operating revenue was $18 million.

     In June 2003, CMS Gas Transmission sold Panhandle to Southern Union
Panhandle Corp., a newly formed entity owned by Southern Union. Southern Union
Panhandle Corp. purchased all of Panhandle's outstanding capital

                                       14

<PAGE>

stock for approximately $582 million in cash and 3.15 million shares of Southern
Union common stock. Southern Union Panhandle Corp. also assumed approximately
$1.166 billion in debt.

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

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

     NATURAL GAS TRANSMISSION PROPERTIES: CMS Gas Transmission has a total of
265 miles of gathering and transmission pipelines located in the state of
Michigan, with a daily capacity of 0.75 bcf. At December 31, 2006, CMS Gas
Transmission had nominal processing capabilities of approximately 0.33 bcf per
day of natural gas in Michigan. Enterprises has entered into a binding letter of
intent to sell these assets.

     At December 31, 2006, CMS Gas Transmission had ownership interests in the
following international pipelines:


<Table>
<Caption>
LOCATION                                             OWNERSHIP INTEREST (%)   MILES OF PIPELINES
--------                                             ----------------------   ------------------

<S>                                                  <C>                      <C>

Argentina..........................................           23.5                   3,362
Argentina-to-Brazil................................             20                     262
Argentina-to-Chile.................................             50                     707
</Table>


     Enterprises has entered into a binding letter of intent to sell its
interest in the Argentina-to-Brazil pipeline, and CMS Energy has announced that
it will conduct an auction sale in 2007 to sell its interest in the Argentina-
to-Chile pipeline. The remaining pipelines in Argentina are subject to a
potential sale to the government of Argentina.

INDEPENDENT POWER PRODUCTION

     CMS Generation was formed in 1986. It invests in, acquires, develops,
constructs and operates non-utility power generation plants in the United States
and abroad. In 2006, the independent power production business segment's
operating revenue was $540 million.

     INDEPENDENT POWER PRODUCTION PROPERTIES: As of December 31, 2006, CMS
Energy had ownership interests in operating independent power plants totaling
8,809 gross MW or 4,308 net MW (net MW reflects that portion of the gross
capacity in relation to CMS Energy's ownership interest). In 2007, Enterprises
plans to exit the international marketplace. In 2007, Enterprises entered into a
definitive purchase and sale agreement or a binding letter of intent to sell its
ownership interests in its power production properties in the Middle East,
Africa, India and Argentina. CMS Energy announced that it will conduct an
auction sale in 2007 to sell its interests in its power production facilities in
Chile and Jamaica.


                                       15

<PAGE>

     The following table details CMS Energy's interest in independent power
plants as of year-end 2006:


<Table>
<Caption>
                                                                                            PERCENTAGE OF
                                                                                            GROSS CAPACITY
                                                                                           UNDER LONG-TERM
                                                     OWNERSHIP INTEREST   GROSS CAPACITY       CONTRACT
LOCATION                             FUEL TYPE               (%)               (MW)              (%)
--------                             ---------       ------------------   --------------   ---------------

<S>                             <C>                  <C>                  <C>              <C>

California....................  Wood                        37.8                  36             100
Connecticut...................  Scrap tire                   100                  31               0
Michigan......................  Coal                          50                  70             100
Michigan......................  Natural gas                  100                 710              42
Michigan......................  Natural gas                  100                 224               0
Michigan......................  Wood                          50                  40             100
Michigan......................  Wood                          50                  38             100
New York......................  Hydro                       17.3                  14             100
North Carolina................  Wood                          50                  50             100
Oklahoma......................  Natural gas                 6.25                 124             100
                                                                               -----
     DOMESTIC TOTAL...........                                                 1,337
                                                                               -----
Argentina.....................  Hydro                       17.2               1,320              20(a)
Argentina.....................  Natural gas                 98.5                 128              57
Argentina.....................  Natural gas/oil             92.6                 597              45
Chile.........................  Natural gas                   50                 720             100
Ghana.........................  Crude oil                     90                 224(b)          100
India.........................  Coal                          50                 250             100
Jamaica.......................  Diesel                      42.3                  63             100
Morocco.......................  Coal                          50               1,356             100(c)
Kingdom of Saudi Arabia.......  Natural gas                   25                 250             100
United Arab Emirates..........  Natural gas                   40                 777             100
United Arab Emirates..........  Natural gas                   20               1,500             100
Venezuela.....................  Gas turbine/diesel            87                 287              (d)
                                                                               -----
  INTERNATIONAL TOTAL.........                                                 7,472
                                                                               -----
TOTAL DOMESTIC AND
  INTERNATIONAL...............                                                 8,809
                                                                               =====

</Table>



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

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

(b) Conversion of the Takoradi power plant from single-cycle to combined-cycle
    with an increase in gross capacity from 224 MW to 341 MW has been delayed.

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

(d) SENECA is a combined generation/distribution utility that produces power for
    its sole use.

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

OIL AND GAS EXPLORATION AND PRODUCTION

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


                                       16

<PAGE>

ENERGY RESOURCE MANAGEMENT

     In 2003, CMS ERM closed its Houston, Texas office and in 2004, CMS ERM
changed its name from CMS Marketing, Services and Trading Company to CMS Energy
Resource Management Company. CMS ERM concentrates on the purchase and sale of
energy commodities in support of CMS Energy's generating facilities. In March
2004, CMS ERM discontinued its natural gas retail program as customer contracts
expired. In 2006, CMS ERM marketed approximately 44 bcf of natural gas and 1,938
GWh of electricity. Its operating revenue was $334 million in 2006, $589 million
in 2005 and $381 million in 2004.

INTERNATIONAL ENERGY DISTRIBUTION

     In October 2001, CMS Energy discontinued the operations of its
international energy distribution business. In 2002, CMS Energy discontinued new
development outside North America, which included closing all non-U.S.
development offices. In 2003, due to the uncertainty of executing an asset sale
on acceptable terms and conditions, CMS Energy reclassified SENECA, which is its
energy distribution business in Venezuela, and CPEE, which is its energy
distribution business in Brazil, to continuing operations. In February 2007, CMS
Energy entered into a memorandum of understanding to sell SENECA. CMS Energy has
announced that it will conduct an auction sale in 2007 to sell its interest in
CPEE.

CMS ENERGY AND CONSUMERS REGULATION

     CMS Energy is a public utility holding company that was previously exempt
from registration under PUHCA of 1935. PUHCA of 1935 was repealed by the Energy
Policy Act of 2005 and replaced by PUHCA of 2005, effective February 8, 2006.
CMS Energy, Consumers and their subsidiaries are subject to regulation by
various federal, state, local and foreign governmental agencies, including those
described below.

MICHIGAN PUBLIC SERVICE COMMISSION

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

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

     RATE PROCEEDINGS: In 2005, the MPSC issued an order that established the
electric authorized rate of return on common equity at 11.15 percent. In 2006,
the MPSC issued an order that established the gas authorized rate of return on
common equity at 11.00 percent.

     MPSC REGULATORY AND MICHIGAN LEGISLATIVE CHANGES: State regulation of the
retail electric and gas utility businesses has undergone significant changes. In
2000, the Michigan Legislature enacted the Customer Choice Act. The Customer
Choice Act provides that as of January 2002, all electric customers have the
choice to buy generation service from an alternative electric supplier. The
Customer Choice Act also imposes rate reductions, rate freezes and rate caps,
which expired at the end of 2005. For additional information regarding the
Customer Choice Act, see ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND
ANALYSIS -- OUTLOOK -- ELECTRIC UTILITY BUSINESS UNCERTAINTIES -- COMPETITION
AND REGULATORY RESTRUCTURING and ITEM 7. CONSUMERS' MANAGEMENT'S DISCUSSION AND
ANALYSIS -- OUTLOOK -- ELECTRIC BUSINESS UNCERTAINTIES -- COMPETITION AND
REGULATORY RESTRUCTURING.

     Consumers transports the natural gas commodity that is sold to some
customers by competitors like gas producers, marketers and others. Pursuant to a
gas customer choice program that Consumers implemented, as of April 2003 all of
Consumers' gas customers were eligible to select an alternative gas commodity
supplier. Consumers' current GCR mechanism allows it to recover from its
customers all prudently incurred costs to purchase natural gas and transport it
to Consumers' facilities. For additional information, see ITEM 8. FINANCIAL

                                       17

<PAGE>

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

FEDERAL ENERGY REGULATORY COMMISSION

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

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

     The Energy Policy Act of 2005 has modified the FERC's traditional
responsibilities in a number of ways, which will affect both Consumers and
Enterprises. Among other things, the new law includes repeal of PUHCA of 1935,
streamlined electric transmission siting rules, measures designed to promote
wholesale competition, certain investment incentives and mandatory electric
supply reliability planning. The FERC is currently in the process of
establishing standards for ensuring a more reliable system of providing
electricity throughout North America through the increased regulation of
generation owners and operators, load serving entities and others.

NUCLEAR REGULATORY COMMISSION

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

OTHER REGULATION

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

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


                                       18

<PAGE>

CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE

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

     CMS Energy has significant possible liability for its obligations
associated with Bay Harbor. For additional information, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 (CONTINGENCIES) OF CMS ENERGY'S
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

     Consumers has installed and is currently installing modern emission
controls at its electric generating plants and has converted and is converting
electric generating units to burn cleaner fuels. Consumers expects that the cost
of future environmental compliance, especially compliance with clean air laws,
will be significant because of EPA regulations and proposed regulations
regarding nitrogen oxide, particulate-related emissions, and mercury. These
regulations will require Consumers to make significant capital expenditures.

     Consumers is in the process of closing older ash disposal areas at two
plants. Construction, operation, and closure of a modern solid waste disposal
area for ash can be expensive, because of strict federal and state requirements.
In order to significantly reduce ash field closure costs, Consumers has worked
with others to use bottom ash and fly ash as part of temporary and final cover
for ash disposal areas instead of native materials, in cases where such use of
bottom ash and fly ash is compatible with environmental standards. To reduce
disposal volumes, Consumers sells coal ash for use as a Portland cement
replacement in concrete products, as a filler for asphalt, as feedstock for the
manufacture of Portland cement and for other environmentally compatible uses.
The EPA has announced its intention to develop new nationwide standards for ash
disposal areas. Consumers intends to work through industry groups to help ensure
that any such regulations require only the minimum cost necessary to adhere to
standards that are consistent with protection of the environment.

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

     Like most electric utilities, Consumers has PCB in some of its electrical
equipment. During routine maintenance activities, Consumers identified PCB as a
component in certain paint, grout and sealant materials at the Ludington Pumped
Storage facility. Consumers removed and replaced part of the PCB material.
Consumers has proposed a plan to the EPA to deal with the remaining materials
and is waiting for a response from the EPA.

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

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

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

CMS ENERGY AND CONSUMERS COMPETITION

ELECTRIC COMPETITION

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


                                       19

<PAGE>

     In the wholesale electricity markets, Consumers competes with other
wholesale suppliers, marketers and brokers. Electric competition in the
wholesale markets increased significantly since 1996 due to FERC Order 888.
While Consumers is still active in wholesale electricity markets, wholesale for
resale transactions by Consumers generated an immaterial amount of Consumers'
2006 revenues from electric utility operations. Consumers believes future loss
of wholesale for resale transactions will be insignificant.

     Price is the principal method of competition for electric generation
services. The Customer Choice Act gives all electric customers the right to buy
generation service from an alternative electric supplier. In June 2004, the MPSC
granted Consumers recovery of implementation costs incurred for the Electric
Customer Choice program. In November 2004, the MPSC adopted a mechanism pursuant
to the Customer Choice Act to provide for recovery of stranded costs that occur
when customers leave Consumers' system to purchase electricity from alternative
electric suppliers. In January 2006, the MPSC approved cost-based retail open
access distribution tariffs. A significant decrease in retail electric
competition occurred in 2005 due to changes in market conditions, including
increased uncertainty and volatility in fuel commodity prices. Energy market
volatility continued into 2006. At December 31, 2006, alternative electric
suppliers were providing 300 MW of generation service to ROA customers. This
amount represents a decrease of 46 percent compared to December 31, 2005, and is
3 percent of Consumers' total distribution load. It is difficult to predict
future ROA customer trends.

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

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

     - municipalities owning or operating competing electric delivery systems;

     - customer self-generation; and

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

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

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

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

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

GAS COMPETITION

     Competition has existed for the past decade in various aspects of
Consumers' gas utility business, and is likely to increase. Competition
traditionally comes from other gas suppliers taking advantage of direct access
to Consumers' customers and from alternate fuels and energy sources, such as
propane, oil and electricity.

INSURANCE

     CMS Energy and its subsidiaries, including Consumers, maintain insurance
coverage similar to comparable companies in the same lines of business. The
insurance policies are subject to terms, conditions, limitations and

                                       20

<PAGE>

exclusions that might not fully compensate CMS Energy for all losses. A portion
of each loss is generally assumed by CMS Energy in the form of deductibles and
self-insured retentions that, in some cases, are substantial. As CMS Energy
renews its policies it is possible that some of the insurance coverage may not
be renewed or obtainable on commercially reasonable terms due to restrictive
insurance markets.

     For a discussion of nuclear insurance coverage, see ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 3 OF CMS ENERGY'S NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS (CONTINGENCIES) -- OTHER CONSUMERS' ELECTRIC
UTILITY CONTINGENCIES -- NUCLEAR MATTERS and ITEM 8. FINANCIAL STATEMENTS AND
SUPPLEMENTARY DATA -- NOTE 3 OF CONSUMERS' NOTES TO CONSOLIDATED FINANCIAL
STATEMENTS (CONTINGENCIES) -- OTHER ELECTRIC CONTINGENCIES -- NUCLEAR MATTERS.
For a discussion of environmental insurance coverage, see ITEM 1.
BUSINESS -- CMS ENERGY AND CONSUMERS ENVIRONMENTAL COMPLIANCE.

EMPLOYEES

CMS ENERGY

     As of December 31, 2006, CMS Energy and its wholly owned subsidiaries,
including Consumers, had 8,640 full-time equivalent employees. Included in the
total are 3,624 employees who are covered by union contracts.

CONSUMERS

     As of December 31, 2006, Consumers and its subsidiaries had 8,026 full-time
equivalent employees. Included in the total are 3,314 full-time operating,
maintenance and construction employees and 309 full-time and part-time call
center employees who are represented by the Utility Workers Union of America.

CMS ENERGY EXECUTIVE OFFICERS (AS OF FEBRUARY 1, 2007)


<Table>
<Caption>
NAME                     AGE  POSITION                                    PERIOD
----                     ---  --------                                    ------
<S>                     <C>   <C>                                    <C>
David W. Joos.........  53    President and Chief Executive Officer
                                of CMS Energy                        2004-Present
                              Chairman of the Board, Chief
                                Executive Officer of Enterprises     2003-Present
                              President, Chief Operating Officer of
                                CMS Energy                           2001-2004
                              Chief Executive Officer of Consumers   2004-Present
                              President, Chief Operating Officer of
                                Consumers                            2001-2004
                              President, Chief Operating Officer of
                                Enterprises                          2001-2003
                              Director of CMS Energy                 2001-Present
                              Director of Consumers                  2001-Present
                              Director of Enterprises                2000-Present
</Table>

                                       21

<PAGE>

<Table>
<Caption>
NAME                     AGE  POSITION                                    PERIOD
----                     ---  --------                                    ------
<S>                     <C>   <C>                                    <C>
Thomas J. Webb........  54    Executive Vice President, Chief
                                Financial Officer of CMS Energy      2002-Present
                              Executive Vice President, Chief
                                Financial Officer of Consumers       2002-Present
                              Executive Vice President, Chief
                                Financial Officer of Enterprises     2002-Present
                              Executive Vice President, Chief
                                Financial Officer of CMS
                                Generation Co.                       2006-Present
                              Executive Vice President of CMS
                                Energy                               2002
                              Executive Vice President of Consumers  2002
                              Director of Enterprises                2002-Present
                              Director of CMS Generation             2003-Present
                              Executive Vice President, Chief
                                Financial Officer of Panhandle
                                Eastern Pipe Line Company            2002-2003
James E. Brunner*.....  54    Senior Vice President and General
                                Counsel of CMS Energy                11/2006-Present
                              Senior Vice President and General
                                Counsel of Consumers                 11/2006-Present
                              Senior Vice President of Enterprises   2006-Present
                              Senior Vice President of CMS
                                Generation                           2006-Present
                              Director of Enterprises                2006-Present
                              Senior Vice President, General
                                Counsel and Chief Compliance
                                Officer of CMS Energy                5/2006-11/2006
                              Senior Vice President, General
                                Counsel and Chief Compliance
                                Officer of Consumers                 5/2006-11/2006
                              Senior Vice President, General
                                Counsel and Interim Chief
                                Compliance Officer of Consumers      2/2006-5/2006
                              Senior Vice President and General
                                Counsel of CMS Energy                2/2006-5/2006
                              Senior Vice President and General
                                Counsel of Consumers                 2/2006-5/2006
                              Vice President and General Counsel of
                                Consumers                            7/2004-2/2006
                              Vice President of Consumers            2004
John M. Butler**......  42    Senior Vice President of CMS Energy    6/2006-Present
                              Senior Vice President of Consumers     6/2006-Present
                              Senior Vice President of Enterprises   6/2006-Present
                              Senior Vice President of CMS
                                Generation                           6/2006-Present
David G. Mengebier....  49    Senior Vice President and Chief
                                Compliance Officer of CMS Energy     11/2006-Present
                              Senior Vice President and Chief
                                Compliance Officer of Consumers      11/2006-Present
                              Senior Vice President of Enterprises   2003-Present
                              Senior Vice President of CMS Energy    2001-11/2006
                              Senior Vice President of Consumers     2001-11/2006
</Table>

                                       22

<PAGE>

<Table>
<Caption>
NAME                     AGE  POSITION                                    PERIOD
----                     ---  --------                                    ------
<S>                     <C>   <C>                                    <C>
Thomas W. Elward......  58    President, Chief Operating Officer of
                                Enterprises                          2003-Present
                              President, Chief Executive Officer of
                                CMS Generation                       2002-Present
                              Director of Enterprises                2003-Present
                              Director of CMS Generation             2002-Present
                              Senior Vice President of Enterprises   2002-2003
John G. Russell.......  49    President and Chief Operating Officer
                                of Consumers                         2004-Present
                              Executive Vice President and
                                President -- Electric & Gas of
                                Consumers                            7/2004-10/2004
                              Executive Vice President, President
                                and Chief Executive
                                Officer -- Electric of Consumers     2001-2004
Glenn P. Barba........  41    Vice President, Controller and Chief
                                Accounting Officer of CMS Energy     2003-Present
                              Vice President, Controller and Chief
                                Accounting Officer of Consumers      2003-Present
                              Vice President, Chief Accounting
                                Officer of Enterprises               2003-Present
                              Vice President and Controller of
                                Consumers                            2002-2003
</Table>


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

*  From 1993 until July of 2004, Mr. Brunner was Assistant General Counsel of
   Consumers.

** From 2002 until 2004, Mr. Butler was Global Compensation and Benefits
   Resource Center Director at The Dow Chemical Company and from 2004 until June
   of 2006, Mr. Butler was Human Resources Director, Manufacturing and
   Engineering at The Dow Chemical Company.

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

     The present term of office of each of the executive officers extends to the
first meeting of the Board of Directors after the next annual election of
Directors of CMS Energy (scheduled to be held on May 18, 2007).

CONSUMERS EXECUTIVE OFFICERS (AS OF FEBRUARY 1, 2007)


<Table>
<Caption>
NAME                     AGE  POSITION                                    PERIOD
----                     ---  --------                                    ------

<S>                     <C>   <C>                                    <C>

David W. Joos.........  53    President and Chief Executive Officer
                                of CMS Energy                        2004-Present
                              Chairman of the Board, Chief
                                Executive Officer of Enterprises     2003-Present
                              President, Chief Operating Officer of
                                CMS Energy                           2001-2004
                              Chief Executive Officer of Consumers   2004-Present
                              President, Chief Operating Officer of
                                Consumers                            2001-2004
                              President, Chief Operating Officer of
                                Enterprises                          2001-2003
                              Director of CMS Energy                 2001-Present
                              Director of Consumers                  2001-Present
                              Director of Enterprises                2000-Present
</Table>

                                       23

<PAGE>

<Table>
<Caption>
NAME                     AGE  POSITION                                    PERIOD
----                     ---  --------                                    ------

<S>                     <C>   <C>                                    <C>
Thomas J. Webb........  54    Executive Vice President, Chief
                                Financial Officer of CMS Energy      2002-Present
                              Executive Vice President, Chief
                                Financial Officer of Consumers       2002-Present
                              Executive Vice President, Chief
                                Financial Officer of Enterprises     2002-Present
                              Executive Vice President, Chief
                                Financial Officer of CMS
                                Generation                           2006-Present
                              Executive Vice President of CMS
                                Energy                               2002
                              Executive Vice President of Consumers  2002
                              Director of Enterprises                2002-Present
                              Director of CMS Generation             2003-Present
                              Executive Vice President, Chief
                                Financial Officer of Panhandle
                                Eastern Pipe Line Company            2002-2003
James E. Brunner*.....  54    Senior Vice President and General
                                Counsel of CMS Energy                11/2006-Present
                              Senior Vice President and General
                                Counsel of Consumers                 11/2006-Present
                              Senior Vice President of Enterprises   2006-Present
                              Senior Vice President of CMS
                                Generation                           2006-Present
                              Director of Enterprises                2006-Present
                              Senior Vice President, General
                                Counsel and Chief Compliance
                                Officer of CMS Energy                5/2006-11/2006
                              Senior Vice President, General
                                Counsel and Chief Compliance
                                Officer of Consumers                 5/2006-11/2006
                              Senior Vice President, General
                                Counsel and Interim Chief
                                Compliance Officer of Consumers      2/2006-5/2006
                              Senior Vice President and General
                                Counsel of CMS Energy                2/2006-5/2006
                              Senior Vice President and General
                                Counsel of Consumers                 2/2006-5/2006
                              Vice President and General Counsel of
                                Consumers                            7/2004-2/2006
                              Vice President of Consumers            2004
John M. Butler**......  42    Senior Vice President of CMS Energy    6/2006-Present
                              Senior Vice President of Consumers     6/2006-Present
                              Senior Vice President of Enterprises   6/2006-Present
                              Senior Vice President of CMS
                                Generation                           6/2006-Present
David G. Mengebier....  49    Senior Vice President and Chief
                                Compliance Officer of CMS Energy     11/2006-Present
                              Senior Vice President and Chief
                                Compliance Officer of Consumers      11/2006-Present
                              Senior Vice President of Enterprises   2003-Present
                              Senior Vice President of CMS Energy    2001-11/2006
                              Senior Vice President of Consumers     2001-11/2006
</Table>

                                       24

<PAGE>

<Table>
<Caption>
NAME                     AGE  POSITION                                    PERIOD
----                     ---  --------                                    ------

<S>                     <C>   <C>                                    <C>
John G. Russell.......  49    President and Chief Operating Officer
                                of Consumers                         2004-Present
                              Executive Vice President and
                                President -- Electric & Gas of
                                Consumers                            7/2004-10/2004
                              Executive Vice President, President
                                and Chief Executive
                                Officer -- Electric of Consumers     2001-2004
Robert A. Fenech......  59    Senior Vice President of Consumers     1997-Present
William E. Garrity....  58    Senior Vice President of Consumers     2005-Present
                              Vice President of Consumers            1999-2005
Frank Johnson.........  58    Senior Vice President of Consumers     2001-Present
                              President, Chief Executive Officer of
                                CMS Electric and Gas                 2000-2002
Paul N. Preketes......  57    Senior Vice President of Consumers     1999-Present
Glenn P. Barba........  41    Vice President, Controller and Chief
                                Accounting Officer of CMS Energy     2003-Present
                              Vice President, Controller and Chief
                                Accounting Officer of Consumers      2003-Present
                              Vice President, Chief Accounting
                                Officer of Enterprises               2003-Present
                              Vice President and Controller of
                                Consumers                            2002-2003
</Table>


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

*  From 1993 until July of 2004, Mr. Brunner was Assistant General Counsel of
   Consumers.

** From 2002 until 2004, Mr. Butler was Global Compensation and Benefits
   Resource Center Director at The Dow Chemical Company and from 2004 until June
   of 2006, Mr. Butler was Human Resources Director, Manufacturing and
   Engineering at The Dow Chemical Company.

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

     The present term of office of each of the executive officers extends to the
first meeting of the Board of Directors after the next annual election of
Directors of Consumers (scheduled to be held on May 18, 2007).

AVAILABLE INFORMATION

     CMS Energy's internet address is www.cmsenergy.com. You can access free of
charge on our Web site all of our annual reports on Form 10-K, quarterly reports
on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed
pursuant to Section 13(a) or 15(d) of the Exchange Act. Such reports are
available as soon as practical after they are electronically filed with the SEC.
Also on our Web site are our:

     - Corporate Governance Principles;

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

     - Board Committee Charters (including the Audit Committee, the Compensation
       and Human Resources Committee, the Finance Committee and the Governance
       and Public Responsibility Committee).

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

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


                                       25

<PAGE>

                              ITEM 1A. RISK FACTORS

RISKS RELATED TO CMS ENERGY

CMS ENERGY DEPENDS ON DIVIDENDS FROM ITS SUBSIDIARIES TO MEET ITS DEBT SERVICE
OBLIGATIONS.

     Due to its holding company structure, CMS Energy depends on dividends from
its subsidiaries to meet its debt obligations. Restrictions contained in
Consumers' preferred stock provisions and other legal restrictions, such as
certain terms in its articles of incorporation, limit Consumers' ability to pay
dividends or acquire its own stock from CMS Energy. As of December 31, 2006, the
most restrictive provisions in its financing documents allowed Consumers to pay
an aggregate of $300 million in dividends to CMS Energy during any year. At
December 31, 2006, Consumers had $215 million of unrestricted retained earnings
available to pay common stock dividends. If sufficient dividends are not paid to
CMS Energy by its subsidiaries, CMS Energy may not be able to generate the funds
necessary to fulfill its cash obligations, thereby adversely affecting its
liquidity and financial condition.

CMS ENERGY HAS SUBSTANTIAL INDEBTEDNESS THAT COULD LIMIT ITS FINANCIAL
FLEXIBILITY AND HENCE ITS ABILITY TO MEET ITS DEBT SERVICE OBLIGATIONS.

     As of December 31, 2006, CMS Energy had outstanding approximately $2.450
billion aggregate principal amount of indebtedness, including approximately $178
million of subordinated indebtedness relating to its convertible preferred
securities but excluding approximately $4.495 billion of indebtedness of its
subsidiaries. In May 2005, CMS Energy entered into the Sixth Amended and
Restated Credit Agreement in the amount of approximately $300 million. As of
December 31, 2006, there were approximately $98 million of letters of credit
outstanding under the Sixth Amended and Restated Credit Agreement. CMS Energy
and its subsidiaries may incur additional indebtedness in the future.

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

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

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

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

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

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

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

CMS ENERGY CANNOT PREDICT THE OUTCOME OF CLAIMS REGARDING ITS PARTICIPATION IN
THE DEVELOPMENT OF BAY HARBOR OR OTHER LITIGATION IN WHICH SUBSTANTIAL MONETARY
CLAIMS ARE INVOLVED.

     As part of the development of Bay Harbor by certain subsidiaries of CMS
Energy, which went forward under an agreement with the MDEQ, third parties
constructed a golf course and a park over several abandoned cement kiln dust
(CKD) piles, left over from the former cement plant operation on the Bay Harbor
site. Pursuant to the agreement with the MDEQ, a water collection system was
constructed to recover seep water from one of the CKD piles and CMS Energy built
a treatment plant to treat the seep water. In 2002, CMS Energy sold its interest
in Bay

                                       26

<PAGE>

Harbor, but retained its obligations under previous environmental
indemnifications entered into at the inception of the project.

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

     In February 2005, the EPA executed an Administrative Order on Consent (AOC)
to address problems at Bay Harbor, upon the consent of CMS Land Company (CMS
Land) and CMS Capital, LLC, both subsidiaries of CMS Energy. Pursuant to the
AOC, the EPA approved a Removal Action Work Plan in July 2005. Among other
things, this plan calls for the installation of collection trenches to intercept
high pH CKD leachate flow to the lake. All collection systems contemplated in
this work plan have been installed. Shoreline effectiveness monitoring is
ongoing, and CMS Land is obligated to address any observed exceedances in pH.
This may potentially include the augmentation of the collection system. In May
2006, the EPA approved a pilot carbon dioxide augmentation plan to augment the
leachate recovery system by improving pH results in the Pine Court area of the
collection system. The augmentation system was installed in June 2006.

     In February 2006, CMS Land submitted to the EPA a proposed Remedial
Investigation and Feasibility Study for the East Park CKD pile. The EPA approved
a schedule for near-term activities, which include consolidating certain CKD
materials and installing collection trenches in the East Park leachate release
area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan
and Final Engineering Design for Consolidation. CMS Energy and the MDEQ have
initiated negotiations of an AOC and to define a long-term remedy at East Park.

     The owner of one parcel of land at Bay Harbor has filed a lawsuit in Emmet
County Circuit Court against CMS Energy and several of its subsidiaries, as well
as Bay Harbor Golf Club Inc., Bay Harbor Company LLC, David C. Johnson, and
David V. Johnson, one of the developers at Bay Harbor. Several of these
defendants have demanded indemnification from CMS Energy and affiliates for the
claims made against them in the lawsuit. After a hearing in March 2006 on
motions filed by CMS Energy and other defendants, the judge dismissed various
counts of the complaint. CMS Energy will defend vigorously the existing case and
any other property damage and personal injury claims or lawsuits. In November
2006, the judge ruled against a motion to dismiss the remaining counts, and the
action is scheduled to go to trial in May 2007. CMS Land has entered into
various access, purchase and settlement agreements with several of the affected
landowners at Bay Harbor. CMS Land has purchased five unimproved lots and two
lots with houses. At this time, CMS Land believes it has all necessary access
arrangements to complete the remediation work required under the AOC.

     CMS Energy has recorded a cumulative charge of $93 million for its
obligations. An adverse outcome of this matter could, depending on the size of
any indemnification obligation or liability under environmental laws, have a
potentially significant adverse effect on CMS Energy's financial condition and
liquidity and could negatively impact CMS Energy's financial results. CMS Energy
cannot predict the ultimate cost or outcome of this matter.

     In addition to the litigation and proceedings discussed above, CMS Energy
or various of its subsidiaries are parties in other pending litigation in which
substantial monetary damages are sought. An adverse outcome in one or more of
these cases could, depending on the timing and size of any award and the
availability of insurance or reimbursement from third parties, have an adverse
effect on CMS Energy's financial condition, liquidity or future results of
operations.

CMS ENERGY RETAINS CONTINGENT LIABILITIES IN CONNECTION WITH ITS ASSET SALES.

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

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

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

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


                                       27

<PAGE>

     Many of these contingent liabilities can remain open for extended periods
of time after the sales are closed. Depending on the extent to which the buyers
may ultimately seek to enforce their rights under these contractual provisions,
and the resolution of any disputes CMS Energy may have concerning them, these
liabilities could have a material adverse effect on its financial condition,
liquidity and future results of operations. See ITEM 7. CMS ENERGY'S
MANAGEMENT'S DISCUSSION AND ANALYSIS -- EXECUTIVE OVERVIEW.

CMS ENERGY HAS MADE SUBSTANTIAL INTERNATIONAL INVESTMENTS THAT ARE SUBJECT TO
POSSIBLE NATIONALIZATION, EXPROPRIATION OR INABILITY TO CONVERT CURRENCY.

     CMS Energy's investments in selected markets around the world in electric
generating facilities, natural gas pipelines and electric distribution systems
face a number of risks inherent in acquiring, developing and owning these types
of international facilities. Although CMS Energy maintains insurance for various
risk exposures, including political risk from possible nationalization,
expropriation or inability to convert currency, it is exposed to some risks that
include local political and economic factors over which it has no control, such
as changes in foreign governmental and regulatory policies (including changes in
industrial regulation and control and changes in taxation), changing political
conditions and international monetary fluctuations. In some cases an investment
may have to be abandoned or disposed of at a loss. These factors could have a
significant adverse effect on the financial results of the affected subsidiary
and CMS Energy's financial position and results of operations.

     International investments of the type CMS Energy has made are subject to
the risk that the investments may be expropriated or that the required
agreements, licenses, permits and other approvals may be changed or terminated
in violation of their terms. These kinds of changes could result in a partial or
total loss of CMS Energy's investment.

     The local foreign currency may be devalued, the conversion of the currency
may be restricted or prohibited or other actions, such as increases in taxes,
royalties or import duties, may be taken which adversely affect the value and
the recovery of CMS Energy's investment.

CMS ENERGY'S NATURAL GAS PIPELINE AND ELECTRIC GENERATION PROJECT LOCATED IN
ARGENTINA AND CHILE MAY BE NEGATIVELY IMPACTED BY ARGENTINE GOVERNMENTAL
RESTRICTIONS PLACED ON NATURAL GAS EXPORTS TO CHILE AND THE EFFECTS OF THESE
RESTRICTIONS ON THE PROJECT'S CONTRACTS FOR THE SALE OF POWER.

     In 2004, the Argentine government authorized the restriction of exports of
natural gas to Chile, giving priority to domestic demand in Argentina. This
restriction had a harmful effect on GasAtacama's earnings since GasAtacama's
gas-fired electric generating plant is located in Chile and uses Argentine gas
for fuel. Bolivia agreed to export 4 million cubic meters of gas per day to
Argentina. With the Bolivian gas supply, Argentina relaxed its export
restrictions to GasAtacama.

     In May 2006, the Bolivian government nationalized the natural gas industry
and raised prices under its existing gas export contracts. Gas supply to
GasAtacama was restricted as Argentina and Bolivia renegotiated the price for
gas. In July 2006, Argentina agreed to increase the price it pays for gas from
Bolivia. Argentina also announced that it would recover all of this price
increase by a special tax on its gas exports. This increased the risk and cost
of GasAtacama's fuel supply.

     In August 2006, a major gas supplier notified GasAtacama that it would no
longer deliver gas to GasAtacama under the Argentine government's current
policy. In the third quarter of 2006, CMS Energy performed an impairment
analysis and recorded an impairment charge of $239 million ($169 million, net of
tax and minority interest) on its Consolidated Statements of Income (Loss). At
December 31, 2006, the carrying value of CMS Energy's investment in GasAtacama
was $117 million. This remaining value continues to be exposed to the threat of
a complete gas restriction by Argentina and the inability of GasAtacama to pass
through the increased costs associated with such a restriction to its regulated
customers. Therefore, if conditions do not improve, the result could be a
further impairment of CMS Energy's investment in GasAtacama.

     In February 2007, CMS Energy announced plans to conduct an auction to sell
GasAtacama. CMS Energy expects to complete the sale by the end of 2007.


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RISKS RELATED TO CMS ENERGY AND CONSUMERS

CMS ENERGY AND CONSUMERS HAVE FINANCING NEEDS AND THEY MAY BE UNABLE TO
SUCCESSFULLY ACCESS BANK FINANCING OR THE CAPITAL MARKETS.

     Consumers expects to incur significant costs for capital expenditures,
including future environmental regulation compliance, especially compliance with
clean air laws. See "CMS Energy and Consumers could incur significant capital
expenditures to comply with environmental standards and face difficulty in
recovering these costs on a current basis" below. As of December 31, 2006,
Consumers had incurred $688 million in capital expenditures to comply with the
federal Clean Air Act and resulting regulations and anticipate that the
remaining $147 million of capital expenditures will be made in 2007 through
2011.

     CMS Energy and Consumers may be subject to liquidity demands pursuant to
commercial commitments under guarantees, indemnities and letters of credit.
Management is actively pursuing plans to sell assets. There can be no assurances
that this business plan will be successful and failure to achieve its goals
could have a material adverse effect on CMS Energy's and Consumers' liquidity
and operations.

     CMS Energy continues to explore financing opportunities to supplement its
financial plan. These potential opportunities include: refinancing its bank
credit facilities, entering into leasing arrangements and refinancing and/or
issuing new capital markets debt, preferred stock and/or common equity. CMS
Energy cannot guarantee the capital market's acceptance of its securities or
predict the impact of factors beyond its control, such as actions of rating
agencies. If CMS Energy is unable to access bank financing or the capital
markets to incur or refinance indebtedness, there could be a material adverse
effect upon its liquidity and operations.

     Similarly, Consumers currently plans to seek funds through the capital
markets and commercial lenders. Entering into new financings is subject in part
to capital market receptivity to utility industry securities in general and to
Consumers' securities issuances in particular. Consumers cannot guarantee the
capital market's acceptance of its securities or predict the impact of factors
beyond its control, such as actions of rating agencies. If Consumers is unable
to access bank financing or the capital markets to incur or refinance
indebtedness, there could be a material adverse effect upon its liquidity and
operations.

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

PERIODIC REVIEWS OF THE VALUES OF CMS ENERGY'S AND CONSUMERS' ASSETS COULD
RESULT IN ACCOUNTING CHARGES.

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

CMS ENERGY AND CONSUMERS MAY BE ADVERSELY AFFECTED BY REGULATORY INVESTIGATIONS
REGARDING "ROUND-TRIP" TRADING BY CMS MST AS WELL AS CIVIL LAWSUITS REGARDING
PRICING INFORMATION THAT CMS MST AND CMS FIELD SERVICES PROVIDED TO MARKET
PUBLICATIONS.

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

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

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

     CMS Energy has notified appropriate regulatory and governmental agencies
that some employees at CMS MST and CMS Field Services appeared to have provided
inaccurate information regarding natural gas trades to various energy industry
publications which compile and report index prices. CMS Energy is cooperating
with an ongoing investigation by the DOJ regarding this matter. CMS Energy is
unable to predict the outcome of the DOJ investigation and what effect, if any,
the investigation will have on CMS Energy. The CFTC filed a civil injunctive
action against two former CMS Field Services employees in Oklahoma federal
district court on February 1, 2005. The action alleges the two engaged in
reporting false natural gas trade information, and seeks to enjoin such acts,
compel compliance with the Commodities Exchange Act, and impose monetary
penalties. A trial has been set for April 2007. CMS Energy is currently
advancing legal defense costs to the two individuals in accordance with existing
indemnification policies.

     CMS Energy, CMS MST, CMS Field Services, Cantera Natural Gas, Inc. (the
company that purchased CMS Field Services) and Cantera Gas Company are named as
defendants in various lawsuits arising as a result of claimed inaccurate natural
gas price reporting. Allegations include manipulation of NYMEX natural gas
futures and options prices, price-fixing conspiracies, and artificial inflation
of natural gas retail prices in California, Colorado, Kansas, Missouri,
Tennessee, and Wyoming. In September 2006, CMS MST reached an agreement in
principle to settle the master class action suit in California for $7 million.
The settlement agreement has been signed. The settlement payment is not due
until the court has approved the settlement. CMS Energy deemed this settlement
to be probable and accrued the payment in its consolidated financial statements
at September 30, 2006. CMS Energy and the other CMS Energy defendants will
defend themselves vigorously against all of these matters but cannot predict
their outcome.

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

REGULATORY CHANGES AND OTHER DEVELOPMENTS HAVE RESULTED AND COULD CONTINUE TO
RESULT IN INCREASED COMPETITION IN THE DOMESTIC ENERGY BUSINESS. GENERALLY,
INCREASED COMPETITION THREATENS MARKET SHARE IN CERTAIN SEGMENTS OF CMS ENERGY'S
BUSINESS AND CAN REDUCE ITS AND CONSUMERS' PROFITABILITY.

     Pursuant to the Customer Choice Act, as of January 1, 2002, all electric
customers in Michigan have the choice of buying electric generation service from
Consumers or an alternative electric supplier. Consumers had experienced, and
could experience in the future, a significant increase in competition for
generation services due to ROA. At December 31, 2006, alternative electric
suppliers were providing 300 MW of generation service to ROA customers. This
amount represents 3 percent of Consumers' total distribution load. It is
difficult to predict the total amount of electric supply load that may be lost
to competitor suppliers in the future.

ELECTRIC INDUSTRY REGULATION COULD ADVERSELY AFFECT CMS ENERGY'S AND CONSUMERS'
BUSINESS, INCLUDING THEIR ABILITY TO RECOVER COSTS FROM THEIR CUSTOMERS.

     Federal and state regulation of electric utilities has changed dramatically
in the last two decades and could continue to change over the next several
years. These changes could adversely affect CMS Energy's and Consumers'
business, financial condition and profitability.

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


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CMS ENERGY AND CONSUMERS COULD INCUR SIGNIFICANT CAPITAL EXPENDITURES TO COMPLY
WITH ENVIRONMENTAL STANDARDS AND FACE DIFFICULTY IN RECOVERING THESE COSTS ON A
CURRENT BASIS.

     CMS Energy, Consumers, and their subsidiaries are subject to costly and
increasingly stringent environmental regulations. They expect that the cost of
future environmental compliance, especially compliance with clean air and water
laws, will be significant.

     In 1998, the EPA issued regulations requiring the State of Michigan to
further limit nitrogen oxide emissions at coal-fired electric generating plants.
The EPA and State of Michigan regulations require Consumers to make significant
capital expenditures estimated to be $835 million. As of December 2006,
Consumers has incurred $688 million in capital expenditures to comply with these
regulations and anticipates that the remaining $147 million of capital
expenditures will be made in 2007 through 2011. In addition to modifying coal-
fired electric plants, Consumers' compliance plan includes the use of nitrogen
oxide emission allowances until all of the control equipment is operational in
2011. The nitrogen oxide emission allowance annual expense is projected to be $3
million per year, which Consumers expects to recover from customers through the
PSCR process.

     In 2005, the EPA adopted the Clean Air Interstate Rule that requires
additional coal-fired electric plant emission controls for nitrogen oxides and
sulfur dioxide. Consumers plans to meet this rule by year-round operation of its
selective catalytic reduction control technology units and installation of flue
gas desulfurization scrubbers at an estimated total cost of $955 million, to be
incurred by 2014.

     Also in March 2005, the EPA issued the Clean Air Mercury Rule, which
requires initial reductions of mercury emissions from coal-fired electric
generating plants by 2010 and further reductions by 2018. Based on current
technology, Consumers anticipates that its capital costs for mercury emissions
reductions required by Phase I of the Clean Air Mercury Rule to be less than $50
million and expect these reductions to be implemented by 2010. Phase II
requirements of the Clean Air Mercury Rule are not yet known and a cost estimate
has not been determined.

     In April 2006, Michigan's governor announced a plan that would result in
mercury emissions reductions of 90 percent by 2015. Consumers is working with
the MDEQ on the details of these rules. We will develop a cost estimate when the
details of these rules are determined.

     Several legislative proposals have been introduced in the United States
Congress that would require reductions in emissions of greenhouse gases,
including potentially carbon dioxide. CMS Energy and Consumers cannot predict
whether any of these proposals will be enacted, or the specific requirements of
any of these proposals and their effect on future operations and financial
results. In addition, the U.S. Supreme Court has agreed to hear a case claiming
that the EPA is required by the Clean Air Act to consider regulating carbon
dioxide emissions from automobiles. The EPA asserts that it lacks authority to
regulate carbon dioxide emissions. If the Supreme Court finds that the EPA has
the authority to regulate carbon dioxide emissions in this case, it could result
in new federal carbon dioxide regulations for other industries, including the
utility industry.

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

     In March 2004, the EPA issued rules that govern electric generating plant
cooling water intake systems. The rules require significant reduction in fish
killed by operating equipment. EPA compliance options in the rule were
challenged in court. In January 2007, the court rejected many of the compliance
options favored by industry and remanded the bulk of the rule back to the EPA
for reconsideration. The court's ruling is expected to increase significantly
the cost of complying with this rule. However, the cost to comply will not be
known until the EPA's reconsideration is complete. At this time, the EPA has not
established a schedule to address the court decision.

     CMS Energy expects to collect fully from its customers, through the
ratemaking process, these and other required environmental expenditures.
However, if these expenditures are not recovered from customers in

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Consumers' rates, CMS Energy and/or Consumers may be required to seek
significant additional financing to fund these expenditures, which could strain
their cash resources.

CMS ENERGY'S AND CONSUMERS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO
RISKS THAT ARE BEYOND THEIR CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE
TERRORIST ATTACKS OR RELATED ACTS OF WAR.

     The cost of repairing damage to CMS Energy's and Consumers' facilities due
to storms, natural disasters, wars, terrorist acts and other catastrophic
events, in excess of insurance recoveries and reserves established for these
repairs, may adversely impact their results of operations, financial condition
and cash flows. The occurrence or risk of occurrence of future terrorist
activity and the high cost or potential unavailability of insurance to cover
this terrorist activity may impact their results of operations and financial
condition in unpredictable ways. These actions could also result in disruptions
of power and fuel markets. In addition, their natural gas distribution system
and pipelines could be directly or indirectly harmed by future terrorist
activity.

CONSUMERS' OWNERSHIP OF A NUCLEAR GENERATING FACILITY CREATES RISK RELATING TO
NUCLEAR ENERGY.

     Consumers owns the Palisades nuclear power plant and is, therefore, subject
to the risks of nuclear generation, including the risks associated with the
operation of plant facilities and the storage and disposal of spent fuel and
other radioactive waste. The NRC has broad authority under federal law to impose
licensing and safety-related requirements for the operation of nuclear
generation facilities. In the event of non-compliance, the NRC has the authority
to impose fines or shut down a unit, or both, depending upon its assessment of
the severity of the situation, until compliance is achieved. In addition, if a
serious nuclear incident were to occur at Consumers' plant, it could harm
Consumers' results of operations and financial condition. A major incident at a
nuclear facility anywhere in the world could cause the NRC to limit or prohibit
the operation or licensing of any domestic nuclear unit.

     In July 2006, Consumers reached an agreement to sell the Palisades nuclear
plant to Entergy for $380 million. Consumers also signed a 15-year power
purchase agreement for 100 percent of the plant's current electric output.
Consumers expects to close the sale in 2007. The sale will result in an
immediate reduction in nuclear operating and decommissioning risk.

CONSUMERS CURRENTLY UNDERRECOVERS IN ITS RATES ITS PAYMENTS TO THE MCV
PARTNERSHIP FOR CAPACITY AND ENERGY.

     The MCV Partnership, which leases and operates the MCV Facility, contracted
to sell electricity to Consumers for a 35-year period beginning in 1990.

     The cost that we incur under the MCV PPA exceeds the recovery amount
allowed by the MPSC. We expensed underrecoveries of $57 million in 2006 and we
estimate cash underrecoveries of $39 million in 2007. However, we use the direct
savings from the RCP, after allocating a portion to customers, to offset a
portion of our capacity and fixed energy underrecoveries expense.

     After September 15, 2007, we expect to claim relief under the regulatory
out provision in the MCV PPA, thereby limiting our capacity and fixed energy
payments to the MCV Partnership to the amounts that we collect from our
customers. The MCV Partnership has notified us that it takes issue with our
intended exercise of the regulatory out provision. We believe that the provision
is valid and fully effective, but cannot assure that it will prevail in the
event of a dispute. If we are successful in exercising the regulatory out
provision, the MCV Partnership has the right to terminate the MCV PPA, which
could affect our reserve margin. We anticipate that the MPSC will review our
exercise of the regulatory out provision and the likely consequences of such
action in 2007. It is possible that in the event that the MCV Partnership ceases
performance under the MCV PPA, prior orders could limit our recovery of
replacement power costs to the amounts that the MPSC authorized for recovery
under the MCV PPA. Depending on the cost of replacement power, this could result
in our costs exceeding the recovery amount allowed by the MPSC. We cannot
predict the outcome of any future disputes concerning these issues.

     In January 2005, we implemented the MPSC-approved RCP with modifications.
The underlying RCP agreement between Consumers and the MCV Partnership extends
through the term of the MCV PPA. However, either party may terminate that
agreement under certain conditions. In January 2007, the Michigan

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Attorney General filed an appeal with the Michigan Supreme Court regarding the
MPSC's order approving the RCP. We cannot predict the outcome of these matters.

     At this time CMS Energy and Consumers cannot predict the impact of these
issues on their future earnings or cash flows.

CONSUMERS' ENERGY RISK MANAGEMENT STRATEGIES MAY NOT BE EFFECTIVE IN MANAGING
FUEL AND ELECTRICITY PRICING RISKS, WHICH COULD RESULT IN UNANTICIPATED
LIABILITIES TO CONSUMERS OR INCREASED VOLATILITY OF ITS EARNINGS.

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

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

                       ITEM 1B. UNRESOLVED STAFF COMMENTS

     Not applicable.

                               ITEM 2. PROPERTIES

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

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

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

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

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

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

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

                            ITEM 3. LEGAL PROCEEDINGS

     CMS Energy, Consumers and some of their subsidiaries and affiliates are
parties to certain routine lawsuits and administrative proceedings incidental to
their businesses involving, for example, claims for personal injury and property
damage, contractual matters, various taxes, and rates and licensing. For
additional information regarding various pending administrative and judicial
proceedings involving regulatory, operating and environmental matters,

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see ITEM 1. BUSINESS -- CMS ENERGY AND CONSUMERS REGULATION, both CMS Energy's
and Consumers' ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS
Energy's and Consumers' ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY
DATA -- NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.

CMS ENERGY

SEC REQUEST

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

GAS INDEX PRICE REPORTING LITIGATION

     Texas-Ohio Energy, Inc. filed a putative class action lawsuit in the United
States District Court for the Eastern District of California in November 2003
against a number of energy companies engaged in the sale of natural gas in the
United States (including CMS Energy). The complaint alleged defendants entered
into a price-fixing scheme by engaging in activities to manipulate the price of
natural gas in California. The complaint alleged violations of the federal
Sherman Act, the California Cartwright Act, and the California Business and
Professions Code relating to unlawful, unfair and deceptive business practices.
The complaint sought both actual and exemplary damages for alleged overcharges,
attorneys' fees and injunctive relief regulating defendants' future conduct
relating to pricing and price reporting. In April 2004, a Nevada Multidistrict
Litigation (MDL) Panel ordered the transfer of the Texas-Ohio case to a pending
MDL matter in the Nevada federal district court that at the time involved seven
complaints originally filed in various state courts in California. These
complaints make allegations similar to those in the Texas-Ohio case regarding
price reporting, although none contain a federal Sherman Act claim. In November
2004, those seven complaints, as well as a number of others that were originally
filed in various state courts in California and subsequently transferred to the
MDL proceeding, were remanded back to California state court. The Texas-Ohio
case remained in Nevada federal district court, and defendants, with CMS Energy
joining, filed a motion to dismiss. The court issued an order granting the
motion to dismiss on April 8, 2005 and entered a judgment in favor of the
defendants on April 11, 2005. Texas-Ohio has appealed the dismissal to the Ninth
Circuit Court of Appeals.

     Three federal putative class actions, Fairhaven Power Company v. Encana
Corp. et al., Utility Savings & Refund Services LLP v. Reliant Energy Resources
Inc. et al., and Abelman Art Glass v. Encana Corp. et al., all of which make
allegations similar to those in the Texas-Ohio case regarding price manipulation
and seek similar relief, were originally filed in the United States District
Court for the Eastern District of California in September 2004, November 2004
and December 2004, respectively. The Fairhaven and Abelman Art Glass cases also
include claims for unjust enrichment and a constructive trust. The three
complaints were filed against CMS Energy and many of the other defendants named
in the Texas-Ohio case. In addition, the Utility Savings case names CMS MST and
Cantera Resources Inc. (Cantera Resources Inc. is the parent of Cantera Natural
Gas, LLC. and CMS Energy is required to indemnify Cantera Natural Gas, LLC and
Cantera Resources Inc. with respect to these actions.)

     The Fairhaven, Utility Savings and Abelman Art Glass cases have been
transferred to the MDL proceeding, where the Texas-Ohio case was pending.
Pursuant to stipulation by the parties and court order, defendants were not
required to respond to the Fairhaven, Utility Savings and Abelman Art Glass
complaints until the court ruled on defendants' motion to dismiss in the Texas-
Ohio case. Plaintiffs subsequently filed a consolidated class action complaint
alleging violations of federal and California antitrust laws. Defendants filed a
motion to dismiss, arguing that the consolidated complaint should be dismissed
for the same reasons as the Texas-Ohio case. The court issued

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an order granting the motion to dismiss on December 19, 2005 and entered
judgment in favor of defendants on December 23, 2005. Plaintiffs have appealed
the dismissal to the Ninth Circuit Court of Appeals.

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

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

     Samuel D. Leggett, et al v. Duke Energy Corporation, et al, a class action
complaint brought on behalf of retail and business purchasers of natural gas in
Tennessee, was filed in the Chancery Court of Fayette County, Tennessee in
January 2005. The complaint contains claims for violations of the Tennessee
Trade Practices Act based upon allegations of false reporting of price
information by defendants to publications that compile and publish indices of
natural gas prices for various natural gas hubs. The complaint seeks statutory
full consideration damages and attorneys fees and injunctive relief regulating
defendants' future conduct. The defendants include CMS Energy, CMS MST and CMS
Field Services. On August 10, 2005, certain defendants, including CMS MST, filed
a motion to dismiss and CMS Energy and CMS Field Services filed a motion to
dismiss for lack of personal jurisdiction. Defendants attempted to remove the
case to federal court, but it was remanded to state court by a federal judge. On
February 2, 2007, the state court granted defendants' motion to dismiss the
complaint.

     J.P. Morgan Trust Company, in its capacity as Trustee of the FLI
Liquidating Trust, filed an action in Kansas state court in August 2005 against
a number of energy companies, including CMS Energy, CMS MST and CMS Field
Services. The complaint alleges various claims under the Kansas Restraint of
Trade Act relating to reporting false natural gas trade information to
publications that report trade information. Plaintiff is seeking statutory full
consideration damages for its purchases of natural gas between January 1, 2000
and December 31, 2001. The case was removed to the United States District Court
for the District of Kansas on September 8, 2005 and transferred to the MDL
proceeding on October 13, 2005. A motion to remand the case back to Kansas state
court was denied on April 21, 2006. The court issued an order granting the
motion to dismiss on December 18, 2006, and entered judgment in favor of
defendants on January 4, 2007.

     On November 20, 2005, CMS MST was served with a summons and complaint which
named CMS Energy, CMS MST and CMS Field Services as defendants in a putative
class action filed in Kansas state court, Learjet, Inc., et al. v. Oneok, Inc.,
et al. Similar to the other actions that have been filed, the complaint alleges
that during the putative class period, January 1, 2000 through October 31, 2002,
defendants engaged in a scheme to violate the Kansas Restraint of Trade Act by
knowingly reporting false or inaccurate information to the publications, thereby
affecting the market price of natural gas. Plaintiffs, who allege they purchased
natural gas from defendants and others for their facilities, are seeking
statutory full consideration damages consisting of the full consideration paid
by plaintiffs for natural gas. On December 7, 2005, the case was removed to the
United States District Court for the District of Kansas and later that month a
motion was filed to transfer the case to the MDL proceeding. On January 6, 2006,
plaintiffs filed a motion to remand the case to Kansas state court. On January
23, 2006, a conditional transfer order transferring the case to the MDL
proceeding was issued. On February 7, 2006, plaintiffs filed an opposition to
the conditional transfer order. The court issued an order dated August 3, 2006
denying the motion to remand the case to Kansas state court.


                                       35

<PAGE>

     Breckenridge Brewery of Colorado, LLC and BBD Acquisition Co. v. Oneok,
Inc., et al., a class action complaint brought on behalf of retail direct
purchasers of natural gas in Colorado, was filed in Colorado state court in May
2006. Defendants, including CMS Energy, CMS Field Services, and CMS MST, are
alleged to have violated the Colorado Antitrust Act of 1992 in connection with
their natural gas price reporting activities. Plaintiffs are seeking full refund
damages. The case was removed to the United States District Court for the
District of Colorado on June 12, 2006 and a conditional transfer order
transferring the case to the MDL proceeding was entered on June 27, 2006.
Plaintiffs are seeking to have the case remanded back to Colorado state court.

     On October 30, 2006, CMS Energy and CMS MST were each served with a summons
and complaint which named CMS Energy, CMS MST and CMS Field Services as
defendants in an action filed in Missouri state court, titled Missouri Public
Service Commission v. Oneok, Inc. The Missouri Public Service Commission
purportedly is acting as an assignee of six local distribution companies, and it
alleges that from at least January 2000 through at least October 2002,
defendants knowingly reported false natural gas prices to publications that
compile and publish indices of natural gas prices, and engaged in wash sales.
The complaint contains claims for violation of the Missouri Anti-Trust Law,
fraud and unjust enrichment.

     A class action complaint, Arandell Corp., et al v. XCEL Energy Inc., et al,
was filed on or about December 15, 2006 in Wisconsin state court on behalf of
Wisconsin commercial entities that purchased natural gas between January 1, 2000
and October 31, 2002. Defendants, including CMS Energy, CMS ERM and Cantera Gas
Company, LLC, are alleged to have violated Wisconsin's Anti-Trust statute by
conspiring to manipulate natural gas prices. Plaintiffs are seeking full
consideration damages, plus exemplary damages in an amount equal to three times
the actual damages, and attorneys' fees.

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

ROUND-TRIP TRADING INVESTIGATIONS

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

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

QUICKSILVER RESOURCES, INC.

     Quicksilver sued CMS MST for breach of contract in connection with a Base
Contract for Sale and Purchase of natural gas, pursuant to which Quicksilver
agreed to sell, and CMS MST to buy, natural gas. Quicksilver contended that a
special provision in the contract requires CMS MST to pay Quicksilver 50 percent
of the difference between $2.47/MMBtu and the index price each month. CMS MST
disagrees with Quicksilver's interpretation of the special provision and
contends that it has paid all monies owed for delivery of gas pursuant to the
contract. Quicksilver is seeking damages of approximately $126 million, plus
prejudgment interest and attorneys' fees, which in CMS Energy's judgment is
unsupported by the facts.

     The judge granted CMS MST's motion for summary judgment. The court of
appeals reversed the summary judgment and remanded the case to the trial court.
Trial is set for March 19, 2007. CMS Energy will continue to defend vigorously
this lawsuit but cannot predict the outcome.


                                       36

<PAGE>

CMS ENERGY AND CONSUMERS

SECURITIES CLASS ACTION LAWSUITS

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

     On January 3, 2007, CMS Energy and other parties entered into a Memorandum
of Understanding (the "MOU") dated December 28, 2006, subject to court approval,
regarding settlement of the two class action lawsuits. The settlement was
approved by a special committee of independent directors and by the full board
of directors. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. The MOU is expected to lead to a detailed
stipulation of settlement that will be presented to the assigned federal judge
and the affected class in the first quarter of 2007. Under the terms of the MOU,
the litigation will be settled for a total of $200 million, including the cost
of administering the settlement and any attorney fees the court awards. CMS
Energy will make a payment of approximately $123 million plus an amount
equivalent to interest on the outstanding unpaid settlement balance beginning on
the date of preliminary approval of the court and running until the balance of
the settlement funds is paid into a settlement account. Out of the total
settlement, CMS Energy's insurers will pay approximately $77 million directly to
the settlement account. CMS Energy took an approximately $123 million pre-tax
charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS
Energy makes no admission of liability under the Shareholder Action and the ACTS
Action.

ENVIRONMENTAL MATTERS

     CMS Energy and Consumers, as well as their subsidiaries and affiliates are
subject to various federal, state and local laws and regulations relating to the
environment. Several of these companies have been named parties to various
actions involving environmental issues. Based on their present knowledge and
subject to future legal and factual developments, they believe it is unlikely
that these actions, individually or in total, will have a material adverse
effect on their financial condition or future results of operations. For
additional information, see both CMS Energy's and Consumers' ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS and both CMS Energy's and Consumers' ITEM
8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS.

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

CMS ENERGY

     During the fourth quarter of 2006, CMS Energy did not submit any matters to
a vote of security holders.

CONSUMERS

     During the fourth quarter of 2006, Consumers did not submit any matters to
a vote of security holders.


                                       37

<PAGE>

                                     PART II

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

CMS ENERGY

     Market prices for CMS Energy's Common Stock and related security holder
matters are contained in ITEM 7. CMS ENERGY'S MANAGEMENT'S DISCUSSION AND
ANALYSIS and ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- NOTE 17 OF
CMS ENERGY'S NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (QUARTERLY FINANCIAL AND
COMMON STOCK INFORMATION (UNAUDITED), which is incorporated by reference herein.
At February 20, 2007, the number of registered holders of CMS Energy Common
Stock totaled 51,043, based upon the number of record holders. In January 2003,
CMS Energy suspended the payment of dividends on its common stock. On January
26, 2007, CMS Energy's Board of Directors reinstated a quarterly dividend on CMS
Energy Common Stock of $0.05 per share, for the first quarter of 2007.
Information regarding securities authorized for issuance under equity
compensation plans is included in our definitive proxy statement, which is
incorporated by reference herein.

CONSUMERS

     Consumers' common stock is privately held by its parent, CMS Energy, and
does not trade in the public market. In February, August and November 2006,
Consumers paid $40 million, $31 million and $76 million in cash dividends,
respectively, on its common stock. In February, May, August and November 2005,
Consumers paid $118 million, $49 million, $40 million and $70 million in cash
dividends, respectively, on its common stock.

                         ITEM 6. SELECTED FINANCIAL DATA

CMS ENERGY

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

CONSUMERS

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

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

CMS ENERGY

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

CONSUMERS

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


                                       38

<PAGE>

       ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

CMS ENERGY

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

CONSUMERS

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


                                       39

<PAGE>

              ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.



<Table>
<S>                                                                    <C>
Index to Financial Statements:
CMS ENERGY CORPORATION
  Selected Financial Information....................................   CMS - 2
  Management's Discussion and Analysis
     Executive Overview.............................................   CMS - 3
     Forward-Looking Statements and Information.....................   CMS - 4
     Results of Operations..........................................   CMS - 6
     Critical Accounting Policies...................................   CMS - 15
     Capital Resources and Liquidity................................   CMS - 24
     Outlook........................................................   CMS - 27
     Implementation of New Accounting Standards.....................   CMS - 35
     New Accounting Standards Not Yet Effective.....................   CMS - 36
  Consolidated Financial Statements
     Consolidated Statements of Income (Loss).......................   CMS - 38
     Consolidated Statements of Cash Flows..........................   CMS - 40
     Consolidated Balance Sheets....................................   CMS - 42
     Consolidated Statements of Common Stockholders' Equity.........   CMS - 44
  Notes to Consolidated Financial Statements:
      1. Corporate Structure and Accounting Policies................   CMS - 46
      2. Asset Sales, Impairment Charges and Discontinued
         Operations.................................................   CMS - 51
      3. Contingencies..............................................   CMS - 56
      4. Financings and Capitalization..............................   CMS - 69
      5. Earnings Per Share.........................................   CMS - 73
      6. Financial and Derivative Instruments.......................   CMS - 74
      7. Retirement Benefits........................................   CMS - 80
      8. Asset Retirement Obligations...............................   CMS - 88
      9. Income Taxes...............................................   CMS - 90
     10. Executive Incentive Compensation...........................   CMS - 93
     11. Leases.....................................................   CMS - 94
     12. Property, Plant, and Equipment.............................   CMS - 96
     13. Equity Method Investments..................................   CMS - 97
     14. Jointly Owned Regulated Utility Facilities.................   CMS - 100
     15. Reportable Segments........................................   CMS - 100
     16. Consolidation of Variable Interest Entities................   CMS - 102
     17. Quarterly Financial and Common Stock Information
         (Unaudited)................................................   CMS - 104
  Report of Independent Registered Public Accounting Firm...........   CMS - 105
</Table>

                                       40

<PAGE>

<Table>
<S>                                                                    <C>
CONSUMERS ENERGY COMPANY
  Selected Financial Information....................................   CE - 2
  Management's Discussion and Analysis
     Executive Overview.............................................   CE - 3
     Forward-Looking Statements and Information.....................   CE - 4
     Results of Operations..........................................   CE - 5
     Critical Accounting Policies...................................   CE - 12
     Capital Resources and Liquidity................................   CE - 18
     Outlook........................................................   CE - 22
     Implementation of New Accounting Standards.....................   CE - 27
     New Accounting Standards Not Yet Effective.....................   CE - 28
  Consolidated Financial Statements
     Consolidated Statements of Income (Loss).......................   CE - 29
     Consolidated Statements of Cash Flows..........................   CE - 30
     Consolidated Balance Sheets....................................   CE - 32
     Consolidated Statements of Common Stockholder's Equity.........   CE - 34
  Notes to Consolidated Financial Statements:
      1. Corporate Structure and Accounting Policies................   CE - 36
      2. Asset Sales and Impairment Charges.........................   CE - 41
      3. Contingencies..............................................   CE - 42
      4. Financings and Capitalization..............................   CE - 51
      5. Financial and Derivative Instruments.......................   CE - 53
      6. Retirement Benefits........................................   CE - 57
      7. Asset Retirement Obligations...............................   CE - 65
      8. Income Taxes...............................................   CE - 67
      9. Executive Incentive Compensation...........................   CE - 69
     10. Leases.....................................................   CE - 71
     11. Property, Plant, and Equipment.............................   CE - 72
     12. Jointly Owned Regulated Utility Facilities.................   CE - 74
     13. Reportable Segments........................................   CE - 74
     14. Consolidation of Variable Interest Entities................   CE - 76
     15. Quarterly Financial and Common Stock Information
         (Unaudited)................................................   CE - 76
  Report of Independent Registered Public Accounting Firm...........   CE - 77
</Table>




                                       41

<PAGE>

                                (CMS ENERGY LOGO)

                     2006 Consolidated Financial Statements



                                      CMS-1

<PAGE>

                             CMS Energy Corporation

                         SELECTED FINANCIAL INFORMATION



<Table>
<Caption>
                                                  2006      2005      2004      2003      2002
                                                -------   -------   -------   -------   -------

<S>                                       <C>   <C>       <C>       <C>       <C>       <C>

Operating revenue (in millions).........   ($)    6,810     6,288     5,472     5,513     8,673
Earnings from equity method investees
  (in millions).........................   ($)       89       125       115       164        92
Income (loss) from continuing operations
  (in millions).........................   ($)      (85)      (98)      127       (42)     (394)
Cumulative effect of change in
  accounting (in millions)..............   ($)       --        --        (2)      (24)       18
Net income (loss) (in millions).........   ($)      (79)      (84)      121       (43)     (650)
Net income (loss) available to common
  stockholders (in millions)............   ($)      (90)      (94)      110       (44)     (650)
Average common shares outstanding (in
  thousands)............................        219,857   211,819   168,553   150,434   139,047
Net income (loss) from continuing
  operations per average common share
     CMS Energy -- Basic................   ($)    (0.44)    (0.51)     0.68     (0.30)    (2.84)
                -- Diluted..............   ($)    (0.44)    (0.51)     0.67     (0.30)    (2.84)
Cumulative effect of change in
  accounting per average common share
     CMS Energy -- Basic................   ($)       --        --     (0.01)    (0.16)     0.13
                -- Diluted..............   ($)       --        --     (0.01)    (0.16)     0.13
Net income (loss) per average common
  share
     CMS Energy -- Basic................   ($)    (0.41)    (0.44)     0.65     (0.30)    (4.68)
                -- Diluted..............   ($)    (0.41)    (0.44)     0.64     (0.30)    (4.68)
Cash provided by (used in) operations
  (in millions).........................   ($)      688       599       353      (250)      614
Capital expenditures, excluding
  acquisitions and capital lease
  additions (in millions)...............   ($)      670       593       525       535       747
Total assets (in millions)(a)...........   ($)   15,371    16,041    15,872    13,838    14,781
Long-term debt, excluding current
  portion (in millions)(a)..............   ($)    6,202     6,800     6,444     6,020     5,357
Long-term debt-related parties,
  excluding current portion (in
  millions)(b)..........................   ($)      178       178       504       684        --
Non-current portion of capital leases
  and finance lease obligations (in
  millions).............................   ($)       42       308       315        58       116
Total preferred stock (in millions).....   ($)      305       305       305       305        44
Total Trust Preferred Securities (in
  millions)(b)..........................   ($)       --        --        --        --       883
Cash dividends declared per common
  share.................................   ($)       --        --        --        --      1.09
Market price of common stock at year-
  end...................................   ($)    16.70     14.51     10.45      8.52      9.44
Book value per common share at year-
  end...................................   ($)    10.03     10.53     10.62      9.84      7.48
Number of employees at year-end (full-
  time equivalents).....................          8,640     8,713     8,660     8,411    10,477
ELECTRIC UTILITY STATISTICS
  Sales (billions of kWh)...............             38        39        38        38        38
  Customers (in thousands)..............          1,797     1,789     1,772     1,754     1,734
  Average sales rate per kWh............   (c)     8.46      6.73      6.88      6.91      6.88
GAS UTILITY STATISTICS
  Sales and transportation deliveries
     (bcf)..............................            309       350       385       380       376
  Customers (in thousands)(c)...........          1,714     1,708     1,691     1,671     1,652
  Average sales rate per mcf............   ($)    10.44      9.61      8.04      6.72      5.67
</Table>


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

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

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

(c)   Excludes off-system transportation customers.


                                      CMS-2

<PAGE>

                             CMS Energy Corporation

                      Management's Discussion and Analysis

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

EXECUTIVE OVERVIEW

     CMS Energy is an energy company operating primarily in Michigan. We are the
parent holding company of Consumers and Enterprises. Consumers is a combination
electric and gas utility company serving Michigan's Lower Peninsula.
Enterprises, through various subsidiaries and equity investments, is engaged in
domestic and international energy businesses including independent power
production, electric distribution, 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, and gas
distribution, transmission, storage, and processing. Our businesses are affected
primarily by:

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

     - economic conditions, primarily in Michigan,

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

     - energy commodity prices,

     - interest rates, and

     - our debt credit rating.

     During the past several years, our business strategy has involved improving
our consolidated balance sheet and maintaining focus on our core strength:
utility operations and service. In 2006, we announced utility asset sales
intended to reduce risk and strengthen our utility business.

     In July 2006, we reached an agreement to sell the Palisades nuclear plant
to Entergy for $380 million. We also signed a 15-year power purchase agreement
with Entergy for 100 percent of the plant's current electric output. We are
targeting to close the sale in the second quarter of 2007. When completed, the
sale will result in an immediate improvement in our cash flow, a reduction in
our nuclear operating and decommissioning risk, and an improvement in our
financial flexibility to support other utility investments. We expect to use the
proceeds to benefit our customers. We plan to use the cash that we retain from
the sale to reduce utility debt. In January 2007, the NRC renewed the Palisades
operating license for 20 years extending it to 2031.

     In November 2006, we sold our interests in the MCV Partnership and the
FMLP. The sale resulted in a $57 million positive impact on our 2006 cash flow.
We used the proceeds to reduce utility debt. The sale reduced our exposure to
volatile natural gas prices.

     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 selected assets. In 2007, we intend to exit the international
marketplace and accelerate our financial improvement plan through the sale of a
major portion of our non-U.S. Enterprises assets.

     In January 2007, we signed a binding letter of intent to sell most of our
Argentine assets and our northern Michigan non-utility natural gas assets to
Lucid Energy, LLC for $180 million. We expect to close the proposed sale, which
is subject to negotiation and execution of a definitive purchase and sale
agreement, in the first half of 2007. In February 2007, we reached an agreement
to sell our ownership interests in businesses in the Middle East, Africa, and
India for $900 million to TAQA. We expect to close this sale in the middle of
2007.


                                      CMS-3

<PAGE>

     In February 2007, we signed a memorandum of understanding with Petroleos de
Venezuela, S.A. to sell our ownership interest in SENECA and certain associated
generating equipment for $106 million. We expect to close on the sale by March
31, 2007. In addition, during 2007, we plan to conduct an auction to sell other
generation and distribution assets in South America. We plan to use the proceeds
from these sales to retire debt and to invest in our utility business. For
additional details on our planned asset sales, see the Enterprise Outlook
Section with this MD&A.

     In January 2007, we took an important step in our business plan by
reinstating a dividend on our common stock after a four-year suspension. The
quarterly dividend is $0.05 per share for the first quarter of 2007.

     We also took steps toward resolving a long-outstanding litigation issue. In
January 2007, we reached a preliminary agreement to settle two class action
lawsuits related to round-trip trading by CMS MST. We believe that eliminating
this business uncertainty is in the best interests of our shareholders.

     In the future, we will focus our strategy on:

     - continued investment in our utility business,

     - successful completion of announced asset sales,

     - reducing parent debt, and

     - growing earnings while controlling operating costs.

     We continue to pursue opportunities and options for our Enterprises
business that enhance value. In October 2006, we signed agreements with Peabody
Energy to co-develop, construct, operate, and indirectly own 15 percent of the
Prairie State Energy Campus, a 1,600 MW power plant and coal mine in southern
Illinois. This project complements our expertise in power plant construction.

     As we execute our strategy, we will need to overcome a sluggish Michigan
economy that has been hampered by negative developments in Michigan's automotive
industry and limited growth in the non-automotive sectors of the state's
economy. The return of ROA customer load has offset some of these negative
effects. At December 31, 2006, alternative electric suppliers were providing 300
MW of generation service to ROA customers. This is 3 percent of our total
distribution load and represents a decrease of 46 percent of ROA load compared
to the end of December 2005.

FORWARD-LOOKING STATEMENTS AND INFORMATION

     This Form 10-K and other written and oral statements that we make contain
forward-looking statements as defined in Rule 3b-6 under the Securities Exchange
Act of 1934, as amended, Rule 175 under 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:

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

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

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

     - currency fluctuations, transfer restrictions, and exchange controls,


                                      CMS-4

<PAGE>

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

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

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

     - potentially adverse regulatory treatment and (or) regulatory lag
       concerning a number of significant questions presently before the MPSC
       including:

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

          - power supply and natural gas supply costs when fuel prices are
            increasing and (or) fluctuating,

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

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

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

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

          - sale of the Palisades plant,

     - the effects on our ability to purchase capacity to serve our customers
       and fully recover the cost of these purchases, if Consumers exercises its
       regulatory out rights and the owners of the MCV Facility exercise their
       right to terminate the MCV PPA,

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

     - energy markets, including availability of capacity and the timing and
       extent of changes in commodity prices for oil, coal, natural gas, natural
       gas liquids, electricity and certain related products due to lower or
       higher demand, shortages, transportation costs problems, or other
       developments,

     - our ability to collect accounts receivable from our customers,

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

     - the effect on our electric utility of the direct and indirect impacts of
       the continued economic downturn experienced by our automotive and
       automotive parts manufacturing customers,

     - 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,

     - changes in available gas supplies or Argentine government regulations
       that could further restrict natural gas exports to our GasAtacama
       electric generating plant and the operating and financial effects of the
       restrictions, including further impairment of our investment in
       GasAtacama,

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

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


                                      CMS-5

<PAGE>

     - achievement of capital expenditure and operating expense goals,

     - changes in financial or regulatory accounting principles or policies,

     - changes in domestic or foreign tax laws, or new IRS or foreign
       governmental interpretations of existing or past tax laws,

     - 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 the outcome of 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 ability to efficiently sell assets when deemed appropriate or
       necessary, including the 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,

     - the successful close of the sale of our ownership interests in businesses
       in the Middle East, Africa, and India,

     - the successful entry into a definitive purchase and sale agreement and
       closing of the proposed sale of certain of our Argentine assets and our
       northern Michigan non-utility natural gas assets,

     - the successful entry into a definitive purchase and sale agreement and
       closing of the proposed sale of SENECA,

     - the outcome of the planned auction of other generation and distribution
       assets in South America, and

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

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

RESULTS OF OPERATIONS

CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS



<Table>
<Caption>
YEARS ENDED DECEMBER 31                                       2006     2005     2004
-----------------------                                       ----     ----     ----
                                                             IN MILLIONS (EXCEPT FOR
                                                                PER SHARE AMOUNTS)

<S>                                                          <C>      <C>      <C>

Net Income (Loss) Available to Common Stockholders.........  $  (90)  $  (94)  $ 110
Basic Earnings (Loss) Per Share............................  $(0.41)  $(0.44)  $0.65
Diluted Earnings (Loss) Per Share..........................  $(0.41)  $(0.44)  $0.64
</Table>




<Table>
<Caption>
YEARS ENDED DECEMBER 31                      2006    2005   CHANGE    2005    2004   CHANGE
-----------------------                      ----    ----   ------    ----    ----   ------
                                                              IN MILLIONS

<S>                                         <C>     <C>     <C>      <C>     <C>     <C>

Electric Utility..........................  $ 199   $ 153    $ 46    $ 153   $ 223    $ (70)
Gas Utility...............................     37      48     (11)      48      71      (23)
Enterprises...............................   (158)   (142)    (16)    (142)     19     (161)
Corporate Interest and Other..............   (174)   (167)     (7)    (167)   (197)      30
Discontinued Operations...................      6      14      (8)      14      (4)      18
Accounting Changes........................     --      --      --       --      (2)       2
                                            -----   -----    ----    -----   -----    -----
Net Income (Loss) Available to Common
  Stockholders............................  $ (90)  $ (94)   $  4    $ (94)  $ 110    $(204)
                                            =====   =====    ====    =====   =====    =====

</Table>




                                      CMS-6

<PAGE>

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

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


<Table>
<Caption>
                                                                    IN MILLIONS
                                                                    -----------

<S>  <C>                                                            <C>

-    decrease in asset impairment charges as the $385 million          $ 216
     impairment related to the MCV Partnership recorded in 2005
     exceeded the $169 million impairment related to GasAtacama
     recorded in 2006,
-    increase from Enterprises primarily due to favorable                 47
     arbitration and property tax awards and lower depreciation
     expense,
-    increase in earnings from our electric utility primarily due         46
     to an increase in revenue from an electric rate order, the
     return to full service-rates of customers previously using
     alternative energy suppliers, and the expiration of rate
     caps in December 2005 offset partially by higher operating
     expense and lower deliveries due to milder weather,
-    decrease in corporate interest and other expenses primarily          33
     due to an insurance reimbursement received for previously
     incurred legal expenses, and a reduction in debt retirement
     charges and other expenses,
-    lower estimate of environmental remediation expenses                 20
     recorded in 2006 related to our involvement in Bay Harbor,
-    decrease in earnings from mark-to-market valuation                 (203)
     adjustments primarily at the MCV Partnership and CMS ERM as
     losses recorded in 2006 replaced gains recorded in 2005,
-    net charge resulting from our agreement to settle                   (80)
     shareholder class action lawsuits,
-    net loss on the sale of our investment in the MCV                   (41)
     Partnership including the negative impact of the associated
     impairment charge recorded in 2006 and the positive impact
     of the recognition of certain derivative instruments,
-    decrease in various corporate and Enterprises tax benefits          (15)
     as the absence of tax benefits recorded in 2005 related to
     the American Jobs Creation Act more than offset benefits
     recorded in 2006, primarily related to the restoration and
     utilization of income tax credits due to the resolution of
     an IRS income tax audit,
-    decrease in earnings from our gas utility primarily due to a        (11)
     reduction in deliveries resulting from increased customer
     conservation efforts and warmer weather in 2006 partially
     offset by other gas revenue associated with pipeline
     capacity optimization and a reduction in operation and
     maintenance expenses, and
-    reduced earnings from discontinued operations as the                 (8)
     positive impact of an arbitration award and a reduction of
     contingent liabilities recorded in 2005 exceeded income
     recorded in 2006 from the favorable resolution of certain
     accrued liabilities.
                                                                       -----
Total Change                                                           $   4
                                                                       =====

</Table>


     For 2005, our net loss was $94 million compared to net income of $110
million for 2004. The year-over-year change was partially due to a decrease in
income from our utilities, which experienced underrecoveries of electric power
supply costs and increases in operating and maintenance expenses. Also
contributing to the change was a loss at our Enterprises segment due to an
increase in asset impairment charges, which more than offset mark-to-market

                                      CMS-7

<PAGE>

gains on long-term gas contracts and associated hedges at the MCV Partnership.
These decreases more than offset the continued reduction in corporate interest
expense and lower income tax expenses.

     Specific changes to net income (loss) available to common stockholders for
2005 versus 2004 are:


<Table>
<Caption>
                                                                    IN MILLIONS
                                                                    -----------

<S>  <C>                                                            <C>

-    decrease in earnings from our ownership interest in the MCV
     Partnership due to a $385 million impairment charge to
     property, plant, and equipment offset partially by an
     increase of $100 million from operations, primarily due to
     an increase in fair value of certain long-term gas contracts
     and financial hedges,                                             $(285)
-    decrease in earnings at our electric utility primarily due
     to increased operating and maintenance expenses, an
     underrecovery of power supply costs, and a reduction in
     income from the regulatory return on capital expenditures,
     offset partially by a weather-driven increase in sales to
     our residential customers and a reduction in interest
     charges,                                                            (70)
-    lower gains on the sale of assets in 2005,                          (30)
-    decrease in earnings at our gas utility primarily due to
     increased operating and maintenance expenses, offset
     partially by a MPSC-authorized gas rate surcharge,                  (23)
-    increase in other corporate expenses primarily due to legal
     fees and the expiration of general business tax credits in
     2005,                                                               (16)
-    absence in 2005 of impairment charges recorded in 2004
     related to the sales of our investments in Loy Yang and GVK,        104
-    reduction in corporate interest expense due to lower debt
     levels and a reduction in average interest rates,                    29
-    increase in tax benefits from the American Jobs Creation Act
     of 2004,                                                             24
-    increase in income from discontinued operations due to
     favorable litigation results and the absence of other
     expenses recorded in 2004,                                           18
-    increase in corporate tax benefits,                                  17
-    increase in Shuweihat earnings,                                      10
-    increase in earnings from other Enterprises' subsidiaries,
     and                                                                  10
-    decrease in debt retirement charges.                                  8
                                                                       -----
Total Change                                                           $(204)
                                                                       =====

</Table>


ELECTRIC UTILITY RESULTS OF OPERATIONS



<Table>
<Caption>
YEARS ENDED DECEMBER 31                       2006   2005   CHANGE   2005   2004   CHANGE
-----------------------                       ----   ----   ------   ----   ----   ------
                                                              IN MILLIONS

<S>                                           <C>    <C>    <C>      <C>    <C>    <C>

Net income..................................  $199   $153    $  46   $153   $223    $ (70)
                                              ====   ====    =====   ====   ====    =====
REASONS FOR THE CHANGE:
Electric deliveries.........................                 $ 254                  $  91
Power supply costs and related revenue......                    57                    (46)
Other operating expenses, other income, and
  non-commodity revenue.....................                  (236)                  (131)
Regulatory return on capital expenditures...                    22                    (30)
General taxes...............................                    (7)                     6
Interest charges............................                   (34)                     5
Income taxes................................                   (10)                    35
                                                             -----                  -----
Total change................................                 $  46                  $ (70)
                                                             =====                  =====

</Table>


     ELECTRIC DELIVERIES: In 2006, electric delivery revenues increased by $254
million over 2005 despite the fact that electric deliveries to end-use customers
were 38.5 billion kWh, a decrease of 0.4 billion kWh or 1.2 percent versus 2005.
The decrease in electric deliveries is primarily due to milder summer weather
compared to 2005, and resulted in a decrease in electric delivery revenue of $16
million. Despite lower electric deliveries, electric delivery

                                      CMS-8

<PAGE>

revenue increased primarily due to an electric rate order, increased surcharge
revenue, and the return of former ROA customers to full-service rates. The
impact of these three issues on electric delivery revenue are discussed in the
following paragraphs.

     Electric Rate Order: In December 2005, the MPSC issued an order in our
electric rate case. The order increased electric tariff rates and impacted PSCR
revenue. As a result of this order, electric delivery revenues increased $160
million in 2006 versus 2005.

     Surcharge Revenue: On January 1, 2006, we started collecting a surcharge
that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This
surcharge increased electric delivery revenue by $51 million in 2006 versus
2005. In addition, on January 1, 2006, we started collecting customer choice
transition costs from our residential customers that increased electric delivery
revenue by $12 million in 2006 versus 2005. Other surcharges decreased electric
delivery revenue by $2 million in 2006 versus 2005.

     ROA Customer Deliveries: The Customer Choice Act allows all of our electric
customers to buy electric generation service from us or from an alternative
electric supplier. At December 31, 2006, alternative electric suppliers were
providing 300 MW of generation service to ROA customers. This amount represents
a decrease of 46 percent of ROA load compared to the end of December 2005. The
return of former ROA customers to full-service rates increased electric revenues
$49 million in 2006 versus 2005.

     For 2005, electric deliveries to end-use customers were 38.9 billion kWh,
an increase of 1.3 billion kWh or 3.4 percent versus 2004. The corresponding $68
million increase in electric delivery revenue was primarily due to increased
sales to residential customers, reflecting warmer summer weather and increased
surcharge revenue from all customers.

     On July 1, 2004, we started collecting a surcharge to recover costs
incurred in the transition to customer choice. This surcharge increased electric
delivery revenue by $13 million in 2005 versus 2004. Surcharge revenue related
to the recovery of Security Costs and Stranded Costs increased electric delivery
revenue by an additional $10 million in 2005 versus 2004.

     POWER SUPPLY COSTS AND RELATED REVENUE: Rate caps for our residential
customers expired on December 31, 2005. In 2006, the absence of rate caps
allowed us to record power supply revenue to offset fully our power supply
costs. Our ability to recover these power supply costs resulted in an $82
million increase in electric revenue in 2006 versus 2005. Additionally, electric
revenue increased $9 million in 2006 versus 2005 primarily due to the return of
former special-contract customers to full-service rates in 2006. The return of
former special-contract customers to full-service rates allowed us to record
power supply revenue to offset fully our power supply costs.

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

     In 2005, our recovery of power supply costs was capped for our residential
customers. The underrecovery of power costs related to these capped customers
increased by $76 million versus 2004. Partially offsetting these underrecoveries
were benefits from the deferral of transmission and nitrogen oxide allowance
expenditures related to our capped customers. To the extent these costs were not
fully recoverable due to the application of rate caps, we deferred them for
recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the
MPSC approved the recovery of these costs. For 2005, deferrals of these costs
increased by $30 million versus 2004.

     OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For
2006, other operating expenses increased $236 million. The increase in other
operating expenses reflects higher operating and maintenance, customer service,
depreciation and amortization, and pension and benefit expenses.

     Operating and maintenance expense increased primarily due to costs related
to a planned refueling outage at our Palisades nuclear plant, and higher tree
trimming and storm restoration costs. Higher customer service expense reflects
contributions, beginning in January 2006 pursuant to a December 2005 MPSC order,
to a fund that provides energy assistance to low-income customers. Depreciation
and amortization expense increased due to higher plant in

                                      CMS-9

<PAGE>

service and greater amortization of certain regulatory assets. The increase in
pension and benefit expense reflects changes in actuarial assumptions in 2005,
and the latest collective bargaining agreement between the Utility Workers Union
of America and Consumers.

     For 2005, other operating expenses increased $139 million, other income
increased $4 million, and non-commodity revenue increased $4 million versus
2004.

     The increase in other operating expenses reflects higher depreciation and
amortization, higher pension and benefit expense, and higher underrecovery
expense related to the MCV PPA, offset partially by our direct savings from the
RCP. Depreciation and amortization expense increased primarily due to a
reduction in 2004 expense to reflect an MPSC order allowing recovery of $57
million of Stranded Costs. Pension and benefit expense increased primarily due
to changes in actuarial assumptions and the remeasurement of our pension and
OPEB plans to reflect the new collective bargaining agreement between the
Utility Workers Union of America and Consumers. Benefit expense also reflects
the reinstatement of the employer matching contribution to our 401(k) plan in
January 2005.

     In 1992, a liability was established for estimated future underrecoveries
of power supply costs under the MCV PPA. In 2004, a portion of the cash
underrecoveries continued to reduce this liability until its depletion in
December. In 2005, all cash underrecoveries were expensed directly to income.
Consequently, the cost associated with the MCV PPA cash underrecoveries
increased operating expense $30 million for 2005 versus 2004. Offsetting this
increased operating expense were the savings from the RCP approved by the MPSC
in January 2005.

     The RCP allows us to dispatch the MCV Facility on the basis of natural gas
prices, which reduces the MCV Facility's annual production of electricity and,
as a result, reduces the MCV Facility's consumption of natural gas. The MCV
Facility's fuel cost savings are first used to offset the cost of replacement
power and fund a renewable energy program. Remaining savings are split between
us and the MCV Partnership. Our direct savings were shared 50 percent with
customers in 2005 and are being shared 70 percent with customers in 2006 and
each year thereafter. Our direct savings, after allocating a portion to
customers, was $9 million for 2006 and $32 million for 2005.

     For 2005, the increase in other income was primarily due to higher interest
income on short-term cash investments versus 2004, offset partially by expenses
associated with the early retirement of debt. The increase in non-commodity
revenue was primarily due to higher transmission services revenue versus 2004.

     REGULATORY RETURN ON CAPITAL EXPENDITURES: For 2006, the return on capital
expenditures in excess of our depreciation base increased income by $22 million
versus 2005. The increase reflects the equity return on the regulatory asset
authorized by the MPSC's December 2005 order which provided for the recovery of
$333 million of Section 10d(4) costs over five years.

     For 2005, the return on capital expenditures in excess of our depreciation
base decreased income by $30 million versus 2004. The decrease reflects a
reduction, in 2005, of the equity return on the regulatory asset authorized by
the MPSC's December 2005 order. Prior to the MPSC order, the equity return was
calculated using a regulatory asset balance that was greater than the amount
authorized by the MPSC.

     GENERAL TAXES: For 2006, the increase in general taxes reflects higher MSBT
expense, offset partially by lower property tax expense.

     For 2005, general taxes decreased primarily due to lower property tax
expense, reflecting the use of revised tax tables by several of our taxing
authorities and, separately, other property tax refunds.

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

     For 2005, interest charges decreased primarily due to higher capitalized
interest. In 2005, we capitalized $33 million of interest in connection with the
MPSC's December 2005 order in our Section 10d(4) Regulatory Asset case. This
benefit was offset partially by higher average debt levels versus 2004.


                                     CMS-10

<PAGE>

     INCOME TAXES: For 2006, income taxes increased versus 2005 primarily due to
higher earnings by the electric utility, offset partially by the resolution of
an IRS income tax audit, which resulted in a $4 million income tax benefit
caused by the restoration and utilization of income tax credits.

     For 2005, income taxes decreased primarily due to lower earnings versus
2004, offset partially by a $2 million increase to reflect the tax treatment of
items related to property, plant, and equipment as required by past MPSC orders.

GAS UTILITY RESULTS OF OPERATIONS


<Table>
<Caption>
YEARS ENDED DECEMBER 31                         2006   2005   CHANGE   2005   2004   CHANGE
-----------------------                         ----   ----   ------   ----   ----   ------
                                                                IN MILLIONS

<S>                                             <C>    <C>    <C>      <C>    <C>    <C>

Net income....................................   $37    $48    $(11)    $48    $71    $(23)
                                                 ===    ===    ====     ===    ===    ====
Reasons for the change:
Gas deliveries................................                 $(61)                  $ (6)
Gas rate increase.............................                   14                     28
Gas wholesale and retail services, other gas
  revenues, and other income..................                   24                      9
Operation and maintenance.....................                    7                    (49)
General taxes and depreciation................                  (10)                    (4)
Interest charges..............................                   (6)                    (2)
Income taxes..................................                   21                      1
                                                               ----                   ----
Total change..................................                 $(11)                  $(23)
                                                               ====                   ====

</Table>



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

     For 2005, gas delivery revenues reflect lower deliveries to our customers
versus 2004. Gas deliveries, including miscellaneous transportation to end-use
customers, were 318 bcf, a decrease of 2 bcf or 0.7 percent.

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

     In December 2003, the MPSC issued an interim gas rate order authorizing a
$19 million annual increase to gas tariff rates. In October 2004, the MPSC
issued a final order authorizing an annual increase of $58 million. As a result
of these orders, gas revenues increased $28 million for 2005 versus 2004.

     GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES, AND OTHER
INCOME: For 2006, the increase in gas wholesale and retail services, other gas
revenues, and other income primarily reflects higher pipeline revenues and
higher pipeline capacity optimization in 2006 versus 2005.

     For 2005, other gas revenue increased versus 2004 primarily due to higher
interest income on short-term cash investments, offset partially by expenses
associated with the early retirement of debt.

     OPERATION AND MAINTENANCE: For 2006, operation and maintenance expenses
decreased versus 2005 primarily due to lower operating expenses, offset
partially by higher customer service and pension and benefit expenses. Customer
service expense increased primarily due to higher uncollectible accounts expense
and contributions, beginning in November 2006 pursuant to a November 2006 MPSC
order, to a fund that provides energy assistance to low-income customers. The
increase in pension and benefit expense reflects changes in actuarial
assumptions in 2005 and the latest collective bargaining agreement between the
Utility Workers Union of America and Consumers.


                                     CMS-11

<PAGE>

     For 2005, operation and maintenance expenses increased primarily due to
increases in benefit costs and additional safety, reliability, and customer
service expenses versus 2004. Pension and benefit expense increased primarily
due to changes in actuarial assumptions and the remeasurement of our pension and
OPEB plans to reflect the new collective bargaining agreement between the
Utility Workers Union of America and Consumers. Benefit expense also reflects
the reinstatement of the employer matching contribution to our 401(k) plan in
January 2005.

     GENERAL TAXES AND DEPRECIATION: For 2006, depreciation expense increased
versus 2005 primarily due to higher plant in service. The increase in general
taxes reflects higher MSBT expense, offset partially by lower property tax
expense.

     For 2005, depreciation expense increased primarily due to higher plant in
service versus 2004. The decrease in general taxes is primarily due to lower
property tax expense versus 2004. Lower property tax expense in 2005 reflects an
increased use of revised tax tables by several of Consumers' taxing authorities,
and separately, other property tax refunds.

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

     For 2005, interest charges reflect higher average debt levels versus 2004,
offset partially by a lower average rate of interest on our debt.

     INCOME TAXES: For 2006, income taxes decreased versus 2005 primarily due to
lower earnings by the gas utility. Also contributing to the decrease was the
absence, in 2006, of the write-off of general business credits that expired in
2005, and the resolution of an IRS income tax audit, which resulted in a $3
million income tax benefit caused by the restoration and utilization of income
tax credits.

     For 2005, income taxes decreased due to lower earnings versus 2004. This
decrease was offset by $5 million to reflect the tax treatment of items related
to property, plant, and equipment as required by past MPSC orders, and the
write-off of general business credits expected to expire in 2005.

ENTERPRISES RESULTS OF OPERATIONS


<Table>
<Caption>
YEARS ENDED DECEMBER 31                      2006    2005   CHANGE    2005   2004    CHANGE
-----------------------                      ----    ----   ------    ----   ----    ------
                                                              IN MILLIONS

<S>                                         <C>     <C>     <C>      <C>     <C>    <C>

Net income (loss).........................  $(158)  $(142)   $ (16)  $(142)   $19   $  (161)
                                            =====   =====    =====   =====    ===   =======
Reasons for the change:
Operating revenues........................                   $ 104                  $   244
Cost of gas and purchased power...........                    (228)                    (192)
Fuel costs mark-to-market at the MCV
  Partnership.............................                    (404)                     219
Earnings from equity method investees.....                     (37)                      11
Gain on sale of assets....................                      71                      (42)
Operation and maintenance.................                      (3)                     (25)
General taxes, depreciation, and other
  income, net.............................                     119                       36
Asset impairment charges..................                     726                   (1,015)
Environmental remediation.................                      31                        5
Fixed charges.............................                      19                       13
Minority interest.........................                    (340)                     455
Income taxes..............................                     (74)                     130
                                                             -----                  -------
Total change..............................                   $ (16)                 $  (161)
                                                             =====                  =======

</Table>




                                     CMS-12

<PAGE>

     OPERATING REVENUES: For 2006, operating revenues increased versus 2005 due
to the impact of increased production at our Takoradi plant and increased demand
at our South American facilities. Also contributing to the increase was a
favorable arbitration settlement of a revenue dispute related to CMS Ensenada.
These increases were offset partially by lower revenue at CMS ERM due to mark-
to-market losses on power and gas contracts, compared to gains on such items in
2005, and lower third-party power sales.

     For 2005, operating revenues increased versus 2004 primarily due to the
impact of increased third-party power and gas sales and mark-to-market gains on
gas contracts at CMS ERM.

     COST OF GAS AND PURCHASED POWER: For 2006, cost of gas and purchased power
increased versus 2005. The increase was primarily due to higher fuel costs
related to increased production at Takoradi. Also contributing to the increase
was an increase in fuel and power purchases in order to meet customer demand,
primarily in South America. These increases were offset partially by decreases
in the prices and volumes of cost of gas sold by CMS ERM.

     For 2005, cost of gas and purchased power increased versus 2004. The
increase was primarily due to the impact of natural gas prices on the cost of
gas sold and the increased cost of purchased power relating to wholesale power
sales at CMS ERM.

     FUEL COSTS MARK-TO-MARKET AT THE MCV PARTNERSHIP: For 2006, the fuel costs
mark-to-market adjustments at the MCV Partnership decreased operating earnings
versus 2005 due to the impact of declining gas prices on the market value of
certain long-term gas contracts and financial hedges. In order to reflect the
market value of these contracts and hedges, mark-to-market losses were recorded
in 2006 compared to gains recorded on these assets in 2005. In 2005, gains were
primarily due to the marking-to-market of certain long-term gas contracts and
financial hedges that, as a result of the implementation of the RCP, no longer
qualified as normal purchases or cash flow hedges.

     For 2005, the fuel costs mark-to-market adjustments of certain long-term
gas contracts and financial hedges at the MCV Partnership increased operating
earnings due to increased gas prices versus reductions in 2004.

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

     For 2005, the increase in equity earnings versus 2004 was primarily due to
$10 million in earnings from Shuweihat, which achieved commercial operations in
the third quarter of 2004, and a $5 million increase in earnings from
GasAtacama, as it was able to import more natural gas from Argentina than in
2004. Also contributing to the increase were higher earnings at Neyveli of $6
million, primarily due to the settlement of a revenue dispute, and $4 million of
other net increases in earnings. These increases were offset partially by the
absence, in 2005, of $8 million in earnings from Goldfields, which we sold in
August 2004 and lower earnings at Jorf Lasfar, primarily due to increases in
coal-related costs.

     GAIN ON SALE OF ASSETS: For 2006, gains on asset sales increased versus
2005. In 2006, we had a gain on the sale of our interest in the MCV Partnership
totaling $77 million. In 2005, we had gains on the sale of GVK and SLAP totaling
$6 million.

     For 2005, gains on asset sales decreased versus 2004. In 2005, we had gains
on the sale of GVK and SLAP totaling $6 million. In 2004, we had gains on the
sale of Goldfields, the Bluewater Pipeline and land in Moapa, Nevada totaling
$48 million.

     OPERATION AND MAINTENANCE: For 2006, operation and maintenance expenses
increased versus 2005 due to higher salaries and benefits, primarily at South
American subsidiaries, increased expenditures related to prospecting initiatives
in North America and higher maintenance expenses at Takoradi and CT Mendoza.
These increases were partially offset by a favorable arbitration settlement
related to DIG.

     For 2005, operation and maintenance expenses increased versus 2004
primarily due to a loss on the termination of a prepaid gas contract, higher
legal fees and the absence of an insurance settlement received in 2004. Also

                                     CMS-13

<PAGE>

contributing to the increase were higher maintenance costs related to scheduled
outages, new development costs and increased costs at South American
subsidiaries related to higher electrical production.

     GENERAL TAXES, DEPRECIATION, AND OTHER INCOME, NET: For 2006, the net of
general tax expense, depreciation and other income increased operating income
versus 2005. This was primarily due to the recognition of a property tax refund
of $88 million at the MCV Partnership, partially offset by related appeal
expenses of $16 million. Also contributing to the increase was lower
depreciation expense at the MCV Partnership resulting from the 2005 impairment
of property, plant and equipment.

     For 2005, the net of general tax expense, depreciation, and other income
increased operating income versus 2004 primarily due to increased interest
income, lower depreciation expense at the MCV Partnership due to the 2005
impairment of property, plant, and equipment, lower accretion expense related to
prepaid gas contracts, and the resolution of a contingent liability related to
Leonard Field.

     ASSET IMPAIRMENT CHARGES: For 2006, asset impairment charges decreased
versus 2005 primarily due to the absence of a 2005 impairment charge of $1.184
billion to property, plant and equipment at the MCV Partnership offset partially
by charges of $218 million related to the sale of the MCV Partnership recorded
in 2006. Also in 2006, a charge of $239 million was recorded for the impairment
of our equity investment in GasAtacama and related notes receivable.

     For 2005, the increase in asset impairment charges is primarily due to the
impairment of property, plant, and equipment at the MCV Partnership, compared to
the 2004 reduction in the fair value of Loy Yang and impairments related to the
sale of our interests in GVK and SLAP.

     ENVIRONMENTAL REMEDIATION: For 2006, we recorded an additional estimated
environmental remediation expense of $9 million in 2006 versus $40 million in
2005 related to our involvement in Bay Harbor.

     For 2005, we recorded an additional estimated environmental remediation
expense of $40 million related to our involvement in Bay Harbor. In 2004, we
recorded our initial estimate of $45 million.

     FIXED CHARGES: For 2006, fixed charges decreased versus 2005 due to lower
interest expenses at the MCV Partnership as a result of lower debt levels and
the sale in November, offset partially by higher interest expense from an
increase in subsidiary debt.

     For 2005, fixed charges decreased compared to 2004 primarily due to lower
expense at the MCV Partnership as a result of lower debt levels due to principal
payments.

     MINORITY INTEREST: The allocation of profits to minority owners decreases
our net income, and the allocation of losses to minority owners increases our
net income. For 2006, minority owners shared in a portion of the reduced losses
at our subsidiaries versus sharing greater losses of these subsidiaries in 2005.
This was primarily due to the share of impairment charges of $95 million in 2006
versus $591 million in 2005 at the MCV Partnership.

     For 2005, net losses attributed to minority interest owners in our
subsidiaries replaced net gains in 2004. The losses relate to the asset
impairment charge to property, plant, and equipment at the MCV Partnership,
offset partially by mark-to-market gains at the MCV Partnership.

     INCOME TAXES: For 2006, the increase in income tax expense versus 2005
reflects higher earnings and resolution of an IRS income tax audit, primarily
for the restoration and utilization of income tax credits. Also contributing to
the increase was the absence of income tax benefits related to the American Jobs
Creation Act recorded in 2005.

     For 2005, the decrease in income tax expense versus 2004 reflects lower
earnings and the income tax benefits related to the American Jobs Creation Act
recorded in 2005.

     SALE OF OUR INTEREST IN THE MCV PARTNERSHIP: This resulted in a net after-
tax loss of $41 million in 2006. We recorded Asset impairment charges of $218
million offset by Gain on sale of assets of $77 million, Minority interest of
$95 million, and Income taxes of $5 million. For additional details, see Note 2,
Asset Sales, Impairment Charges and Discontinued Operations.


                                     CMS-14

<PAGE>

CORPORATE INTEREST AND OTHER NET EXPENSES


<Table>
<Caption>
YEARS ENDED DECEMBER 31                      2006    2005   CHANGE    2005    2004   CHANGE
-----------------------                      ----    ----   ------    ----    ----   ------
                                                              IN MILLIONS

<S>                                         <C>     <C>     <C>      <C>     <C>     <C>

Net loss..................................  $(174)  $(167)    $(7)   $(167)  $(197)    $30
                                            =====   =====     ===    =====   =====     ===

</Table>



     For 2006, corporate interest and other net expenses were $174 million, an
increase of $7 million compared to 2005. The increase reflects an $80 million
after tax net charge in 2006 as a result of our agreement to settle shareholder
class action lawsuits. This impact was offset partially by the 2006 resolution
of an IRS income tax audit, which resulted in an income tax benefit primarily
for the restoration and utilization of income tax credits. Further offsetting
the $80 million charge were lower early debt retirement premiums, and the
receipt of insurance proceeds for previously incurred legal expenses.

     For 2005, corporate interest and other net expenses were $167 million, a
decrease of $30 million compared to the same period in 2004. The decrease
reflects lower interest expense due to lower average debt levels and a reduction
in the average rate of interest. Also contributing to the reduction in expenses
were lower debt retirement charges and an increase in corporate income tax
benefits. The decrease was offset partially by increased legal fees.

     DISCONTINUED OPERATIONS: Discontinued operations contributed $6 million in
net income for 2006, a decrease of $8 million compared to the same period in
2005. Net income for 2006 was primarily comprised of income from the favorable
resolution of certain accrued contingent liabilities associated with previously
disposed businesses. Net income of $14 million recorded in 2005 primarily
reflects an arbitration award related to the 2003 sale of Marysville and a
reduction in contingent liabilities due to favorable results from litigation
involving previously sold businesses. A $4 million net loss for 2004 was
primarily due to income tax adjustments, offset partially by gains on asset
sales. For additional details, see Note 2, Asset Sales, Impairment Charges and
Discontinued Operations.

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

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

USE OF ESTIMATES AND ASSUMPTIONS

     We use estimates and assumptions in preparing our consolidated financial
statements that may affect reported amounts and disclosures. We use accounting
estimates 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.
Actual results may differ from estimated results due to factors such as changes
in the regulatory environment, competition, foreign exchange, 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 a loss is probable and the amount
of loss can be reasonably estimated. We use the principles in SFAS No. 5 when
recording estimated liabilities for contingencies. We consider many factors in
making these assessments, including the history and specifics of each matter.

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

                                     CMS-15

<PAGE>

result, our effective tax rate may fluctuate significantly on a quarterly basis.
In July 2006, the FASB issued a new interpretation on the recognition and
measurement of uncertain tax positions. For additional details, see the "New
Accounting Standards Not Yet Effective" section included in this MD&A.

     LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. We periodically perform tests of impairment if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $15.371
billion at December 31, 2006, 56 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.

     We evaluate an asset for impairment if an event occurs or circumstances
change in a manner that indicates the recoverability of a long-lived asset
should be assessed. We evaluate an asset held in use for impairment by
calculating the undiscounted future cash flows expected to result from the use
of the asset and its eventual disposition. If the undiscounted future cash flows
are less than the carrying amount, we recognize an impairment loss. 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. We
record an asset considered held for sale at the lower of its carrying amount or
fair value, less cost to sell.

     We assess our ability to recover the carrying amounts of our equity method
investments using the fair values of these investments. We determine fair value
using valuation methodologies, including discounted cash flows and the ability
of the investee to sustain an earnings capacity that justifies the carrying
amount of the investment. 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, which could have a
material impact on our consolidated financial statements.

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

ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION

     Because we are involved in a regulated industry, regulatory decisions
affect the timing and recognition of revenues and expenses. We use SFAS No. 71
to account for the effects of these regulatory decisions. As a result, we may
defer or recognize revenues and expenses differently than a non-regulated
entity.

     For example, we may record as regulatory assets items that a non-regulated
entity normally would expense if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, we may record as
regulatory liabilities items that non-regulated entities may normally recognize
as revenues if the actions of the regulator indicate they will require that such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. At
December 31, 2006, we had $2.316 billion recorded as regulatory assets and
$1.954 billion recorded as regulatory liabilities.


                                     CMS-16

<PAGE>

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

     FINANCIAL INSTRUMENTS: Debt and equity securities classified as available-
for-sale are reported at fair value determined from quoted market prices. Debt
and equity securities classified as held-to-maturity are reported at cost.

     Unrealized gains or losses resulting from changes in fair value of certain
available-for-sale debt and equity securities are reported, net of tax, in
equity as part of AOCL. Unrealized gains or losses are excluded from earnings
unless the related changes in fair value are determined to be other than
temporary. Unrealized gains or losses on our nuclear decommissioning investments
are reflected as regulatory liabilities on our Consolidated Balance Sheets.
Realized gains or losses would not affect our consolidated earnings or cash
flows.

     DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if
certain contracts must be accounted for as derivative instruments. These
criteria are complex and significant judgment is often required in applying the
criteria to specific contracts. If a contract is a derivative, it is recorded on
our consolidated balance sheet at its fair value. We then adjust the resulting
asset or liability each quarter to reflect any change in the market value of the
contract, a practice known as marking the contract to market. For additional
details on accounting for derivatives, see Note 6, Financial and Derivative
Instruments.

     To determine the fair value of our derivatives, we use information from
external sources (i.e., quoted market prices and third-party valuations), if
available. For certain contracts, this information is not available and we use
mathematical valuation models to value our derivatives. These models require
various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. Changes in
forward prices or volatilities could significantly change the calculated fair
value of our derivative contracts. The cash returns we actually realize on these
contracts may vary, either positively or negatively, from the results that we
estimate using these models. As part of valuing our derivatives at market, we
maintain reserves, if necessary, for credit risks arising from the financial
condition of our counterparties.

     The following table summarizes the interest rate and volatility rate
assumptions we used to value these contracts at December 31, 2006:


<Table>
<Caption>
                                                      INTEREST RATES (%)   VOLATILITY RATES (%)
                                                      ------------------   --------------------

<S>                                                   <C>                  <C>

Gas-related option contracts........................         5.00                 51 - 62
Electricity-related option contracts................         5.00                44 - 104
</Table>


     The types of contracts we typically classify as derivative instruments are
interest rate swaps, gas supply options, certain gas and electric forward
contracts, electric and gas options, electric swaps, and foreign currency
exchange contracts. The majority of our commodity purchase and sale contracts
are not subject to derivative accounting under SFAS No. 133 because:

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

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

     - there is not an active market for the commodity.

     Our coal purchase contracts are not derivatives because there is not an
active market for the coal we purchase. If an active market for coal develops in
the future, some of these contracts may qualify as derivatives and the resulting
mark-to-market impact on earnings could be material.

     Establishment of the Midwest Energy Market: In 2005, the MISO began
operating the Midwest Energy Market. As of December 31, 2006, we have determined
that, due to the increased liquidity for electricity within the Midwest Energy
Market since its inception, it is our best judgment that this market should be
considered an active market, as defined by SFAS No. 133. This conclusion does
not impact how we account for our electric capacity and energy contracts,
however, because these contracts qualify for the normal purchases and sales
exception and, as a result, are not required to be marked-to-market.

     Derivatives Associated with the MCV Partnership: In November 2006, we sold
our interest in the MCV Partnership. In conjunction with that sale, our interest
in all of the MCV Partnership's long-term gas contracts and

                                     CMS-17

<PAGE>

related futures, options, and swaps was sold. Before the sale, we accounted for
certain long-term gas contracts and all of the related futures, options, and
swaps as derivatives.

     Certain of these derivatives, specifically the long-term gas contracts, the
options, and a portion of the futures and swaps, did not qualify for cash flow
hedge accounting treatment. As such, we recorded the mark-to-market gains and
losses from these derivatives in earnings each quarter. The gains and losses
recorded in earnings during 2006, through the date of the sale, were as follows:


<Table>
<Caption>
                                                                    2006
                                               ---------------------------------------------
                                                FIRST     SECOND    THIRD     FOURTH
                                               QUARTER   QUARTER   QUARTER   QUARTER   TOTAL
                                               -------   -------   -------   -------   -----
                                                                IN MILLIONS

<S>                                            <C>       <C>       <C>       <C>       <C>

Long-term gas contracts......................   $(111)     $(34)     $(16)     $10     $(151)
Related futures, options, and swaps..........     (45)       (8)      (12)      12       (53)
                                                -----      ----      ----      ---     -----
Total........................................   $(156)     $(42)     $(28)     $22     $(204)
                                                =====      ====      ====      ===     =====

</Table>


     These derivatives incurred significant mark-to-market losses in the first
three quarters of the year, due to the decrease in natural gas prices during
that time. In the fourth quarter (through the date of the sale), natural gas
prices increased, resulting in a mark-to-market gain. The overall net losses,
shown before consideration of tax effects and minority interest, are included in
the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated
Statements of Income (Loss).

     The remaining futures and swaps held by the MCV Partnership did qualify for
cash flow hedge accounting. As such, we recorded our proportionate share of the
mark-to-market gains and losses from these derivatives in AOCL each quarter. As
of the date of the sale, we had accumulated a net gain of $30 million, net of
tax and minority interest, in AOCL representing our proportionate share of the
mark-to-market gains from these cash flow hedges. After the sale, this amount
was reclassified to and recognized in earnings as a reduction of the total loss
on the sale in our Consolidated Statements of Income (Loss).

     As a result of the sale, we no longer consolidate the MCV Partnership.
Accordingly, we no longer record the fair value of the long-term gas contracts
and related futures, options, and swaps on our Consolidated Balance Sheets and
are not required to record gains or losses related to changes in the fair value
of these contracts in earnings or AOCL. For additional details on the sale of
our interest in the MCV Partnership, see the "Other Electric Utility Business
Uncertainties -- The MCV Partnership" section in this MD&A and Note 2, Asset
Sales, Impairment Charges and Discontinued Operations.

     CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts that
support CMS Energy's ongoing operations. CMS ERM holds certain contracts for the
future purchase and sale of electricity and natural gas that will result in
physical delivery of the commodity at contractual prices. These forward
contracts are generally long-term in nature and are classified as non-trading.
CMS ERM also uses various financial instruments, including swaps, options, and
futures, to manage commodity price risks associated with its forward purchase
and sale contracts and with generation assets owned by CMS Energy or its
subsidiaries. These financial contracts are classified as trading activities.

     In accordance with SFAS No. 133, non-trading and trading contracts that
qualify as derivatives are recorded at fair value on our Consolidated Balance
Sheets. The resulting assets and liabilities are marked to market each quarter,
and the changes in fair value are recorded in earnings. For trading contracts,
these gains and losses are recorded net in accordance with EITF Issue No. 02-03.
Contracts that do not meet the definition of a derivative are accounted for as
executory contracts (that is, on an accrual basis).


                                     CMS-18

<PAGE>

     We include the fair value of the derivative contracts held by CMS ERM in
either Price risk management assets or Price risk management liabilities on our
Consolidated Balance Sheets. The following tables provide a summary of these
contracts at December 31, 2006:


<Table>
<Caption>
                                                             NON-
                                                           TRADING     TRADING     TOTAL
                                                           -------     -------     -----
                                                                    IN MILLIONS

<S>                                                        <C>         <C>         <C>

Fair value of contracts outstanding at December 31,
  2005...................................................    $(63)      $ 100       $ 37
Fair value of new contracts when entered into during the
  period(a)..............................................      --         (11)       (11)
Contracts realized or otherwise settled during the
  period.................................................     117(b)     (116)(c)      1
Other changes in fair value(d)...........................     (23)        (41)       (64)
                                                             ----       -----       ----
Fair value of contracts outstanding at December 31,
  2006...................................................    $ 31       $ (68)      $(37)
                                                             ====       =====       ====

</Table>


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

(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)   During the third quarter of 2006, CMS ERM terminated certain non-trading
      gas contracts. CMS ERM had recorded derivative liabilities, representing
      cumulative unrealized mark-to-market losses, associated with these
      contracts. As the contracts are now settled, the related derivative
      liabilities are no longer included in the balance of CMS ERM's non-trading
      derivative contracts at December 31, 2006 and, as a result, that balance
      has changed significantly from December 31, 2005 and is now an asset.

(c)   During the third quarter of 2006, CMS ERM terminated certain trading gas
      contracts. CMS ERM had recorded derivative assets, representing cumulative
      unrealized mark-to-market gains, associated with these contracts. As the
      contracts are now settled, the related derivative assets are no longer
      included in the balance of CMS ERM's trading derivative contracts at
      December 31, 2006 and, as a result, that balance has changed significantly
      from December 31, 2005 and is now a liability.

(d)   Reflects changes in the fair value of contracts over the period, as well
      as increases or decreases to credit reserves.


<Table>
<Caption>
                                                            FAIR VALUE OF NON-TRADING CONTRACTS AT
                                                                       DECEMBER 31, 2006
                                                        ----------------------------------------------
                                                                      MATURITY (IN YEARS)
                                              TOTAL     ----------------------------------------------
SOURCE OF FAIR VALUE                       FAIR VALUE   LESS THAN 1   1 TO 3   4 TO 5   GREATER THAN 5
--------------------                       ----------   -----------   ------   ------   --------------
                                                                   IN MILLIONS

<S>                                        <C>          <C>           <C>      <C>      <C>

Prices actively quoted...................      $--          $--         $--      $--          $--
Prices obtained from external sources or
  based on models and other valuation
  methods................................       31           12          19       --           --
                                               ---          ---         ---      ---          ---
Total....................................      $31          $12         $19      $--          $--
                                               ===          ===         ===      ===          ===

</Table>




<Table>
<Caption>
                                                              FAIR VALUE OF TRADING CONTRACTS AT
                                                                       DECEMBER 31, 2006
                                                        ----------------------------------------------
                                                                      MATURITY (IN YEARS)
                                              TOTAL     ----------------------------------------------
SOURCE OF FAIR VALUE                       FAIR VALUE   LESS THAN 1   1 TO 3   4 TO 5   GREATER THAN 5
--------------------                       ----------   -----------   ------   ------   --------------
                                                                   IN MILLIONS

<S>                                        <C>          <C>           <C>      <C>      <C>

Prices actively quoted...................     $(40)         $(15)      $(25)     $--          $--
Prices obtained from external sources or
  based on models and other valuation
  methods................................      (28)          (22)        (6)      --           --
                                              ----          ----       ----      ---          ---
Total....................................     $(68)         $(37)      $(31)     $--          $--
                                              ====          ====       ====      ===          ===

</Table>


     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 may use various contracts to manage these
risks, including swaps, options, futures, and forward contracts. We enter into
these risk management contracts using established policies and procedures, under
the direction of both:

     - an executive oversight committee consisting of senior management
       representatives, and


                                     CMS-19

<PAGE>

     - a risk committee consisting of business unit managers.

     Our intention is to limit our exposure to risk from interest rate,
commodity price, and currency exchange rate volatility.

     These contracts contain credit risk, which is the risk that counterparties,
primarily financial institutions and energy marketers, will fail to perform
their contractual obligations. We reduce this risk through established credit
policies, which include performing financial credit reviews of our
counterparties. We determine our counterparties' credit quality using a number
of factors, including credit ratings, disclosed financial condition, and
collateral requirements. If terms permit, we use standard agreements that allow
us to net positive and negative exposures associated with the same counterparty.
Based on these policies, our current exposures, and our credit reserves, we do
not expect a material adverse effect on our financial position or future
earnings as a result of counterparty nonperformance.

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

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

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


<Table>
<Caption>
DECEMBER 31                                                         2006   2005
-----------                                                         ----   ----
                                                                    IN MILLIONS

<S>                                                                 <C>    <C>

Variable-rate financing -- before-tax annual earnings exposure....  $  4   $  4
Fixed-rate financing -- potential REDUCTION in fair value(a)......   193    223
</Table>


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

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

     Certain entities in which we have a minority interest have entered into
interest rate swaps. These instruments are not included in the sensitivity
analysis above, but can have an impact on financial results.

     Commodity Price Risk: Operating in the energy industry, we are exposed to
commodity price risk, which arises from fluctuations in the price of
electricity, natural gas, coal, and other commodities. Commodity prices are
influenced by a number of factors, including weather, changes in supply and
demand, and liquidity of commodity markets. In order to manage commodity price
risk, we enter into various non-trading derivative contracts, such as gas supply
call and put options and forward purchase and sale contracts for electricity and
natural gas. We also enter into trading derivative contracts, including electric
and gas options and swaps. For additional details on these contracts, see Note
6, Financial and Derivative Instruments.


                                     CMS-20

<PAGE>

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


<Table>
<Caption>
DECEMBER 31                                                          2006   2005
-----------                                                          ----   ----
                                                                     IN MILLIONS

<S>                                                                  <C>    <C>

Potential REDUCTION in fair value:
Non-trading contracts
  Gas supply option contracts......................................   $--    $ 1
  Fixed fuel price contracts(a)....................................     1     --
  CMS ERM gas forward contracts....................................     3     --
  Derivative contracts associated with the MCV Partnership:
     Long-term gas contracts(b)....................................    --     39
     Gas futures, options, and swaps(b)............................    --     48
Trading contracts
  Electricity-related option contracts.............................     3      2
  Electricity-related swaps........................................    --     13
  Gas-related option contracts.....................................     1      1
  Gas-related swaps and futures....................................     1      4
</Table>


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

(a)   We have entered into two contracts that, from January to September 2007,
      will fix the prices we pay for gasoline and diesel fuel used in our fleet
      vehicles and equipment. These contracts are derivatives with an immaterial
      fair value at December 31, 2006.

(b)   The potential reduction in fair value for the MCV Partnership's long-term
      gas contracts and gas futures, options, and swaps decreased to $0 as a
      result of the sale of our interest in the MCV Partnership. In conjunction
      with that sale, our interest in these contracts was also sold and, as a
      result, we no longer record the fair value of these contracts on our
      Consolidated Balance Sheets at December 31, 2006.

     Currency Exchange Risk: Our investments in foreign operations and equity
interests in various international projects expose us to currency exchange risk.
In order to protect the company from the risk associated with unfavorable
changes in currency exchange rates, which could materially affect cash flow, we
may use risk mitigating instruments. These instruments, such as forward exchange
contracts, allow us to hedge currency exchange rates. At December 31, 2006 and
2005, we had no outstanding foreign exchange contracts.

     In January and February 2007, we reached agreements and announced plans to
sell our ownership interests in businesses in the Middle East, Africa, India,
and Latin America. The sale of these investments will significantly reduce our
exposure to currency exchange risk.

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

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


<Table>
<Caption>
DECEMBER 31                                                          2006   2005
-----------                                                          ----   ----
                                                                     IN MILLIONS

<S>                                                                  <C>    <C>

Potential REDUCTION in fair value of available-for-sale equity
  securities (primarily SERP investments):.........................   $6     $5
</Table>


     Consumers maintains trust funds, as required by the NRC, for the purpose of
funding certain costs of nuclear plant decommissioning. These funds are invested
primarily in equity securities, fixed-rate, fixed-income debt securities, and
cash and cash equivalents, and are recorded at fair value on our Consolidated
Balance Sheets. These investments are exposed to price fluctuations in equity
markets and changes in interest rates. Because the accounting for nuclear plant
decommissioning recognizes that costs are recovered through Consumers' electric
rates, fluctuations in equity prices or interest rates do not affect our
consolidated earnings or cash flows.


                                     CMS-21

<PAGE>

     For additional details on market risk and derivative activities, see Note
6, Financial and Derivative Instruments. For additional details on nuclear plant
decommissioning at Big Rock and Palisades, see the "Other Electric Utility
Business Uncertainties -- Nuclear Matters" section included in this MD&A.

ACCOUNTING FOR PENSION AND OPEB

     Pension: We have external trust funds to provide retirement pension
benefits to our employees under a non-contributory, defined benefit Pension
Plan. On September 1, 2005, the defined benefit Pension Plan was closed to new
participants and we implemented the DCCP, which provides an employer
contribution of 5 percent of base pay to the existing Employees' Savings Plan.
An employee contribution is not required to receive the plan's employer cash
contribution. All employees hired on and after September 1, 2005 participate in
this plan as part of their retirement benefit program. Previous cash balance
pension plan participants also participate in the DCCP as of September 1, 2005.
Additional pay credits under the cash balance pension plan were discontinued as
of that date.

     401(k): We resumed the employer's match in CMS Energy Common Stock in our
401(k) Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled
in the company's 401(k) Savings Plan had their employer match increased from 50
percent to 60 percent on eligible contributions up to the first six percent of
an employee's wages.

     Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be
an investment option available for new investments in the 401(k) Savings Plan
and the employer's match will no longer be in CMS Energy Common Stock.
Participants will have the opportunity to reallocate investments in CMS Energy
Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any
remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds
will be reallocated to other plan investment options. At February 20, 2007,
there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy
Stock Fund.

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

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

     - life expectancies,

     - present-value discount rates,

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

     - rate of compensation increases, and

     - anticipated health care costs.

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

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


<Table>
<Caption>
EXPECTED COSTS                                      PENSION COST   OPEB COST   CONTRIBUTIONS
--------------                                      ------------   ---------   -------------
                                                                   IN MILLIONS

<S>                                                 <C>            <C>         <C>

2007..............................................      $109          $44           $160
2008..............................................       105           41             51
2009..............................................       113           39             51
</Table>


     Actual future pension cost and contributions will depend on future
investment performance, changes in future discount rates and various other
factors related to the populations participating in the Pension Plan.

     Lowering the expected long-term rate of return on the Pension Plan assets
by 0.25 percent (from 8.25 percent to 8.00 percent) would increase estimated
pension cost for 2007 by $2 million. Lowering the discount rate by 0.25 percent
(from 5.65 percent to 5.40 percent) would increase estimated pension cost for
2007 by $1 million.


                                     CMS-22

<PAGE>

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

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

     SFAS No. 143, as clarified by FASB Interpretation No. 47, requires
companies to record the fair value of the cost to remove assets at the end of
their useful lives, if there is a legal obligation to remove them. We have legal
obligations to remove some of our assets, including our nuclear plants, at the
end of their useful lives. For Consumers, as required by SFAS No. 71, we account
for the implementation of this standard by recording regulatory assets and
liabilities instead of a cumulative effect of a change in accounting principle.

     The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made.

     If a reasonable estimate of fair value cannot be made in the period in
which the ARO is incurred, such as for assets with indeterminate lives, the
liability is recognized when a reasonable estimate of fair value can be made.
Generally, electric and gas transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets or associated obligations related to potential future
abandonment. In addition, 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 include use of
decommissioning studies that largely utilize third-party cost estimates. For
additional details see Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase
Agreement," and Note 8, Asset Retirement Obligations.

ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS

     The MPSC and the FERC regulate the recovery of costs to decommission, or
remove from service, our Big Rock and Palisades nuclear plants. 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 assist us in
developing decommissioning cost estimates. We use various inflation rates for
labor, non-labor, and contaminated equipment disposal costs 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 spent
nuclear fuel from the sites, as required by the Nuclear Waste Policy Act of
1982.

     We have 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. The decommissioning trust funds include equities and fixed-
income investments. Equities are converted to fixed-income investments during
decommissioning, and fixed-income investments are converted to cash as needed.
The costs of decommissioning these sites and the adequacy of the trust funds
could be affected by:

     - variances from expected trust earnings,

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

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

     Based on current projections, the current level of funds provided by the
trusts is not adequate to fund fully the decommissioning of Big Rock. This is
due in part to the DOE's failure to accept the spent nuclear fuel on schedule

                                     CMS-23

<PAGE>

and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation. For
additional details, see Note 3, Contingencies, "Other Consumers' Electric
Utility Contingencies -- The Sale of Nuclear Assets and the Palisades Power
Purchase Agreement," "Nuclear Plant Decommissioning" and "Nuclear Matters," and
Note 8, Asset Retirement Obligations.

CAPITAL RESOURCES AND LIQUIDITY

     Factors affecting our liquidity and capital requirements are:

     - results of operations,

     - capital expenditures,

     - energy commodity and transportation costs,

     - contractual obligations,

     - regulatory decisions,

     - debt maturities,

     - credit ratings,

     - working capital needs, and

     - collateral requirements.

     During the summer months, we purchase natural gas and store it for resale
primarily during the winter heating season. Although our prudent natural gas
costs are recoverable from our customers, the amount paid for natural gas stored
as inventory requires additional liquidity due to the lag in cost recovery. We
have credit agreements with our commodity suppliers containing terms that have
previously resulted in margin calls. While we currently have no outstanding
margin calls associated with our natural gas purchases, they may be required if
agency ratings are lowered or if market conditions become unfavorable relative
to our obligations to those parties.

     Our current financial plan includes controlling operating expenses and
capital expenditures, executing on asset sales and evaluating market conditions
for financing opportunities, if needed.

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

     - our current level of cash and revolving credit facilities,

     - our anticipated cash flows from operating and investing activities,
       including asset sales, and

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

     In the second quarter of 2006, Moody's affirmed our liquidity rating and
revised the credit rating outlook for Consumers to stable from negative. In the
third quarter of 2006, Moody's upgraded Consumers' and CMS Energy's credit
ratings.

     In January 2007, the Board of Directors voted to reinstate a quarterly
common stock dividend of $0.05 per share, for the first quarter of 2007. The
dividend is payable February 28, 2007 to shareholders of record on February 7,
2007.

CASH POSITION, INVESTING, AND FINANCING

     Our operating, investing, and financing activities meet consolidated cash
needs. At December 31, 2006, $422 million consolidated cash was on hand, which
includes $71 million of restricted cash and $5 million from entities
consolidated pursuant to FASB Interpretation No. 46(R). For additional details,
see Note 16, Consolidation of Variable Interest Entities.

     Our primary ongoing source of cash is dividends and other distributions
from our subsidiaries. For the year ended December 31, 2006, Consumers paid $147
million in common stock dividends to CMS Energy.


                                     CMS-24

<PAGE>

SUMMARY OF CASH FLOWS:


<Table>
<Caption>
                                                              2006    2005    2004
                                                              ----    ----    ----
                                                                  IN MILLIONS

<S>                                                          <C>     <C>     <C>

Net cash provided by (used in):
  Operating activities.....................................  $ 688   $ 599   $ 353
  Investing activities.....................................   (751)   (494)   (347)
                                                             -----   -----   -----
Net cash provided by (used in) operating and investing
  activities...............................................    (63)    105       6
  Financing activities.....................................   (434)     74     (43)
Effect of exchange rates on cash...........................      1      (1)     --
                                                             -----   -----   -----
Net Increase (Decrease) in Cash and Cash Equivalents.......  $(496)  $ 178   $ (37)
                                                             =====   =====   =====

</Table>


OPERATING ACTIVITIES:

     2006: Net cash provided by operating activities was $688 million, an
increase of $89 million versus 2005. This was the result of a decrease in
accounts receivable, reduced inventory purchases, cash proceeds from the sale of
excess sulfur dioxide allowances, and a return of funds formerly held as
collateral under certain gas hedging arrangements. These changes were offset
partially by decreases in the MCV Partnership gas supplier funds on deposit. The
decrease in accounts receivable was primarily due to the collection of
receivables in 2006 reflecting higher gas prices billed during the latter part
of 2005 and reduced billings in the latter part of 2006 due to milder weather.
The decrease in the MCV Partnership gas supplier funds on deposit was the result
of refunds to suppliers from decreased exposure due to declining gas prices in
2006.

     2005: Net cash provided by operating activities was $599 million, an
increase of $246 million versus 2004. Included in cash provided by operations is
an insurance settlement, a decrease in prepaid gas margin call costs, the
positive effect of rising gas prices on accounts payable and the MCV Partnership
gas supplier funds on deposit, and other timing differences. These increases
were offset partially by the negative effect of rising gas prices on accounts
receivable and inventories.

INVESTING ACTIVITIES:

     2006: Net cash used in investing activities was $751 million, an increase
of $257 million versus 2005. This was primarily due to cash relinquished from
the sale of assets, the absence of short-term investment proceeds, an increase
in capital expenditures and cost to retire property, and an increase in non-
current notes receivable. This activity was offset by the release of restricted
cash in February 2006, which we used to extinguish long-term debt -- related
parties.

     2005: Net cash used in investing activities was $494 million, an increase
of $147 million versus 2004. This was primarily due to an increase in restricted
cash and restricted short-term investments combined with a decrease in proceeds
from asset sales. These changes were offset partially by a net increase in
short-term investment proceeds and a decrease in investments in unconsolidated
subsidiaries. The increase in restricted cash and restricted short-term
investments was due to a deposit made with a trustee for extinguishing the
current portion of long-term debt -- related parties.

FINANCING ACTIVITIES:

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

     2005: Net cash provided by financing activities was $74 million, an
increase of $117 million versus 2004. This was primarily due to a decrease in
debt retirements of $122 million.

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


                                     CMS-25

<PAGE>

OBLIGATIONS AND COMMITMENTS

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


<Table>
<Caption>
                                                                PAYMENTS DUE
                                        -----------------------------------------------------------
CONTRACTUAL OBLIGATIONS AT                        LESS THAN      ONE TO      THREE TO     MORE THAN
DECEMBER 31, 2006                        TOTAL     ONE YEAR   THREE YEARS   FIVE YEARS   FIVE YEARS
--------------------------               -----    ---------   -----------   ----------   ----------
                                                                IN MILLIONS

<S>                                     <C>       <C>         <C>           <C>          <C>

Long-term debt(a).....................  $ 6,753     $  401       $1,651       $1,013       $ 3,688
Long-term debt -- related parties(a)..      178         --           --           --           178
Interest payments on long-term
  debt(b).............................    2,972        403          652          473         1,444
Capital leases(c).....................       55         13           14           10            18
Interest payments on capital
  leases(d)...........................       26         --            9            6            11
Operating leases(e)...................      164         25           44           34            61
Purchase obligations(f)...............   16,334      2,118        2,109        1,661        10,446
                                        -------     ------       ------       ------       -------
  Total contractual obligations.......  $26,482     $2,960       $4,479       $3,197       $15,846
                                        =======     ======       ======       ======       =======

</Table>


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

(a)   Principal amounts due on outstanding debt obligations, current and long-
      term, at December 31, 2006. For additional details on long-term debt, see
      Note 4, Financings and Capitalization.

(b)   Currently scheduled interest payments on both variable and fixed rate
      long-term debt and long-term debt -- related parties, current and long-
      term. Variable interest payments are based on contractual rates in effect
      at December 31, 2006.

(c)   Minimum lease payments under our capital leases, comprised mainly of
      leased service vehicles, leased office furniture, and certain power
      purchase agreements.

(d)   Imputed interest in the capital leases.

(e)   Minimum noncancelable lease payments under our leases of railroad cars,
      certain vehicles, and miscellaneous office buildings and equipment, which
      are accounted for as operating leases.

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

      - natural gas and associated transportation,

      - electricity, and

      - coal and associated transportation.

     Our purchase obligations include long-term power purchase agreements with
various generating plants, which require us to make monthly capacity payments
based on the plants' availability or deliverability. These payments will
approximate $42 million per month during 2007. If a plant is not available to
deliver electricity, we are not obligated to make these payments to the plant
for that period of time. For additional details on power supply costs, see
"Electric Utility Results of Operations" within this MD&A and Note 3,
Contingencies, "Consumers' Electric Utility Rate Matters -- Power Supply Costs."

     REVOLVING CREDIT FACILITIES: At December 31, 2006, CMS Energy had $202
million available and Consumers had $742 million available in secured revolving
credit facilities. The facilities are available for general corporate purposes,
working capital, and letters of credit. For additional details on revolving
credit facilities, see Note 4, Financings and Capitalization.

     OFF-BALANCE SHEET ARRANGEMENTS: CMS Energy and certain of its subsidiaries
enter into various arrangements in the normal course of business to facilitate
commercial transactions with third parties. These arrangements include
indemnifications, letters of credit, surety bonds, and financial and performance
guarantees.


                                     CMS-26

<PAGE>

     We enter into agreements containing indemnifications standard in the
industry and indemnifications specific to a transaction, such as the sale of a
subsidiary. Indemnifications are usually agreements to reimburse other companies
if those companies incur losses due to third-party claims or breach of contract
terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a
third-party. Letters of credit substitute the bank's credit for ours and reduce
credit risk for the third-party beneficiary. We monitor these obligations and
believe it is unlikely that we would be required to perform or otherwise incur
any material losses associated with these guarantees.

     In February 2007, we reached an agreement to sell our ownership interests
in businesses in the Middle East, Africa, and India to TAQA. The proposed
agreement calls for TAQA to either arrange for substitute guarantee agreements
to replace our contingent obligations related to our project-financing security
agreements or assume all of our contingent obligations under such agreements.
For more details on the sale of our ownership interests to TAQA, see Note 2,
Asset Sales, Impairment Charges and Discontinued Operations.

     For additional details on these and other guarantee arrangements, see Note
3, Contingencies, "Other Contingencies -- FASB Interpretation No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others."

     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 $1.167 billion at December 31, 2006. The timing of the
payments of non-recourse debt only affects the cash flow and liquidity of the
partnerships and joint ventures. For summarized financial information of our
investments in certain partnerships and joint ventures, see Note 13, Equity
Method Investments.

     Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, Consumers may sell up to $325 million of certain accounts receivable.
The highly liquid and efficient market for securitized financial assets provides
a lower cost source of funding compared to unsecured debt. For additional
details, see Note 4, Financings and Capitalization.

     DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4,
Financings and Capitalization.

     CAPITAL EXPENDITURES: We estimate that we will make the following capital
expenditures, including new lease commitments, during 2007 through 2009. We
prepare these estimates for planning purposes. Periodically, we review these
estimates and may revise them due to a number of factors including environmental
regulations, business opportunities, market volatility, economic trends, and the
ability to access capital.


<Table>
<Caption>
YEARS ENDING DECEMBER 31                                       2007   2008   2009
------------------------                                       ----   ----   ----
                                                                   IN MILLIONS

<S>                                                            <C>    <C>    <C>

Electric utility operations(a)(b)............................  $618   $487   $455
Gas utility operations(b)....................................   164    216    274
Enterprises..................................................    65     92    124
                                                               ----   ----   ----
                                                               $847   $795   $853
                                                               ====   ====   ====

</Table>


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

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

(b)   These amounts include estimates for capital expenditures related to
      information technology projects, facility improvements, and vehicle
      leasing.

OUTLOOK

CORPORATE OUTLOOK

     Over the next few years, our primary business strategy will focus on the
successful completion of announced asset sales, continued investment in our
utility business, reducing parent debt, and growing earnings while controlling
operating costs.

     In November 2006, we announced a reorganization of our utility business to
improve operating efficiency, reliability, and customer service.


                                     CMS-27

<PAGE>

     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. In 2007, we have begun to exit the international
marketplace. We reached agreements and announced plans to sell our ownership
interests in businesses in the Middle East, Africa, India, and Latin America. We
plan to use the proceeds from the pending asset sales to invest in our utility
business and reduce parent company debt. We will continue to optimize the value
of our North American non-utility assets.

     As a result of the reorganization at our utility business, we may incur
charges in 2007. Completion of planned asset sales may also result in additional
charges in 2007. We are unable to estimate the timing or extent of these
charges.

     In January 2007, we reinstated a dividend on our common stock after a four-
year suspension. The dividend is $0.05 per share for the first quarter of 2007.

ELECTRIC UTILITY BUSINESS OUTLOOK

     GROWTH: Temperatures in the summer of 2006 were higher than historical
averages yet lower than in the summer of 2005. Industrial activity declined
during 2006 compared with 2005. These factors resulted in a decline of one
percent in annual electric deliveries, excluding transactions with other
wholesale market participants and other electric utilities. In 2007, we project
electric deliveries to grow less than one-half of one percent compared to the
levels experienced in 2006. This short-term outlook for 2007 assumes a small
decline in industrial economic activity and normal weather conditions throughout
the year.

     Over the next five years, we expect electric deliveries to grow at an
average rate of less than 1.5 percent a year. However, this is dependent on a
modestly growing customer base and a stabilizing Michigan economy after 2007.
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 the following:

     - fluctuations in weather conditions and

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

     ELECTRIC RESERVE MARGIN: We are planning for a reserve margin of
approximately 11 percent for summer 2007, or supply resources equal to 111
percent of projected firm summer peak load. Of the 2007 supply resources target
of 111 percent, we expect 96 percent to come from our electric generating plants
and long-term power purchase contracts, and 15 percent to come from other
contractual arrangements. We have purchased capacity and energy contracts
covering partially the estimated reserve margin requirements for 2007 through
2010. As a result, we recognized an asset of $62 million for unexpired capacity
and energy contracts at December 31, 2006. Upon the completion of the sale of
the Palisades plant, the 15-year power purchase agreement with Entergy for 100
percent of the plant's current electric output will offset the reduction in the
owned capacity represented by the Palisades plant.

     The MCV PPA is unaffected by the sale of our interest in the MCV
Partnership. After September 15, 2007, we expect to exercise the regulatory out
provision in the MCV PPA. If we are successful, the MCV Partnership has the
right to terminate the MCV PPA, which could affect our reserve margin status.
The MCV PPA represents 13 percent of our 2007 supply resources target.

     ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission
service to us, increased substantially the transmission rates it charged us in
2006. The revenue collected by METC under those rates is subject to refund
pending a FERC ruling. In January 2007, a settlement agreement among the parties
was filed with the FERC resolving all issues associated with the rates METC
charged us in 2006. This settlement, if approved by the FERC, will result in a
refund of 2006 transmission charges of $18 million and a corresponding reduction
of our power supply costs.

     In August 2006, the MPSC approved recovery of the increased METC electric
transmission costs included in our 2006 PSCR plan. Due to the delay in recovery,
we were unable to collect these increased costs in a timely manner

                                     CMS-28

<PAGE>

and our cash flows from electric utility operations were affected negatively.
For additional details, see Note 3, Contingencies, "Consumers' Electric Utility
Rate Matters -- Power Supply Costs."

     CUSTOMER REVENUE OUTLOOK: Our electric utility customer base includes a mix
of residential, commercial, and diversified industrial customers. In 2006,
Michigan's automotive industry experienced negative developments resulting in
manufacturing facility closures and restructurings. Our electric utility
operations are not dependent upon a single customer, or even a few customers,
and customers in the automotive sector constitute five percent of our total 2006
electric revenue. In addition, returning former ROA industrial customers benefit
our electric utility revenue. However, we cannot predict the impact of current
or possible future restructuring plans or possible future actions by our
industrial customers.

     21ST CENTURY ENERGY PLAN: In January 2006, the MPSC Staff issued a report
on future electric capacity in the state of Michigan. The report indicated that
existing generation resources are adequate in the short term, but could be
insufficient to maintain reliability standards by 2009. The MPSC Staff
recommended a review process for proposed new power plants. In January 2007, the
chairman of the MPSC expanded on the capacity need work conducted by the MPSC
Staff and proposed three major policy initiatives to the governor of Michigan.
The initiatives involve the use of more renewable energy resources by all load-
serving entities such as Consumers, the creation of an energy efficiency
program, and a procedure for reviewing proposals to construct new generation
facilities. The January 2007 proposal indicated that Michigan needs new baseload
generation by 2015 and recommends regulatory measures to make it easier to
predict customer demand and revenues. The proposed initiatives will require
changes to current legislation. We will continue to participate as the MPSC,
legislature, and other stakeholders addresses future electric capacity needs.

ELECTRIC UTILITY BUSINESS UNCERTAINTIES

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

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

     Clean Air Act: Compliance with the federal Clean Air Act and resulting
regulations continues to be a significant focus for us. The Nitrogen Oxide State
Implementation Plan requires significant reductions in nitrogen oxide emissions.
To comply with the regulations, we expect to incur capital expenditures totaling
$835 million. These expenditures include installing selective catalytic
reduction control technology on four of our coal-fired generating units. The key
assumptions 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

     - an AFUDC capitalization rate.

     Our current capital cost estimates include an escalation rate of 2.6
percent and an AFUDC capitalization rate of 7.8 percent. As of December 2006, we
have incurred $688 million in capital expenditures to comply with the federal
Clean Air Act and resulting regulations and anticipate that the remaining $147
million of capital expenditures will be made in 2007 through 2011.

     In addition to modifying coal-fired electric generating plants, our
compliance plan includes the use of nitrogen oxide emission allowances until all
of the control equipment is operational in 2011. The nitrogen oxide emission
allowance annual expense is projected to be $3 million per year, which we expect
to recover from our customers through the PSCR process. The projected annual
expense is based on market price forecasts and forecasts of regulatory
provisions, known as progressive flow control, that restrict the usage in any
given year of allowances

                                     CMS-29

<PAGE>

banked from previous years. The allowances and their cost are accounted for as
inventory. The allowance inventory is expensed at the rolling average cost as
the coal-fired electric generating plants emit nitrogen oxide.

     Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air
Interstate Rule that requires additional coal-fired electric generating plant
emission controls for nitrogen oxides and sulfur dioxide. We plan to meet this
rule by year-round operation of our selective catalytic reduction control
technology units and installation of flue gas desulfurization scrubbers at an
estimated total cost of $955 million, to be incurred by 2014. The rule may also
require us to purchase additional nitrogen oxide allowances beginning in 2009.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.4 percent. We will need to acquire additional
sulfur dioxide emission allowances for an average annual cost of $21 million per
year for the years 2011 through 2014.

     Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air
Mercury Rule, which requires initial reductions of mercury emissions from coal-
fired electric generating plants by 2010 and further reductions by 2018. Based
on current technology, we anticipate our capital costs for mercury emissions
reductions required by Phase I of the Clean Air Mercury Rule to be less than $50
million and expect these reductions to be implemented by 2010. Phase II
requirements of the Clean Air Mercury Rule are not yet known and a cost estimate
has not been determined.

     In April 2006, Michigan's governor announced a plan that would result in
mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ
on the details of these rules. We will develop a cost estimate when the details
of these rules are determined.

     Greenhouse gases: Several legislative proposals have been introduced in the
United States Congress that would require reductions in emissions of greenhouse
gases, including carbon dioxide. We cannot predict whether any of these
proposals will be enacted, or the specific requirements of any of these
proposals and their effect on our future operations and financial results. In
addition, the U.S. Supreme Court has agreed to hear a case claiming that the EPA
is required by the Clean Air Act to consider regulating carbon dioxide emissions
from automobiles. The EPA asserts that it lacks authority to regulate carbon
dioxide emissions. If the Supreme Court finds that the EPA has authority to
regulate carbon dioxide emissions in this case, it could result in new federal
carbon dioxide regulations for other industries, including the utility industry.

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

     Water: In March 2004, the EPA issued rules that govern electric generating
plant cooling water intake systems. The rules require significant reduction in
fish killed by operating equipment. EPA compliance options in the rule were
challenged in court. In January 2007, the court rejected many of the compliance
options favored by industry and remanded the bulk of the rule back to the EPA
for reconsideration. The court's ruling is expected to increase significantly
the cost of complying with this rule. However, the cost to comply will not be
known until the EPA's reconsideration is complete. At this time, the EPA has not
established a schedule to address the court decision.

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

     COMPETITION AND REGULATORY RESTRUCTURING: The Customer Choice Act allows
all of our electric customers to buy electric generation service from us or from
an alternative electric supplier. At December 31, 2006, alternative electric
suppliers were providing 300 MW of generation service to ROA customers. This is
3 percent of our total distribution load and represents a decrease of 46 percent
of ROA load compared to the end of December 2005. In prior orders, the MPSC
approved recovery of Stranded Costs incurred from 2002 through 2003 through a
surcharge assessed to ROA customers. It is difficult to predict future ROA
customer trends and their impact on the timely recovery of our Stranded Costs.


                                     CMS-30

<PAGE>

     ELECTRIC RATE CASE: We expect to file an electric rate case in March 2007.

     For additional details and material changes relating to the restructuring
of the electric utility industry and electric rate matters, see Note 3,
Contingencies, "Consumers' Electric Utility Rate Matters."

OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES

     THE MCV PARTNERSHIP: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990.

     Sale of our Interest in the MCV Partnership and the FMLP: In November 2006,
we sold 100 percent of our ownership interest in MCV GP II (the successor of CMS
Midland, Inc.) and 100 percent of our ownership interest in the stock of CMS
Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland
Capital Energy Investments for $60.5 million. These Consumers subsidiaries held
our interests in the MCV Partnership and the FMLP. The sales agreement calls for
the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy
Investments, to pay $85 million, subject to certain conditions and reimbursement
rights, if Dow terminates an agreement under which the MCV Partnership provides
it power and steam. The purchaser secured their reimbursement obligation with an
irrevocable letter of credit of up to $85 million. The MCV PPA and the
associated customer rates are unaffected by the sale. The transaction resulted
in a net after-tax loss of $41 million, which includes the reversal of $30
million, into earnings, of certain cumulative amounts of the MCV Partnership
derivative fair value changes that we accounted for in AOCL. For additional
details on the sale of our interests in the MCV Partnership and the FMLP, see
Note 2, Asset Sales, Impairment Charges and Discontinued Operations and Note 6,
Financial and Derivative Instruments, "Derivative Contracts Associated with the
MCV Partnership."

     Underrecoveries related to the MCV PPA: The cost that we incur under the
MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we
incurred cash underrecoveries of capacity and fixed energy payments of $57
million in 2006 and we estimate cash underrecoveries of $39 million in 2007.
However, we use the direct savings from the RCP, after allocating a portion to
customers, to offset a portion of our capacity and fixed energy underrecoveries
expense. After September 15, 2007, we expect to claim relief under the
regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed
energy payments to the MCV Partnership to the amounts that we collect from our
customers. This action would eliminate our underrecoveries of capacity and fixed
energy payments.

     The MCV Partnership has notified us that it takes issue with our intended
exercise of the regulatory out provision after September 15, 2007. We believe
that the provision is valid and fully effective, but cannot assure that it will
prevail in the event of a dispute. If we are successful in exercising the
regulatory out provision, the MCV Partnership has the right to terminate the MCV
PPA. If the MCV Partnership terminates the MCV PPA, we would seek to replace the
lost capacity to maintain an adequate electric reserve margin. This could
involve entering into a new PPA and (or) entering into electric capacity
contracts on the open market. We cannot predict our ability to enter into such
contracts at a reasonable price. We are also unable to predict regulatory
approval of the terms and conditions of such contracts, or that the MPSC would
allow full recovery of our incurred costs.

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

     NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006, we reached an
agreement to sell Palisades to Entergy for $380 million and pay Entergy $30
million to assume ownership and responsibility for the Big Rock Independent
Spent Fuel Storage Installation (ISFSI). Under the agreement, if the transaction
does not close by March 1, 2007, there is a reduction in the purchase price of
approximately $80,000 per day, with additional costs if the transaction does not
close by June 1, 2007. Based on the MPSC's published schedule for the contested
case proceedings regarding this transaction, we target to close on the
transaction in the second quarter of 2007. We estimate that the Palisades sale
will result in a $31 million premium above the Palisades asset values at the
anticipated closing date after accounting for estimated sales-related costs. We
expect that this premium will benefit our customers.

     Entergy will assume responsibility for the future decommissioning of the
plant and for storage and disposal of spent nuclear fuel located at the
Palisades and the Big Rock ISFSI sites. At the anticipated date of close, we
estimate decommissioning trust assets to be $605 million. We will retain $205
million of these funds at the time of close and

                                     CMS-31

<PAGE>

will be entitled to receive a return of an additional $147 million, pending
either a favorable federal tax ruling regarding the release of the funds or, if
no such ruling is issued, after decommissioning of the Palisades site is
complete. These estimates fluctuate based on existing market conditions. The
disposition of the retained and receivable nuclear decommissioning funds is
subject to regulatory approval. We expect to use the proceeds to benefit our
customers. We plan to use the cash that we retain from the sale to reduce
utility debt.

     As part of the transaction, Entergy will sell us 100 percent of the plant's
output up to its current capacity of 798 MW under a 15-year power purchase
agreement. The sale is subject to various regulatory approvals, including the
MPSC's approval of the power purchase agreement and the NRC's approval of the
transfer of the operating license to Entergy and other related matters. In
February 2007, the FERC issued an order approving the sale of power to us under
the power purchase agreement and granted other related approvals, with what we
believe are minor exceptions and conditions that we believe can be adequately
accepted. In October 2006, the Federal Trade Commission issued a notice that
neither it nor the DOJ's Antitrust Division plan to take enforcement action on
the sale. The final purchase price will be subject to various closing
adjustments such as working capital and capital expenditure adjustments,
adjustments for nuclear fuel usage and inventory, and the date of closing. We
cannot predict with certainty whether or when satisfaction of the closing
conditions will occur or whether or when completion of the transaction will
occur.

     We have notified the NMC that we plan to terminate the NMC's operation of
Palisades, if the sale is completed, which would require us to pay the NMC an
estimated $12 million. Due to the regulatory approvals pending, we have not
recorded this contingent obligation.

     For additional details on sale of Palisades and the Big Rock ISFSI, see
Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies -- The
Sale of Nuclear Assets and the Palisades Power Purchase Agreement."

     Big Rock: Dismantlement and decommissioning of the Big Rock Plant was
completed in August 2006. In November 2006, we requested the NRC to release
approximately 435 acres from the terms of our operating license. In January
2007, the NRC approved our request to release the 435 acres for unrestricted
public use. An area of approximately 107 acres including the Big Rock ISFSI,
where eight casks loaded with spent fuel and other high-level radioactive
material are stored, is part of the sale of nuclear assets as previously
described.

     Palisades: The amount of spent nuclear fuel at Palisades exceeds the
plant's temporary onsite wet storage pool capacity. We are using dry casks for
temporary onsite dry storage to supplement the wet storage pool capacity.

     Palisades' original license from the NRC was scheduled to expire in 2011.
In March 2005, the NMC, which operates the Palisades plant, applied for a 20-
year license renewal for the plant on behalf of Consumers. In January 2007, the
NRC renewed the Palisades operating license for 20 years, extending it to 2031.

     For additional details on nuclear plant decommissioning at Big Rock and
Palisades, see Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies -- Nuclear Plant Decommissioning."

GAS UTILITY BUSINESS OUTLOOK

     GROWTH: In 2007, we project gas deliveries will decline slightly, on a
weather-adjusted basis, from 2006 levels due to continuing conservation and
overall economic conditions in the state of Michigan. Over the next five years,
we expect gas deliveries to decline by less than one-half of one percent
annually. Actual gas deliveries in future periods may be affected by:

     - fluctuations in weather conditions,

     - use by independent power producers,

     - competition in sales and delivery,

     - changes in gas commodity prices,

     - Michigan economic conditions,

     - the price of competing energy sources or fuels,


                                     CMS-32

<PAGE>

     - gas consumption per customer, and

     - improvements in gas appliance efficiency.

GAS UTILITY BUSINESS UNCERTAINTIES

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

     GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. For additional details, see Note 3, Contingencies, "Consumers' Gas
Utility Contingencies -- Gas Environmental Matters."

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

     GAS DEPRECIATION: We are required to file our next gas depreciation case
with the MPSC within 90 days after the MPSC issuance of a final order in the
pending case related to ARO accounting. We cannot predict when the MPSC will
issue a final order in the ARO accounting case.

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

     2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC
seeking an 11.25 percent authorized return on equity along with an $88 million
annual increase in our gas delivery and transportation rates. We have proposed
the use of a Revenue Decoupling and Conservation Incentive Mechanism for
residential and general service rate classes to help assure a reasonable
opportunity to recover costs that do not fluctuate with volumetric changes.

ENTERPRISES OUTLOOK

     Our primary focus with respect to our non-utility businesses is to optimize
cash flow and further reduce our business risk and leverage through the sale of
non-strategic assets.

     In January 2007, we signed a binding letter of intent with Lucid Energy,
LLC to sell a portfolio of our businesses in Argentina and our northern Michigan
non-utility natural gas assets for $180 million. The assets being sold include
all of our electric generating plant interests in Argentina and our interest in
the TGM natural gas pipeline business in Argentina. We will maintain our
interest in the TGN natural gas business in Argentina, which remains subject to
a potential sale to the government of Argentina. We  presently plan to retain
our interest in TGN until such time as any interest or option held by the
Argentine government expires. In Michigan, the sale includes the Antrim natural
gas processing plant, 155 miles of associated gathering lines, and interests in
three special purpose gas transmission pipelines that total 110 miles. We expect
to close on the sale in the first half of 2007.

     In February 2007, we entered into an Agreement of Purchase and Sale with
TAQA to sell our ownership interest in businesses in the Middle East, Africa,
and India for $900 million. Businesses included in the sale are Taweelah,
Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We expect to close on the
sale in the middle of 2007.

     In February 2007, we signed a memorandum of understanding with Petroles de
Venezuela, S.A. to sell our ownership interest in SENECA and certain associated
generating equipment for $106 million. We expect to close on the sale by March
31, 2007.

     We anticipate gross proceeds from these sale transactions to total
approximately $1.186 billion. The book value of these assets at December 31,
2006 is approximately $913 million. The asset book values will vary between
December 31, 2006 and each transaction's closing date. Final book value is
dependent upon the timing of closing,

                                     CMS-33

<PAGE>

results of operations for certain of the assets up to closing, and other
factors. The cumulative currency translation losses at December 31, 2006 related
to all of our business in Argentina are $256 million, net of tax.

     We also announced plans to conduct an auction to sell our Atacama combined
gas pipeline and power generation businesses in Argentina and Chile, our
electric generating plant in Jamaica, and our CPEE electric distribution
business in Brazil. We expect to complete the sale of these businesses by the
end of 2007.

     Our pending asset sales are subject to the receipt of all necessary
governmental, lender and partner approvals. As we restructure our Enterprises
business, we will continue to optimize the value of our North American non-
utility assets. For additional details, see Note 2, Asset Sales, Impairment
Charges and Discontinued Operations.

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

     - successful close of the sale of our ownership interests in businesses in
       the Middle East, Africa, and India,

     - successful entry into a definitive purchase and sale agreement and
       closing of the proposed sale of certain of our Argentine assets and our
       northern Michigan non-utility natural gas assets,

     - successful close of the sale of our ownership interest in SENECA,

     - the outcome of the planned auction of other generation and distribution
       assets in South America, including the following uncertainties which
       could affect the value of these businesses:

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

       - changes in exchange rates or in local economic or political conditions,

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

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

     - impact of indemnity and environmental remediation obligations at Bay
       Harbor, and

     - changes in commodity prices and interest rates on certain derivative
       contracts that do not qualify for hedge accounting and must be marked to
       market through earnings.

     GASATACAMA: In 2004, the Argentine government authorized the restriction of
exports of natural gas to Chile, giving priority to domestic demand in
Argentina. This restriction had a harmful effect on GasAtacama's earnings since
GasAtacama's gas-fired electric generating plant is located in Chile and uses
Argentine gas for fuel. Bolivia agreed to export 4 million cubic meters of gas
per day to Argentina. With the Bolivian gas supply, Argentina relaxed its export
restrictions to GasAtacama.

     In May 2006, the Bolivian government nationalized the natural gas industry
and raised prices under its existing gas export contracts. Gas supply to
GasAtacama was restricted as Argentina and Bolivia renegotiated the price for
gas. In July 2006, Argentina agreed to increase the price it paid for gas from
Bolivia. Argentina also announced that it would recover all of this price
increase by a special tax on its gas exports. This increased the risk and cost
of GasAtacama's fuel supply.

     In August 2006, a major gas supplier notified GasAtacama that it would no
longer deliver gas to GasAtacama under the Argentine government's current
policy. In the third quarter of 2006, we performed an impairment analysis and
recorded an impairment charge of $239 million ($169 million, net of tax and
minority interest) in our Consolidated Statements of Income (Loss). At December
31, 2006, the carrying value of our investment in GasAtacama was $117 million.
This remaining value continues to be exposed to the threat of a complete gas
restriction by Argentina and the inability of GasAtacama to pass through the
increased costs associated with such a restriction to its regulated customers.
Therefore, if conditions do not improve, the result could be a further
impairment of our investment in GasAtacama.


                                     CMS-34

<PAGE>

     In February 2007, we announced plans to conduct an auction to sell
GasAtacama. We expect to complete the sale by the end of 2007. For additional
details, see Note 2, Asset Sales, Impairment Charges and Discontinued
Operations.

     PRAIRIE STATE: In October 2006, we signed agreements with Peabody Energy to
co-develop the Prairie State Energy Campus (Prairie State), a 1,600 MW power
plant and coal mine in southern Illinois. Enterprises and Peabody Energy will
co-develop and each own 15 percent of Prairie State indirectly through a jointly
owned limited liability company. Enterprises will serve as lead developer,
construction manager, and operator of the mine-mouth power plant. Peabody Energy
will be lead developer of the mine that will fuel the power plant. Financial
close of the project is contingent upon Peabody Energy and Enterprises being
able to secure:

     - non-recourse project financing,

     - an engineering, procurement, and construction contract for the power
       plant, and

     - long-term power purchase agreements which will include protection against
       unknown future carbon dioxide regulation, or hedging contracts for a
       substantial portion of Enterprises' and Peabody Energy's share of the
       project's output.

     Construction of the first 800 MW generating unit is expected to take about
four years to complete and the second 800 MW unit will be completed shortly
afterward. We expect to finance our projected equity investment of approximately
$200 million with a bridge loan until the completion of construction.

OTHER OUTLOOK

     RULES REGARDING BILLING PRACTICES: In December 2006, the MPSC issued
proposed rule changes to residential customer billing standards and practices.
These changes, if adopted, would provide additional protection to low-income
customers during the winter heating season that will be defined as November 1
through March 31, extend the time between billing date and due date from 17 days
to 22 days, and eliminate estimated metering readings unless actual readings are
not feasible. We are presently evaluating the impacts of these proposed rules
and are working with other Michigan utilities in providing comments to the MPSC
regarding the proposed rule changes.

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

     FIXED PRICE CONTRACTS: DIG and CMS ERM are parties to long-term
requirements contracts to provide steam and/or electricity based on a fixed
price schedule. The price of natural gas, the primary fuel used by DIG, is
volatile and has increased substantially in recent years. Because the prices
charged under DIG's contracts do not reflect current natural gas prices, DIG's
and CMS ERM's financial performance has been impacted negatively. However, since
not all of its capacity is committed under these contracts, DIG has been able to
sell a portion of its electric capacity and/or energy on the market at a profit,
or, through CMS ERM, engage in a hedging strategy to minimize its losses. DIG
and CMS ERM may take various actions such as seeking restructuring of the
contracts. CMS Energy may also take other measures to address the unfavorable
returns.

     PENSION REFORM: In August 2006, the President signed into law the Pension
Protection Act of 2006. The bill reforms the funding rules for employer-provided
pension plans, effective for plan years beginning after 2007. As a result of
this bill, we expect to reduce our contributions to the Pension Plan over the
next 10 years by a present value amount of $56 million.

IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

     SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R)
requires companies to use the fair value of employee stock options and similar
awards at the grant date to value the awards. SFAS No. 123(R) was

                                     CMS-35

<PAGE>

effective for us on January 1, 2006. We elected to adopt the modified
prospective method recognition provisions of this Statement instead of
retrospective restatement. We adopted the fair value method of accounting for
share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not
have a significant impact on our consolidated results of operations when it
became effective. We applied the additional guidance provided by SAB No. 107
upon implementation of SFAS No. 123(R).

     STAFF ACCOUNTING BULLETIN NO. 108, CONSIDERING THE EFFECTS OF PRIOR YEAR
MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL
STATEMENTS: SAB No. 108 was adopted on December 31, 2006. The standard clarifies
how we should assess the materiality of prior period financial statement errors
in the current period. Prior to the adoption of this standard,we used the "iron-
curtain" method to quantify the effects of prior period financial statement
errors. The iron-curtain method focuses on the effects of correcting the period-
end balance sheet with less emphasis on the effects the correction would have on
our consolidated  income statement. This standard requires quantification of
financial statement errors based on their effect on each of our consolidated
financial statements. The adoption of this standard did not have an effect on
our financial position or results of  operations.

     SFAS NO. 158, EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER
POSTRETIREMENT PLANS -- AN AMENDMENT OF FASB STATEMENTS NO. 87, 88, 106, AND
132(R): In September 2006, the FASB issued SFAS No. 158. This standard requires
us to recognize the funded status of our defined benefit postretirement plans on
our Consolidated Balance Sheets at December 31, 2006. Upon implementation of
this standard, we recorded an additional postretirement benefit liability of
$647 million, a regulatory asset of $680 million and a reduction of $7 million
to AOCL, after tax. This standard also requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008.
We do not believe that implementation of this provision of the standard will
have a material effect on our consolidated financial statements. We expect to
adopt the measurement date provisions of SFAS No. 158 in 2008.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

     FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006, the FASB
issued FIN 48, effective for us in January 2007. This interpretation provides a
two-step approach for the recognition and measurement of uncertain tax positions
taken, or expected to be taken, by a company on its income tax returns. The
first step is to evaluate the tax position to determine if, based on
management's best judgment, it is greater than 50 percent likely that the taxing
authority will sustain the tax position. The second step is to measure the
appropriate amount of the benefit to recognize. This is done by estimating the
potential outcomes and recognizing the greatest amount that has a cumulative
probability of at least 50 percent. FIN 48 requires interest and penalties, if
applicable, to be accrued on differences between tax positions recognized in our
consolidated financial statements and the amount claimed, or expected to be
claimed, on the tax return. Our policy is to include interest and penalties
accrued on uncertain tax positions as part of the related tax liability on our
consolidated balance sheet and as part of the income tax expense in our
consolidated income statement. The impact from adopting FIN 48 should be
recorded as a cumulative adjustment to the beginning retained earnings balance
and a corresponding adjustment to a current or non-current tax liability.
Although we have not yet determined the full effect of FIN 48, we believe that
any reduction to our retained earnings as of January 1, 2007 will be less than
$30 million.

     SFAS NO. 157, FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued
SFAS No. 157, effective for us January 1, 2008. The standard provides a revised
definition of "fair value" and gives guidance on how to measure the fair value
of assets and liabilities. Under the standard, fair value is defined as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly exchange between market participants. The standard does not expand
the use of fair value in any new circumstances. However, additional disclosures
will be required on the impact and reliability of fair value measurements
reflected in our consolidated financial statements. The standard will also
eliminate the existing prohibition of recognizing "day one" gains or losses on
derivative instruments, and will generally require such gains and losses to be
recognized through earnings. We are presently evaluating the impacts, if any, of
implementing SFAS No. 157. We currently do not hold any derivatives that would
involve day one gains or losses.


                                     CMS-36

<PAGE>

     SFAS NO. 159, THE FAIR VALUE OPTION FOR FINANCIAL ASSETS AND FINANCIAL
LIABILITIES, INCLUDING AN AMENDMENT TO FASB STATEMENT NO. 115: In February 2007,
the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard
will give us the option to select certain financial instruments and other items,
which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we
would recognize unrealized gains and losses associated with changes in the fair
value of the item over time. The statement will also require disclosures for
items for which the fair value option has been elected. We are presently
evaluating whether we will choose to elect the fair value option for any
financial instruments or other items.


                                     CMS-37

<PAGE>

                             CMS Energy Corporation

                    CONSOLIDATED STATEMENTS OF INCOME (LOSS)



<Table>
<Caption>
                                                             YEARS ENDED DECEMBER 31
                                                            ------------------------
                                                             2006     2005     2004
                                                             ----     ----     ----
                                                                   IN MILLIONS

<S>                                                         <C>      <C>      <C>

OPERATING REVENUE.........................................  $6,810   $6,288   $5,472
EARNINGS FROM EQUITY METHOD INVESTEES.....................      89      125      115
OPERATING EXPENSES
  Fuel for electric generation............................     984      720      774
  Fuel costs mark-to-market at the MCV Partnership........     204     (200)      19
  Purchased and interchange power.........................     829      546      344
  Cost of gas sold........................................   2,131    2,297    1,786
  Other operating expenses................................   1,225    1,105      954
  Maintenance.............................................     326      249      256
  Depreciation, depletion and amortization................     576      525      431
  General taxes...........................................     198      261      270
  Asset impairment charges................................     459    1,184      160
                                                            ------   ------   ------
                                                             6,932    6,687    4,994
                                                            ------   ------   ------
OPERATING INCOME (LOSS)...................................     (33)    (274)     593
OTHER INCOME (DEDUCTIONS)
  Accretion expense.......................................      (4)     (18)     (23)
  Gain on asset sales, net................................      79        6       52
  Interest and dividends..................................      86       66       27
  Regulatory return on capital expenditures...............      26        4      113
  Foreign currency gains (losses), net....................      --       (7)      (3)
  Other income............................................      33       36       27
  Other expense...........................................     (19)     (30)     (15)
                                                            ------   ------   ------
                                                               201       57      178
                                                            ------   ------   ------
FIXED CHARGES
  Interest on long-term debt..............................     468      477      502
  Interest on long-term debt -- related parties...........      15       29       58
  Other interest..........................................      33       16       44
  Capitalized interest....................................     (10)     (38)      25
  Preferred dividends of subsidiaries.....................       5        5        5
                                                            ------   ------   ------
                                                               511      489      634
                                                            ------   ------   ------
INCOME (LOSS) BEFORE MINORITY INTERESTS (OBLIGATIONS),
  NET.....................................................    (343)    (706)     137
MINORITY INTERESTS (OBLIGATIONS), NET.....................    (100)    (440)      15
                                                            ------   ------   ------
INCOME (LOSS) BEFORE INCOME TAXES.........................    (243)    (266)     122
INCOME TAX BENEFIT........................................    (158)    (168)      (5)
                                                            ------   ------   ------
INCOME (LOSS) FROM CONTINUING OPERATIONS..................     (85)     (98)     127
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $2 TAX
  EXPENSE IN 2006, $8 TAX EXPENSE IN 2005 AND $18 TAX
  EXPENSE IN 2004.........................................       6       14       (4)
                                                            ------   ------   ------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN
  ACCOUNTING..............................................     (79)     (84)     123
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR RETIREMENT
  BENEFITS, NET OF $1 TAX BENEFIT.........................      --       --       (2)
                                                            ------   ------   ------
NET INCOME (LOSS).........................................     (79)     (84)     121
PREFERRED DIVIDENDS.......................................      11       10       11
                                                            ------   ------   ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS........  $  (90)  $  (94)  $  110
                                                            ======   ======   ======

</Table>




                                     CMS-38

<PAGE>

<Table>
<Caption>
                                                             YEARS ENDED DECEMBER 31
                                                            ------------------------
                                                             2006     2005     2004
                                                            ------   ------   ------
                                                             IN MILLIONS, EXCEPT PER
                                                                  SHARE AMOUNTS

<S>                                                         <C>      <C>      <C>

CMS ENERGY
  NET INCOME (LOSS)
     Net Income (Loss) Available to Common Stockholders...  $  (90)  $  (94)  $  110
                                                            ======   ======   ======
  BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
     Income (Loss) from Continuing Operations.............  $(0.44)  $(0.51)  $ 0.68
     Income (Loss) from Discontinued Operations...........    0.03     0.07    (0.02)
     Loss from Change in Accounting.......................      --       --    (0.01)
                                                            ------   ------   ------
     Net Income (Loss) Attributable to Common Stock.......  $(0.41)  $(0.44)  $ 0.65
                                                            ======   ======   ======
  DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
     Income (Loss) from Continuing Operations.............  $(0.44)  $(0.51)  $ 0.67
     Income (Loss) from Discontinued Operations...........    0.03     0.07    (0.02)
     Loss from Change in Accounting.......................      --       --    (0.01)
                                                            ------   ------   ------
     Net Income (Loss) Attributable to Common Stock.......  $(0.41)  $(0.44)  $ 0.64
                                                            ======   ======   ======
  DIVIDENDS DECLARED PER COMMON SHARE.....................  $   --   $   --   $   --
                                                            ======   ======   ======

</Table>



        The accompanying notes are an integral part of these statements.


                                     CMS-39

<PAGE>

                             CMS Energy Corporation

                      CONSOLIDATED STATEMENTS OF CASH FLOWS



<Table>
<Caption>
                                                            YEARS ENDED DECEMBER 31
                                                           -------------------------
                                                            2006     2005      2004
                                                            ----     ----      ----
                                                                  IN MILLIONS

<S>                                                        <C>     <C>       <C>

CASH FLOWS FROM OPERATING ACTIVITIES
  Net income (loss)......................................  $ (79)  $   (84)  $   121
  Adjustments to reconcile net income (loss) to net cash
     provided by operating activities
     Depreciation, depletion and amortization (includes
       nuclear decommissioning of $6 per year)...........    576       525       431
     Deferred income taxes and investment tax credit.....   (271)     (199)       67
     Regulatory return on capital expenditures...........    (26)       (4)     (113)
     Minority interests (obligations), net...............   (100)     (440)       15
     Fuel costs mark-to-market at the MCV Partnership....    204      (200)       19
     Asset impairment charges............................    459     1,184       160
     Capital lease and other amortization................     44        40        28
     Accretion expense...................................      4        18        23
     Bad debt expense....................................     28        23        19
     Gain on the sale of assets (includes discontinued
       operations).......................................    (79)      (20)      (50)
     Cumulative effect of accounting changes.............     --        --         2
     Earnings from equity method investees...............    (89)     (125)     (115)
     Cash distributions from equity method investees.....     75       108        27
     Changes in other assets and liabilities:
       Increase in accounts receivable, notes receivable,
          and accrued revenues...........................    (91)     (311)     (144)
       Increase in inventories...........................   (105)     (245)     (109)
       Increase (decrease) in accounts payable...........    (43)      170       109
       Increase in legal settlement liability............    200        --        --
       Increase in accrued taxes.........................      3        19        16
       Increase (decrease) in accrued expenses...........     36       (11)       21
       Increase (decrease) in the MCV Partnership gas
          supplier funds on deposit......................   (147)      173        15
       Decrease (increase) in other current and non-
          current assets.................................     45       (37)     (117)
       Increase (decrease) in other current and non-
          current liabilities............................     44        15       (72)
                                                           -----   -------   -------
  Net cash provided by operating activities..............    688       599       353
                                                           -----   -------   -------
CASH FLOWS FROM INVESTING ACTIVITIES
  Capital expenditures (excludes assets placed under
     capital lease)......................................   (670)     (593)     (525)
  Investments in partnerships and unconsolidated
     subsidiaries........................................     --        --       (71)
  Cost to retire property................................    (78)      (27)      (28)
  Restricted cash and restricted short-term investments..    124      (151)      145
  Investments in Electric Restructuring Implementation
     Plan................................................     --        --        (7)
  Investments in nuclear decommissioning trust funds.....    (21)       (6)       (6)
  Proceeds from nuclear decommissioning trust funds......     22        39        36
  Proceeds from short-term investments...................     --       295     2,267
  Purchase of short-term investments.....................     --      (186)   (2,376)
  Maturity of the MCV Partnership restricted investment
     securities held-to-maturity.........................    130       318       675
  Purchase of the MCV Partnership restricted investment
     securities held-to-maturity.........................   (131)     (270)     (674)
  Proceeds from sale of assets...........................     69        61       219
  Cash relinquished from sale of assets..................   (148)       --        --
  Decrease (increase) in non-current notes receivable....    (50)        1       (10)
  Other investing........................................      2        25         8
                                                           -----   -------   -------
     Net cash used in investing activities...............   (751)     (494)     (347)
                                                           -----   -------   -------
</Table>

                                     CMS-40

<PAGE>

<Table>
<Caption>
                                                            YEARS ENDED DECEMBER 31
                                                           -------------------------
                                                            2006     2005      2004
                                                            ----     ----      ----
                                                                  IN MILLIONS

<S>                                                        <C>     <C>       <C>
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds from notes, bonds, and other long-term debt...    100     1,385     1,392
  Issuance of common stock...............................      8       295       290
  Retirement of bonds and other long-term debt...........   (493)   (1,509)   (1,631)
  Payment of preferred stock dividends...................    (11)      (11)      (11)
  Payment of capital lease and finance lease
     obligations.........................................    (26)      (29)      (44)
  Increase in notes payable..............................      2        --        --
  Debt issuance costs, financing fees, and other.........    (14)      (57)      (39)
                                                           -----   -------   -------
     Net cash provided by (used in) financing
       activities........................................   (434)       74       (43)
                                                           -----   -------   -------
EFFECT OF EXCHANGE RATES ON CASH.........................      1        (1)       --
                                                           -----   -------   -------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS.....   (496)      178       (37)
CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB
  INTERPRETATION NO. 46 CONSOLIDATION....................     --        --       174
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD...........    847       669       532
                                                           -----   -------   -------
CASH AND CASH EQUIVALENTS, END OF PERIOD.................  $ 351   $   847   $   669
                                                           =====   =======   =======
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND
  FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
  Interest paid (net of amounts capitalized).............  $ 487   $   454   $   601
  Income taxes paid (net of refunds).....................     --        (9)       --
  Pension and OPEB cash contribution.....................     69        63        63
NON-CASH TRANSACTIONS
  Other assets placed under capital lease................  $   7   $    12   $     3
                                                           -----   -------   -------

</Table>



        The accompanying notes are an integral part of these statements.


                                     CMS-41

<PAGE>

                             CMS ENERGY CORPORATION

                           CONSOLIDATED BALANCE SHEETS



<Table>
<Caption>
                                                                   DECEMBER 31
                                                                -----------------
                                                                  2006      2005
                                                                  ----      ----
                                                                   IN MILLIONS

<S>                                                             <C>       <C>

ASSETS
PLANT AND PROPERTY (AT COST)
  Electric utility............................................  $ 8,504   $ 8,204
  Gas utility.................................................    3,273     3,151
  Enterprises.................................................      834     1,068
  Other.......................................................       31        25
                                                                -------   -------
                                                                 12,642    12,448
  Less accumulated depreciation, depletion and amortization...    5,317     5,123
                                                                -------   -------
                                                                  7,325     7,325
  Construction work-in-progress...............................      651       520
                                                                -------   -------
                                                                  7,976     7,845
                                                                -------   -------
INVESTMENTS
  Enterprises.................................................      588       712
  Other.......................................................       10        13
                                                                -------   -------
                                                                    598       725
                                                                -------   -------
CURRENT ASSETS
  Cash and cash equivalents at cost, which approximates
     market...................................................      351       847
  Restricted cash and restricted short-term investments at
     cost, which approximates market..........................       71       198
  Accounts receivable, notes receivable, and accrued revenue,
     less allowances of $33 in 2006 and $31 in 2005...........      808       845
  Accounts receivable, dividends receivable, and notes
     receivable -- related parties............................       67        54
  Inventories at average cost
     Gas in underground storage...............................    1,129     1,069
     Materials and supplies...................................      102        96
     Generating plant fuel stock..............................      126       110
  Price risk management assets................................       45       113
  Regulatory assets -- postretirement benefits................       19        19
  Derivative instruments......................................       --       242
  Deferred income taxes.......................................      155        --
  Deferred property taxes.....................................      150       160
  Prepayments and other.......................................      120       167
                                                                -------   -------
                                                                  3,143     3,920
                                                                -------   -------
NON-CURRENT ASSETS
  Regulatory assets
     Securitized costs........................................      514       560
     Additional minimum pension...............................       --       399
     Postretirement benefits..................................    1,131       116
     Customer Choice Act......................................      190       222
     Other....................................................      462       484
  Price risk management assets................................       19       165
  Nuclear decommissioning trust funds.........................      602       555
  Goodwill....................................................       26        27
  Notes receivable -- related parties.........................      125       187
  Notes receivable............................................      246       187
  Other.......................................................      339       649
                                                                -------   -------
                                                                  3,654     3,551
                                                                -------   -------
TOTAL ASSETS..................................................  $15,371   $16,041
                                                                =======   =======

</Table>




                                     CMS-42

<PAGE>

<Table>
<Caption>
                                                                   DECEMBER 31
                                                                -----------------
                                                                  2006      2005
                                                                  ----      ----
                                                                   IN MILLIONS

<S>                                                             <C>       <C>

STOCKHOLDERS' INVESTMENT AND LIABILITIES
CAPITALIZATION
  Common stockholders' equity
  Common stock, authorized 350.0 shares; outstanding 222.8
     shares in 2006 and 220.5 shares in 2005..................  $     2   $     2
  Other paid-in capital.......................................    4,468     4,436
  Accumulated other comprehensive loss........................     (318)     (288)
  Retained deficit............................................   (1,918)   (1,828)
                                                                -------   -------
                                                                  2,234     2,322
  Preferred stock of subsidiary...............................       44        44
  Preferred stock.............................................      261       261
  Long-term debt..............................................    6,202     6,800
  Long-term debt -- related parties...........................      178       178
  Non-current portion of capital and finance lease
     obligations..............................................       42       308
                                                                -------   -------
                                                                  8,961     9,913
                                                                -------   -------
MINORITY INTERESTS............................................       91       333
                                                                -------   -------
CURRENT LIABILITIES
  Current portion of long-term debt, capital and finance
     leases...................................................      564       316
  Current portion of long-term debt -- related parties........       --       129
  Notes payable...............................................        2        --
  Accounts payable............................................      564       597
  Accounts payable -- related parties.........................        2        16
  Accrued interest............................................      130       145
  Accrued taxes...............................................      331       331
  Price risk management liabilities...........................       70        80
  Current portion of gas supply contract obligations..........       --        10
  Deferred income taxes.......................................       --        55
  MCV Partnership gas supplier funds on deposit...............       --       193
  Legal settlement liability..................................      200        --
  Other.......................................................      293       262
                                                                -------   -------
                                                                  2,156     2,134
                                                                -------   -------
NON-CURRENT LIABILITIES
  Regulatory liabilities
     Regulatory liabilities for cost of removal...............    1,166     1,120
     Income taxes, net........................................      539       455
     Other regulatory liabilities.............................      249       178
  Postretirement benefits.....................................    1,071       382
  Deferred income taxes.......................................      120       297
  Deferred investment tax credit..............................       62        67
  Asset retirement obligations................................      500       496
  Price risk management liabilities...........................       31       161
  Gas supply contract obligations.............................       --        61
  Other.......................................................      425       444
                                                                -------   -------
                                                                  4,163     3,661
                                                                -------   -------
     Commitments and Contingencies (Notes 3,4,6,9 and 11)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES................  $15,371   $16,041
                                                                =======   =======

</Table>



        The accompanying notes are an integral part of these statements.


                                     CMS-43

<PAGE>

                             CMS Energy Corporation

             Consolidated Statements of Common Stockholders' Equity



<Table>
<Caption>
                                                      YEARS ENDED DECEMBER 31
                                     ---------------------------------------------------------
                                       2006      2005      2004      2006      2005      2004
                                       ----      ----      ----      ----      ----      ----
                                         NUMBER OF SHARES IN               IN MILLIONS
                                              THOUSANDS

<S>                                  <C>       <C>       <C>       <C>       <C>       <C>

COMMON STOCK
  At beginning and end of period...                                $     2   $     2   $     2
                                                                   -------   -------   -------
OTHER PAID-IN CAPITAL
  At beginning of period...........  220,497   194,997   161,130     4,436     4,140     3,846
  Common stock repurchased.........      (98)      (88)      (43)       (2)       (1)       (1)
  Common stock reacquired..........      (59)       --      (270)       --        --        (5)
  Common stock issued..............    2,375    25,493    34,180        33       296       301
  Common stock reissued............       68        95        --         1         1        --
  Issuance cost of preferred
     stock.........................       --        --        --        --        --        (1)
                                     -------   -------   -------   -------   -------   -------
       At end of period............  222,783   220,497   194,997     4,468     4,436     4,140
                                     -------   -------   -------   -------   -------   -------
ACCUMULATED OTHER COMPREHENSIVE
  LOSS
  Retirement benefits liability
     At beginning of period........                                    (19)      (17)       --
     Retirement benefits liability
       adjustments(a)..............                                      3        (2)      (17)
     Adjustment to initially apply
       FASB Statement No. 158......                                     (7)       --        --
                                                                   -------   -------   -------
       At end of period............                                    (23)      (19)      (17)
                                                                   -------   -------   -------
  Investments
     At beginning of period........                                      9         9         8
     Unrealized gain on
       investments(a)..............                                      5        --         1
                                                                   -------   -------   -------
       At end of period............                                     14         9         9
                                                                   -------   -------   -------
  Derivative instruments
     At beginning of period........                                     35        (9)       (8)
     Unrealized gain (loss) on
       derivative instruments(a)...                                    (15)       51         5
     Reclassification adjustments
       included in net income
       (loss)(a)...................                                    (32)       (7)       (6)
                                                                   -------   -------   -------
       At end of period............                                    (12)       35        (9)
                                                                   -------   -------   -------
FOREIGN CURRENCY TRANSLATION
  At beginning of period...........                                   (313)     (319)     (419)
  Loy Yang sale....................                                     --        --       110
  Other foreign currency
     translations(a)...............                                     16         6       (10)
                                                                   -------   -------   -------
     At end of period..............                                   (297)     (313)     (319)
                                                                   -------   -------   -------
       At end of period............                                   (318)     (288)     (336)
                                                                   -------   -------   -------
RETAINED DEFICIT
  At beginning of period...........                                 (1,828)   (1,734)   (1,844)
  Net income (loss)(a).............                                    (79)      (84)      121
  Preferred stock dividends
     declared......................                                    (11)      (10)      (11)
                                                                   -------   -------   -------
       At end of period............                                 (1,918)   (1,828)   (1,734)
                                                                   -------   -------   -------
TOTAL COMMON STOCKHOLDERS' EQUITY..                                $ 2,234   $ 2,322   $ 2,072
                                                                   =======   =======   =======

</Table>




                                     CMS-44

<PAGE>

<Table>
<Caption>
                                                                   YEARS ENDED
                                                                   DECEMBER 31
                                                               -------------------
                                                                2006   2005   2004
                                                                ----   ----   ----
                                                                   IN MILLIONS

<S>                                                            <C>     <C>    <C>

(A) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
     Retirement benefits liability
       Retirement benefits liability adjustments, net of tax
          (tax benefit) of $1 in 2006, $(1) in 2005 and $(9)
          in 2004............................................  $   3   $ (2)  $(17)
     Investments
       Unrealized gain on investments, net of tax of $2 in
          2006, $- in 2005 and $1 in 2004....................      5     --      1
     Derivative instruments
       Unrealized gain (loss) on derivative instruments, net
          of tax (tax benefit) of $(11) in 2006, $29 in 2005
          and $12 in 2004....................................    (15)    51      5
       Reclassification adjustments included in net income
          (loss), net of tax benefit of $(19) in 2006, $(9)
          in 2005 and $(6) in 2004...........................    (32)    (7)    (6)
     Loy Yang sale...........................................     --     --    110
     Other foreign currency translations.....................     16      6    (10)
     Net income (loss).......................................    (79)   (84)   121
                                                               -----   ----   ----
       Total Other Comprehensive Income (Loss)...............  $(102)  $(36)  $204
                                                               =====   ====   ====

</Table>



        The accompanying notes are an integral part of these statements.


                                     CMS-45

<PAGE>

                             CMS ENERGY CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS



1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES

     CORPORATE STRUCTURE: CMS Energy is an energy company operating primarily in
Michigan. We are the parent holding company of Consumers and Enterprises.
Consumers is a combination electric and gas utility company serving Michigan's
Lower Peninsula. Enterprises, through various subsidiaries and equity
investments, is engaged in domestic and international diversified energy
businesses including independent power production, electric distribution, 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
CMS Energy, Consumers, Enterprises, and all other entities in which we have a
controlling financial interest or are the primary beneficiary, in accordance
with FASB Interpretation No. 46(R). We use the equity method of accounting for
investments in companies and partnerships that are not consolidated, where we
have significant influence over operations and financial policies, but are not
the primary beneficiary. We eliminate intercompany transactions and balances.

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

     We record estimated liabilities for contingencies in our consolidated
financial statements when it is probable that a loss will be incurred in the
future as a result of a current event, and when an amount can be reasonably
estimated. For additional details, see Note 3, Contingencies.

     REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of
electricity and natural gas, and the transportation, processing, and storage of
natural gas when services are provided. We record sales tax on a net basis and
exclude it from revenues. We recognize revenues on sales of marketed
electricity, natural gas, and other energy products at delivery. We recognize
mark-to-market changes in the fair values of energy trading contracts that
qualify as derivatives as revenues in the periods in which the changes occur.

     ACCOUNTING FOR MISO TRANSACTIONS: CMS ERM accounts for MISO transactions on
a net basis for all of the generating units for which CMS ERM markets power. CMS
ERM allocates other fixed costs associated with MISO settlements back to the
generating units and records billing adjustments when it receives invoices.
Consumers accounts for MISO transactions on a net basis for all of its
generating units combined. Consumers records billing adjustments when it
receives invoices and records an expense accrual for future adjustments based on
historical experience.

     ACCRETION EXPENSE: CMS ERM engaged in prepaid sales arrangements to provide
natural gas to various entities over periods of up to 12 years at predetermined
price levels. CMS ERM established a liability for those outstanding obligations
equal to the discounted present value of the contracts, and hedged its exposures
under those arrangements. As CMS ERM fulfilled its obligations under the
contracts, it recognized revenues upon the delivery of natural gas, recorded a
reduction to the outstanding obligation, and recognized accretion expense. In
August 2006, CMS ERM extinguished its outstanding obligations for $70 million,
which included a $6 million loss on extinguishment.

     CAPITALIZED INTEREST: We 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
incurred. Our regulated businesses capitalize AFUDC on regulated construction
projects and include such amounts in plant in service.

     CASH EQUIVALENTS AND RESTRICTED CASH: Cash equivalents are all liquid
investments with an original maturity of three months or less.


                                     CMS-46

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     At December 31, 2006, our restricted cash on hand was $71 million. We
classify restricted cash dedicated for repayment of Securitization bonds as a
current asset, as the related payments occur within one year.

     COLLECTIVE BARGAINING AGREEMENTS: At December 31, 2006, the Utility Workers
of America Union represented approximately 45 percent of Consumers employees.
The Union represents Consumers' operating, maintenance, and construction
employees and call center employees.

     DETERMINATION OF PENSION MRV OF PLAN ASSETS: We determine the MRV for
pension plan assets, as defined in SFAS No. 87, as the fair value of plan assets
on the measurement date, adjusted by the gains or losses that will not be
admitted into MRV until future years. We reflect each year's assets gain or loss
in MRV in equal amounts over a five-year period beginning on the date the
original amount was determined. We use the MRV in the calculation of net pension
cost.

     EARNINGS PER SHARE: We calculate basic and diluted EPS using the weighted
average number of shares of common stock and dilutive potential common stock
outstanding during the period. Potential common stock, for purposes of
determining diluted EPS, includes the effects of dilutive stock options,
warrants and convertible securities. We compute the effect on potential common
stock using the treasury stock method or the if-converted method, as applicable.
Diluted EPS excludes the impact of antidilutive securities, which are those
securities resulting in an increase in EPS or a decrease in loss per share. For
earnings per share computation, see Note 5, Earnings Per Share.

     EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN
CURRENT YEAR FINANCIAL STATEMENTS: SAB No. 108 was adopted on December 31, 2006.
The standard clarifies how we should assess the materiality of prior period
financial statement errors in the current period. Prior to the adoption of this
standard, we used the "iron-curtain" method to quantify the effects of prior
period financial statement errors. The iron-curtain method focuses on the
effects of correcting the period-end balance sheet with less emphasis on the
effects the correction would have on our income statement. This standard
requires quantification of financial statement errors based on their effect on
each of our consolidated financial statements. The adoption of this standard did
not have an effect on our financial position or results of operations.

     FINANCIAL AND DERIVATIVE INSTRUMENTS: We record debt and equity securities
classified as available-for-sale at fair value determined from quoted market
prices. We record debt and equity securities classified as held-to-maturity at
cost.

     On a specific identification basis, we report unrealized gains or losses
from changes in fair value of certain available-for-sale debt and equity
securities, net of tax, in equity as part of AOCL. We exclude unrealized gains
or losses from earnings unless the related changes in fair value are determined
to be other than temporary. We reflect unrealized gains or losses on our nuclear
decommissioning investments as regulatory liabilities on our Consolidated
Balance Sheets. Realized gains or losses would not affect our consolidated
earnings or cash flows.

     We account for derivative instruments using SFAS No. 133. We report
derivatives on our Consolidated Balance Sheets at their fair value. We record
changes in fair value in AOCL if the derivative qualifies for cash flow hedge
accounting; otherwise, we record the changes in earnings.

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

     GOODWILL: Goodwill is the excess of the purchase price over the fair value
of the net assets of acquired companies. We test goodwill annually for
impairment. There is no goodwill at the electric and gas utility segments.


                                     CMS-47

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The changes in the carrying amount of goodwill at the Enterprises segment
for the years ended December 31, 2005 and 2006 are included in the following
table:


<Table>
<Caption>
                                                                      IN MILLIONS
                                                                      -----------

<S>                                                                   <C>

Balance at January 1, 2005..........................................      $23
  Currency translation adjustment...................................        4
                                                                          ---
Balance at December 31, 2005........................................      $27
  Currency translation adjustment...................................       (1)
                                                                          ---
Balance at December 31, 2006........................................      $26
                                                                          ===

</Table>


     IMPAIRMENT OF LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: We evaluate
potential impairments of our long-lived assets, other than goodwill, based on
various analyses, including the projection of undiscounted cash flows, whenever
events or changes in circumstances indicate that the carrying amount of the
assets may not be recoverable. If the carrying amount of the investment or asset
exceeds its estimated undiscounted future cash flows, we recognize an impairment
loss and write-down the investment or asset to its estimated fair value.

     We also assess our ability to recover the carrying amounts of our equity
method investments whenever events or changes in circumstances indicate that the
carrying amount of the investments may not be recoverable. This assessment
requires us to determine the fair values of our equity method investments. We
determine fair value using valuation methodologies, including discounted cash
flows and the ability of the investee to sustain an earnings capacity that
justifies the carrying amount of the investment. We record a write down if the
fair value is less than the carrying value and the decline in value is
considered to be other than temporary.

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

     INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY: Our subsidiaries and
affiliates whose functional currency is not the U.S. dollar translate their
assets and liabilities into U.S. dollars at the exchange rates in effect at the
end of the fiscal period. We translate revenue and expense accounts of such
subsidiaries and affiliates into U.S. dollars at the average exchange rates that
prevailed during the period. We show these foreign currency translation
adjustments in the stockholders' equity section on our Consolidated Balance
Sheets. We include exchange rate fluctuations on transactions denominated in a
currency other than the functional currency, except those that are hedged, in
determining net income.

     At December 31, 2006, the cumulative Foreign Currency Translation component
of stockholders' equity is $297 million, which primarily represents currency
losses in Argentina and Brazil. The cumulative foreign currency loss due to the
unfavorable exchange rate of the Argentine peso using an exchange rate of 3.073
pesos per U.S. dollar was $256 million, net of tax. The cumulative foreign
currency loss due to the unfavorable exchange rate of the Brazilian real using
an exchange rate of 2.136 reais per U.S. dollar was $45 million, net of tax.

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

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

                                     CMS-48

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

replacements. We depreciate utility property using straight-line rates approved
by the MPSC. The composite depreciation rates for our properties are:


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                         2006   2005   2004
-----------------------                                         ----   ----   ----

<S>                                                             <C>    <C>    <C>

Electric utility property.....................................   3.1%   3.1%  3.1%
Gas utility property..........................................   3.6%   3.6%  3.7%
Other property................................................   8.2%   7.6%  8.4%
</Table>


     NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on
the quantity of heat produced for electric generation. For nuclear fuel used
after April 6, 1983, we charge certain disposal costs to nuclear fuel expense,
recover these costs through electric rates, and remit them to the DOE quarterly.
We elected to defer payment for disposal of spent nuclear fuel burned before
April 7, 1983. Our DOE liability is $152 million at December 31, 2006 and $145
million at December 31, 2005. This amount includes interest, which is payable
upon the first delivery of spent nuclear fuel to the DOE. We have recovered,
through electric rates, the amount of this liability, excluding a portion of
interest. In conjunction with the sale of Palisades and the Big Rock ISFSI, we
will retain this obligation and provide security to Entergy for this obligation
in the form of cash, a letter of credit, or other acceptable means. For
additional details on disposal of spent nuclear fuel, see Note 3, Contingencies,
"Other Consumers' Electric Utility Contingencies -- Nuclear Matters."

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                          2006   2005   2004
-----------------------                                          ----   ----   ----
                                                                     IN MILLIONS

<S>                                                              <C>    <C>    <C>

Other income
  Interest and dividends -- related parties....................   $ 9    $10    $ 6
  Return on stranded and security costs........................     5      6      9
  Nitrogen oxide allowance sales...............................     8      2     --
  Electric restructuring return................................     4      6      6
  Investment sale gain.........................................     1     --      3
  Reversal of contingent liability.............................    --      3     --
  Refund of surety bond premium................................     1     --     --
  All other....................................................     5      9      3
                                                                  ---    ---    ---
Total other income.............................................   $33    $36    $27
                                                                  ===    ===    ===

</Table>




<Table>
<Caption>
YEARS ENDED DECEMBER 31                                         2006   2005   2004
-----------------------                                         ----   ----   ----
                                                                    IN MILLIONS

<S>                                                             <C>    <C>    <C>

Other expense
  Loss on SERP investment.....................................  $ --   $ (2)  $ (3)
  Loss on reacquired and extinguished debt....................    (5)   (16)    --
  Civic and political expenditures............................    (2)    (2)    (2)
  Donations...................................................    (9)    --     (1)
  All other...................................................    (3)   (10)    (9)
                                                                ----   ----   ----
Total other expense...........................................  $(19)  $(30)  $(15)
                                                                ====   ====   ====

</Table>


     PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, we charge the original
cost to accumulated depreciation, along with associated cost of removal, net of
salvage. Cost of removal collected from our customers, but not spent, is
recorded as a regulatory liability. We capitalize AFUDC on regulated major
construction projects. We recognize gains or losses on the retirement or
disposal of non-regulated assets in income. For additional details, see Note 8,
Asset Retirement Obligations and Note 12, Property, Plant, and Equipment.


                                     CMS-49

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

     RELATED PARTY TRANSACTIONS: We recorded income and expense from related
parties as follows:


<Table>
<Caption>
TYPE                                      RELATED PARTY            2006   2005   2004
----                                      -------------            ----   ----   ----

<S>                              <C>                               <C>    <C>    <C>

Income from our investments in   Trust Preferred Securities
  related party trusts           Companies......................   $ --   $  1   $  2
Interest expense on long-term    Trust Preferred Securities
  debt                           Companies......................    (15)   (29)   (58)
</Table>


     TRADE RECEIVABLES: Accounts receivable is primarily composed of trade
receivables and unbilled receivables. We record our accounts receivable at fair
value. We establish an allowance for uncollectible accounts based on historical
losses and management's assessment of existing economic conditions, customer
trends, and other factors. We assess late payment fees on trade receivables
based on contractual past-due terms established with customers. We charge
accounts deemed uncollectible to operating expense.

     UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums,
discounts, and expenses incurred in connection with the issuance of long-term
debt and amortize those costs over the terms of the debt issues. We expense any
refinancing costs as incurred. For the regulated portions of our businesses, if
we refinance debt, we capitalize any remaining unamortized premiums, discounts,
and expenses and amortize them over the terms of the newly issued debt.

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

     We reflect the following regulatory assets and liabilities, which include
both current and non-current amounts, on our Consolidated Balance Sheets. We
expect to recover these costs through rates over periods of up to 14 years. We
recognized an OPEB transition obligation in accordance with SFAS No. 106 and
established a regulatory asset for the amount that we expect to recover in rates
over the next six years.


<Table>
<Caption>
DECEMBER 31                                                        2006     2005
-----------                                                        ----     ----
                                                                    IN MILLIONS

<S>                                                               <C>      <C>

Securitized costs (Note 4)......................................  $  514   $  560
Additional minimum pension liability (Note 7)(a)................      --      399
Postretirement benefits (Note 7)(a).............................   1,150      135
Customer Choice Act.............................................     190      222
Electric restructuring implementation plan......................      40       74
Manufactured gas plant sites (Note 3)...........................      56       62
Abandoned Midland project.......................................       9        9
Unamortized debt costs..........................................      86       93
Asset retirement obligations (Note 8)...........................     177      169
Stranded costs..................................................      65       63
Other...........................................................      29       14
                                                                  ------   ------
Total regulatory assets(b)......................................  $2,316   $1,800
                                                                  ======   ======
Cost of removal (Note 8)........................................  $1,166   $1,120
Income taxes, net (Note 9)......................................     539      455
Asset retirement obligations (Note 8)...........................     180      165
Other...........................................................      69       13
                                                                  ------   ------
Total regulatory liabilities(b).................................  $1,954   $1,753
                                                                  ======   ======

</Table>




                                     CMS-50

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

--------

(a)    The change from 2005 to 2006 is largely due to the implementation of SFAS
       No. 158, Employers' Accounting for Defined Benefit Pension and Other
       Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106,
       and 132(R). For additional details, see Note 7, Retirement Benefits.

(b)    At December 31, 2006, we classified $19 million of regulatory assets as
       current regulatory assets and we classified $2.297 billion of regulatory
       assets as non-current regulatory assets. At December 31, 2005, we
       classified $19 million of regulatory assets as current regulatory assets
       and we classified $1.781 billion of regulatory assets as non-current
       regulatory assets. At December 31, 2006 and December 31, 2005, all of our
       regulatory liabilities represented non-current regulatory liabilities.

     NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE: SFAS No. 157, Fair Value
Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us
January 1, 2008. The standard provides a revised definition of "fair value" and
gives guidance on how to measure the fair value of assets and liabilities. Under
the standard, fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly exchange between market
participants. The standard does not expand the use of fair value in any new
circumstances. However, additional disclosures will be required on the impact
and reliability of fair value measurements reflected in our consolidated
financial statements. The standard will also eliminate the existing prohibition
of recognizing "day one" gains or losses on derivative instruments, and will
generally require such gains and losses to be recognized through earnings. We
are presently evaluating the impacts, if any, of implementing SFAS No. 157. We
currently do not hold any derivatives that would involve day one gains or
losses.

     SFAS No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities, Including an amendment to FASB Statement No. 115: In February 2007,
the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard
will give us the option to select certain financial instruments and other items,
which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we
would recognize unrealized gains and losses associated with changes  in the fair
value of the item over time. The statement will also require disclosures for
items for which the fair value option has been elected. We are presently
evaluating whether we will choose to elect the fair value option for any
financial instruments or other items.

     FIN 48, Accounting for Uncertainties in Income Taxes: We discuss the
requirements of this new accounting standard in Note 9, Income Taxes.

2:  ASSET SALES, IMPAIRMENT CHARGES AND DISCONTINUED OPERATIONS

ASSET SALES

     Gross cash proceeds received from the sale of assets, including
discontinued operations, totaled $69 million in 2006, $61 million in 2005, and
$219 million in 2004.

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


<Table>
<Caption>
DATE                                                                PRETAX   AFTER-TAX
SOLD      BUSINESS/PROJECT                                           GAIN       GAIN
----      ----------------                                          ------   ---------
                                                                        IN MILLIONS

<S>       <C>                                                       <C>      <C>

October   Land in Ludington, Michigan(a).........................     $ 2       $ 2
November  MCV GP II(b)...........................................      77        38
                                                                      ---       ---
          Total gain on asset sales..............................     $79       $40
                                                                      ===       ===

</Table>


--------

(a)    Sale of Ludington Land: We sold 36 parcels of land near Ludington,
       Michigan. Consumers held a majority share of the land, which Consumers
       co-owned with DTE Energy. Our portion of the gross proceeds was
       approximately $6 million.


                                     CMS-51

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



(b)    Sale of our Interest in the MCV Partnership and the MCV Facility: We sold
       100 percent of our ownership interest of MCV GP II (the successor to CMS
       Midland, Inc.) and 100 percent of our ownership of the stock of CMS
       Midland Holdings Company to an affiliate of GSO Capital Partners and
       Rockland Capital Energy Investments for $60.5 million. These Consumers
       subsidiaries held our 49 percent interest in the MCV Partnership and our
       35 percent lessor interest in the MCV Facility, held by the FMLP. The
       transaction is composed of non-real estate and real estate components.
       Since the carrying value of the MCV Facility, the real estate component
       of the transaction, exceeded the fair value, we recorded an impairment
       charge of $218 million. After considering tax effects and minority
       interest, the impairment charge reduced our consolidated net income by
       $80 million.

     Because of the MCV PPA, the transaction is a sale and leaseback for
     accounting purposes. SFAS No. 98 specifies the accounting required for a
     seller's sale and simultaneous leaseback involving real estate. We will
     have continuing involvement with the MCV Partnership through an existing
     guarantee associated with the future operations of the MCV Facility. As a
     result, we accounted for the MCV Facility, which is the asset subject to
     the leaseback, as a financing for accounting purposes and not a sale. We
     accounted for the non-real estate assets and liabilities associated with
     the transaction as a sale.

     As a financing, the MCV Facility remains on our Consolidated Balance Sheets
     and the related proceeds are recorded as a financing obligation. The value
     of the finance obligation is based on an allocation of the sale proceeds to
     the fair values of the net assets sold and fair value of the MCV Facility
     asset under the financing. The total proceeds of $57 million (net of $3
     million of selling expenses) were less than the fair value of the net
     assets sold. As a result, there were no proceeds remaining to allocate to
     the MCV Facility and a finance obligation was not recorded.

     The previously described transaction resulted in an after-tax loss of $41
     million. This loss includes the reversal of $30 million, into earnings, of
     certain cumulative amounts of the MCV Partnership derivative fair value
     changes that we accounted for in AOCL, the impairment charge on the MCV
     Facility, and gain on the sale of our interests in the MCV Partnership and
     the FMLP. For further information, see Note 6, Financial and Derivative
     Instruments, "Derivative Contracts Associated with the MCV Partnership."

     The following table summarizes the impacts of the transaction on net loss
and stockholders' equity:


<Table>
<Caption>
DESCRIPTION                                                         AFTER-TAX IMPACT
-----------                                                         ----------------
                                                                       IN MILLIONS

<S>                                                                 <C>

Asset impairment charges, net of minority interest of $95 million
  and $43 million in taxes........................................        $(80)
General taxes, net of $1 million in taxes.........................           1
Gain on asset sales, net
  Reclassification of AOCL into earnings, net of $17 million in
     taxes........................................................          30
  Removal of interests in the MCV Partnership and the FMLP, net of
     $22 million in taxes.........................................           8
                                                                          ----
Increase to consolidated net loss.................................        $(41)
  Reclassification of AOCL into earnings, net of $17 million in
     taxes........................................................         (30)
                                                                          ----
Decrease to stockholders' equity..................................        $(71)
                                                                          ====

</Table>


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


<Table>
<Caption>
DATE                                                                PRETAX   AFTER-TAX
SOLD      BUSINESS/PROJECT                                           GAIN       GAIN
----      ----------------                                          ------   ---------
                                                                        IN MILLIONS

<S>       <C>                                                       <C>      <C>

February  GVK....................................................     $ 4       $ 3
April     Scudder Latin American Power Fund......................       2         1
April     Gas turbine and auxiliary equipment....................      --        --
                                                                      ---       ---
          Total gain on asset sales..............................     $ 6       $ 4
                                                                      ===       ===

</Table>




                                     CMS-52

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     For the year ended December 31, 2004, we sold the following assets:


<Table>
<Caption>
DATE                                                                PRETAX   AFTER-TAX
SOLD      BUSINESS/PROJECT                                           GAIN       GAIN
----      ----------------                                          ------   ---------
                                                                        IN MILLIONS

<S>       <C>                                                       <C>      <C>

February  Bluewater Pipeline.....................................     $ 1       $ 1
April     Loy Yang...............................................      --        --
May       American Gas Index fund................................       1         1
August    Goldfields.............................................      45        29
December  Moapa..................................................       3         2
Various   Other..................................................       2         1
                                                                      ---       ---
          Total gain on asset sales..............................     $52       $34
                                                                      ===       ===

</Table>


     PENDING ASSET SALES: In January 2007, we signed a binding letter of intent
with Lucid Energy, LLC to sell a portfolio of our businesses in Argentina and
our northern Michigan non-utility natural gas assets for $180 million. The
assets being sold include all of our electric generating plant interests in
Argentina and our interest in the TGM natural gas pipeline business in
Argentina. We will maintain our interest in the TGN natural gas business in
Argentina, which remains subject to a potential sale to the government of
Argentina. We presently plan to retain our interest in TGN until such time as
any interest or option held by the Argentine government expires. In Michigan,
the sale includes the Antrim natural gas processing plant, 155 miles of
associated gathering lines, and interests in three special purpose gas
transmission pipelines that total 110 miles. We expect to close on the sale in
the first half of 2007.

     In February 2007, we entered into an Agreement of Purchase and Sale with
TAQA to sell our ownership interest in businesses in the Middle East, Africa,
and India for $900 million. Businesses included in the sale are Taweelah,
Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We expect to close on the
sale in the middle of 2007.

     In February 2007, we signed a memorandum of understanding with Petroleos de
Venezuela, S.A. to sell our ownership interest in SENECA and certain associated
generating equipment for $106 million. We expect to close on the sale by March
31, 2007.

     We anticipate gross proceeds from these sale transactions to total
approximately $1.186 billion. The book value of these assets at December 31,
2006 is approximately $913 million. The asset book values will vary between
December 31, 2006 and each transaction's closing date. Final book value is
dependent upon the timing of closing, results of operations for certain of the
assets up to closing, and other factors. The cumulative currency translation
losses at December 31, 2006 related to all of our businesses in Argentina are
$256 million, net of tax.

     We also announced plans to conduct an auction to sell our Atacama combined
gas pipeline and power generation businesses in Argentina and Chile, our
electric generating plant in Jamaica, and our CPEE electric distribution
business in Brazil. We expect to complete the sale of these businesses by the
end of 2007.

     Takoradi and SENECA are consolidated subsidiaries that meet the criteria of
held for sale under SFAS No. 144 subsequent to December 31, 2006. As a result,
the major classes of assets and liabilities of Takoradi and SENECA

                                     CMS-53

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

will be classified as held for sale on our Consolidated Balance Sheets in 2007.
The major classes of assets and liabilities of Takoradi and SENECA at December
31, 2006 are as follows:


<Table>
<Caption>
DECEMBER 31                                                               2006
-----------                                                               ----
                                                                      IN MILLIONS

<S>                                                                   <C>

ASSETS
  Cash..............................................................      $ 35
  Accounts receivable, net..........................................        49
  Notes receivable..................................................       106
  Property, plant and equipment, net................................        52
  Other.............................................................        12
                                                                          ----
Total assets........................................................      $254
                                                                          ====
LIABILITIES
  Accounts payable..................................................      $ 40
  Minority interest.................................................        16
  Other.............................................................        23
                                                                          ----
Total liabilities...................................................      $ 79
                                                                          ====

</Table>


     Our pending asset sales are subject to the receipt of all necessary
governmental, lender and partner approvals. We plan to use the proceeds from the
pending asset sales to invest in our utility business and reduce parent company
debt.

ASSET IMPAIRMENT CHARGES

     The following table summarizes our asset impairments:


<Table>
<Caption>
YEARS ENDED DECEMBER 31       PRETAX 2006   AFTER-TAX 2006   PRETAX 2005   AFTER-TAX 2005   PRETAX 2004   AFTER-TAX 2004
-----------------------       -----------   --------------   -----------   --------------   -----------   --------------
                                                                      IN MILLIONS

<S>                           <C>           <C>              <C>           <C>              <C>           <C>

Asset impairments:
  Enterprises:
     MCV Partnership(a).....      $218           $ 80           $1,184          $385            $ --           $ --
     GasAtacama(b)..........       239            169               --            --              --             --
     Loy Yang(c)............        --             --               --            --             125             81
     GVK....................        --             --               --            --              30             20
     SLAP...................        --             --               --            --               5              3
     Other..................         2              1               --            --              --             --
                                  ----           ----           ------          ----            ----           ----
Total asset impairments.....      $459           $250           $1,184          $385            $160           $104
                                  ====           ====           ======          ====            ====           ====

</Table>


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

(a)   As discussed in "Asset Sales," in November of 2006, we recorded an
      impairment charge of $218 million in our Consolidated Statements of Income
      (Loss). This impairment charge recognizes the reduction in fair value of
      the MCV Facility's real estate assets and results in an $80 million
      reduction to our consolidated net income after considering tax effects and
      minority interest.

      In the third quarter of 2005, NYMEX forward natural gas price forecasts
      for the years 2005 through 2010 increased substantially. Additionally,
      other independent natural gas long-term forward price forecasting
      organizations indicated their intention to raise their forecasts for the
      price of natural gas beyond 2010. As a result, the MCV Partnership
      determined an impairment analysis considering revised forward natural gas
      price assumptions was required. The MCV Partnership determined the fair
      value of its fixed assets by discounting a set of probability-weighted
      streams of future operating cash flows. The carrying value of the MCV
      Partnership's fixed assets exceeded the estimated fair value resulting in
      impairment charges of $1.159 billion to recognize the reduction in fair
      value of the MCV Facility's fixed assets and $25 million

                                     CMS-54

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      of interest capitalized during the construction of the MCV Facility. Our
      2005 consolidated net income was reduced by $385 million, after
      considering tax effects and minority interest.

(b)   In 2004, the Argentine government authorized the restriction of exports of
      natural gas to Chile, giving priority to domestic demand in Argentina.
      This restriction had a harmful effect on GasAtacama's earnings since
      GasAtacama's gas-fired electric generating plant is located in Chile and
      uses Argentine gas for fuel. Bolivia agreed to export 4 million cubic
      meters of gas per day to Argentina. With the Bolivian gas supply,
      Argentina relaxed its export restrictions to GasAtacama.

      On May 1, 2006, the Bolivian government announced its intention to
      nationalize the natural gas industry and raise prices under its existing
      gas export contracts. Since May, gas flow from Bolivia has been restricted
      while Argentina and Bolivia renegotiated the price for gas.
      Simultaneously, gas supply to GasAtacama was restricted. In July 2006,
      Argentina agreed to increase the price it pays for gas from Bolivia
      through the term of the existing contract. Argentina also announced that
      it would recover all of this price increase by a special tax on its gas
      exports. The decision of Argentina to increase the cost of its gas
      exports, in addition to maintaining the gas restriction, increased the
      risk and cost of GasAtacama's fuel supply.

      In August 2006, a major gas supplier notified GasAtacama that it would no
      longer deliver gas to GasAtacama under the Argentine government's current
      policy. We performed an impairment analysis to determine the fair value of
      our investment in GasAtacama and concluded that the fair value of our
      investment, which includes notes receivable-related party from GasAtacama,
      was lower than the carrying amount and that this decline was other than
      temporary. In the third quarter of 2006, we recorded an impairment charge
      of $239 million in our Consolidated Statements of Income (Loss). As a
      result, our consolidated net income was reduced by $169 million after
      considering tax effects and minority interest.

      Our remaining investment in GasAtacama consists of $117 million of notes
      receivable, which includes a $49 million valuation allowance recognized
      due to the impairment. We report the notes under the Enterprises business
      segment and classify them as Notes receivable-related parties on our
      Consolidated Balance Sheets. Our proportionate share of earnings or losses
      at GasAtacama is first applied to the notes receivable valuation
      allowance. We apply all cash received on the notes, whether for principal
      or interest, to the principal of the notes. If we receive cash payments on
      the notes after the principal amount has been fully collected, we will
      record interest income.

(c)   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.

DISCONTINUED OPERATIONS

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                          2006   2005   2004
-----------------------                                          ----   ----   ----
                                                                     IN MILLIONS

<S>                                                              <C>    <C>    <C>

Revenues.......................................................   $--    $--    $11
                                                                  ===    ===    ===
Discontinued operations:
  Pretax income from discontinued operations...................   $ 8(a) $22(b) $14(c)
  Income tax expense...........................................     2      8     18
                                                                  ---    ---    ---
Income (Loss) From Discontinued Operations.....................   $ 6    $14    $(4)
                                                                  ===    ===    ===

</Table>




                                     CMS-55

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

--------

(a)    Adjustments include reductions of contingent tax liabilities primarily
       related to CMS Oil and Gas.

(b)    In December 2005, we received an arbitration award related to a
       discontinued operation of $13 million ($9 million after-tax). Additional
       adjustments include a reduction of a contingent liability and a
       settlement of a tax contingency primarily related to CMS Oil and Gas.

(c)    Includes a $15 million gain on disposal of discontinued operations
       primarily related to Parmelia.

3:  CONTINGENCIES

     SEC AND DOJ INVESTIGATIONS: During the period of May 2000 through January
2002, CMS MST engaged in simultaneous, prearranged commodity trading
transactions in which energy commodities were sold and repurchased at the same
price. These so called round-trip trades had no impact on previously reported
consolidated net income, earnings per share or cash flows, but had the effect of
increasing operating revenues and operating expenses by equal amounts.

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

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

     On January 3, 2007, CMS Energy and other parties entered into a Memorandum
of Understanding (the "MOU") dated December 28, 2006, subject to court approval,
regarding settlement of the two class action lawsuits. The settlement was
approved by a special committee of independent directors and by the full board
of directors. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. The MOU is expected to lead to a detailed
stipulation of settlement that will be presented to the assigned federal judge
and the affected class in the first quarter of 2007. Under the terms of the MOU,
the litigation will be settled for a total of $200 million, including the cost
of administering the settlement and any attorney fees the court awards. CMS
Energy will make a payment of approximately $123 million plus an amount
equivalent to interest on the outstanding unpaid settlement balance beginning on
the date of preliminary approval of the court and running until the balance of
the settlement funds is paid into a settlement account. Out of the total
settlement, CMS Energy's insurers will pay approximately $77 million directly to
the settlement account. CMS Energy took an approximately $123 million net

                                     CMS-56

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

pre-tax charge to 2006 earnings in the fourth quarter. In entering into the MOU,
CMS Energy makes no admission of liability under the Shareholder Action and the
ACTS Action. At December 31, 2006, we have recorded the $77 million as an
accounts receivable and the $200 million as a legal settlement liability on our
Consolidated Balance Sheets.

     GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified
appropriate regulatory and governmental agencies that some employees at CMS MST
and CMS Field Services appeared to have provided inaccurate information
regarding natural gas trades to various energy industry publications, which
compile and report index prices. CMS Energy is cooperating with an ongoing
investigation by the DOJ regarding this matter. CMS Energy is unable to predict
the outcome of the DOJ investigation and what effect, if any, the investigation
will have on its business. The CFTC filed a civil injunctive action against two
former CMS Field Services employees in Oklahoma federal district court on
February 1, 2005. The action alleges the two engaged in reporting false natural
gas trade information, and seeks to enjoin such acts, compel compliance with the
Commodities Exchange Act, and impose monetary penalties. A trial has been set
for April 2007. CMS Energy is currently advancing legal defense costs to the two
individuals in accordance with  existing indemnification policies.

     BAY HARBOR:  As part of the development of Bay Harbor by certain
subsidiaries of CMS Energy, which went forward under an agreement with the MDEQ,
third parties constructed a golf course and a park over several abandoned cement
kiln dust (CKD) piles, left over from the former cement plant operation on the
Bay Harbor site. Pursuant to the agreement with the MDEQ, a water collection
system was constructed to recover seep water from one of the CKD piles and CMS
Energy built a treatment plant to treat the seep water. In 2002, CMS Energy sold
its interest in Bay Harbor, but retained its obligations under previous
environmental indemnifications entered into at the inception of the project.

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

     In February 2005, the EPA executed an Administrative Order on Consent (AOC)
to address problems at Bay Harbor, upon the consent of CMS Land Company (CMS
Land) and CMS Capital, LLC, both subsidiaries of CMS Energy. Pursuant to the
AOC, the EPA approved a Removal Action Work Plan in July 2005. Among other
things, this plan calls for the installation of collection trenches to intercept
high-pH CKD leachate flow to the lake. All collection systems contemplated in
this work plan have been installed. Shoreline effectiveness monitoring is
ongoing, and CMS Land is obligated to address any observed exceedances in pH.
This may potentially include the augmentation of the collection system. In May
2006, the EPA approved a pilot carbon dioxide augmentation plan to augment the
leachate recovery system by improving pH results in the Pine Court area of the
collection system. The augmentation system was installed in June 2006.

     In February 2006, CMS Land submitted to the EPA a proposed Remedial
Investigation and Feasibility Study for the East Park CKD pile. The EPA approved
a schedule for near-term activities, which includes consolidating certain CKD
materials and installing collection trenches in the East Park leachate release
area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan
and Final Engineering Design for Consolidation. CMS Energy and the MDEQ have
initiated negotiations of an AOC and to define a long-term remedy at East Park.

     The owner of one parcel of land at Bay Harbor has filed a lawsuit in Emmet
County Circuit Court against CMS Energy and several of its subsidiaries, as well
as Bay Harbor Golf Club Inc., Bay Harbor Company LLC, David C. Johnson, and
David V. Johnson, one of the developers at Bay Harbor. Several of these
defendants have demanded indemnification from CMS Energy and affiliates for the
claims made against them in the lawsuit. After a hearing in March 2006 on
motions filed by CMS Energy and other defendants, the judge dismissed various
counts of the complaint. CMS Energy will defend vigorously the existing case and
any other property damage and personal injury claims or lawsuits. In November
2006, the judge ruled against a motion to dismiss the remaining counts, and the
action is scheduled to go to trial in May 2007. CMS Land has entered into
various access, purchase and settlement

                                     CMS-57

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

agreements with several of the affected landowners at Bay Harbor. CMS Land has
purchased five unimproved lots and two lots with houses. At this time, CMS Land
believes it has all necessary access arrangements to complete the remediation
work required under the AOC.

     CMS Energy recorded charges related to this matter in 2004, 2005, and 2006
totaling $93 million, of which $9 million was recorded in 2006. At December 31,
2006, CMS Energy has a liability recorded of $52 million for its remaining
obligations We based the liability on 2006 discounted costs, using a discount
rate of 4.7 percent and an inflation rate of 1 percent on annual operating and
maintenance costs. We used the interest rate for 30-year U.S. Treasury
securities for the discount rate. The undiscounted amount of the remaining
obligation is $65 million. We expect to pay $18 million in 2007, $17 million in
2008, $3 million in 2009, and the remaining expenditures as part of long-term
operating and maintenance costs. 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 impact our
estimate of remedial action costs and the timing of the expenditures. An adverse
outcome of this matter could, depending on the size of any indemnification
obligation or liability under environmental laws, have a potentially significant
adverse effect on CMS Energy's financial condition and liquidity and could
negatively impact CMS Energy's financial results. CMS Energy cannot predict the
ultimate cost or outcome of this matter.

CONSUMERS' ELECTRIC UTILITY CONTINGENCIES

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

     Routine Maintenance Classification: The EPA has alleged that some utilities
have incorrectly classified plant modifications as "routine maintenance" rather
than seeking permits to modify the plant 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
generating plants and potentially pay fines. Additionally, the viability of
certain plants remaining in operation could be called into question.

     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 our experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $10 million. At December 31, 2006, we have
recorded a liability for the minimum amount of our estimated probable Superfund
liability. The timing of payments related to the remediation of our Superfund
sites is uncertain. Any significant change in assumptions, such as different
remediation techniques, nature and extent of contamination, and legal and
regulatory requirements, could affect our estimate of remedial action costs and
the timing of our remediation payments.

     In October 1998, during routine maintenance activities, we identified PCB
as a component in certain paint, grout, and sealant materials at Ludington. We
removed and replaced part of the PCB material. Since proposing a plan to deal
with the remaining materials, we have had several conversations with the EPA.
The EPA has proposed a rule which would authorize continued use of such material
in place, subject to certain restrictions. We are not able to predict when a
final rule will be issued.

     LITIGATION: In 2003, a group of eight PURPA qualifying facilities (the
plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit
Court. The lawsuit alleged that we incorrectly calculated the energy charge
payments made pursuant to power purchase agreements with qualifying facilities.
The judge deferred to the primary

                                     CMS-58

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

jurisdiction of the MPSC, dismissing the circuit court case without prejudice.
In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding
that we have been correctly administering the energy charge calculation
methodology. The plaintiffs have appealed the MPSC order to the Michigan Court
of Appeals. The plaintiffs also filed suit in the United States Court for the
Western District of Michigan, which the judge subsequently dismissed. The
plaintiffs have appealed the dismissal to the United States Court of Appeals. We
cannot predict the outcome of these appeals.

CONSUMERS' ELECTRIC UTILITY RATE MATTERS

     ELECTRIC ROA: In prior orders, the MPSC approved recovery of Stranded Costs
incurred from 2002 through 2003 plus the cost of money through the period of
collection. At December 31, 2006, we had a regulatory asset for Stranded Costs
of $65 million on our Consolidated Balance Sheets. We collect Stranded Costs
through a surcharge on ROA customers. At December 31, 2006, alternative electric
suppliers were providing 300 MW of generation service to ROA customers, which
represent a decrease of 46 percent of ROA load compared to the end of December
2005. If downward ROA trends continue, it may extend the time it takes to
recover fully our Stranded Costs. It is difficult to predict future ROA customer
trends and their effect on the timely recovery of Stranded Costs.

     POWER SUPPLY COSTS: To reduce the risk of high power supply costs during
peak demand periods and to achieve our reserve margin target, we purchase
electric capacity and energy contracts for the physical delivery of electricity
primarily in the summer months and to a lesser degree in the winter months. We
have purchased capacity and energy contracts covering partially the estimated
reserve margin requirements for 2007 through 2010. As a result, we have an asset
of $62 million for unexpired seasonal capacity and energy contracts at December
31, 2006. Capacity cost for these primarily seasonal electric capacity and
energy contracts was $17 million in 2006.

     PSCR: The PSCR process allows recovery of reasonable and prudent power
supply costs. The MPSC reviews these costs for reasonableness and prudency in
annual plan and reconciliation proceedings.

     2005 PSCR Reconciliation: In March 2006, we submitted our 2005 PSCR
reconciliation filing to the MPSC. Our filing indicated that 2005
underrecoveries were $36 million for commercial and industrial customers.

     2006 PSCR Plan: In August 2006, the MPSC issued an order approving our
amended 2006 PSCR plan, which resulted in an increased PSCR factor for the
remainder of 2006. PSCR underrecoveries for 2006 were $119 million. These
underrecoveries are due to the MPSC delaying recovery of our increased METC
costs and coal supply costs, increased bundled sales, and other cost increases
beyond those included in the 2006 PSCR plan filings.

     PSCR 2007 Plan: In December 2006, the MPSC issued a temporary order
allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as
filed in our September 2006 case filing. The order also approved the
incorporation of our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR
monthly factor and allowed us to continue to roll in prior year under and
overrecoveries into future PSCR plans.

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

OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES

     THE MCV PPA: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-
year power purchase agreement beginning in 1990. We estimate that capacity and
energy payments under the MCV PPA will be $620 million per year. The MCV PPA and
the associated customer rates are unaffected by the November 2006 sale of our
interest in the MCV Partnership.

     Underrecoveries related to the MCV PPA: The cost that we incur under the
MCV PPA exceeds the recovery amount allowed by the MPSC. We expensed
underrecoveries of $57 million in 2006 and we estimate cash

                                     CMS-59

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

underrecoveries of $39 million in 2007. However, we use the direct savings from
the RCP, after allocating a portion to customers, to offset a portion of our
capacity and fixed energy underrecoveries expense.

     RCP: In January 2005, we implemented the MPSC-approved RCP with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV Facility based on natural gas market prices.
This results in fuel cost savings for the MCV Facility, which the MCV
Partnership shares with us. The RCP also requires us to contribute $5 million
annually to a renewable resources program. As of December 2006, we have
contributed $10 million to the renewable resources program. The underlying RCP
agreement between Consumers and the MCV Partnership extends through the term of
the MCV PPA. However, either party may terminate that agreement under certain
conditions. In January 2007, the Michigan Attorney General filed an appeal with
the Michigan Supreme Court regarding the MPSC's order approving the RCP. We
cannot predict the outcome of this matter.

     Regulatory Out Provision in the MCV PPA: After September 15, 2007, we
expect to claim relief under the regulatory out provision in the MCV PPA,
thereby limiting our capacity and fixed energy payments to the MCV Partnership
to the amounts that we collect from our customers. The MCV Partnership has
notified us that it takes issue with our intended exercise of the regulatory out
provision. We believe that the provision is valid and fully effective, but
cannot assure that it will prevail in the event of a dispute. If we are
successful in exercising the regulatory out provision, the MCV Partnership has
the right to terminate the MCV PPA, which could affect our reserve margin. We
anticipate that the MPSC will review our exercise of the regulatory out
provision and the likely consequences of such action in 2007. It is possible
that in the event that the MCV Partnership ceases performance under the MCV PPA,
prior orders could limit recovery of replacement power costs to the amounts that
the MPSC authorized for recovery under the MCV PPA. Depending on the cost of
replacement power, this could result in our costs exceeding the recovery amount
allowed by the MPSC. We cannot predict the outcome these matters.

     THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT: In
July 2006, we reached an agreement to sell Palisades to Entergy for $380 million
and pay Entergy $30 million to assume ownership and responsibility for the Big
Rock ISFSI.

     Palisades Asset Sale: The sale is subject to various regulatory approvals,
including the MPSC's approval of the power purchase agreement, and the NRC's
approval of the transfer of the operating license to Entergy and other related
matters. In February 2007, the FERC issued an order approving the sale of power
to us under the power purchase agreement and granted other related approvals,
with what we believe are minor exceptions and conditions that we believe can be
adequately accepted. In October 2006, the Federal Trade Commission issued a
notice that neither it nor the DOJ's Antitrust Division plans to take
enforcement action on the sale. The final purchase price will be subject to
various closing adjustments such as working capital and capital expenditure
adjustments, adjustments for nuclear fuel usage and inventory, and the date of
closing. However, termination of the sale agreement can occur if the closing
does not take place by January 2008. To accommodate delays in receiving
regulatory approval, extension of the closing can occur for up to six months. We
cannot predict with certainty whether or when satisfaction of the closing
conditions will occur or whether or when completion of the transaction will
occur.

     Under the agreement, if the transaction does not close by March 1, 2007, a
reduction in the purchase price occurs of approximately $80,000 per day, with
additional costs if the deal does not close by June 1, 2007. Based on the MPSC's
published schedule for the contested case proceedings regarding this
transaction, we target to close on the transaction in the second quarter of
2007. Based on the anticipated closing date, this delay would result in a
purchase price reduction for Palisades of approximately $5 million. We estimate
that the Palisades sale will result in a $31 million premium above the Palisades
asset value at the anticipated closing date after accounting for estimated
sales-related costs. We expect that this premium will benefit our customers. We
cannot predict with certainty whether or when satisfaction of the closing
conditions will occur or whether or when completion of the transaction will
occur.


                                     CMS-60

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     We have notified the NMC that we plan to terminate the NMC's operation of
Palisades, if the sale is completed, which would require us to pay the NMC an
estimated $12 million. Due to the regulatory approvals pending, we have not
recorded this contingent obligation.

     Palisades Power Purchase Agreement: As part of the transaction, Entergy
will sell us 100 percent of the plant's output up to its current capacity of 798
MW under a 15-year power purchase agreement. During the term of the power
purchase agreement, Entergy is obligated to supply, and we are obligated to
take, all capacity and energy from the Palisades plant, exclusive of uprates
above the plant's presently specified capacity. When the plant is not operating
or is derated, under certain circumstances Entergy can elect to provide
replacement power from another source at the rates set in the power purchase
agreement. Otherwise, we would have to obtain replacement power from the market.
However, we are only obligated to pay Entergy for capacity and energy actually
delivered by Entergy either from the plant or from an allowable replacement
source chosen by Entergy. If Entergy schedules a plant outage in June, July or
August, Entergy is required to provide replacement power at power purchase
agreement rates. There are significant penalties incurred by Entergy if the
delivered energy fails to achieve a minimum capacity factor level during July
and August. Over the term of the power purchase agreement, the pricing terms are
such that Consumers' ratepayers will retain the benefits of the Palisades
plant's low-cost nuclear generation.

     Because of the power purchase agreement that will be in place between
Consumers and Entergy, the transaction is effectively a sale and leaseback for
accounting purposes. SFAS No. 98 specifies the accounting required for a
seller's sale and simultaneous leaseback transaction involving real estate,
including real estate with equipment. Due to forms of continuing involvement, we
will account for the transaction as a financing for accounting purposes and not
a sale. As such, we have not classified the assets as held for sale on our
Consolidated Balance Sheets.

     NUCLEAR PLANT DECOMMISSIONING: The MPSC and the FERC regulate the recovery
of costs to decommission, or remove from service, our Big Rock and Palisades
nuclear plants. Decommissioning funding practices approved by the MPSC require
us to file a report on the adequacy of funds for decommissioning at three-year
intervals. We prepared and filed updated cost estimates for Big Rock and
Palisades in March 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. Big Rock's estimated cost includes historical
expenditures in nominal dollars and future costs in 2003 dollars, with all
Palisades costs given in 2003 dollars. Updated cost projections for Big Rock
indicate an anticipated decommissioning cost of $390 million as of December
2006.

     Big Rock: In December 2000, funding of the Big Rock trust fund stopped
because the MPSC-authorized decommissioning surcharge collection period expired.
In our March 2004 report to the MPSC, we indicated that we would manage the
decommissioning trust fund to meet annual NRC financial assurance requirements
by withdrawing NRC radiological decommissioning costs from the fund and
initially funding non-NRC greenfield costs out of corporate funds. In March
2006, we contributed $16 million to the trust fund from our corporate funds to
support NRC radiological decommissioning costs. Excluding the additional nuclear
fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we
are projecting that the level of funds provided by the trust will fall short of
the amount needed to complete the decommissioning by an additional $37 million.
This total of $53 million, which are costs associated with NRC radiological and
non-NRC greenfield decommissioning work, are being funded out of corporate
funds. We plan to seek recovery of such expenditures recorded on our
consolidated balance sheets in future filings with the MPSC.

     We have incurred Big Rock expenditures, excluding nuclear fuel storage
costs, of $41 million for the year ended December 31, 2006, and cumulative
expenditures through December 31, 2006 of $386 million. These activities had no
material impact on consolidated net income. At December 31, 2006, we have an
investment in nuclear decommissioning corporate funded trust funds of $4 million
for Big Rock. In addition, at December 31, 2006, we have charged $10 million to
our FERC jurisdictional depreciation reserve for the decommissioning of Big
Rock.


                                     CMS-61

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     Palisades: Excluding additional nuclear fuel storage costs due to the DOE's
failure to accept spent fuel on schedule, we concluded, based on the cost
estimates filed in March 2004, that the existing Palisades' surcharge of $6
million needed to be increased to $25 million annually, beginning January 2006.
A settlement agreement was approved by the MPSC, providing for the continuation
of the existing $6 million annual decommissioning surcharge through 2011, which
was our original license expiration date, and for the next periodic review to be
filed in March 2007. Amounts collected from electric retail customers and
deposited in trusts, including trust earnings, are credited to a regulatory
liability.

     At December 31, 2006, we have an investment in the MPSC nuclear
decommissioning trust funds of $587 million for Palisades. In addition, at
December 31, 2006, we have a FERC decommissioning trust fund with a balance of
$11 million. In the FERC's February 2007 order regarding the Palisades sale, the
FERC granted our request to apply the $11 million FERC decommissioning trust
fund balance toward the Big Rock decommissioning shortfall, subject to the
outcome of the NRC operating license transfer proceedings and completion of the
Palisades sale transaction. For additional details on decommissioning costs
accounted for as asset retirement obligations, see Note 8, Asset Retirement
Obligations.

     In March 2005, the NMC, which operates the Palisades plant, applied for a
20-year license renewal for the plant on behalf of Consumers. In January 2007,
the NRC renewed the Palisades operating license for 20 years, extending it to
2031. At this time, we cannot determine what impact this will have on
decommissioning costs or the adequacy of funding. Initial estimates of
decommissioning costs, assuming a plant retirement date of 2031, show
decommissioning costs of either $818 million or $1.049 billion for Palisades,
depending on the decommissioning methodology assumed. These costs, which exclude
additional costs for spent nuclear fuel storage due to the DOE's failure to
accept spent nuclear fuel on schedule, are given in 2003 dollars.

     NUCLEAR MATTERS

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

     There are two court decisions that support the right of utilities to pursue
damage claims in the United States Court of Claims against the DOE for failure
to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims. We filed our complaint in
December 2002. If our litigation against the DOE is successful, we plan to use
any recoveries as reimbursement for the incurred costs of spent nuclear fuel
storage. We can make no assurance that the litigation against the DOE will be
successful.

     In 2002, the site at Yucca Mountain, Nevada was designated for the
development of a repository for the disposal of high-level radioactive waste and
spent nuclear fuel. We expect that the DOE, in due course, will submit a final
license application to the NRC for the repository. The application and review
process is estimated to take several years.

     Insurance: We maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $30 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 energy
hazard for up to approximately $10.761 billion, the maximum insurance liability
limits established by the Price-Anderson Act. Part of the Price-Anderson Act's
financial protection is a mandatory industry-wide program under which owners of
nuclear generating facilities could be assessed if a nuclear incident

                                     CMS-62

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

occurs at any nuclear generating facility. The maximum assessment against us
could be $101 million per occurrence, limited to maximum annual installment
payments of $15 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. This requirement will
end December 31, 2007.

     Big Rock remains insured for nuclear liability up to $544 million through
nuclear insurance and NRC indemnity, and maintains a nuclear property insurance
policy from NEIL.

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

CONSUMERS' GAS UTILITY CONTINGENCIES

     GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remediation
costs at a number of sites under the Michigan Natural Resources and
Environmental Protection Act, a Michigan statute that covers environmental
activities including remediation. These sites include 23 former manufactured gas
plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or
may own only a portion of the original site. In 2005, we estimated our remaining
costs to be between $29 million and $71 million, based on 2005 discounted costs,
using a discount rate of three percent. The discount rate represents a 10-year
average of U.S. Treasury bond rates reduced for increases in the consumer price
index. We expect to fund most of these costs through proceeds derived from a
settlement with insurers and MPSC-approved rates. At December 31, 2006, we have
a liability of $24 million, net of $59 million of expenditures incurred to date,
and a regulatory asset of $56 million. The timing of payments related to the
remediation of our manufactured gas plant sites is uncertain. 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 and
the timing our remediation payments.

CONSUMERS' GAS UTILITY RATE MATTERS

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

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


<Table>
<Caption>
                                 GAS COST RECOVERY RECONCILIATION
--------------------------------------------------------------------------------------------------
                                      NET OVER-     GCR COST
GCR YEAR   DATE FILED   ORDER DATE    RECOVERY     OF GAS SOLD    DESCRIPTION OF NET OVERRECOVERY
--------   ----------   ----------   ----------   ------------   ---------------------------------

<S>        <C>          <C>          <C>          <C>            <C>

2004-2005  June 2005    April 2006   $2 million   $1.4 billion   The net overrecovery includes
                                                                 interest expense through March
                                                                 2005 and refunds that we received
                                                                 from our suppliers that are
                                                                 required to be refunded to our
                                                                 customers.
2005-2006  June 2006    Pending      $3 million   $1.8 billion   The net overrecovery includes $1
                                                                 million interest income through
                                                                 March 2006, which resulted from a
                                                                 net underrecovery position during
                                                                 the majority of the GCR period.
</Table>


     GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for
our 2005-2006 GCR Plan year, which resulted in approval of a settlement
agreement and established a fixed price cap of $10.10 per mcf for the December
2005 through March 2006 billing period. We were able to maintain our billing GCR
factor below the

                                     CMS-63

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

authorized level for that period. The order was appealed to the Michigan Court
of Appeals by one intervenor. We are unable to predict the outcome of this
proceeding.

     GCR plan for year 2006-2007: In December 2005, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2006
through March 2007. Our request proposed using a GCR factor consisting of:

     - a base GCR ceiling factor of $11.10 per mcf, plus

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

     In July 2006, all parties signed a partial settlement agreement, which
calls for a base GCR ceiling factor of $9.48 per mcf. The settlement agreement
base GCR ceiling factor is subject to a quarterly GCR ceiling price adjustment
mechanism. The adjustment mechanism allows an adjustment of the base ceiling
factor to reflect a portion of cost increases, if the average NYMEX price for a
specified period is greater than that used in calculating the base GCR factor.
The MPSC approved the settlement agreement in August 2006.

     The GCR billing factor is adjusted monthly in order to minimize the over or
underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor
for the month of February 2007 is $7.63 per mcf.

     GCR plan for year 2007-2008: In December 2006, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2007
through March 2008. Our request proposed using a GCR factor consisting of:

     - a base GCR ceiling factor of $8.47 per mcf, plus

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

     2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC for
an annual gas rate increase of $132 million. In May 2006, the MPSC issued an
order granting us interim rate relief of $18 million annually.

     In November 2006, the MPSC issued an order granting rate relief of $81
million, which included the $18 million of interim relief granted in May 2006.
The MPSC authorized an 11 percent return on common equity, a reduction from our
then current 11.4 percent authorized rate of return. In addition, the order made
permanent the collection of a $58 million surcharge granted in October 2004.

     2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC
for an annual gas rate increase of $88 million and an 11.25 percent authorized
return on equity. We have proposed the use of a Revenue Decoupling and
Conservation Incentive Mechanism for residential and general service rate
classes to help assure a reasonable opportunity to recover costs that do not
fluctuate with volumetric changes.

OTHER CONTINGENCIES

     GAS INDEX PRICE REPORTING LITIGATION: CMS Energy, CMS MST, CMS Field
Services, Cantera Natural Gas, Inc. (the company that purchased CMS Field
Services) and Cantera Gas Company are named as defendants in various lawsuits
arising as a result of claimed inaccurate natural gas price reporting.
Allegations include manipulation of NYMEX natural gas futures and options
prices, price-fixing conspiracies, and artificial inflation of natural gas
retail prices in California, Colorado, Kansas, Missouri, Tennessee, and Wyoming.
In September 2006, CMS MST reached an agreement in principle to settle the
master class action suit in California for $7 million. The settlement agreement
has been signed. The settlement payment is not due until the court has approved
the settlement. CMS Energy deemed this settlement to be probable and accrued the
payment in its consolidated financial statements at September 30, 2006. CMS
Energy and the other CMS Energy defendants will defend themselves vigorously
against all of these matters but cannot predict their outcome.

     DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD),
the primary construction contractor for the DIG facility, presented DIG with a
change order to their construction contract and filed an action

                                     CMS-64

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

in Michigan state court against DIG, claiming contractual damages in the amount
of $110 million, plus interest and costs. DFD also filed a construction lien for
the $110 million. DIG contested both of the claims made by DFD. In addition to
drawing down on three letters of credit totaling $30 million that it obtained
from DFD, DIG 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. The arbitration hearing
concluded on September 28, 2006 and the arbitration panel issued its award on
December 21, 2006. The arbitration panel awarded DIG approximately $25 million,
including interest, on its various claims against DFD presented in the
arbitration. The panel also awarded DFD approximately $5 million on its claims
and credited DFD approximately $30 million for the three letters of credit DIG
drew against DFD, plus $2 million in interest on the award amount. This resulted
in a net amount due DFD, inclusive of interest, in the amount of approximately
$12 million, which DIG has paid. CMS Energy had previously accrued a liability
of approximately $30 million relating to the three letters of credit. In
December 2006, we recorded $20 million pre-tax as a reduction of Operating
Expenses in our Consolidated Statements of Income (Loss). The arbitration
between DIG and DFD is now complete.

     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. Appeals were filed of the original verdict and a subsequent
decision of the court on remand. The court of appeals issued an opinion on May
26, 2005 remanding the case to the trial court for a new trial on damages. At a
status conference on April 10, 2006, the judge set a six-month discovery period.
The case is set for a new trial on damages in August 2007. The parties attended
a court-ordered mediation on July 14, 2006 and the matter was not resolved.
Enterprises has an indemnity obligation with regard to losses to Terra that
might result from this litigation.

     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.

     The Argentine commercial court granted injunctive relief to CMS Ensenada
pursuant to an ex parte action, and such relief remained in effect until
completion of arbitration on the matter, administered by the International
Chamber of Commerce (ICC). The arbitration hearing was held in July 2005. The
ICC released the arbitral tribunal's partial award dated August 22, 2006. The
partial award is generally favorable to CMS Ensenada. Following the arbitation
decision, CMS Ensenada reached agreement with YPF Repsol, under which YPF Repsol
paid approximately $24 million for the period through December 31, 2006, and the
parties agreed to revert substantially to the terms and conditions of the
original contract. We recorded $21 million as Operating Revenue and $3 million
as Other interest in our Consolidated Statements of Income (Loss). The parties
have notified the ICC that all outstanding issues relating to the arbitral
tribunal's partial award have been resolved fully by mutual agreement between
the parties.

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

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


                                     CMS-65

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

     The ICSID Convention provides that either party may seek annulment of the
award based upon five possible grounds specified in the Convention. Argentina's
Application for Annulment was formally registered by ICSID on September 27, 2005
and will be considered by a newly constituted panel.

     On December 28, 2005, certain insurance underwriters paid the sum of $75
million to CMS Gas Transmission in respect of their insurance obligations
resulting from non-payment of the ICSID award. The payment, plus interest, is
subject to repayment by CMS Gas Transmission in the event that the ICSID award
is annulled. Pending the outcome of the annulment proceedings, CMS Energy has
recorded the $75 million payment as a long-term deferred credit.

     QUICKSILVER RESOURCES, INC.: Quicksilver sued CMS MST for breach of
contract in connection with a Contract for Sale and Purchase of natural gas,
pursuant to which Quicksilver agreed to sell, and CMS MST to buy, natural gas,
Quicksilver believes that it is entitled to more payments for natural gas than
it has received. CMS MST disagrees with Quicksilver's analysis and believes that
it has paid all amounts owed for delivery of gas pursuant to the contract.
Quicksilver is seeking damages of up to approximately $126 million, plus
prejudgement interest and attorney fees, which in our judgement is totally
unsupported by the facts.

     T.E.S. FILER CITY AIR PERMIT ISSUE: In January 2007, we received a Notice
of Violation (NOV) from the EPA alleging that T.E.S. Filer City, a generating
facility in which we have a 50 percent partnership interest, exceeded certain
air permit limits. We are in discussions with the EPA with regard to these
allegations, but cannot predict the financial impact or outcome of this issue.

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

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

     FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE
REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF
OTHERS: The Interpretation requires the guarantor, upon issuance of a guarantee,
to recognize a liability for the fair value of the obligation it undertakes in
issuing the guarantee.


                                     CMS-66

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The following table describes our guarantees at December 31, 2006:


<Table>
<Caption>
                                                                               MAXIMUM    CARRYING
GUARANTEE DESCRIPTION               ISSUE DATE         EXPIRATION DATE       OBLIGATION    AMOUNT
---------------------              ------------   ------------------------   ----------   --------
                                                                                 (IN MILLIONS)

<S>                                <C>            <C>                        <C>          <C>

Indemnifications from asset
  sales and other agreements(a)    October 1995   Indefinite                   $1,133        $ 1
Standby letters of credit and
  loans(b)                         Various        Various through May 2010         85         --
Surety bonds and other
  indemnifications                 Various        Indefinite                       10         --
Guarantees and put options(c)      Various        Various through                 209          1
                                                  September 2027
Nuclear insurance retrospective
  premiums                         Various        Indefinite                      137         --
</Table>


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

(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 claims resulting from tax disputes and the
      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)   Standby letters of credit include letters of credit issued under an
      amended credit agreement with Citicorp USA, Inc. The amended credit
      agreement is supported by a guaranty issued by certain subsidiaries of CMS
      Energy. At December 31, 2006, letters of credit issued on behalf of
      unconsolidated affiliates totaling $65 million were outstanding.

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


                                     CMS-67

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The following table provides additional information regarding our
guarantees:


<Table>
<Caption>
                                                            EVENTS THAT WOULD
                                          HOW GUARANTEE          REQUIRE
GUARANTEE DESCRIPTION                         AROSE            PERFORMANCE
---------------------                     -------------     -----------------

<S>                                     <C>                 <C>

Indemnifications from asset sales and   Stock and asset     Findings of
  other                                 sales               misrepresenta-
  agreements                            agreements          tion, breach of
                                                            warranties, and
                                                            other specific
                                                            events or
                                                            circumstances
Standby letters of credit               Credit agreement    Non-payment by
  and loans                                                 CMS
                                                            Energy and
                                                            Enterprises of
                                                            obligations under
                                                            the credit
                                                            agreement
Surety bonds and other                  Normal operating    Nonperformance
  indemnifications                      activity, permits
                                        and licenses
Guarantees and put options              Normal operating    Nonperformance or
                                        activity            non-payment by a
                                        Agreement to        subsidiary under
                                        provide power and   a related
                                        steam to Dow Bay    contract MCV
                                        Harbor              Partnership's
                                        remediation         nonperformance or
                                        efforts             non-payment under
                                                            a related
                                                            contract Owners
                                                            exercising put
                                                            options requiring
                                                            us to purchase
                                                            property
Nuclear insurance retrospective         Normal operations   Call by NEIL and
  premiums                              of nuclear plants   Price-Anderson
                                                            Act for nuclear
                                                            incident
</Table>


     At December 31, 2006, certain contracts contained provisions allowing us to
recover, from third parties, amounts paid under the guarantees. For example, if
we are required to purchase a property under a put option agreement, we may sell
the property to recover the amount paid under the option.

     We enter into various agreements containing tax and other indemnification
provisions in connection with a variety of transactions, including the sale of
our interests in the MCV Partnership and the FMLP. While we are unable to
estimate the maximum potential obligation related to these indemnities, we
consider the likelihood that we would be required to perform or incur
significant losses related to these indemnities and the guarantees listed in the
preceding tables to be remote.

     Project Financing: We enter into various project-financing security
arrangements such as equity pledge agreements and share mortgage agreements to
provide financial or performance assurance to third parties on behalf of certain
unconsolidated affiliates. Expiration dates for these agreements vary from March
2015 to June 2020 or terminate upon payment or cancellation of the obligation.
Non-payment or other act of default by an unconsolidated affiliate would trigger
enforcement of the security. If we were required to perform under these
agreements, the maximum amount of our obligation under these agreements would be
equal to the value of the shares relinquished to the guaranteed party at the
time of default.

     In February 2007, we reached an agreement to sell our ownership interests
in businesses in the Middle East, Africa, and India to TAQA. The proposed
agreement calls for TAQA to either arrange for substitute guarantee agreements
to replace our contingent obligations related to our project-financing security
agreements or assume all of our contingent obligations under such agreements. In
the event beneficiaries under these agreements refuse to accept substitution or
assumption of our contingent obligations, TAQA will indemnify us for any losses
under our project-financing security agreements that relate to events occurring
after the close of the sale. For more details on the sale of our ownership
interests to TAQA, see Note 2, Asset Sales, Impairment Charges and Discontinued
Operations.


                                     CMS-68

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

4:  FINANCINGS AND CAPITALIZATION


<Table>
<Caption>
LONG-TERM DEBT AT DECEMBER 31 FOLLOWS:        INTEREST RATE (%)    MATURITY    2006     2005
--------------------------------------        -----------------    --------    ----     ----
                                                                               (IN MILLIONS)

<S>                                           <C>                 <C>         <C>      <C>

CMS ENERGY CORPORATION
  Senior notes..............................         9.875           2007     $  289   $  365
                                                     8.900           2008        260      260
                                                     7.500           2009        409      409
                                                     7.750           2010        300      300
                                                     8.500           2011        300      300
                                                     6.300           2012        150      150
                                                     6.875           2015        125      125
                                                     3.375(a)        2023        150      150
                                                     2.875(a)        2024        288      288
                                                                              ------   ------
                                                                               2,271    2,347
  Other.....................................                                       1        2
                                                                              ------   ------
     Total -- CMS Energy Corporation........                                   2,272    2,349
                                                                              ------   ------
CONSUMERS ENERGY COMPANY
  First mortgage bonds......................         4.250           2008        250      250
                                                     4.800           2009        200      200
                                                     4.400           2009        150      150
                                                     4.000           2010        250      250
                                                     5.000           2012        300      300
                                                     5.375           2013        375      375
                                                     6.000           2014        200      200
                                                     5.000           2015        225      225
                                                     5.500           2016        350      350
                                                     5.150           2017        250      250
                                                     5.650           2020        300      300
                                                     5.650           2035        147      150
                                                     5.800           2035        175      175
                                                                              ------   ------
                                                                               3,172    3,175
                                                                              ------   ------
  Senior notes..............................         6.375           2008        159      159
                                                     6.875           2018        180      180
                                                                              ------   ------
                                                                                 339      339
                                                                              ------   ------
  Securitization bonds......................         5.384(b)     2007-2015      340      369
  FMLP debt.................................                                      --      207
  Nuclear fuel disposal liability...........                         (c)         152      145
  Tax-exempt pollution control revenue
     bonds..................................       Various        2010-2035      161      161
                                                                              ------   ------
     Total -- Consumers Energy Company......                                   4,164    4,396
                                                                              ------   ------
OTHER SUBSIDIARIES..........................                                     331      363
                                                                              ------   ------
Total principal amount outstanding                                             6,767    7,108
  Current amounts...........................                                    (551)    (289)
  Net unamortized discount..................                                     (14)     (19)
                                                                              ------   ------
Total long-term debt........................                                  $6,202   $6,800
                                                                              ======   ======

</Table>


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

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

(b)   Represents the weighted average interest rate at December 31, 2006 (5.295
      percent at December 31, 2005).

(c)   Maturity date uncertain.


                                     CMS-69

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     RETIREMENTS: The following is a summary of significant long-term debt
retirements during 2006:


<Table>
<Caption>
                                     PRINCIPAL
                                   (IN MILLIONS)   INTEREST RATE (%)   RETIREMENT DATE   MATURITY DATE
                                   -------------   -----------------   ---------------   -------------

<S>                                <C>             <C>                 <C>               <C>

CMS ENERGY
  Senior notes...................       $ 76               9.875       January through    October 2007
                                                                          April 2006
CONSUMERS
  Long-term debt -- related
     parties.....................        129                9.00        February 2006      June 2031
  FMLP debt......................         56               13.25          July 2006        July 2006
  FMLP debt(a)...................        151             Various        November 2006      July 2009
ENTERPRISES
  CMS Generation Investment Co.
     IV Bank Loan................         49            Variable         June through    December 2008
                                                                        December 2006
                                        ----
     Total.......................       $461
                                        ====

</Table>


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

(a)   FMLP debt of $151 million was removed as part of the November 2006
      transaction in which Consumers sold its interest in the FMLP.

     FIRST MORTGAGE BONDS: Consumers secures its FMB by a mortgage and lien on
substantially all of its property. Its ability to issue FMB is restricted by
certain provisions in the first mortgage bond indenture and the need for
regulatory approvals under federal law. Restrictive new issuance provisions in
the first mortgage bond indenture include achieving a two-times interest
coverage ratio and having sufficient unfunded net property additions.

     SECURITIZATION BONDS: Certain regulatory assets collateralize
Securitization bonds. The bondholders have no recourse to our other assets.
Through Consumers' rate structure, we bill customers for securitization
surcharges to fund the payment of principal, interest, and other related
expenses on the Securitization bonds. Securitization surcharges collected are
remitted to a trustee for the Securitization bonds and are not available to
creditors of Consumers or its affiliates. Securitization surcharges totaled $50
million in 2006 and 2005.

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

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


<Table>
<Caption>
DEBENTURE AND RELATED PARTY                       INTEREST RATE (%)   MATURITY   2006    2005
---------------------------                       -----------------   --------   ----    ----
                                                                                      (IN
                                                                                   MILLIONS)

<S>                                               <C>                 <C>        <C>    <C>

Convertible subordinated debentures, CMS Energy
  Trust I.......................................         7.75           2027     $178   $ 178
Subordinated debentures:
  Consumers Energy Company Financing IV.........         9.00                      --     129
                                                                                 ----   -----
Total principal amounts outstanding.............                                  178     307
  Current amounts...............................                                   --    (129)
                                                                                 ----   -----
Total Long-term debt -- related parties.........                                 $178   $ 178
                                                                                 ====   =====

</Table>


     In the event of default, holders of the Trust Preferred Securities would be
entitled to exercise and enforce the trusts' creditor rights against us, which
may include acceleration of the principal amount due on the debentures. CMS
Energy and Consumers, as applicable, have issued certain guarantees with respect
to payments on the preferred securities. These guarantees, when taken together
with our obligations under the debentures, related

                                     CMS-70

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

indenture and trust documents, provide full and unconditional guarantees for the
trusts' obligations under the preferred securities.

     DEBT MATURITIES: At December 31, 2006, the aggregate annual contractual
maturities for long-term debt and long-term debt -- related parties for the next
five years are:


<Table>
<Caption>
                                                               PAYMENTS DUE
                                                     --------------------------------
                                                     2007   2008   2009   2010   2011
                                                     ----   ----   ----   ----   ----
                                                               (IN MILLIONS)

<S>                                                  <C>    <C>    <C>    <C>    <C>

Long-term debt and long-term debt -- related
  parties..........................................  $401   $837   $814   $660   $353
</Table>


     REGULATORY AUTHORIZATION FOR FINANCINGS: In May 2006, the FERC issued an
order authorizing Consumers to issue up to $2.0 billion of secured and unsecured
short-term securities for the following purposes:

     - up to $1.0 billion for general corporate purposes, and

     - up to $1.0 billion of FMB or other securities to be issued solely as
       collateral for other short-term securities.

     Also in May 2006, the FERC issued an order authorizing Consumers to issue
up to $5.0 billion of secured and unsecured long-term securities for the
following purposes:

     - up to $1.5 billion for general corporate purposes,

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

     - up to $2.5 billion of FMB or other securities to be issued solely as
       collateral for other long-term securities.

     The authorizations are for a two-year period beginning July 1, 2006 and
ending June 30, 2008. Any long-term issuances during the two-year authorization
period are exempt from the FERC's competitive bidding and negotiated placement
requirements.

     REVOLVING CREDIT FACILITIES: The following secured revolving credit
facilities with banks are available at December 31, 2006:


<Table>
<Caption>
                                                                             OUTSTANDING
                                                      AMOUNT OF    AMOUNT    LETTERS-OF-     AMOUNT
COMPANY                             EXPIRATION DATE    FACILITY   BORROWED      CREDIT     AVAILABLE
-------                             ---------------   ---------   --------   -----------   ---------
                                                              (IN MILLIONS)

<S>                                 <C>               <C>         <C>        <C>           <C>

CMS Energy........................    May 18, 2010       $300        $--         $98          $202
Consumers.........................   March 30, 2007       300         --          --           300
Consumers.........................    May 18, 2010        500         --          58           442
</Table>


     Effective February 2007, Consumers terminated their $300 million facility.

     DIVIDEND RESTRICTIONS: CMS Energy's $300 million secured revolving credit
facility restricts payments of dividends on our common stock during a 12-month
period to $150 million, dependent on the aggregate amounts of unrestricted cash
and unused commitments under the facility.

     Under the provisions of its articles of incorporation, at December 31,
2006, Consumers had $215 million of unrestricted retained earnings available to
pay common stock dividends. Covenants in Consumers' debt facilities restrict its
ability to pay dividends to us by capping common stock dividend payments at $300
million in a calendar year. At December 31, 2006, $2.702 billion of net assets
were subject to such restrictions. Provisions of the Federal Power Act and the
Natural Gas Act effectively restrict dividends to the amount of Consumers'
retained earnings. During 2006, we received $147 million of common stock
dividends from Consumers.

     SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, Consumers sells certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. The special purpose entity

                                     CMS-71

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

sold $325 million of receivables at December 31, 2006 and December 31, 2005.
Consumers continues to service the receivables sold to the special purpose
entity. The purchaser of the receivables has no recourse against Consumers'
other assets for failure of a debtor to pay when due and no right to any
receivables not sold. Consumers has neither recorded a gain or loss on the
receivables sold nor retained interest in the receivables sold.

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                            2006     2005
-----------------------                                            ----     ----
                                                                   (IN MILLIONS)

<S>                                                               <C>      <C>

Net cash flow as a result of accounts receivable financing......  $   --   $   21
Collections from customers......................................  $5,684   $4,859
</Table>


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

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

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

     PREFERRED STOCK: Our Preferred Stock outstanding follows:


<Table>
<Caption>
                                                       NUMBER OF SHARES
                                                    ---------------------
DECEMBER 31                                            2006        2005     2006   2005
-----------                                            ----        ----     ----   ----
                                                                                (IN
                                                                             MILLIONS)

<S>                                                 <C>         <C>         <C>    <C>

Preferred Stock
  4.50% convertible,
     Authorized 10,000,000 shares(a)..............  5,000,000   5,000,000   $250   $250
  Preferred subsidiary interest...................                            11     11
                                                                            ----   ----
Total Preferred stock.............................                          $261   $261
                                                                            ====   ====

</Table>


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

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

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


<Table>
<Caption>
                                                   OPTIONAL     NUMBER OF SHARES
                                                  REDEMPTION   -----------------
DECEMBER 31                              SERIES      PRICE       2006      2005    2006   2005
-----------                              ------   ----------     ----      ----    ----   ----
                                                                                       (IN
                                                                                    MILLIONS)

<S>                                      <C>      <C>          <C>       <C>       <C>    <C>

Preferred Stock
  Cumulative $100 par value, Authorized
     7,500,000 shares, with no
     mandatory redemption..............   $4.16     $103.25     68,451    68,451    $ 7    $ 7
                                          $4.50     $110.00    373,148   373,148     37     37
                                                                                    ---    ---
Total Preferred stock of subsidiary....                                             $44    $44
                                                                                    ===    ===

</Table>


     CONTINGENTLY CONVERTIBLE SECURITIES: At December 31, 2006, the significant
terms of our contingently convertible securities were as follows:


<Table>
<Caption>
                                                      NUMBER     OUTSTANDING    CONVERSION   TRIGGER
CONTINGENTLY CONVERTIBLE SECURITY        MATURITY    OF UNITS   (IN MILLIONS)      PRICE      PRICE
---------------------------------        --------   ---------   -------------   ----------   -------

<S>                                      <C>        <C>         <C>             <C>          <C>

4.50% preferred stock..................     N/A     5,000,000        $250         $ 9.89      $11.87
3.375% senior notes....................    2023       150,000        $150         $10.67      $12.81
2.875% senior notes....................    2024       287,500        $288         $14.75      $17.70
</Table>




                                     CMS-72

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The note holders have the right to require us to purchase the 3.375 percent
convertible senior notes at par on July 15, 2008, 2013, and 2018. The note
holders have the right to require us to purchase the 2.875 percent convertible
senior notes at par on December 1, 2011, 2014, and 2019. On or after December 5,
2008, we may cause the 4.50 percent convertible preferred stock to convert if
the closing price of our common stock remains at or above $12.86 for 20 of any
30 consecutive trading days.

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

     All of our contingently convertible securities require us, if converted, to
pay cash up to the principal (or par) amount of the securities and any
conversion value in excess of that amount in shares of our common stock. In
December 2006, the trigger price contingency was met for our 4.50 percent
convertible preferred stock and our 3.375 percent convertible senior notes. As a
result, these securities are convertible at the option of the security holders
during the three months ended March 31, 2007. As of February 2007, none of the
security holders have notified us of their intention to convert these
securities.

     Because the 3.375 percent senior notes are convertible on demand, they are
classified as current liabilities.

5: EARNINGS PER SHARE

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                      2006     2005     2004
-----------------------                                     ------   ------   ------
                                                              (IN MILLIONS, EXCEPT
                                                               PER SHARE AMOUNTS)

<S>                                                         <C>      <C>      <C>

EARNINGS AVAILABLE TO COMMON STOCKHOLDERS
  Income (Loss) from Continuing Operations................  $  (85)  $  (98)  $  127
  Less Preferred Dividends................................     (11)     (10)     (11)
                                                            ------   ------   ------
  Income (Loss) from Continuing Operations Available to
     Common Stockholders -- Basic.........................     (96)    (108)     116
  Add dilutive impact of Contingently Convertible
     Securities (net of tax)..............................      --       --        1
                                                            ------   ------   ------
  Income (Loss) from Continuing Operations Available to
     Common Stockholders -- Diluted.......................  $  (96)  $ (108)  $  117
                                                            ======   ======   ======
AVERAGE COMMON SHARES OUTSTANDING APPLICABLE TO BASIC AND
  DILUTED EPS
     Weighted Average Shares -- Basic.....................   219.9    211.8    168.6
     Add dilutive impact of Contingently Convertible
       Securities.........................................      --       --      3.0
     Add dilutive Stock Options and Warrants..............      --       --      0.5
                                                            ------   ------   ------
     Weighted Average Shares -- Diluted...................   219.9    211.8    172.1
                                                            ======   ======   ======
EARNINGS (LOSS) PER AVERAGE COMMON SHARE AVAILABLE TO
  COMMON STOCKHOLDERS
       Basic..............................................  $(0.44)  $(0.51)  $ 0.68
       Diluted............................................  $(0.44)  $(0.51)  $ 0.67
</Table>



     Contingently Convertible Securities: Due to accounting EPS dilution
principles, there was no impact to diluted EPS from our contingently convertible
securities for the years ended December 31, 2006 and 2005.

                                     CMS-73

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

Assuming positive income from continuing operations, our contingently
convertible securities dilute EPS to the extent that the conversion value, which
is based on the average market price of our common stock, exceeds the principal
or par value. Had there been positive income from continuing operations, our
contingently convertible securities would have contributed an additional 11.3
million shares to the calculation of diluted EPS for 2006 and 10.9 million
shares for 2005. For additional details on our contingently convertible
securities, see Note 4, Financings and Capitalization.

     Stock Options and Warrants: For the year ended December 31, 2006, due to
accounting EPS dilution principles, there was no impact to diluted EPS for
options and warrants to purchase 2.9 million shares of common stock and 1.9
million shares of restricted stock. For the year ended December 31, 2005 there
was no impact to diluted EPS for options and warrants to purchase 3.5 million
shares of common stock and 1.7 million shares of restricted stock, due to
accounting EPS dilution principles. For the year ended December 31, 2004, since
the exercise price was greater than the average market price of common stock,
there was no impact to diluted EPS from options and warrants to purchase 4.5
million shares of common stock.

     Convertible Debentures: Due to accounting EPS dilution principles, for the
years ended December 31, 2006, 2005, and 2004, there was no impact to diluted
EPS from our 7.75 percent convertible subordinated debentures. Using the if-
converted method, the debentures would have:

     - increased the numerator of diluted EPS by $9 million for the years ended
       December 31, 2006, 2005 and 2004, from an assumed reduction of interest
       expense, net of tax, and

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

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

6: FINANCIAL AND DERIVATIVE INSTRUMENTS

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

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


<Table>
<Caption>
                                                    2006                                2005
                                     ---------------------------------   ---------------------------------
                                                            UNREALIZED                          UNREALIZED
DECEMBER 31                           COST    FAIR VALUE   GAIN (LOSS)    COST    FAIR VALUE   GAIN (LOSS)
-----------                          ------   ----------   -----------   ------   ----------   -----------
                                                                 (IN MILLIONS)

<S>                                  <C>      <C>          <C>           <C>      <C>          <C>

Long-term debt(a)..................  $6,753     $6,949        $(196)     $7,089     $7,315        $(226)
Long-term debt -- related
  parties(b).......................     178        155           23         307        280           27
</Table>


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

   (a) Includes current maturities of $551 million at December 31, 2006 and $289
       million at December 31, 2005. Settlement of long-term debt is generally
       not expected until maturity.

   (b) Includes current maturities of $129 million at December 31, 2005.


                                     CMS-74

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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


<Table>
<Caption>
                                                2006                                     2005
                               --------------------------------------   --------------------------------------
                                      UNREALIZED   UNREALIZED    FAIR          UNREALIZED   UNREALIZED    FAIR
DECEMBER 31                    COST      GAINS       LOSSES     VALUE   COST      GAINS       LOSSES     VALUE
-----------                    ----   ----------   ----------   -----   ----   ----------   ----------   -----
                                                                (IN MILLIONS)

<S>                            <C>    <C>          <C>          <C>     <C>    <C>          <C>          <C>

Nuclear decommissioning
  investments(a):
  Equity securities..........  $140      $150          $(4)      286     134       123          (5)       252
  Debt securities............   307         4           (2)      309     287         6          (2)       291
SERP:
  Equity securities..........    36        21           --        57      34        15          --         49
  Debt securities............    13        --           --        13      17        --          --         17
</Table>


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

   (a) Nuclear decommissioning investments include cash and cash equivalents and
       accrued income totaling $7 million at December 31, 2006 and $12 million
       at December 31, 2005. Unrealized gains and losses on nuclear
       decommissioning investments are reflected as regulatory liabilities.

     The fair value of available-for-sale debt securities by contractual
maturity at December 31, 2006 is as follows:


<Table>
<Caption>
                                                                (IN MILLIONS)
                                                                -------------

<S>                                                             <C>

Due in one year or less.......................................       $ 38
Due after one year through five years.........................         97
Due after five years through ten years........................         76
Due after ten years...........................................        111
                                                                     ----
  Total.......................................................       $322
                                                                     ====

</Table>


     In July 2006, we reached an agreement to sell Palisades and the Big Rock
ISFSI to Entergy. Entergy will assume responsibility for the future
decommissioning of the plant and for storage and disposal of spent nuclear fuel.
Accordingly, upon completion of the sale, we will transfer $400 million of
nuclear decommissioning trust fund assets to Entergy and retain $205 million. We
will also be entitled to receive a return of $147 million, pending either a
favorable federal tax ruling regarding the release of the funds, or if no such
ruling is issued, after decommissioning of the Palisades site is complete. These
estimates fluctuate based on existing market conditions and the closing date of
the transaction. The disposition of the retained and receivable nuclear
decommissioning funds is subject to regulatory proceedings.

     Our held-to-maturity investments consist of debt securities held by the MCV
Partnership totaling $91 million at December 31, 2005. They were removed as part
of the November 2006 transaction in which we sold our interest in the MCV
Partnership. These securities represent funds restricted primarily for future
lease payments and are classified as Other assets on our Consolidated Balance
Sheets. These investments had original maturity dates of approximately one year
or less and, because of their short-term maturities, carrying amounts
approximate fair value.

     DERIVATIVE INSTRUMENTS: In order to limit our exposure to certain market
risks, we may enter into various risk management contracts, such as swaps,
options, futures, and forward contracts. These contracts, used primarily to
manage our exposure to changes in interest rates, commodity prices, and currency
exchange rates, are classified as either non-trading or trading. We enter into
these contracts 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.


                                     CMS-75

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The contracts we use to manage market risks may qualify as derivative
instruments that are subject to derivative and hedge accounting under SFAS No.
133. If a contract is a derivative, it is recorded on our consolidated balance
sheet at its fair value. We then adjust the resulting asset or liability each
quarter to reflect any change in the market value of the contract, a practice
known as marking the contract to market. From time to time, we enter into cash
flow hedges. If a derivative qualifies for cash flow hedge accounting treatment,
the changes in fair value (gains or losses) are reported in AOCL; otherwise, the
changes are reported in earnings.

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

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

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

     - the forecasted transaction being hedged must be probable.

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

     To determine the fair value of our derivatives, we use information from
external sources (i.e., quoted market prices and third-party valuations), if
available. For certain contracts, this information is not available and we use
mathematical valuation models to value our derivatives. These models require
various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. The cash
returns we actually realize on these contracts may vary, either positively or
negatively, from the results that we estimate using these models. As part of
valuing our derivatives at market, we maintain reserves, if necessary, for
credit risks arising from the financial condition of our counterparties.

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

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

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

     - there is not an active market for the commodity.

     Our coal purchase contracts are not derivatives because there is not an
active market for the coal we purchase. If an active market for coal develops in
the future, some of these contracts may qualify as derivatives and the resulting
mark-to-market impact on earnings could be material.

     In 2005, the MISO began operating the Midwest Energy Market. As of December
31, 2006, we have determined that, due to the increased liquidity for
electricity within the Midwest Energy Market since its inception, it is our best
judgment that this market should be considered an active market, as defined by
SFAS No. 133. This conclusion does not impact how we account for our electric
capacity and energy contracts held in Michigan, however, because these contracts
qualify for the normal purchases and sales exception and, as a result, are not
required to be marked-to-market.


                                     CMS-76

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     Derivative accounting is required for certain contracts used to limit our
exposure to interest rate risk, commodity price risk, and foreign exchange risk.
The following table summarizes our derivative instruments:


<Table>
<Caption>
DECEMBER 31                                          2006                         2005
-----------                               --------------------------   --------------------------
                                                  FAIR    UNREALIZED           FAIR    UNREALIZED
DERIVATIVE INSTRUMENTS                    COST   VALUE   GAIN (LOSS)   COST   VALUE   GAIN (LOSS)
----------------------                    ----   -----   -----------   ----   -----   -----------
                                                                IN MILLIONS

<S>                                       <C>    <C>     <C>           <C>    <C>     <C>

Non-trading:
  Gas supply option contracts...........  $ --    $ --       $ --      $  1    $ (1)      $ (2)
  FTRs..................................    --      --         --        --       1          1
Derivative contracts associated with the
  MCV Partnership:
  Long-term gas contracts(a)............    --      --         --        --     205        205
  Gas futures, options, and swaps(a)....    --      --         --        --     223        223
CMS ERM contracts:
  Non-trading electric / gas
     contracts(b).......................    --      31         31        --     (63)       (63)
  Trading electric / gas contracts(c)...   (11)    (68)       (57)       (3)    100        103
Derivative contracts associated with
  equity investments in:
  Shuweihat.............................    --     (14)       (14)       --     (20)       (20)
  Taweelah..............................   (35)    (11)        24       (35)    (17)        18
  Jorf Lasfar...........................    --      (5)        (5)       --      (8)        (8)
  Other.................................    --       1          1        --       1          1
</Table>


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

(a)    The fair value of the MCV Partnership's long-term gas contracts and gas
       futures, options, and swaps has decreased to $0 as a result of the sale
       of our interest in the MCV Partnership in November 2006. In conjunction
       with that sale, our interest in these contracts was also sold and, as a
       result, we no longer record the fair value of these contracts on our
       Consolidated Balance Sheets.

(b)    The fair value of CMS ERM's non-trading electric and gas contracts has
       increased significantly from December 31, 2005 due to the termination of
       certain gas contracts. CMS ERM had recorded derivative liabilities,
       representing cumulative unrealized mark-to-market losses, associated with
       these gas contracts. As the contracts are now settled, the related
       derivative liabilities are no longer included in the balance of CMS ERM's
       non-trading electric and gas contracts.

(c)    The fair value of CMS ERM's trading electric and gas contracts has
       decreased significantly from December 31, 2005 due to the termination of
       certain gas contracts. CMS ERM had recorded derivative assets,
       representing cumulative unrealized mark-to-market gains, associated with
       these gas contracts. As the contracts are now settled, the related
       derivative assets are no longer included in the balance of CMS ERM's
       trading electric and gas contracts.

     At December 31, 2005, we recorded the fair value of our gas supply option
contracts, FTRs, and the derivative contracts associated with the MCV
Partnership in Derivative instruments, Other assets, or Other liabilities on our
Consolidated Balance Sheets. We include the fair value of the derivative
contracts held by CMS ERM in either Price risk management assets or Price risk
management liabilities on our Consolidated Balance Sheets. The fair value of
derivative contracts associated with our equity investments is included in
Investments -- Enterprises on our Consolidated Balance Sheets.

     GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses gas supply call
and put options to meet our regulatory obligation to provide gas to our
customers at a reasonable and prudent cost. As part of regulatory accounting,
the mark-to-market gains and losses associated with these options are reported
directly in earnings as part of Other income, and then immediately reversed out
of earnings and recorded on our consolidated balance sheet as a regulatory asset
or liability.


                                     CMS-77

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     FTRS: With the creation of the Midwest Energy Market, FTRs were
established. FTRs are financial instruments that manage price risk related to
electricity transmission congestion. An FTR entitles its holder to receive
compensation (or, conversely, to remit payment) for congestion-related
transmission charges. As part of regulatory accounting, the mark-to-market gains
and losses associated with these instruments are reported directly in earnings
as part of Other income, and then immediately reversed out of earnings and
recorded on our consolidated balance sheet as a regulatory asset or liability.

     DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: In November 2006,
we sold our interest in the MCV Partnership. In conjunction with that sale, our
interest in all of the MCV Partnership's long-term gas contracts and related
futures, options, and swaps was sold. Before the sale, we accounted for certain
long-term gas contracts and all of the related futures, options, and swaps as
derivatives.

     Long-term gas contracts: The MCV Partnership used long-term gas contracts
to purchase and manage the cost of the natural gas it needed to generate
electricity and steam. The MCV Partnership determined that certain of these
contracts qualified as normal purchases under SFAS No. 133. Accordingly, we did
not recognize these contracts at fair value on our Consolidated Balance Sheets.

     The MCV Partnership also held certain long-term gas contracts that did not
qualify as normal purchases because they contained volume optionality or because
the gas was not expected to be used to generate electricity or steam in the
normal course of business. Accordingly, prior to the sale, we accounted for
these contracts as derivatives, with changes in fair value recorded in earnings
each quarter.

     During 2006, through the date of the sale, we recorded a $151 million loss,
before considering tax effects and minority interest, associated with the net
decrease in fair value of these long-term gas contracts. This loss is included
in the total Fuel costs mark-to-market at the MCV Partnership in our
Consolidated Statements of Income (Loss). As a result of the sale, we no longer
consolidate the MCV Partnership. Accordingly, we will no longer record the fair
value of the long-term gas contracts on our Consolidated Balance Sheets and will
not be required to record gains or losses related to changes in the fair value
of these contracts in earnings.

     Gas Futures, Options, and Swaps: The MCV Partnership entered into natural
gas futures, options, and over-the-counter swap transactions in order to hedge
against unfavorable changes in the market price of natural gas. The MCV
Partnership used these financial instruments to:

     - ensure an adequate supply of natural gas for the projected generation and
       sales of electricity and steam, and

     - manage price risk by fixing the price to be paid for natural gas on some
       of its long-term gas contracts.

     Certain of the futures and swaps held by the MCV Partnership qualified for
cash flow hedge accounting and, prior to the sale, we recorded our proportionate
share of their mark-to-market gains and losses in AOCL. As of the date of the
sale, we had accumulated a net gain of $30 million, net of tax and minority
interest, in AOCL representing our proportionate share of mark-to-market gains
from these cash flow hedges. After the sale, this amount was reclassified to and
recognized in earnings as a reduction of the total loss on the sale in our
Consolidated Statements of Income (Loss).

     The remaining futures, options, and swap contracts held by the MCV
Partnership did not qualify as cash flow hedges and we recorded any changes in
their fair value in earnings each quarter. During 2006, through the date of the
sale, we recorded a $53 million loss, before considering tax effects and
minority interest, associated with the net decrease in fair value of these
contracts. This loss is included in the total Fuel costs mark-to-market at the
MCV Partnership in our Consolidated Statements of Income (Loss).

     As a result of the sale, we will no longer record the fair value of the
futures, options, and swaps on our Consolidated Balance Sheets and will not be
required to record gains or losses related to changes in the fair value of these
contracts in earnings or AOCL. For additional details on the sale of our
interest in the MCV Partnership, see Note 2, Asset Sales, Impairment Charges and
Discontinued Operations.


                                     CMS-78

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts that
support CMS Energy's ongoing operations. CMS ERM holds certain contracts for the
future purchase and sale of natural gas that will result in physical delivery of
the commodity at contractual prices. These forward contracts are generally long-
term in nature and are classified as non-trading. CMS ERM also uses various
financial instruments, including swaps, options, and futures, to manage
commodity price risks associated with its forward purchase and sale contracts
and with generation assets owned by CMS Energy or its subsidiaries. These
financial contracts are classified as trading activities.

     In accordance with SFAS No. 133, non-trading and trading contracts that
qualify as derivatives are recorded at fair value on our Consolidated Balance
Sheets. The resulting assets and liabilities are marked to market each quarter,
and changes in fair value are recorded in earnings as a component of Operating
Revenue. For trading contracts, these gains and losses are recorded net in
accordance with EITF Issue No. 02-03. Contracts that do not meet the definition
of a derivative are accounted for as executory contracts (that is, on an accrual
basis).

     DERIVATIVE CONTRACTS ASSOCIATED WITH EQUITY INVESTMENTS: At December 31,
2006, some of our equity method investees held:

     - interest rate contracts that hedged the risk associated with variable-
       rate debt, and

     - foreign exchange contracts that hedged the foreign currency risk
       associated with payments to be made under operating and maintenance
       service agreements.

     We record our proportionate share of the change in fair value of these
contracts in AOCL if the contracts qualify for cash flow hedge accounting;
otherwise, we record our share in Earnings from Equity Method Investees. There
was no ineffectiveness associated with any of the contracts that qualify for
cash flow hedge accounting.

     FOREIGN EXCHANGE DERIVATIVES: At times, we use forward exchange and option
contracts to hedge the value of investments in foreign operations. These
contracts limit the risk from currency exchange rate movements because gains and
losses on such contracts offset losses and gains, respectively, on the hedged
investments. At December 31, 2006, we had no outstanding foreign exchange
contracts. However, the impact of previous hedges on our investments in foreign
operations is reflected in AOCL as a component of the foreign currency
translation adjustment on our Consolidated Balance Sheets. Gains or losses from
the settlement of these hedges are maintained in the foreign currency
translation adjustment until we sell or liquidate the hedged investments. At
December 31, 2006, our total foreign currency translation adjustment was a net
loss of $297 million, which included a net hedging loss of $26 million, net of
tax, related to the settlement of these contracts.

     CREDIT RISK: Our swaps, options, and forward contracts contain credit risk,
which is the risk that counterparties will fail to perform their contractual
obligations. We reduce this risk through established credit policies. For each
counterparty, we assess credit quality by using credit ratings, financial
condition, and other available information. We then establish a credit limit for
each counterparty based upon our evaluation of credit quality. We monitor the
degree to which we are exposed to potential loss under each contract and take
remedial action, if necessary.

     CMS ERM enters into contracts primarily with companies in the electric and
gas industry. This industry concentration may have an impact on our exposure to
credit risk, either positively or negatively, based on how these counterparties
are affected by similar changes in economic conditions, the weather, or other
conditions. CMS ERM typically uses industry-standard agreements that allow for
netting positive and negative exposures associated with the same counterparty,
thereby reducing exposure. These contracts also typically provide for the
parties to demand adequate assurance of future performance when there are
reasonable grounds for doing so.

     The following table illustrates our exposure to potential losses at
December 31, 2006, if each counterparty within this industry concentration
failed to perform its contractual obligations. This table includes contracts
accounted for as financial instruments. It does not include trade accounts
receivable, derivative contracts that

                                     CMS-79

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

qualify for the normal purchases and sales exception under SFAS No. 133, or
other contracts that are not accounted for as derivatives.


<Table>
<Caption>
                                                                            NET EXPOSURE      NET EXPOSURE
                                     EXPOSURE                             FROM INVESTMENT   FROM INVESTMENT
                                      BEFORE      COLLATERAL      NET          GRADE             GRADE
                                  COLLATERAL(A)      HELD      EXPOSURE     COMPANIES(B)     COMPANIES (%)
                                  -------------   ----------   --------   ---------------   ---------------
                                                                (IN MILLIONS)

<S>                               <C>             <C>          <C>        <C>               <C>

CMS ERM.........................       $56            $--         $56           $13                23%
</Table>


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

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

(b)    The majority of the remaining balance of CMS ERM's net exposure was from
       a counterparty whose credit rating fell below investment grade after
       December 31, 2005.

     Based on our credit policies, our current exposures, and our credit
reserves, we do not expect a material adverse effect on our financial position
or future earnings as a result of counterparty nonperformance.

7:  RETIREMENT BENEFITS

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

     - a non-contributory, defined benefit Pension Plan,

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

     - a DCCP for employees hired on or after September 1, 2005,

     - benefits to certain management employees under SERP,

     - a defined contribution 401(k) Savings Plan,

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

     - health care and life insurance benefits under OPEB.

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

     On September 1, 2005, we implemented the DCCP.  The DCCP provides an
employer contribution of 5 percent of base pay to the existing employees'
Savings Plan. No employee contribution is required in order to receive the
plan's employer contribution. All employees hired on and after September 1, 2005
participate in this plan as part of their retirement benefit program. Cash
balance pension plan participants also participate in the DCCP as of September
1, 2005. Additional pay credits under the cash balance pension plan were
discontinued as of that date. The DCCP expense was $2 million for the year ended
December 31, 2006 and less than $1 million for the year ended December 31, 2005.

     Effective January 11, 2006, the MPSC electric rate order authorized
Consumers to include $33 million of electric pension expense in its electric
rates. Effective November 21, 2006, the MPSC gas rate order authorized Consumers
to include $22 million of gas pension expense in its gas rates. Due to the
volatility of these costs, the orders also established a pension equalization
mechanism to track actual costs. If actual pension expenses are greater than the
amounts included in rate cases, the difference will be recognized as a
regulatory asset for future recovery from customers. If actual pension expenses
are less than the amounts included in rate cases, the difference will be
recognized as a regulatory liability, and refunded to our customers. The
difference between pension expenses allowed in Consumers' rate cases and
Consumers' $66 million net pension cost under SFAS No. 87 resulted in the
recognition of a regulatory asset of $11 million.


                                     CMS-80

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     SERP: SERP benefits are paid from a trust established in 1988. SERP is not
a qualified plan under the Internal Revenue Code. SERP trust earnings are
taxable and trust assets are included in our consolidated assets. Trust assets
were $71 million at December 31, 2006 and $66 million at December 31, 2005. The
assets are classified as Other non-current assets on our Consolidated Balance
Sheets. The ABO for SERP was $78 million at December 31, 2006 and $74 million at
December 31, 2005.

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

     401(k): The employer's match for the 401(k) Savings Plan, which was
suspended on September 1, 2002, resumed on January 1, 2005. The employer's match
is in CMS Energy Common Stock. On September 1, 2005, employees enrolled in the
company's 401(k) Savings Plan had their employer match increased from 50 percent
to 60 percent on eligible contributions up to the first six percent of an
employee's wages. The total 401(k) Savings Plan cost was $15 million for the
year ended December 31, 2006 and $13 million for the year ended December 31,
2005.

     Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be
an investment option available for new investments in the 401(k) Savings Plan
and the employer's match will no longer be in CMS Energy Common Stock.
Participants will have the opportunity to reallocate investments in CMS Energy
Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any
remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds
will be reallocated to other plan investment options. At February 20, 2007,
there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy
Stock Fund.

     The MCV Partnership sponsors a defined contribution retirement plan and a
401(k) Savings Plan covering all employees. Amounts contributed under these
plans were $1 million for the period January 1, 2006 through November 21, 2006
and $1 million for each of the years ended December 31, 2005 and 2004.

     EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select group of management, or other highly
compensated employees. Terms of the plan may include payment of a lump sum,
payment of monthly benefits for life, payment of premiums for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. The EISP expense was $1 million for each of the years ended
December 31, 2006 and 2005. The ABO for the EISP was $5 million at December 31,
2006 and $4 million at December 31, 2005.

     OPEB: The OPEB plan covers all regular full-time employees covered by the
employee health care plan on a company-subsidized basis the day before they
retire from the company at age 55 or older and who have at least 10 full years
of applicable continuous service. Regular full-time employees who qualify for a
disability retirement and have 15 years of applicable continuous service are
also eligible. Retiree health care costs were based on the assumption that costs
would increase 10 percent in 2006. Starting in 2007, we will use two health care
trend rates: one for retirees under 65 and the other for retirees 65 and over.
The two health care trend rates recognize that prescription drug costs are
increasing at a faster pace than other medical claim costs and that prescription
drug costs make up a larger portion of expenses for retirees age 65 and over.
The 2007 rate of increase for OPEB health costs for those under 65 is expected
to be 9 percent and for those over 65 is expected to be 10.5 percent. The rate
of increase is expected to slow to 5 percent for those under 65 by 2011 and for
those over 65 by 2013 and thereafter.

     Effective January 11, 2006, the MPSC electric rate order authorized
Consumers to include $28 million of electric OPEB expense in its electric rates.
Effective November 21, 2006, the MPSC gas rate order authorized Consumers to
include $21 million of gas OPEB expense in its gas rates. Due to the volatility
of these costs, the orders also established an OPEB equalization mechanism to
track actual costs. If actual OPEB expenses are greater

                                     CMS-81

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

than the amounts included in rate cases, the difference will be recognized as a
regulatory asset for future recovery from our customers. If actual OPEB expenses
are less than the amounts included in rate cases, the difference will be
recognized as a regulatory liability, and refunded to our customers. The
difference between OPEB expenses allowed in Consumers' rate cases and Consumers'
$51 million net OPEB cost under SFAS No. 106 resulted in the recognition of a
regulatory asset of $2 million.

     The MCV Partnership sponsors defined cost postretirement health care plans
that cover all full-time employees, except key management. The ABO of the MCV
Partnership's postretirement plans was $5 million at December 31, 2005. The MCV
Partnership's net periodic postretirement health care cost for the period
January 1, 2006 through November 21, 2006 and year ended December 31, 2005 was
less than $1 million.

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


<Table>
<Caption>
                                                          ONE PERCENTAGE   ONE PERCENTAGE
                                                          POINT INCREASE   POINT DECREASE
                                                          --------------   --------------
                                                                   (IN MILLIONS)

<S>                                                       <C>              <C>

Effect on total service and interest cost component.....       $ 19             $ (15)
Effect on postretirement benefit obligation.............       $220             $(186)
</Table>


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

     The measurement date for all CMS Energy plans is November 30 for 2006, 2005
and 2004. We changed our measurement date in 2004 from December 31 to November
30, which resulted in a $2 million cumulative effect of change in accounting for
retirement benefits, net of tax benefit, as a decrease to earnings. We also
increased the amount of accrued benefit cost on our Consolidated Balance Sheets
by $4 million. The measurement date for the MCV Partnership's plan was December
31 for 2005 and 2004.

     SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other
Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106, and
132(R): In September 2006, the FASB issued SFAS No. 158. This standard requires
us to recognize the funded status of our defined benefit postretirement plans on
our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 requires us
to recognize changes in the funded status of our plans in the year in which the
changes occur. This standard also requires that we change our plan measurement
date from November 30 to December 31, effective December 31, 2008. We do not
believe that implementation of this provision of the standard will have a
material effect on our consolidated financial statements. We expect to adopt the
measurement date provisions of SFAS No. 158 in 2008.

     The following table recaps the incremental effect of applying SFAS No. 158
on individual line items on our Consolidated Balance Sheets. The adoption of
SFAS No. 158 had no effect on our Consolidated Statements of Income (Loss) for
the year ended December 31, 2006, or for any prior period presented, and it will
not affect our operating results in future periods. Had we not been required to
adopt SFAS No. 158 at December 31, 2006, we would have recognized an additional
minimum liability pursuant to the provisions of SFAS No. 87. The effect of

                                     CMS-82

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

recognizing the additional minimum liability is included in the following table
in the column labeled "Before Application of SFAS No. 158:"


<Table>
<Caption>
                                                       BEFORE                         AFTER
                                                   APPLICATION OF                APPLICATION OF
YEAR ENDED DECEMBER 31, 2006                        SFAS NO. 158    ADJUSTMENT    SFAS NO. 158
----------------------------                       --------------   ----------   --------------
                                                                    IN MILLIONS

<S>                                                <C>              <C>          <C>

Regulatory asset(a)..............................      $   470         $ 680         $ 1,150
Intangible asset.................................           48           (48)             --
                                                       -------         -----         -------
Total assets.....................................          518           632           1,150
Liability for retirement benefits(b).............         (425)         (647)         (1,072)
Regulatory liabilities -- Income taxes, net(c)...         (459)          (80)           (539)
Deferred income taxes............................         (208)           88            (120)
                                                       -------         -----         -------
Total liabilities................................       (1,092)         (639)         (1,731)
Accumulated other comprehensive loss.............           16             7              23
                                                       -------         -----         -------
Total decrease in stockholders' equity...........           16             7              23
                                                       =======         =====         =======

</Table>


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

(a)   Consumers recognized the cost of their minimum liability prior to the
      application of SFAS No. 158 and the adjustment resulting from adoption of
      SFAS No. 158 as a regulatory asset under SFAS No. 71, based upon guidance
      from the MPSC.

(b)   Liabilities for retirement benefits include $1.071 billion that are non-
      current and $1 million that is current at December 31, 2006.

(c)   The adjustment represents the Medicare D Subsidy tax benefit of
      implementing SFAS No. 158.

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

WEIGHTED AVERAGE FOR BENEFIT OBLIGATIONS:


<Table>
<Caption>
                                                   PENSION & SERP               OPEB
                                               ---------------------   ---------------------
YEARS ENDED DECEMBER 31                         2006    2005    2004    2006    2005    2004
-----------------------                         ----    ----    ----    ----    ----    ----

<S>                                            <C>     <C>     <C>     <C>     <C>     <C>

Discount rate...............................   5.65%   5.75%   6.00%   5.65%   5.75%   6.00%
Expected long-term rate of return on plan
  assets(a).................................   8.25%   8.50%   8.75%
  Union.....................................                                           8.75%
  Non-Union.................................                                           6.00%
  Combined in 2005..........................                           7.75%   8.00%
Mortality table(b)..........................    2000    2000    1983    2000    2000    1983
Rate of compensation increase:
  Pension...................................   4.00%   4.00%   3.50%
  SERP......................................   5.50%   5.50%   5.50%
</Table>




                                     CMS-83

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

WEIGHTED AVERAGE FOR NET PERIODIC BENEFIT COST:


<Table>
<Caption>
                                                   PENSION & SERP               OPEB
                                               ---------------------   ---------------------
YEARS ENDED DECEMBER 31                         2006    2005    2004    2006    2005    2004
-----------------------                         ----    ----    ----    ----    ----    ----

<S>                                            <C>     <C>     <C>     <C>     <C>     <C>

Discount rate...............................   5.75%   5.75%   6.25%   5.75%   5.75%   6.25%
Expected long-term rate of return on plan
  assets(a).................................   8.50%   8.75%   8.75%
  Union.....................................                                           8.75%
  Non-Union.................................                                           6.00%
  Combined in 2005..........................                           8.00%   8.25%
Mortality table(b)..........................    2000    2000    1983    2000    2000    1983
Rate of compensation increase:
  Pension...................................   4.00%   3.50%   3.25%
  SERP......................................   5.50%   5.50%   5.50%
</Table>


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

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

(b)   Prior to 2005, we utilized the 1983 Group Annuity Mortality Table.
      Starting in 2005, we utilize the Combined Healthy RP-2000 Table from the
      2000 Group Annuity Mortality Tables.

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


<Table>
<Caption>
                                                                  PENSION & SERP
                                                               -------------------
YEARS ENDED DECEMBER 31                                        2006   2005    2004
-----------------------                                        ----   ----    ----
                                                                   IN MILLIONS

<S>                                                            <C>    <C>    <C>

Net periodic pension cost
  Service cost...............................................  $ 51   $ 44   $  37
  Interest expense...........................................    88     83      79
  Expected return on plan assets.............................   (85)   (97)   (109)
  Amortization of:
     Net loss................................................    43     35      14
     Prior service cost......................................     7      6       6
                                                               ----   ----   -----
  Net periodic pension cost..................................   104     71      27
  Regulatory adjustment......................................   (11)    --      --
                                                               ----   ----   -----
Net periodic pension cost after regulatory adjustment........  $ 93   $ 71   $  27
                                                               ====   ====   =====

</Table>




                                     CMS-84

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


<Table>
<Caption>
                                                                       OPEB
                                                                ------------------
YEARS ENDED DECEMBER 31                                         2006   2005   2004
-----------------------                                         ----   ----   ----
                                                                    IN MILLIONS

<S>                                                             <C>    <C>    <C>

Net periodic OPEB cost
  Service cost................................................  $ 23   $ 23   $ 19
  Interest expense............................................    64     61     58
  Expected return on plan assets..............................   (57)   (54)   (48)
  Amortization of:
     Net loss.................................................    20     20     10
     Prior service credit.....................................   (10)    (9)    (9)
                                                                ----   ----   ----
  Net periodic OPEB cost......................................    40     41     30
  Regulatory adjustment.......................................    (2)    --     --
                                                                ----   ----   ----
Net periodic OPEB cost after regulatory adjustment............    38   $ 41   $ 30
                                                                ====   ====   ====

</Table>


     The estimated net loss and prior service cost for the defined benefit
pension plans that will be amortized into net periodic benefits cost over the
next fiscal year from regulatory asset is $50 million and from AOCL is $3
million. The estimated net loss and prior service credit for OPEB plans that
will be amortized into net periodic benefit cost over the next fiscal year from
regulatory asset is $12 million and from AOCL is $1 million.

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


<Table>
<Caption>
                                             PENSION PLAN        SERP            OPEB
                                           ---------------   -----------   ---------------
YEARS ENDED DECEMBER 31                     2006     2005    2006   2005    2006     2005
-----------------------                     ----     ----    ----   ----    ----     ----
                                                             IN MILLIONS

<S>                                        <C>      <C>      <C>    <C>    <C>      <C>

Benefit obligation at beginning of
  period.................................  $1,510   $1,328   $ 91   $ 83   $1,136   $1,073
Service cost.............................      49       42      2      2       23       23
Interest cost............................      83       78      5      5       64       61
Plan amendment...........................      --       39     --      1       --      (19)
Actuarial loss (gain)....................      51      146     (2)     4       70       47
Benefits paid............................    (117)    (123)    (4)    (4)     (50)     (49)
                                           ------   ------   ----   ----   ------   ------
Benefit obligation at end of period(a)...   1,576    1,510     92     91    1,243    1,136
                                           ------   ------   ----   ----   ------   ------
Plan assets at fair value at beginning of
  period.................................   1,018    1,040     --     --      714      654
Actual return on plan assets.............     126      101     --     --       73       45
Company contribution.....................      13       --      4      4       58       63
Actual benefits paid(b)..................    (117)    (123)    (4)    (4)     (47)     (48)
                                           ------   ------   ----   ----   ------   ------
Plan assets at fair value at end of
  period.................................   1,040    1,018     --     --      798      714
                                           ------   ------   ----   ----   ------   ------
Funded status at end of measurement
  period.................................    (536)    (492)   (92)   (91)    (445)    (422)
Additional VEBA Contributions or Non-
  Trust Benefit Payments.................      --       --     --     --       14       16
                                           ------   ------   ----   ----   ------   ------
Funded status at December 31.............  $ (536)  $ (492)  $(92)  $(91)  $ (431)  $ (406)
                                           ======   ======   ====   ====   ======   ======

</Table>


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

(a)   The Medicare Prescription Drug, Improvement and Modernization Act of 2003
      establishes a prescription drug benefit under Medicare (Medicare Part D),
      and a federal subsidy, which is tax-exempt, to sponsors of retiree health
      care benefit plans that provide a benefit that is actuarially equivalent
      to Medicare Part D. The Medicare Part D annualized reduction in net OPEB
      cost was $28 million for 2006 and $24 million for 2005. The

                                     CMS-85

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

      reduction includes $7 million for the year ended December 31, 2006 and $6
      million for the year ended December 31, 2005 in capitalized OPEB costs.

(b)   We received $3 million in Medicare Part D Subsidy payments for the year
      ended December 31, 2006.

     The following table provides a reconciliation of benefit obligations, plan
assets and funded status of the plans as of December 31, 2005 for all plans
combined. (In accordance with SFAS No. 158, we recognized the underfunded status
of our defined benefit postretirement plans as a liability on our consolidated
balance sheets as of December 31, 2006.)


<Table>
<Caption>
                                                          PENSION PLAN   SERP    OPEB
                                                          ------------   ----   ------
YEAR ENDED DECEMBER 31                                        2005       2005    2005
----------------------                                        ----       ----    ----
                                                                   IN MILLIONS

<S>                                                       <C>            <C>    <C>

Fair value of plan assets...............................     $1,018      $ --   $  714
Net benefit obligations.................................      1,510        91    1,136
                                                             ------      ----   ------
Funded status (plan assets less plan obligations).......       (492)      (91)    (422)
Amounts not recognized
  Net actuarial loss....................................        747         8      375
  Prior service cost (credit)...........................         56         2     (113)
Additional VEBA Contributions or Non-Trust Benefit
  Payments..............................................         --        --       16
                                                             ------      ----   ------
Net amount recognized...................................     $  311      $(81)  $ (144)
                                                             ======      ====   ======

</Table>


     The following table provides a reconciliation of the amounts recognized on
our Consolidated Balance Sheets as of December 31, 2005 for all plans combined:


<Table>
<Caption>
                                                           PENSION PLAN   SERP    OPEB
                                                           ------------   ----   -----
YEAR ENDED DECEMBER 31                                         2005       2005    2005
----------------------                                         ----       ----    ----
                                                                   IN MILLIONS

<S>                                                        <C>            <C>    <C>

Prepaid benefit cost.....................................      $ 311      $ --   $  --
Accrued benefit cost.....................................         --       (81)   (144)
Additional minimum liability.............................       (481)       --      --
Intangible asset.........................................         56        --      --
AOCL.....................................................         26        --      --
Regulatory asset.........................................        399        --      --
                                                               -----      ----   -----
Net amount recognized....................................      $ 311      $(81)  $(144)
                                                               =====      ====   =====

</Table>


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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                            2006     2005
-----------------------                                            ----     ----
                                                                    IN MILLIONS

<S>                                                               <C>      <C>

Pension ABO.....................................................  $1,240   $1,188
Fair value of pension plan assets...............................   1,040    1,018
                                                                  ------   ------
Pension ABO in excess of pension plan assets....................  $  200   $  170
                                                                  ======   ======

</Table>




                                     CMS-86

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     SFAS No. 158 Recognized: The following table recaps the amounts recognized
in SFAS No. 158 regulatory assets and AOCL that have not been recognized as
components of net periodic benefit cost. For additional details on regulatory
assets, see Note 1, Corporate Structure and Accounting Policies, "Utility
Regulation:"


<Table>
<Caption>
                                                              PENSION & SERP   OPEB
                                                              --------------   ----
YEAR ENDED DECEMBER 31                                             2006        2006
----------------------                                             ----        ----
                                                                   IN MILLIONS

<S>                                                           <C>              <C>

Regulatory assets
  Net loss..................................................       $676        $416
  Prior service cost (credit)...............................         45         (99)
AOCL
  Net loss (gain)...........................................         46         (11)
  Prior service cost (credit)...............................          4          (4)
                                                                   ----        ----
Total amounts recognized in regulatory assets and AOCL......       $771        $302
                                                                   ====        ====

</Table>


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


<Table>
<Caption>
                                                              PENSION         OPEB
                                                            -----------   -----------
NOVEMBER 30                                                 2006   2005   2006   2005
-----------                                                 ----   ----   ----   ----

<S>                                                         <C>    <C>    <C>    <C>

Asset Category:
  Fixed Income............................................   28%    33%    37%    58%
  Equity Securities:......................................   62%    65%    63%    40%
     CMS Energy Common Stock(a)...........................   --     --     --      1%
     Alternative Strategy.................................   10%     2%    --      1%
</Table>


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

(a)   At November 30, 2006, there were no shares of CMS Energy Common Stock in
      the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a
      fair value of $2 million. At November 30, 2005, there were no shares of
      CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in
      the OPEB plan assets with a fair value of $2 million.

     We contributed $56 million to our OPEB plan in 2006 and we plan to
contribute $51 million to our OPEB plan in 2007. We contributed $13 million to
our Pension Plan in 2006 and we plan to contribute $109 million to our Pension
plan in 2007.

     We have established a target asset allocation for our Pension Plan assets
of 60 percent equity, 30 percent fixed income, and 10 percent alternative
strategy investments to maximize the long-term return on plan assets, while
maintaining a prudent level of risk. The level of acceptable risk is a function
of the liabilities of the plan. Equity investments are diversified mostly across
the Standard & Poor's 500 Index, with lesser allocations to the Standard &
Poor's Mid Cap Index, the Small Cap Indexes and a Foreign Equity Index Fund.
Fixed-income investments are diversified across investment grade instruments of
both government and corporate issuers. Alternative strategies are diversified
across absolute return investment approaches and global tactical asset
allocation. Annual liability measurements, quarterly portfolio reviews, and
periodic asset/liability studies are used to evaluate the need for adjustments
to the portfolio allocation.

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


                                     CMS-87

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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


<Table>
<Caption>
                                                            PENSION   SERP   OPEB(A)
                                                            -------   ----   -------
                                                                   IN MILLIONS

<S>                                                         <C>       <C>    <C>

2007......................................................    $ 58     $ 4     $ 54
2008......................................................      65       4       56
2009......................................................      73       4       58
2010......................................................      81       4       60
2011......................................................      93       4       62
2012-2016.................................................     652      21      333
</Table>


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

(a)   OPEB benefit payments are net of employee contributions and expected
      Medicare Part D prescription drug subsidy payments. The subsidies to be
      received are estimated to be $5 million for 2007, $6 million each year for
      2008 through 2011 and $33 million combined for 2012 through 2016.

8: ASSET RETIREMENT OBLIGATIONS

     SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard
requires companies to record the fair value of the cost to remove assets at the
end of their useful life, if there is a legal obligation to remove them. 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 $25
million.

     If a reasonable estimate of fair value cannot be made in the period in
which the ARO is incurred, such as for assets with indeterminate lives, the
liability is to be recognized when a reasonable estimate of fair value can be
made. Generally, electric and gas transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets or associated obligations related to potential future
abandonment. 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 include use of
decommissioning studies that largely utilize third-party cost estimates.

     FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarified the term "conditional asset
retirement obligation" as used in SFAS No. 143. The term refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event. We determined that
abatement of asbestos included in our plant investments qualifies as a
conditional ARO, as defined by FASB Interpretation No. 47.


                                     CMS-88

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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


<Table>
<Caption>
                                      IN SERVICE
ARO DESCRIPTION                          DATE                LONG-LIVED ASSETS              TRUST FUND
---------------                       ----------   ------------------------------------   -------------
                                                                                          (IN MILLIONS)

<S>                                   <C>          <C>                                    <C>


December 31, 2006

Palisades-decommission plant site...       1972    Palisades nuclear plant                     $598
Big Rock-decommission plant site....       1962    Big Rock nuclear plant                         4
JHCampbell intake/discharge water
  line..............................       1980    Plant intake/discharge water line             --
Closure of coal ash disposal areas..    Various    Generating plants coal ash areas              --
Closure of wells at gas storage
  fields............................    Various    Gas storage fields                            --
Indoor gas services equipment
  relocations.......................    Various    Gas meters located inside structures          --
Asbestos abatement..................       1973    Electric and gas utility plant                --
Natural gas-fired power plant.......       1997    Gas fueled power plant                        --
Close gas treating plant and gas
  wells.............................    Various    Gas transmission and storage                  --
</Table>




<Table>
<Caption>
                                            ARO                                                         ARO
                                         LIABILITY                                       CASH FLOW   LIABILITY
ARO DESCRIPTION                          1/1/05(A)   INCURRED   SETTLED(B)   ACCRETION   REVISIONS    12/31/05
---------------                          ---------   --------   ----------   ---------   ---------   ---------
                                                                      IN MILLIONS

<S>                                      <C>         <C>        <C>          <C>         <C>         <C>

Palisades-decommission.................     $350        $--        $ --         $25         $--         $375
Big Rock - decommission................       30         --         (42)         15          24           27
JHCampbell intake line.................       --         --          --          --          --           --
Coal ash disposal areas................       54         --          (5)          5          --           54
Wells at gas storage fields............        1         --          --          --          --            1
Indoor gas services relocations........        1         --          --          --          --            1
Natural gas-fired power plant..........        1         --          --          --          --            1
Close gas treating plant and gas
  wells................................        2         --          (1)         --          --            1
Asbestos abatement.....................       33         --          --           3          --           36
                                            ----        ---        ----         ---         ---         ----
  Total................................     $472        $--        $(48)        $48         $24         $496
                                            ====        ===        ====         ===         ===         ====

</Table>




<Table>
<Caption>
                                            ARO                                                         ARO
                                         LIABILITY                                       CASH FLOW   LIABILITY
ARO DESCRIPTION                            1/1/06    INCURRED   SETTLED(B)   ACCRETION   REVISIONS    12/31/06
---------------                          ---------   --------   ----------   ---------   ---------   ---------
                                                                      IN MILLIONS

<S>                                      <C>         <C>        <C>          <C>         <C>         <C>

Palisades-decommission.................     $375        $--        $ --         $26         $--         $401
Big Rock-decommission..................       27         --         (28)          3          --            2
JHCampbell intake line.................       --         --          --          --          --           --
Coal ash disposal areas................       54         --          (2)          5          --           57
Wells at gas storage fields............        1         --          --          --          --            1
Indoor gas services relocations........        1         --          --          --          --            1
Natural gas-fired power plant..........        1         --          --          --          --            1
Close gas treating plant and gas
  wells................................        1         --          --           1          --            2
Asbestos abatement.....................       36         --          (3)          2          --           35
                                            ----        ---        ----         ---         ---         ----
  Total................................     $496        $--        $(33)        $37         $--         $500
                                            ====        ===        ====         ===         ===         ====

</Table>


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

(a)   The ARO liability at January 1, 2005 in the preceding table reflects the
      ARO liability as if FASB Interpretation No. 47 had been in effect at that
      time, as required by the Interpretation. Our consolidated financial
      statements for that period do not reflect the asbestos abatement ARO. As
      required by SFAS No. 71, we accounted for the implementation of this
      Interpretation by recording a regulatory asset instead of a cumulative
      effect of a change in accounting principle. There was no effect on
      consolidated net income.


                                     CMS-89

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



(b)   These cash payments are included in the Other current and non-current
      liabilities line in Net cash provided by operating activities in our
      Consolidated Statements of Cash Flows.

     In October 2004, the MPSC initiated a generic proceeding to review SFAS No.
143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing
Requirements for Asset Retirement Obligations, and related accounting and
ratemaking issues for MPSC-jurisdictional electric and gas utilities. In
December 2005, the ALJ issued a Proposal for Decision recommending that the MPSC
dismiss the proceeding. In March 2006, the MPSC remanded the case to the ALJ for
findings and recommendations. In August 2006, the ALJ issued a second Proposal
for Decision that included recommendations that the MPSC:

     - adopt SFAS No. 143 and FERC Order No. 631 for accounting purposes but not
       for ratemaking purposes,

     - consider adopting standardized retirement units for certain accounts,

     - consider revising the method of determining cost of removal, and

     - withhold approving blanket regulatory asset and regulatory liability
       accounting treatment related to ARO, stating that modifications to the
       MPSC's Uniform System of Accounts should precede any such accounting
       approval.

     We consider the proceeding a clarification of accounting and reporting
issues that relate to all Michigan utilities. We cannot predict the outcome of
the proceeding.

9: INCOME TAXES

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

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

     AMT paid generally becomes a tax credit that we can carry forward
indefinitely to reduce regular tax liabilities in future periods when regular
taxes paid exceed the tax calculated for AMT. At December 31, 2006, we had AMT
credit carryforwards of $271 million that do not expire, tax loss carryforwards
of $1.616 billion that expire from 2023 through 2025, including SRLY tax loss
carryforwards of $15 million that expire from 2018 through 2020. We do not
believe that a valuation allowance is required, as we expect to utilize the loss
carryforwards prior to their expiration. In addition, we had general business
credit carryforwards of $16 million, capital loss carryforwards of $36 million
that expire in 2010 and 2011 and charitable contribution carryforwards of $7
million that expire from 2007 through 2009, for which valuation allowances in
each case have been provided.

     U.S. income taxes are not recorded on the undistributed earnings of foreign
subsidiaries that have been or are intended to be reinvested indefinitely. Upon
distribution, those earnings may be subject to both U.S. income taxes (adjusted
for foreign tax credits or deductions) and withholding taxes payable to various
foreign countries. Cumulative undistributed earnings of foreign subsidiaries for
which income taxes have not been provided totaled approximately $274 million at
December 31, 2006. In 2007, we announced we had signed agreements or plans to
sell substantially all of our foreign assets or subsidiaries. These potential
sales would result in the recognition in 2007 of approximately $96 million of
U.S. tax associated with the change in our determination of our permanent
reinvestment of these undistributed earnings. Also, we presently cannot estimate
the amount of unrecognized withholding taxes that may result. For additional
information, see Note 2, Asset Sales, Impairment Charges and Discontinued
Operations.

     The American Jobs Creation Act (AJCA) of 2004 created a one-time
opportunity to receive a tax benefit for U.S. corporations that reinvest, in the
U.S., dividends received in a year (2005 for CMS Energy) from controlled

                                     CMS-90

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

foreign corporations. During 2005, we repatriated $370 million of foreign
earnings that qualified for the tax benefit. The net effect of the repatriated
earnings were tax benefits of $45 million in 2005 and $21 million in 2004, which
were recorded in income from continuing operations.

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                        2006    2005   2004
-----------------------                                        ----    ----   ----
                                                                  (IN MILLIONS)

<S>                                                           <C>     <C>     <C>

Current income taxes:
  Federal...................................................  $ 129   $  76   $ --
  Federal income tax benefit of operating loss
     carryforwards..........................................    (31)    (70)    --
  State and local...........................................      1      (3)     3
  Foreign...................................................     14      26      9
                                                              -----   -----   ----
                                                              $ 113   $  29   $ 12
Deferred income taxes:
  Federal...................................................  $(255)  $(141)  $  8
  Federal tax benefit of American Jobs Creation Act of
     2004...................................................     --     (45)   (21)
  State.....................................................     --      --     (5)
  Foreign...................................................    (12)      2      6
                                                              -----   -----   ----
                                                              $(267)  $(184)  $(12)
Deferred ITC, net...........................................     (4)    (13)    (5)
                                                              -----   -----   ----
Tax expense (benefit).......................................  $(158)  $(168)  $ (5)
                                                              =====   =====   ====

</Table>


     Current tax expense includes the settlement of income tax audits for prior
years, as well as the provision for 2006 income taxes prior to the use of loss
carryforwards. Deferred tax assets and liabilities are recognized for the
estimated future tax effect of temporary differences between the tax basis of
assets or liabilities and the reported amounts in our consolidated financial
statements. Deferred tax assets and liabilities are classified as current or
noncurrent according to the classification of the related assets or liabilities.
Deferred tax assets and liabilities not related to assets or liabilities are
classified according to the expected reversal date of the temporary differences.

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


<Table>
<Caption>
DECEMBER 31                                                        2006      2005
-----------                                                        ----      ----
                                                                   (IN MILLIONS)

<S>                                                              <C>       <C>

Property.......................................................  $  (790)  $  (764)
Securitized costs..............................................     (177)     (172)
Employee benefits..............................................       38       (67)
Gas inventories................................................     (168)     (148)
Tax loss and credit carryforwards..............................      867       648
SFAS No. 109 regulatory liabilities, net.......................      189       159
Foreign investments inflation indexing.........................       86        --
Valuation allowances...........................................     (116)      (10)
Other, net.....................................................      106         2
                                                                 -------   -------
  Net deferred tax assets/(liabilities)........................  $    35   $  (352)
                                                                 =======   =======
Deferred tax liabilities.......................................  $(1,324)  $(1,325)
Deferred tax assets, net of valuation reserves.................    1,359       973
                                                                 -------   -------
  Net deferred tax assets/(liabilities)........................  $    35   $  (352)
                                                                 =======   =======

</Table>


     During 2006, our Venezuelan investments employed inflation indexing to
their balance sheet, most notably to fixed assets, resulting in a tax basis
increase for local tax purposes. Such adjustments are not recognized for U.S.
purposes; thus, a basis difference exists. We do not believe it to be more
likely than not that we will benefit from

                                     CMS-91

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

increased depreciation deductions attributable to this write up, due to income
limitations. Therefore the deferred tax assets have been fully reserved.

     In June 2006, the IRS concluded its most recent audit of CMS Energy and its
subsidiaries and proposed changes to taxable income for the years ended December
31, 1987 through December 31, 2001. The proposed overall cumulative increase to
taxable income related primarily to the disallowance of the simplified service
cost method with respect to certain self-constructed utility assets. We have
accepted these proposed adjustments to taxable income, which resulted in the
payment of $76 million of tax and a reduction of our income tax provision of $62
million, net of interest expense, primarily for the restoration and utilization
of previously written off income tax credits.

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                       2006    2005    2004
-----------------------                                       ----    ----    ----
                                                                 (IN MILLIONS)

<S>                                                          <C>     <C>     <C>

Income (loss) from continuing operations before income
  taxes
  Domestic.................................................  $(129)  $(463)  $ 199
  Foreign..................................................   (114)    197     (77)
                                                             -----   -----   -----
     Total.................................................   (243)   (266)    122
Statutory federal income tax rate..........................   x 35%   x 35%   x 35%
                                                             -----   -----   -----
Expected income tax expense (benefit)......................    (85)    (93)     42
Increase (decrease) in taxes from:
  Property differences.....................................     19      15      13
  Income tax effect of foreign investments.................    (28)    (24)    (25)
  AJCA foreign dividends benefit...........................     --     (45)    (21)
  ITC amortization.........................................     (4)     (4)     (6)
  State and local income taxes, net of federal benefit.....     --      (2)     (1)
  Return to accrual adjustments............................     (7)     (1)     (5)
  Medicare Part D exempt income............................    (10)     (6)     (6)
  Tax exempt income........................................     (3)     (3)     (3)
  Tax contingency reserves.................................     --      (5)      5
  Valuation allowance......................................     20      --      --
  IRS Settlement / Credit Restoration......................    (62)     --      --
  Other, net...............................................      2      --       2
                                                             -----   -----   -----
Recorded income tax benefit................................  $(158)  $(168)  $  (5)
                                                             -----   -----   -----
Effective tax rate.........................................   65.0%   63.2%   (4.1)%
                                                             =====   =====   =====

</Table>


     During 2006, the valuation allowance increased by $20 million. The increase
was due to a $12 million increase in the allowance attributable to the capital
loss on our November 2006 disposition of the MCV Partnership and a $14 million
increase for the anticipated future capital loss on our GasAtacama investment.
These increases were offset by a $3 million reduction in the valuation allowance
for the anticipated use of prior year capital loss carryovers as well as for $3
million of allowance attributable to charitable contributions and tax credits
that expired on December 31, 2006.

     The amount of income taxes we pay is subject to ongoing audits by federal,
state and foreign tax authorities, which can result in proposed assessments. Our
estimate for the potential outcome for any uncertain tax issue is highly
judgmental. We believe that our accrued tax liabilities at December 31, 2006 are
adequate for all years.

     FIN 48, Accounting for Uncertainty in Income Taxes: In June 2006, the FASB
issued FIN 48, effective for us January 2007. This interpretation provides a
two-step approach for the recognition and measurement of uncertain tax positions
taken, or expected to be taken, by a company on its income tax returns. The
first step is to evaluate the tax position to determine if, based on
management's best judgment, it is greater than 50 percent likely that the taxing


                                     CMS-92

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

authority will sustain the tax position. The second step is to measure the
appropriate amount of the benefit to recognize. This is done by estimating the
potential outcomes and recognizing the greatest amount that has a cumulative
probability of at least 50 percent. FIN 48 requires interest and penalties, if
applicable, to be accrued on differences between tax positions recognized in our
consolidated financial statements and the amount claimed, or expected to be
claimed, on the tax return. Our policy is to include interest and penalties
accrued on uncertain tax positions as part of the related tax liability on our
consolidated balance sheet and as part of the income tax expense in our
consolidated income statement. The impact from adopting FIN 48 should be
recorded as a cumulative adjustment to the beginning retained earnings balance
and a corresponding adjustment to a current or non-current tax liability. At
this time, we are continuing to evaluate the impact of FIN 48 on our
consolidated financial statements.

10: EXECUTIVE INCENTIVE COMPENSATION

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

     All grants under the Plan for 2006 and 2005 were in the form of restricted
stock. Restricted stock awards are outstanding shares to which the recipient has
full voting and dividend rights and vest 100 percent after three years of
continued employment. Restricted stock awards granted to officers in 2006, 2005,
and 2004 are also subject to the achievement of specified levels of total
shareholder return, including a comparison to a peer group of companies. All
restricted stock awards are subject to forfeiture if employment terminates
before vesting. However, if certain minimum service requirements are met,
restricted shares may continue to vest upon retirement or disability and vest
fully if control of CMS Energy changes, as defined by the Plan. In April 2006,
we amended the Plan to allow awards not subject to achievement of total
shareholder return to vest fully upon retirement, subject to the participant not
accepting employment with a direct competitor. This modification did not have a
material impact on our consolidated financial statements.

     The Plan also allows for stock options, stock appreciation rights, phantom
shares, and performance units. None of which were granted in 2006 or 2005.

     Select participants may elect to receive all or a portion of their
incentive payments under the Officer's Incentive Compensation Plan in the form
of cash, shares of restricted common stock, shares of restricted stock units, or
any combination of these. These participants may also receive awards of
additional restricted common stock or restricted stock units, provided the total
value of these additional grants does not exceed $2.5 million for any fiscal
year.

     Shares awarded or subject to stock options, phantom shares, and performance
units may not exceed 6 million shares from June 2004 through May 2009, nor may
such awards to any participant exceed 250,000 shares in any fiscal year. We may
issue awards of up to 4,382,800 shares of common stock under the Plan at
December 31, 2006. Shares for which payment or exercise is in cash, as well as
forfeited shares or stock options may be awarded or granted again under the
Plan.

     The following table summarizes restricted stock activity under the Plan:


<Table>
<Caption>
                                                                       WEIGHTED-AVERAGE
                                                           NUMBER OF      GRANT DATE
RESTRICTED STOCK                                             SHARES       FAIR VALUE
----------------                                           ---------   ----------------

<S>                                                        <C>         <C>

Nonvested at December 31, 2005...........................  1,682,056        $10.64
  Granted................................................    587,830        $13.84
  Vested.................................................   (308,698)       $ 7.71
  Forfeited..............................................    (58,750)       $10.82
                                                           ---------        ------
Nonvested at December 31, 2006...........................  1,902,438        $12.10
                                                           =========        ======

</Table>




                                     CMS-93

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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

     We expense the fair value over the required service period of the awards.
As a result, we recognize all compensation expense for share-based awards with
accelerated service provisions upon retirement by the period in which the
employee becomes eligible to retire.

     The total fair value of shares vested was $4 million in 2006, $4 million in
2005, and $1 million in 2004. We calculate the fair value of restricted shares
granted based on the price of our common stock on the grant date and expense the
fair value over the required service period. Compensation expense related to
restricted stock was $9 million in 2006, $4 million in 2005, and $2 million in
2004. The total related income tax benefit recognized in income was $3 million
in 2006, $2 million in 2005, and $1 million in 2004. At December 31, 2006, there
was $10 million of total unrecognized compensation cost related to restricted
stock. We expect to recognize this cost over a weighted-average period of 1.3
years.

     The following table summarizes stock option activity under the Plan:


<Table>
<Caption>
                                         OPTIONS
                                       OUTSTANDING,
                                      FULLY VESTED,                      WEIGHTED-AVERAGE     AGGREGATE
                                           AND        WEIGHTED-AVERAGE       REMAINING        INTRINSIC
STOCK OPTIONS                          EXERCISABLE     EXERCISE PRICE    CONTRACTUAL TERM       VALUE
-------------                         -------------   ----------------   ----------------   -------------
                                                                                            (IN MILLIONS)

<S>                                   <C>             <C>                <C>                <C>

Outstanding at December 31, 2005....    3,541,338          $21.21            5.4 years           $(24)
  Granted...........................           --              --
  Exercised.........................     (137,500)         $ 7.39
  Cancelled or Expired..............     (490,568)         $30.53
                                        ---------          ------            ---------           ----
Outstanding at December 31, 2006....    2,913,270          $20.29            4.7 years           $(10)
                                        =========          ======            =========           ====

</Table>


     Stock options give the holder the right to purchase common stock at a price
equal to the fair value of our common stock on the grant date. Stock options are
exercisable upon grant, and expire up to 10 years and one month from the grant
date. We issue new shares when participants exercise stock options. The total
intrinsic value of stock options exercised was $1 million in 2006, $2 million in
2005, and $2 million in 2004. Cash received from exercise of these stock options
was $1 million for the year ended December 31, 2006. Since we have utilized tax
loss carryforwards, we were not able to realize the excess tax benefits upon
exercise of stock options. Therefore, we did not recognize the related excess
tax benefits in equity.

11: LEASES

     Lessee: We lease various assets, including service vehicles, railcars,
construction equipment, office furniture, and buildings. We purchase renewable
energy under certain power purchase agreements, as required by the MPSC. In
accordance with SFAS No. 13, we account for these power purchase agreements as
capital and operating leases.

     Operating leases for coal-carrying railcars have lease terms expiring over
the next 15 years. These leases contain fair market value extension and buyout
provisions, with some providing for predetermined extension period rentals.
Capital leases for our vehicle fleet operations have a maximum term of 120
months and TRAC end-of-life provisions. The capital lease for furniture
terminates in 2013, but provides for an early buyout in April 2008. Power
purchase agreements range from 7 to 20 years. Most of our power purchase
agreements contain options at the end of the initial contract term to renew the
agreement annually.


                                     CMS-94

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                          2006   2005   2004
-----------------------                                          ----   ----   ----
                                                                    (IN MILLIONS)

<S>                                                              <C>    <C>    <C>

Capital lease expense..........................................   $15    $14    $13
Operating lease expense........................................    19     18     14
Income from subleases..........................................    (2)    (2)    (1)
                                                                  ===    ===    ===

</Table>


     Minimum annual rental commitments under our non-cancelable leases at
December 31, 2006 are:


<Table>
<Caption>
                                                                 CAPITAL   OPERATING
                                                                  LEASES     LEASES
                                                                 -------   ---------
                                                                    (IN MILLIONS)

<S>                                                              <C>       <C>

2007...........................................................    $13        $ 25
2008...........................................................     12          24
2009...........................................................     11          20
2010...........................................................      9          17
2011...........................................................      7          17
2012 and thereafter............................................     29          61
                                                                   ---        ----
Total minimum lease payments(a)................................     81        $164
                                                                              ====
Less imputed interest..........................................     26
                                                                   ---
Present value of net minimum lease payments....................     55
Less current portion...........................................     13
                                                                   ---
Non-current portion............................................    $42
                                                                   ===

</Table>


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

(a)    Minimum payments have not been reduced by minimum sublease rentals of $4
       million due in the future under noncancelable subleases.

     Lessor: We have a 44 percent ownership interest in a 31-mile intrastate
pipeline that runs from Coldwater Township, Michigan to Hanover Township,
Michigan. We lease our interest in the pipeline through a direct finance lease.
The lease expires in October 2031, with an annual option to extend the lease.

     We sell power, through the Takoradi power plant located in the Republic of
Ghana, Africa, under a power purchase agreement with the Volta River Authority.
In accordance with SFAS No. 13, we account for this transaction as a direct
finance lease. The initial lease term of the agreement expires in 2025.


                                     CMS-95

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     The following table summarizes the net investment in direct finance leases
at December 31, 2006:


<Table>
<Caption>
                                                                 DIRECT FINANCE LEASES
                                                                 ---------------------
                                                                     (IN MILLIONS)

<S>                                                              <C>

2007...........................................................           $ 25
2008...........................................................             25
2009...........................................................             25
2010...........................................................             24
2011...........................................................             24
2012 and thereafter............................................            333
                                                                          ----
Total minimum lease payments...................................            456
Less unearned income...........................................            346
                                                                          ----
Net investment in direct finance leases........................            110
Less current portion...........................................              1
                                                                          ----
Non-current portion............................................           $109
                                                                          ====

</Table>


12: PROPERTY, PLANT, AND EQUIPMENT

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


<Table>
<Caption>
                                                           ESTIMATED
                                                          DEPRECIABLE
DECEMBER 31                                              LIFE IN YEARS    2006     2005
-----------                                              -------------   ------   ------
                                                                          (IN MILLIONS)

<S>                                                      <C>             <C>      <C>

Electric:
  Generation...........................................      13-85       $3,573   $3,487
  Distribution.........................................      12-75        4,425    4,226
  Other................................................       7-40          421      404
  Capital leases(a)....................................                      85       87
Gas:
  Underground storage facilities(b)....................      30-65          263      262
  Transmission.........................................      15-75          465      416
  Distribution.........................................      40-75        2,216    2,141
  Other................................................       7-50          300      306
  Capital leases(a)....................................                      29       26
Enterprises:
  IPP..................................................       3-40          565      813
  CMS Gas Transmission.................................       3-40          116      131
  CMS Electric and Gas.................................       2-30          120       99
  Other................................................       4-25           33       25
Other:.................................................       7-71           31       25
Construction work-in-progress..........................                     651      520
Less accumulated depreciation, depletion, and
  amortization(c)......................................                   5,317    5,123
                                                                         ------   ------
Net property, plant, and equipment(d)(e)...............                  $7,976   $7,845
                                                                         ======   ======

</Table>


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

(a)    Capital leases presented in this table are gross amounts. Amortization of
       capital leases was $59 million in 2006 and $54 million in 2005. Capital
       lease additions were $7 million and capital lease retirements and
       adjustments were $6 million in 2006. Capital lease additions were $12
       million and capital lease retirements and adjustments were $7 million in
       2005.

(b)    Includes unrecoverable base natural gas in underground storage of $26
       million at December 31, 2006 and December 31, 2005, which is not subject
       to depreciation.


                                     CMS-96

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



(c)    At December 31, 2006, accumulated depreciation, depletion, and
       amortization included $4.982 billion from our public utility plant assets
       and $335 million from other plant assets. At December 31, 2005,
       accumulated depreciation, depletion, and amortization included $4.804
       billion from our public utility plant assets and $319 million from other
       plant assets.

(d)    At December 31, 2006, public utility plant additions were $470 million
       and public utility plant retirements, including other plant adjustments,
       were $82 million. At December 31, 2005, public utility plant additions
       were $450 million and public utility plant retirements, including other
       plant adjustments, were $64 million.

(e)    Included in net property, plant and equipment are intangible assets
       related primarily to software development costs, consents, leasehold
       improvements, and rights of way. The estimated amortization lives for
       software development costs range from seven to twelve years. The
       estimated amortization life for leasehold improvements is the life of the
       lease. Other intangible amortization lives range from 13 to 75 years.

     The following tables summarize our intangible assets:


<Table>
<Caption>
                                                                                  INTANGIBLE
                                                                    ACCUMULATED     ASSET,
DECEMBER 31, 2006                                     GROSS COST   AMORTIZATION       NET
-----------------                                     ----------   ------------   ----------
                                                                   (IN MILLIONS)

<S>                                                   <C>          <C>            <C>

Software development................................     $204          $153          $ 51
Rights of way.......................................      115            32            83
Leasehold improvements..............................       19            15             4
Franchises and consents.............................       19            10             9
Other intangibles...................................       29            17            12
                                                         ----          ----          ----
Total...............................................     $386          $227          $159
                                                         ====          ====          ====

</Table>




<Table>
<Caption>
                                                                                  INTANGIBLE
                                                                    ACCUMULATED     ASSET,
DECEMBER 31, 2005                                     GROSS COST   AMORTIZATION       NET
-----------------                                     ----------   ------------   ----------
                                                                   (IN MILLIONS)

<S>                                                   <C>          <C>            <C>

Software development................................     $200          $135          $ 65
Rights of way.......................................      103            29            74
Leasehold improvements..............................       19            14             5
Franchises and consents.............................       19             9            10
Other intangibles...................................       42            19            23
                                                         ----          ----          ----
Total...............................................     $383          $206          $177
                                                         ====          ====          ====

</Table>


     Pretax amortization expense related to these intangible assets was $23
million for the year ended December 31, 2006, $21 million for the year ended
December 31, 2005, and $21 million for the year ended December 31, 2004.
Amortization of intangible assets is forecasted to range between $14 million and
$23 million per year over the next five years.

13: EQUITY METHOD INVESTMENTS

     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, where ownership is more than 20 percent but less than a majority.
Earnings from equity method investments was $89 million in 2006, $125 million in
2005, and $115 million in 2004. The amount of consolidated retained earnings
that represents undistributed earnings from these equity method investments was
$14 million as of December 31, 2006 and $17 million as of December 31, 2005.


                                     CMS-97

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     Our most significant equity method investments are:

     - a 50 percent interest in Jorf Lasfar, and

     - a 40 percent interest in Taweelah.

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

     At December 31, 2006, Jorf Lasfar exceeded the 10 percent and 20 percent
thresholds. At December 31, 2005, Jorf Lasfar exceeded the 10 percent threshold
and no equity method investments exceeded the 20 percent threshold. At December
31, 2004, Jorf Lasfar exceeded the 20 percent threshold and both Jorf Lasfar and
Taweelah exceeded the 10 percent threshold.

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

Income Statement Data



<Table>
<Caption>


                                                            Year Ended December 31,
                                                                      2006
                                                           -------------------------
                                                              Jorf      All
                                                           Lasfar(a)  Others   Total
                                                           ---------  ------   -----
                                                                 (In Millions)

<S>                                                        <C>        <C>     <C>

Operating revenue........................................     $482    $1,611  $2,093
Operating expenses.......................................      317     1,283   1,600
                                                              ----    ------  ------
Operating income.........................................      165       328     493
Other expense, net.......................................       57       195     252
                                                              ----    ------  ------
Net income...............................................     $108    $  133  $  241
                                                              ====    ======  ======

</Table>





<Table>
<Caption>


                                                            Year Ended December 31,
                                                                      2005
                                                           -------------------------
                                                              Jorf      All
                                                           Lasfar(a)  Others   Total
                                                           ---------  ------  ------
                                                                 (In Millions)

<S>                                                        <C>        <C>     <C>

Operating revenue........................................     $508    $1,550  $2,058
Operating expenses.......................................      340     1,190   1,530
                                                              ----    ------  ------
Operating income.........................................      168       360     528
Other expense, net.......................................       56       187     243
                                                              ----    ------  ------
Net income...............................................     $112    $  173  $  285
                                                              ====    ======  ======

</Table>




                                     CMS-98

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)


<Table>
<Caption>


                                                         Year Ended December 31, 2004
                                                     -----------------------------------
                                                        Jorf                All
                                                     Lasfar(a)  Taweelah  Others   Total
                                                     ---------  --------  ------  ------
                                                                (In Millions)

<S>                                                  <C>        <C>       <C>     <C>

Operating revenue..................................     $461       $99    $1,448  $2,008
Operating expenses.................................      282        40     1,207   1,529
                                                        ----       ---    ------  ------
Operating income...................................      179        59       241     479
Other expense, net.................................       53        23       140     216
                                                        ----       ---    ------  ------
Net income.........................................     $126       $36    $  101  $  263
                                                        ====       ===    ======  ======

</Table>



Balance Sheet Data



<Table>
<Caption>


                                                               December 31, 2006
                                                           -------------------------
                                                              Jorf      All
                                                           Lasfar(a)  Others   Total
                                                           ---------  ------  ------
                                                                 (In Millions)

<S>                                                        <C>        <C>     <C>

Assets
  Current assets.........................................    $  239   $  555  $  794
  Property, plant and equipment, net.....................        15    2,931   2,946
  Other assets...........................................     1,047      480   1,527
                                                             ------   ------  ------
                                                             $1,301   $3,966  $5,267
                                                             ======   ======  ======


Liabilities
  Current liabilities....................................    $  272   $  546  $  818
  Long-term debt and other non-current liabilities.......       403    2,721   3,124
  Equity.................................................       626      699   1,325
                                                             ------   ------  ------
                                                             $1,301   $3,966  $5,267
                                                             ======   ======  ======

</Table>





<Table>
<Caption>


                                                               December 31, 2005
                                                           -------------------------
                                                              Jorf      All
                                                           Lasfar(a)  Others   Total
                                                           ---------  ------  ------

<S>                                                        <C>        <C>     <C>

Assets
  Current assets.........................................    $  264   $  554  $  818
  Property, plant and equipment, net.....................        15    3,372   3,387
  Other assets...........................................     1,022      516   1,538
                                                             ------   ------  ------
                                                             $1,301   $4,442  $5,743
                                                             ======   ======  ======


Liabilities
  Current liabilities....................................    $  241   $  458  $  699
  Long-term debt and other non-current liabilities.......       441    2,914   3,355
  Equity.................................................       619    1,070   1,689
                                                             ------   ------  ------
                                                             $1,301   $4,442  $5,743
                                                             ======   ======  ======

</Table>



--------------
(a)     Our investment in Jorf Lasfar was $313 million at December 31, 2006 and
        $310 million at December 31, 2005. Our share of net income from Jorf
        Lasfar was $54 million for the year ended December 31, 2006, $56 million
        for the year ended December 31, 2005, and $63 million for the year ended
        December 31, 2004.


                                     CMS-99

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

     In February 2007, we reached an agreement to sell our ownership interests
in businesses in the Middle East, Africa, and India, including Jorf Lasfar and
Taweelah. We expect to close the sale in the middle of 2007. For additional
details on the sale of our interest in certain equity method investees, see Note
2, Asset Sales, Impairment Charges and Discontinued Operations.

14: JOINTLY OWNED REGULATED UTILITY FACILITIES

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


<Table>
<Caption>


                                                                 Accumulat-  Construct-
                                                         Net         ed          ion
                                                       Invest-    Deprecia-    Work in
                                          Ownership    ment(a)      tion      Progress
                                            Share    ----------  ----------  ----------
DECEMBER 31                               (Percent)  2006  2005  2006  2005  2006  2005
-----------                               ---------  ----  ----  ----  ----  ----  ----
                                                          (In Millions)

<S>                                       <C>        <C>   <C>   <C>   <C>   <C>   <C>

Campbell Unit 3.........................      93.3   $262  $270  $370  $354  $353  $258
Ludington...............................      51.0     68    72    95    92     1     1
Distribution............................   Various     98   100    47    45     4     9
</Table>



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

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

15: REPORTABLE SEGMENTS

     Our reportable segments consist of business units organized and managed by
their products and services. We evaluate performance based upon the net income
of each segment. We operate principally in three reportable segments: electric
utility, gas utility, and enterprises.

     The electric utility segment consists of regulated activities associated
with the generation and distribution of electricity in the state of Michigan
through our subsidiary, Consumers. The gas utility segment consists of regulated
activities associated with the transportation, storage, and distribution of
natural gas in the state of Michigan through our subsidiary, Consumers. The
enterprises segment consists of:

     - investing in, acquiring, developing, constructing, managing, and
       operating non-utility power generation plants, electric distribution
       assets, and natural gas facilities in the United States and abroad, and

     - providing gas, oil, and electric marketing services to energy users.

     Accounting policies of our segments are the same as we describe in the
summary of significant accounting policies. Our consolidated financial
statements reflect the assets, liabilities, revenues, and expenses directly
related to the individual segments where it is appropriate. We allocate accounts
between the segments where common accounts are attributable to more than one
segment. The allocations are based on certain measures of business activities,
such as revenue, labor dollars, customers, other operation and maintenance
expense, construction expense, leased property, taxes or functional surveys. For
example, customer receivables are allocated based on revenue. Pension provisions
are allocated based on labor dollars.

     We account for inter-segment sales and transfers at current market prices
and eliminate them in consolidated net income (loss) by segment. The "Other"
segment includes corporate interest and other, discontinued operations,

                                     CMS-100

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

certain deferred income taxes and the cumulative effect of accounting changes.
The following tables show our financial information by reportable segment:



<Table>
<Caption>
YEARS ENDED DECEMBER 31                                    2006     2005      2004
-----------------------                                    ----     ----      ----
                                                                (IN MILLIONS)

<S>                                                      <C>      <C>       <C>

Operating Revenues
  Electric utility.....................................  $ 3,302  $ 2,695   $ 2,583
  Gas utility..........................................    2,373    2,483     2,081
  Enterprises..........................................    1,135    1,110       808
                                                         -------  -------   -------
                                                         $ 6,810  $ 6,288   $ 5,472
                                                         =======  =======   =======
Earnings from Equity Method Investees
  Enterprises..........................................  $    87  $   124   $   113
  Other................................................        2        1         2
                                                         -------  -------   -------
                                                         $    89  $   125   $   115
                                                         =======  =======   =======
Depreciation, Depletion, and Amortization
  Electric utility.....................................  $   380  $   292   $   189
  Gas utility..........................................      122      117       112
  Enterprises..........................................       71      115       129
  Other................................................        3        1         1
                                                         -------  -------   -------
                                                         $   576  $   525   $   431
                                                         =======  =======   =======
Interest Charges
  Electric utility.....................................  $   164  $   132   $   203
  Gas utility..........................................       73       68        64
  Enterprises..........................................       79       76        87
  Other................................................      190      208       275
                                                         -------  -------   -------
                                                         $   506  $   484   $   629
                                                         =======  =======   =======
Income Tax Expense (Benefit)
  Electric utility.....................................  $    95  $    85   $   120
  Gas utility..........................................       18       39        40
  Enterprises..........................................     (102)    (176)      (46)
  Other................................................     (169)    (116)     (119)
                                                         -------  -------   -------
                                                         $  (158) $  (168)  $    (5)
                                                         =======  =======   =======
Net Income (Loss) Available to Common Stockholders
  Electric utility.....................................  $   199  $   153   $   223
  Gas utility..........................................       37       48        71
  Enterprises..........................................     (158)    (142)       19
  Other................................................     (168)    (153)     (203)
                                                         -------  -------   -------
                                                         $   (90) $   (94)  $   110
                                                         =======  =======   =======
Investments in Equity Method Investees
  Enterprises..........................................  $   588  $   712   $   729
  Other................................................       10       13        23
                                                         -------  -------   -------
                                                         $   598  $   725   $   752
                                                         =======  =======   =======
</Table>

                                     CMS-101

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

<Table>
<Caption>
YEARS ENDED DECEMBER 31                                    2006     2005      2004
-----------------------                                    ----     ----      ----
                                                                (IN MILLIONS)

<S>                                                      <C>      <C>       <C>
Total Assets
  Electric utility(a)..................................  $ 8,516  $ 7,755   $ 7,289
  Gas utility(a).......................................    3,950    3,609     3,187
  Enterprises..........................................    2,339    4,130     4,980
  Other................................................      566      547       416
                                                         -------  -------   -------
                                                         $15,371  $16,041   $15,872
                                                         =======  =======   =======
Capital Expenditures(b)
  Electric utility.....................................  $   462  $   384   $   360
  Gas utility..........................................      172      168       137
  Enterprises..........................................       42       50        37
  Other................................................        1        3         1
                                                         -------  -------   -------
                                                         $   677  $   605   $   535
                                                         =======  =======   =======

</Table>



Geographic Areas(c)


<Table>
<Caption>
                                                            2006     2005     2004
                                                            ----     ----     ----
                                                                (IN MILLIONS)

<S>                                                       <C>      <C>      <C>

United States
  Operating Revenue.....................................  $ 6,140  $ 5,894  $ 5,163
  Operating Income (Loss)...............................      (13)    (461)     586
  Total Assets..........................................  $14,123  $14,675  $14,419
International
  Operating Revenue.....................................  $   670  $   394  $   309
  Operating Income (Loss)...............................      (20)     187        7
  Total Assets..........................................  $ 1,248  $ 1,366  $ 1,453
</Table>



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

(b)    Amounts include electric restructuring implementation plan, purchase of
       nuclear fuel, and capital lease additions. Amounts also include a portion
       of Consumers' capital expenditures for plant and equipment attributable
       to both the electric and gas utility businesses.

(c)    Revenues are based on the country location of customers.

16: CONSOLIDATION OF VARIABLE INTEREST ENTITIES

     Until their sale in November 2006, we had a 49 percent partnership interest
in the MCV Partnership and a 46.4 percent partnership interest in the FMLP.
Prior to their sale, we were the primary beneficiary of both the MCV Partnership
and the FMLP because Consumers is the primary purchaser of power from the MCV
Partnership through a long-term power purchase agreement and Consumers, through
its ownership interest in the FMLP, held a 35 percent lessor interest in the MCV
Facility. Therefore, we consolidated these partnerships into our consolidated
financial statements as of and for the year ended December 31, 2005. Upon the
sale of our interests in the MCV Partnership and the FMLP, we are no longer the
primary beneficiary of these entities and the entities were deconsolidated. For
additional details on the sale of our interests in the MCV Partnership and the
FMLP, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

     These partnerships had third-party obligations totaling $482 million at
December 31, 2005. Property, plant, and equipment serving as collateral for
these obligations had a carrying value of $224 million at December 31,

                                     CMS-102

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

2005. The creditors of these partnerships did not have recourse to the general
credit of Consumers. At December 31, 2005, the MCV Partnership had total assets
of $1.318 billion and a net loss of $917 million for the year.

     We are the primary beneficiary of three other variable interest entities.
We have 50 percent partnership interests each 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 of these entities. Therefore, we
consolidated these partnerships into our consolidated financial statements for
all periods presented. These partnerships have third-party obligations totaling
$97 million at December 31, 2006 and $108 million at December 31, 2005.
Property, plant, and equipment serving as collateral for these obligations has a
carrying value of $157 million at December 31, 2006 and $163 million at December
31, 2005. Other than through outstanding letters of credit and guarantees of $5
million, the creditors of these partnerships do not have recourse to the general
credit of CMS Energy.

     Additionally, we hold interests in variable interest entities in which we
are not the primary beneficiary. The following chart details our involvement in
these entities at December 31, 2006:



<Table>
<Caption>
                                                                      INVESTMENT      OPERATING       TOTAL
NAME                      NATURE OF THE                INVOLVEMENT     BALANCE     AGREEMENT WITH  GENERATING
(OWNERSHIP INTEREST)          ENTITY        COUNTRY        DATE     (IN MILLIONS)    CMS ENERGY     CAPACITY
--------------------      -------------     -------    -----------  -------------  --------------  ----------

<S>                       <C>            <C>           <C>          <C>            <C>             <C>

Taweelah (40%)..........  Generator      United Arab       1999
                                         Emirates                        $ 83            Yes           777MW
Jubail (25%)............  Generator      Saudi Arabia      2001            --             No           250MW
Shuweihat (20%).........  Generator      United Arab       2001
                                         Emirates                          56            Yes         1,500MW
                                                                         ----                        -------
Total...................                                                 $139                        2,527MW
                                                                         ====                        =======

</Table>



     Our maximum exposure to loss through our interests in these variable
interest entities is limited to our investment balance of $139 million, and
letters of credit, guarantees, and indemnities totaling $47 million.

     In February 2007, we entered into an Agreement of Purchase and Sale with
TAQA to sell our ownership interest in businesses in the Middle East, Africa,
and India for $900 million. Businesses included in the sale are Taweelah,
Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We expect to close on the
sale in the middle of 2007. For additional details on the sale of our interests
in these entities, see Note 2, Asset Sales, Impairment Charges and Discontinued
Operations.


                                     CMS-103

<PAGE>

                             CMS ENERGY CORPORATION

             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)

17: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)



<Table>
<Caption>
                                                                      2006
                                                    ---------------------------------------
QUARTERS ENDED                                      MARCH 31  JUNE 30  SEPT. 30  DEC. 31(D)
--------------                                      --------  -------  --------  ----------
                                                    (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

<S>                                                 <C>       <C>      <C>       <C>

Operating revenue.................................   $2,032    $1,396   $1,462     $1,920
Operating income (loss)...........................       (8)       97       (1)      (121)
Income (loss) from continuing operations(a).......      (25)       73     (102)       (31)
Income from discontinued operations(b)............        1         2        1          2
Net income (loss).................................      (24)       75     (101)       (29)
Preferred dividends...............................        3         3        2          3
Net income (loss) available to common
  stockholders....................................      (27)       72     (103)       (32)
Income (loss) from continuing operations per
  average common share -- basic...................    (0.13)     0.32    (0.47)     (0.16)
Income (loss) from continuing operations per
  average common share -- diluted.................    (0.13)     0.30    (0.47)     (0.16)
Basic earnings (loss) per average common
  share(a)........................................    (0.12)     0.33    (0.47)     (0.15)
Diluted earnings (loss) per average common
  share(a)........................................    (0.12)     0.31    (0.47)     (0.15)
Common stock prices(c)
  High............................................    15.22     13.66    14.79      16.95
  Low.............................................    12.95     12.46    12.92      14.55
</Table>



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


<Table>
<Caption>
                                                                      2005
                                                    ---------------------------------------
QUARTERS ENDED                                      MARCH 31  JUNE 30  SEPT. 30  DEC. 31(E)
--------------                                      --------  -------  --------  ----------
                                                    (IN MILLIONS, EXCEPT PER SHARE AMOUNTS)

<S>                                                 <C>       <C>      <C>       <C>

Operating revenue.................................   $1,845    $1,230   $1,307     $1,906
Operating income (loss)...........................      451        95     (804)       (16)
Income (loss) from continuing operations(a).......      152        30     (263)       (17)
Income from discontinued operations(b)............       --        --       --         14
Net income (loss).................................      152        30     (263)        (3)
Preferred dividends...............................        2         3        2          3
Net income (loss) available to common
  stockholders....................................      150        27     (265)        (6)
Income (loss) from continuing operations per
  average common share -- basic...................     0.77      0.12    (1.21)     (0.09)
Income (loss) from continuing operations per
  average common share -- diluted.................     0.74      0.12    (1.21)     (0.09)
Basic earnings (loss) per average common
  share(a)........................................     0.77      0.12    (1.21)     (0.03)
Diluted earnings (loss) per average common
  share(a)........................................     0.74      0.12    (1.21)     (0.03)
Common stock prices(c)
  High............................................    13.38     15.16    16.71      16.48
  Low.............................................     9.81     12.56    14.98      13.39
</Table>



--------------
(a)     Sum of the quarters may not equal the annual earnings (loss) per share
        due to changes in shares outstanding.

(b)     Net of tax.

(c)     Based on New York Stock Exchange -- Composite transactions.

(d)     The quarter ended December 31, 2006 includes a $41 million net loss on
        the sale of our investment in the MCV Partnership including the negative
        impact of the associated asset impairment charge. The quarter also
        includes an $80 million net after-tax charge resulting from our
        agreement to settle shareholder class action lawsuits. For additional
        details, see Note 2, Asset Sales, Impairment Charges and Discontinued
        Operations and Note 3, Contingencies.

(e)     The quarter ended December 31, 2005 includes a $26 million after-tax
        charge related to environmental remediation at Bay Harbor. For
        additional details, see Note 3, Contingencies.


                                     CMS-104

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of CMS Energy Corporation

     We have audited the accompanying consolidated balance sheets of CMS Energy
Corporation (a Michigan Corporation) as of December 31, 2006 and 2005, and the
related consolidated statements of income (loss), common stockholders' equity,
and cash flows for each of the three years in the period ended December 31,
2006. Our audits also included the financial statement schedules listed in the
Index at Item 15(a)(2). These financial statements and schedules are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and schedules based on our audits. We did
not audit the financial statements of Midland Cogeneration Venture Limited
Partnership, a former 49% owned variable interest entity which has been
consolidated through the date of sale, November 21, 2006 (Note 2), which
statements reflect total assets constituting 8.2% in 2005, and total revenues
constituting 8.0% in 2006, 9.4% in 2005 and 11.9% in 2004 of the related
consolidated totals. We also did not audit the 2004 financial statements of Jorf
Lasfar Energy Company S.C.A. (which represents an investment accounted for under
the equity method of accounting). CMS Energy Corporation's equity in the net
income of Jorf Lasfar Energy Company S.C.A. is stated at $63 million for the
year ended December 31, 2004. Those statements were audited by other auditors
whose reports have been furnished to us, and our opinion on the consolidated
financial statements, insofar as it relates to the amounts included for the
periods indicated above for Midland Cogeneration Venture Limited Partnership and
Jorf Lasfar Energy Company S.C.A., respectively, is based solely on the reports
of the other auditors.

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

     In our opinion, based on our audits and the reports of other auditors, the
financial statements referred to above present fairly, in all material respects,
the consolidated financial position of CMS Energy Corporation at December 31,
2006 and 2005, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2006, in
conformity with U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedules, when considered in relation
to the basic financial statements taken as a whole, present fairly in all
material respects the information set forth therein.

     As discussed in Note 7 to the consolidated financial statements, in 2006,
the Company adopted Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards No. 158, "Employers' Accounting for Defined
Benefit Pension and Other Postretirement Plans -- an amendment of FASB
Statements No. 87, 88, 106 and 132(R)." As discussed in Note 10 to the
consolidated financial statements, in 2006, the Company adopted FASB Statement
of Financial Accounting Standards No. 123(R) "Share-Based Payment." In addition,
as discussed in Note 8 to the consolidated financial statements, in 2005 the
Company adopted FASB Interpretation No. 47, "Accounting for Conditional Asset
Retirement Obligations." As discussed in Note 7 to the consolidated financial
statements, in 2004 the Company changed its measurement date for all CMS Energy
Corporation pension and postretirement plans.

     We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of CMS
Energy Corporation's internal control over financial reporting as of December
31, 2006, based on criteria established in Internal Control-Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated February 21, 2007, expressed an unqualified opinion
thereon.

                                        /s/ Ernst & Young LLP

Detroit, Michigan
February 21, 2007


                                     CMS-105

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:

     In our opinion, the accompanying balance sheets and the related statements
of operations, of partners' equity (deficit) and comprehensive income (loss) and
of cash flows present fairly, in all material respects, the financial position
of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and
December 31, 2005, and the results of its operations and its cash flows for the
period ended November 21, 2006 and the two years in the period ended December
31, 2005 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Partnership's management. Our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits of these
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

                                        /s/ PricewaterhouseCoopers LLP

February 19, 2007


                                     CMS-106

<PAGE>

                         REPORT OF INDEPENDENT AUDITORS

To the Management Committee
and Stockholders of Jorf Lasfar
Energy Company S.C.A.
B.P. 99 Sidi Bouzid
El Jadida

     We have audited the accompanying balance sheets of Jorf Lasfar Energy
Company S.C,A (the "Company") as of December 31, 2004, 2003 and 2002, and the
related statements of income, of stockholders' equity and of cash flows for the
years then ended. These financial statements are the responsibility of the
Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

     In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Jorf Lasfar Energy Company
S.C.A at December 31, 2004, 2003 and 2002, and the results of its operations and
its cash flows for the years then ended, in conformity with accounting
principles generally accepted in the United States of America.

                                        /s/ Price Waterhouse

Casablanca, Morocco,
February 11, 2005


                                     CMS-107

<PAGE>

                             (CONSUMERS ENERGY LOGO)

                     2006 CONSOLIDATED FINANCIAL STATEMENTS



                                      CE-1

<PAGE>

                            CONSUMERS ENERGY COMPANY

                         SELECTED FINANCIAL INFORMATION



<Table>
<Caption>
                                                   2006     2005     2004     2003     2002
                                                   ----     ----     ----     ----     ----

<S>                                         <C>   <C>      <C>      <C>      <C>      <C>

Operating revenue (in millions)...........   ($)   5,721    5,232    4,711    4,435   4,169
Earnings from equity method investees (in
  millions)...............................   ($)       1        1        1       42      53
Income (loss) before cumulative effect of
  change in accounting principle (in
  millions)...............................   ($)     186      (96)     280      196     363
Cumulative effect of change in accounting
  (in millions)...........................   ($)      --       --       (1)      --      18
Net income (loss) (in millions)(a)........   ($)     186      (96)     279      196     381
Net income (loss) available to common
  stockholder (in millions)...............   ($)     184      (98)     277      194     335
Cash from operations (in millions)........   ($)     474      640      595        5     760
Capital expenditures, excluding capital
  lease additions (in millions)...........   ($)     646      572      508      486     559
Total assets (in millions)(b).............   ($)  12,845   13,178   12,811   10,745   9,598
Long-term debt, excluding current portion
  (in millions)(b)........................   ($)   4,127    4,303    4,000    3,583   2,442
Long-term debt -- related parties,
  excluding current portion (in
  millions)(c)............................   ($)      --       --      326      506      --
Non-current portion of capital leases and
  finance lease obligations (in
  millions)...............................   ($)      42      308      315       58     116
Total preferred stock (in millions).......   ($)      44       44       44       44      44
Total Trust Preferred Securities (in
  millions)(c)............................   ($)      --       --       --       --     490
Number of preferred shareholders at year-
  end.....................................         1,728    1,823    1,931    2,032   2,132
Book value per common share at year-end...   ($)   35.17    33.03    28.68    24.51   22.46
Number of full-time equivalent employees
  at  year-end............................         8,026    8,114    8,050    7,947   8,311
ELECTRIC STATISTICS
  Sales (billions of kWh).................            38       39       38       38      38
  Customers (in thousands)................         1,797    1,789    1,772    1,754   1,734
  Average sales rate per kWh..............   (c)    8.46     6.73     6.88     6.91    6.88
GAS UTILITY STATISTICS
  Sales and transportation deliveries
     (bcf)................................           309      350      385      380     376
  Customers (in thousands)(d).............         1,714    1,708    1,691    1,671   1,652
  Average sales rate per mcf..............   ($)   10.44     9.61     8.04     6.72    5.67
</Table>



--------------
(a)   See Notes 1 and 3 in the notes to the consolidated financial statements.

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

(c)   Effective December 31, 2003, Trust Preferred Securities are classified on
      our consolidated balance sheets as Long-term debt -- related parties.

(d)   Excludes off-system transportation customers.


                                      CE-2

<PAGE>

                                                        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 serving Michigan's Lower Peninsula. Our
customer base includes a mix of residential, commercial, and diversified
industrial customers.

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

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

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

     - economic conditions,

     - regulation and regulatory issues,

     - energy commodity prices,

     - interest rates, and

     - our debt credit rating.

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

     We are focused on growing the equity base of our company and have been
refinancing our debt to reduce interest rate costs. In 2006, we received $200
million of cash contributions from CMS Energy and we extinguished, through a
legal defeasance, $129 million of 9 percent related party notes.

     In July 2006, we reached an agreement to sell the Palisades nuclear plant
to Entergy for $380 million. We also signed a 15-year power purchase agreement
with Entergy for 100 percent of the plant's current electric output. We are
targeting to close the sale in the second quarter of 2007. When completed, the
sale will result in an immediate improvement in our cash flow, a reduction in
our nuclear operating and decommissioning risk, and an improvement in our
financial flexibility to support other utility investments. We expect to use the
proceeds to benefit our customers. We plan to use the cash that we retain from
the sale to reduce utility debt. In January 2007, the NRC renewed the Palisades
operating license for 20 years, extending it to 2031.

     Natural gas prices are volatile and have an impact on working capital and
cash flow. Although our natural gas costs are recoverable from our utility
customers, higher-priced natural gas stored as inventory requires additional
liquidity due to the lag in cost recovery.

     In November 2006, we sold our interests in the MCV Partnership and the
FMLP. The sale resulted in a $57 million positive impact on our 2006 cash flow.
We used the proceeds to reduce debt. The sale reduced our exposure to volatile
natural gas prices.

     In the future, we will continue to focus on:

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


                                      CE-3

<PAGE>

                                                        Consumers Energy Company

     - growing earnings, and

     - managing cash flow issues.

     As we execute our strategy, we will need to overcome a sluggish Michigan
economy that has been hampered by negative developments in Michigan's automotive
industry and limited growth in the non-automotive sectors of the state's
economy. The return of ROA customer load has offset some of these negative
effects. At December 31, 2006, alternative electric suppliers were providing 300
MW of generation service to ROA customers. This is 3 percent of our total
distribution load and represents a decrease of 46 percent of ROA load compared
to the end of December 2005.

FORWARD-LOOKING STATEMENTS AND INFORMATION

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

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

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

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

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

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

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

     - potentially adverse regulatory treatment and (or) regulatory lag
       concerning a number of significant questions presently before the MPSC
       including:

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

          - power supply and natural gas supply costs when fuel prices are
            increasing and (or) fluctuating,

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

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

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

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

          - sale of the Palisades plant,

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


                                      CE-4

<PAGE>

                                                        Consumers Energy Company

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

     - energy markets, including availability of capacity and the timing and
       extent of changes in commodity prices for oil, coal, natural gas, natural
       gas liquids, electricity and certain related products due to lower or
       higher demand, shortages, transportation costs problems, or other
       developments,

     - our ability to collect accounts receivable from our customers,

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

     - the effect on our electric utility of the direct and indirect impacts of
       the continued economic downturn experienced by our automotive and
       automotive parts manufacturing customers,

     - 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, operation, 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,

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

     - outcome, cost, and other effects of legal and administrative proceedings,
       settlements, investigations and claims,

     - disruptions in the normal commercial insurance and surety bond markets
       that may increase costs or reduce traditional insurance coverage,
       particularly terrorism and sabotage insurance 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, many of which are
       beyond our control.

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

RESULTS OF OPERATIONS

NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER


<Table>
<Caption>
YEARS ENDED DECEMBER 31                      2006    2005   CHANGE    2005   2004   CHANGE
-----------------------                      ----   -----   ------   -----   ----   ------
                                                              IN MILLIONS

<S>                                          <C>    <C>     <C>      <C>     <C>    <C>

Electric...................................  $199   $ 153    $ 46    $ 153   $222    $ (69)
Gas........................................    37      48     (11)      48     71      (23)
Other (Includes the MCV
Partnership interest)......................   (52)   (299)    247     (299)   (16)    (283)
                                             ----   -----    ----    -----   ----    -----
Net Income (Loss) Available to Common
  Stockholder..............................  $184   $ (98)   $282    $ (98)  $277    $(375)
                                             ====   =====    ====    =====   ====    =====

</Table>



     For 2006, our net income available to our common stockholder was $184
million, compared to a net loss available to our common stockholder of $98
million for 2005. The increase is primarily due to the absence of a 2005
impairment charge to property, plant, and equipment at the MCV Partnership
offset partially by charges related to the sale of the MCV Partnership recorded
in 2006. For additional details on the impairment and sale of the MCV Facility,
see Note 2, Asset Sales and Impairment Charges. The increase also reflects
higher net income from our

                                      CE-5

<PAGE>

                                                        Consumers Energy Company

electric utility, primarily due to increased revenue resulting from an electric
rate order, the expiration of rate caps on our residential customers, and the
return of former ROA customers to full-service rates. Partially offsetting these
increases are higher operating and maintenance costs at our electric utility,
and a reduction in net income from our gas utility. Lower, weather-driven sales
at our gas utility exceeded the benefits from lower operating costs and a gas
rate increase authorized by the MPSC in November of 2006.

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


<Table>
<Caption>
                                                                        IN MILLIONS
                                                                        -----------

<S>  <C>                                                                <C>

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

</Table>


     For 2005, our net loss available to our common stockholder was $98 million,
compared to net income available to our common stockholder of $277 million for
2004. The decrease is primarily due to an impairment charge to property, plant,
and equipment at the MCV Partnership to reflect the excess of the carrying value
of these assets over their estimated fair value. For additional details on the
impairment of the MCV Facility, see Note 2, Asset Sales and Impairment Charges.
The decrease also reflects a reduction in net income from our electric utility,
as higher operating and maintenance costs exceeded higher, weather-driven sales
to our residential customers. Additionally, the decrease reflects a reduction in
net income from our gas utility, as higher operating and maintenance costs
exceeded the benefits derived from the increase in revenue resulting from the
gas rates surcharge authorized by the MPSC in October 2004. Partially offsetting
these decreases is an increase in the fair value of certain long-term gas
contracts and financial hedges at the MCV Partnership.


                                      CE-6

<PAGE>

                                                        Consumers Energy Company

     Specific changes to net income (loss) available to our common stockholder
for 2005 versus 2004 are:


<Table>
<Caption>
                                                                        IN MILLIONS
                                                                        -----------

<S>  <C>                                                                <C>

-    decrease in earnings related to our ownership interest in the         $(285)
     MCV Partnership due to an impairment charge to property, plant,
     and equipment to reflect excess of the carrying value over the
     estimated fair value of the assets, offset partially by an
     increase of $100 million from operations, primarily due to an
     increase in fair value of certain long-term gas contracts and
     financial hedges,
-    increase in operating expenses primarily due to higher                 (136)
     depreciation and amortization expense, expense, higher pension
     and benefit expense, and higher underrecovery expense related to
     the MCV PPA, offset partially by our direct savings from the
     RCP,
-    increase in underrecoveries of electric power supply costs due          (30)
     primarily to higher coal costs, as these costs could not be
     recovered from certain customers due to rate caps that expired
     at the end of 2005,
-    decrease in return on electric utility capital expenditures in          (20)
     excess of depreciation base as allowed by the Customer Choice
     Act, net of related capitalized interest,
-    increase in electric delivery revenue due to warmer weather and          59
     increased surcharge revenue,
-    decrease in interest charges,                                            12
-    increase in gas delivery revenue due to the MPSC's October 2004          20
     final gas rate order and higher miscellaneous income, offset
     partially by lower deliveries, and
-    decrease in general tax expense.                                          5
                                                                           -----
Total Change                                                               $(375)
                                                                           =====

</Table>


ELECTRIC UTILITY RESULTS OF OPERATIONS


<Table>
<Caption>
YEARS ENDED DECEMBER 31                       2006   2005   CHANGE   2005   2004   CHANGE
-----------------------                       ----   ----   ------   ----   ----   ------
                                                              IN MILLIONS

<S>                                           <C>    <C>    <C>      <C>    <C>    <C>

Net income..................................  $199   $153    $  46   $153   $222    $ (69)
                                              ====   ====    =====   ====   ====    =====
REASONS FOR THE CHANGE:
Electric deliveries.........................                 $ 254                  $  91
Power supply costs and related revenue......                    57                    (46)
Other operating expenses, other income, and
  non-commodity revenue.....................                  (236)                  (131)
Regulatory return on capital expenditures...                    22                    (30)
General taxes...............................                    (7)                     6
Interest charges............................                   (34)                     5
Income taxes................................                   (10)                    35
Cumulative effect of change in accounting,
  net of tax expense........................                    --                      1
                                                             -----                  -----
Total change................................                 $  46                  $ (69)
                                                             =====                  =====

</Table>


     ELECTRIC DELIVERIES: In 2006, electric delivery revenues increased by $254
million over 2005 despite the fact that electric deliveries to end-use customers
were 38.5 billion kWh, a decrease of 0.4 billion kWh or 1.2 percent versus 2005.
The decrease in electric deliveries is primarily due to milder summer weather
compared to 2005, and resulted in a decrease in electric delivery revenue of $16
million. Despite lower electric deliveries, electric delivery revenue increased
primarily due to an electric rate order, increased surcharge revenue, and the
return of former ROA

                                      CE-7

<PAGE>

                                                        Consumers Energy Company

customers to full-service rates. The impact of these three issues on electric
delivery revenue are discussed in the following paragraphs.

     Electric Rate Order: In December 2005, the MPSC issued an order in our
electric rate case. The order increased electric tariff rates and impacted PSCR
revenue. As a result of this order, electric delivery revenues increased $160
million in 2006 versus 2005.

     Surcharge Revenue: On January 1, 2006, we started collecting a surcharge
that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This
surcharge increased electric delivery revenue by $51 million in 2006 versus
2005. In addition, on January 1, 2006, we started collecting customer choice
transition costs from our residential customers that increased electric delivery
revenue by $12 million in 2006 versus 2005. Other surcharges decreased electric
delivery revenue by $2 million in 2006 versus 2005.

     ROA Customer Deliveries: The Customer Choice Act allows all of our electric
customers to buy electric generation service from us or from an alternative
electric supplier. At December 31, 2006, alternative electric suppliers were
providing 300 MW of generation service to ROA customers. This amount represents
a decrease of 46 percent of ROA load compared to the end of December 2005. The
return of former ROA customers to full-service rates increased electric revenues
$49 million in 2006 versus 2005.

     For 2005, electric deliveries to end-use customers were 38.9 billion kWh,
an increase of 1.3 billion kWh or 3.4 percent versus 2004. The corresponding $68
million increase in electric delivery revenue was primarily due to increased
sales to residential customers, reflecting warmer summer weather and increased
surcharge revenue from all customers.

     On July 1, 2004, we started collecting a surcharge to recover costs
incurred in the transition to customer choice. This surcharge increased electric
delivery revenue by $13 million in 2005 versus 2004. Surcharge revenue related
to the recovery of Security Costs and Stranded Costs increased electric delivery
revenue by an additional $10 million in 2005 versus 2004.

     POWER SUPPLY COSTS AND RELATED REVENUE: Rate caps for our residential
customers expired on December 31, 2005. In 2006, the absence of rate caps
allowed us to record power supply revenue to offset fully our power supply
costs. Our ability to recover these power supply costs resulted in an $82
million increase in electric revenue in 2006 versus 2005. Additionally, electric
revenue increased $9 million in 2006 versus 2005 primarily due to the return of
former special-contract customers to full-service rates in 2006. The return of
former special-contract customers to full-service rates allowed us to record
power supply revenue to offset fully our power supply costs.

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

     In 2005, our recovery of power supply costs was capped for our residential
customers. The underrecovery of power costs related to these capped customers
increased by $76 million versus 2004. Partially offsetting these underrecoveries
were benefits from the deferral of transmission and nitrogen oxide allowance
expenditures related to our capped customers. To the extent these costs were not
fully recoverable due to the application of rate caps, we deferred them for
recovery under Section 10d(4) of the Customer Choice Act. In December 2005, the
MPSC approved the recovery of these costs. For 2005, deferrals of these costs
increased by $30 million versus 2004.

     OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For
2006, other operating expenses increased $236 million. The increase in other
operating expenses reflects higher operating and maintenance, customer service,
depreciation and amortization, and pension and benefit expenses.

     Operating and maintenance expense increased primarily due to costs related
to a planned refueling outage at our Palisades nuclear plant, and higher tree
trimming and storm restoration costs. Higher customer service expense reflects
contributions, beginning in January 2006 pursuant to a December 2005 MPSC order,
to a fund that provides energy assistance to low-income customers. Depreciation
and amortization expense increased due to higher plant in service and greater
amortization of certain regulatory assets. The increase in pension and benefit
expense reflects

                                      CE-8

<PAGE>

                                                        Consumers Energy Company

changes in actuarial assumptions in 2005, and the latest collective bargaining
agreement between the Utility Workers Union of America and Consumers.

     For 2005, other operating expenses increased $139 million, other income
increased $4 million, and non-commodity revenue increased $4 million versus
2004.

     The increase in other operating expenses reflects higher depreciation and
amortization, higher pension and benefit expense, and higher underrecovery
expense related to the MCV PPA, offset partially by our direct savings from the
RCP. Depreciation and amortization expense increased primarily due to a
reduction in 2004 expense to reflect an MPSC order allowing recovery of $57
million of Stranded Costs. Pension and benefit expense increased primarily due
to changes in actuarial assumptions and the remeasurement of our pension and
OPEB plans to reflect the new collective bargaining agreement between the
Utility Workers Union of America and Consumers. Benefit expense also reflects
the reinstatement of the employer matching contribution to our 401(k) plan in
January 2005.

     In 1992, a liability was established for estimated future underrecoveries
of power supply costs under the MCV PPA. In 2004, a portion of the cash
underrecoveries continued to reduce this liability until its depletion in
December. In 2005, all cash underrecoveries were expensed directly to income.
Consequently, the cost associated with the MCV PPA cash underrecoveries
increased operating expense $30 million for 2005 versus 2004. Offsetting this
increased operating expense were the savings from the RCP approved by the MPSC
in January 2005.

     The RCP allows us to dispatch the MCV Facility on the basis of natural gas
prices, which reduces the MCV Facility's annual production of electricity and,
as a result, reduces the MCV Facility's consumption of natural gas. The MCV
Facility's fuel cost savings are first used to offset the cost of replacement
power and fund a renewable energy program. Remaining savings are split between
us and the MCV Partnership. Our direct savings were shared 50 percent with
customers in 2005 and are being shared 70 percent with customers in 2006 and
each year thereafter. Our direct savings, after allocating a portion to
customers, was $9 million for 2006 and $32 million for 2005.

     For 2005, the increase in other income was primarily due to higher interest
income on short-term cash investments versus 2004, offset partially by expenses
associated with the early retirement of debt. The increase in non-commodity
revenue was primarily due to higher transmission services revenue versus 2004.

     REGULATORY RETURN ON CAPITAL EXPENDITURES: For 2006, the return on capital
expenditures in excess of our depreciation base increased income by $22 million
versus 2005. The increase reflects the equity return on the regulatory asset
authorized by the MPSC's December 2005 order which provided for the recovery of
$333 million of Section 10d(4) costs over five years.

     For 2005, the return on capital expenditures in excess of our depreciation
base decreased income by $30 million versus 2004. The decrease reflects a
reduction, in 2005, of the equity return on the regulatory asset authorized by
the MPSC's December 2005 order. Prior to the MPSC order, the equity return was
calculated using a regulatory asset balance that was greater than the amount
authorized by the MPSC.

     GENERAL TAXES: For 2006, the increase in general taxes reflects higher MSBT
expense, offset partially by lower property tax expense.

     For 2005, general taxes decreased primarily due to lower property tax
expense, reflecting the use of revised tax tables by several of our taxing
authorities and, separately, other property tax refunds.

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

     For 2005, interest charges decreased primarily due to higher capitalized
interest. In 2005, we capitalized $33 million of interest in connection with the
MPSC's December 2005 order in our Section 10d(4) Regulatory Asset case. This
benefit was offset partially by higher average debt levels versus 2004.


                                      CE-9

<PAGE>

                                                        Consumers Energy Company

     INCOME TAXES: For 2006, income taxes increased versus 2005 primarily due to
higher earnings by the electric utility, offset partially by the resolution of
an IRS income tax audit, which resulted in a $4 million income tax benefit
caused by the restoration and utilization of income tax credits.

     For 2005, income taxes decreased primarily due to lower earnings versus
2004, offset partially by a $2 million increase to reflect the tax treatment of
items related to property, plant, and equipment as required by past MPSC orders.

     CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF TAX EXPENSE: The
measurement date for all of our benefit plans is November 30 for 2006, 2005 and
2004, and December 31 for 2003. As a result of the measurement date change, in
2004, we recorded a $1 million, net of tax, cumulative effect adjustment as a
decrease to earnings.

GAS UTILITY RESULTS OF OPERATIONS


<Table>
<Caption>
YEARS ENDED DECEMBER 31                         2006   2005   CHANGE   2005   2004   CHANGE
-----------------------                         ----   ----   ------   ----   ----   ------
                                                                IN MILLIONS

<S>                                             <C>    <C>    <C>      <C>    <C>    <C>

Net income....................................   $37    $48    $(11)    $48    $71    $(23)
                                                 ===    ===    ====     ===    ===    ====
REASONS FOR THE CHANGE:
Gas deliveries................................                 $(61)                  $ (6)
Gas rate increase.............................                   14                     28
Gas wholesale and retail services, other gas
  revenues, and other income..................                   24                      9
Operation and maintenance.....................                    7                    (49)
General taxes and depreciation................                  (10)                    (4)
Interest charges..............................                   (6)                    (2)
Income taxes..................................                   21                      1
                                                               ----                   ----
Total change..................................                 $(11)                  $(23)
                                                               ====                   ====

</Table>


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

     For 2005, gas delivery revenues reflect lower deliveries to our customers
versus 2004. Gas deliveries, including miscellaneous transportation to end-use
customers, were 318 bcf, a decrease of 2 bcf or 0.7 percent.

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

     In December 2003, the MPSC issued an interim gas rate order authorizing a
$19 million annual increase to gas tariff rates. In October 2004, the MPSC
issued a final order authorizing an annual increase of $58 million. As a result
of these orders, gas revenues increased $28 million for 2005 versus 2004.

     GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES, AND OTHER
INCOME: For 2006, the increase in gas wholesale and retail services, other gas
revenues, and other income primarily reflects higher pipeline revenues and
higher pipeline capacity optimization in 2006 versus 2005.

     For 2005, other gas revenue increased versus 2004 primarily due to higher
interest income on short-term cash investments, offset partially by expenses
associated with the early retirement of debt.

     OPERATION AND MAINTENANCE: For 2006, operation and maintenance expenses
decreased versus 2005 primarily due to lower operating expenses, offset
partially by higher customer service and pension and benefit expenses. Customer
service expense increased primarily due to higher uncollectible accounts expense
and contributions, beginning in November 2006 pursuant to a November 2006 MPSC
order, to a fund that provides energy assistance to low-income customers. The
increase in pension and benefit expense reflects changes in

                                      CE-10

<PAGE>

                                                        Consumers Energy Company

actuarial assumptions in 2005 and the latest collective bargaining agreement
between the Utility Workers Union of America and Consumers.

     For 2005, operation and maintenance expenses increased primarily due to
increases in benefit costs and additional safety, reliability, and customer
service expenses versus 2004. Pension and benefit expense increased primarily
due to changes in actuarial assumptions and the remeasurement of our pension and
OPEB plans to reflect the new collective bargaining agreement between the
Utility Workers Union of America and Consumers. Benefit expense also reflects
the reinstatement of the employer matching contribution to our 401(k) plan in
January 2005.

     GENERAL TAXES AND DEPRECIATION: For 2006, depreciation expense increased
versus 2005 primarily due to higher plant in service. The increase in general
taxes reflects higher MSBT expense, offset partially by lower property tax
expense.

     For 2005, depreciation expense increased primarily due to higher plant in
service versus 2004. The decrease in general taxes is primarily due to lower
property tax expense versus 2004. Lower property tax expense in 2005 reflects an
increased use of revised tax tables by several of Consumers' taxing authorities,
and separately, other property tax refunds.

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

     For 2005, interest charges reflect higher average debt levels versus 2004,
offset partially by a lower average rate of interest on our debt.

     INCOME TAXES: For 2006, income taxes decreased versus 2005 primarily due to
lower earnings by the gas utility. Also contributing to the decrease was the
absence, in 2006, of the write-off of general business credits that expired in
2005, and the resolution of an IRS income tax audit, which resulted in a $3
million income tax benefit caused by the restoration and utilization of income
tax credits.

     For 2005, income taxes decreased due to lower earnings versus 2004. This
decrease was offset by $5 million to reflect the tax treatment of items related
to property, plant, and equipment as required by past MPSC orders, and the
write-off of general business credits expected to expire in 2005.

OTHER NONUTILITY RESULTS OF OPERATIONS


<Table>
<Caption>
YEARS ENDED DECEMBER 31               2006     2005    CHANGE     2005    2004    CHANGE
-----------------------               ----    -----    ------    -----    ----    ------
                                                          IN MILLIONS

<S>                                   <C>     <C>      <C>       <C>      <C>     <C>

Net loss..........................    $(52)   $(299)    $247     $(299)   $(16)    $(283)
                                      ====    =====     ====     =====    ====     =====

</Table>


     For 2006, other nonutility operations was a net loss of $52 million, an
improvement of $247 million versus 2005. The change is primarily due to a $225
million increase in earnings related to our ownership interest in the MCV
Partnership. The increase in MCV Partnership earnings is primarily due to the
absence of a 2005 impairment charge to property, plant, and equipment at the MCV
Partnership. Partially offseting this increase were charges related to the sale
of the MCV Partnership recorded in 2006 and mark-to-market losses on MCV
Partnership's long-term gas contracts and associated hedges (which partially
reduced gains recorded in 2005).

     For 2005, other nonutility operations was a net loss of $299 million, a
decrease of $283 million versus 2004. The change is primarily due to a $285
million decrease in earnings related to our ownership interest in the MCV
Partnership. In September 2005, the MCV Partnership recorded an impairment
charge to property, plant, and equipment to reflect the excess of the carrying
value of these assets over their estimated fair value. Partially offsetting the
impairment charge were mark-to-market gains on the MCV Partnership's long-term
gas contracts and associated hedges.


                                      CE-11

<PAGE>

                                                        Consumers Energy Company

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

USE OF ESTIMATES AND ASSUMPTIONS

     We use estimates and assumptions in preparing our consolidated financial
statements that may affect reported amounts and disclosures. We use accounting
estimates 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.
Actual results may differ from estimated results due to factors 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 a loss is probable and the amount
of loss can be reasonably estimated. We use the principles in SFAS No. 5 when
recording estimated liabilities for contingencies. We consider many factors in
making these assessments, including the history and specifics of each matter. We
discuss significant contingencies in the "Outlook" section included in this
MD&A.

     LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. We periodically perform tests of impairment if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $12.845
billion at December 3l, 2006, 58 percent represent long-lived assets and equity
method investments that are subject to this type of analysis. We base our
evaluations of impairment on such indicators as:

     - the nature of the assets,

     - projected future economic benefits,

     - regulatory and political environments,

     - state and federal regulatory and political environments,

     - historical and future cash flow and profitability measurements, and

     - other external market conditions or factors.

     We evaluate an asset for impairment if an event occurs or circumstances
change in a manner that indicates the recoverability of a long-lived asset
should be assessed. We evaluate an asset held-in-use for impairment by
calculating the undiscounted future cash flows expected to result from the use
of the asset and its eventual disposition. If the undiscounted future cash flows
are less than the carrying amount, we recognize an impairment loss. 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. We
record an asset considered held-for-sale at the lower of its carrying amount or
fair value, less cost to sell.

     We assess our ability to recover the carrying amounts of our equity method
investments using the fair values of these investments. We determine fair value
using valuation methodologies, including discounted cash flows and the ability
of the investee to sustain an earnings capacity that justifies the carrying
amount of the investment. 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, which could have a
material impact on our consolidated financial statements.

     For additional details on asset impairments, see Note 2, Asset Sales and
Impairment Charges.


                                      CE-12

<PAGE>

                                                        Consumers Energy Company

ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION

     Because we are involved in a regulated industry, regulatory decisions
affect the timing and recognition of revenues and expenses. We use SFAS No. 71
to account for the effects of these regulatory decisions. As a result, we may
defer or recognize revenues and expenses differently than a non-regulated
entity.

     For example, we may record as regulatory assets items that a non-regulated
entity normally would expense if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, we may record as
regulatory liabilities items that non-regulated entities may normally recognize
as revenues if the actions of the regulator indicate they will require that such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. At
December 31, 2006, we had $2.316 billion recorded as regulatory assets and
$1.954 billion recorded as regulatory liabilities.

ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION

     FINANCIAL INSTRUMENTS: Debt and equity securities classified as available-
for-sale are reported at fair value determined from quoted market prices. Debt
and equity securities classified as held-to-maturity are reported at cost.

     Unrealized gains or losses resulting from changes in fair value of certain
available-for-sale debt and equity securities are reported, net of tax, in
equity as part of AOCI. Unrealized gains or losses are excluded from earnings
unless the related changes in fair value are determined to be other than
temporary. Unrealized gains or losses on our nuclear decommissioning investments
are reflected as regulatory liabilities on our Consolidated Balance Sheets.
Realized gains or losses would not affect our consolidated earnings or cash
flows.

     DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133 to determine if
certain contracts must be accounted for as derivative instruments. These
criteria are complex and significant judgment is often required in applying the
criteria to specific contracts. If a contract is a derivative, it is recorded on
our consolidated balance sheet at its fair value. We then adjust the resulting
asset or liability each quarter to reflect any change in the market value of the
contract, a practice known as marking the contract to market. For additional
details on accounting for derivatives, see Note 5, Financial and Derivative
Instruments.

     To determine the fair value of our derivatives, we use information from
external sources (i.e., quoted market prices and third-party valuations), if
available. For certain contracts, this information is not available and we use
mathematical valuation models to value our derivatives. These models require
various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. Changes in
forward prices or volatilities could significantly change the calculated fair
value of our derivative contracts. The cash returns we actually realize on these
contracts may vary, either positively or negatively, from the results that we
estimate using these models. As part of valuing our derivatives at market, we
maintain reserves, if necessary, for credit risks arising from the financial
condition of our counterparties.

     The types of contracts we typically classify as derivative instruments are
interest rate swaps and gas supply options. The majority of our commodity
purchase and sale contracts are not subject to derivative accounting under SFAS
No. 133 because:

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

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

     - there is not an active market for the commodity.

     Our coal purchase contracts are not derivatives because there is not an
active market for the coal we purchase. If an active market for coal develops in
the future, some of these contracts may qualify as derivatives and the resulting
mark-to-market impact on earnings could be material.

     Establishment of the Midwest Energy Market: In 2005, the MISO began
operating the Midwest Energy Market. As of December 31, 2006, we have determined
that, due to the increased liquidity for electricity within the Midwest Energy
Market since its inception, it is our best judgment that this market should be
considered an active market, as defined by SFAS No. 133. This conclusion does
not impact how we account for our electric capacity and

                                      CE-13

<PAGE>

                                                        Consumers Energy Company

energy contracts, however, because these contracts qualify for the normal
purchases and sales exception and, as a result, are not required to be marked-
to-market.

     Derivatives Associated with the MCV Partnership: In November 2006, we sold
our interest in the MCV Partnership. In conjunction with that sale, our interest
in all of the MCV Partnership's long-term gas contracts and related futures,
options, and swaps was sold. Before the sale, we accounted for certain long-term
gas contracts and all of the related futures, options, and swaps as derivatives.

     Certain of these derivatives, specifically the long-term gas contracts, the
options, and a portion of the futures and swaps, did not qualify for cash flow
hedge accounting treatment. As such, we recorded the mark-to-market gains and
losses from these derivatives in earnings each quarter. The gains and losses
recorded in earnings during 2006, through the date of the sale, were as follows:


<Table>
<Caption>
                                                                    2006
                                                 -----------------------------------------
                                                  FIRST    SECOND   THIRD    FOURTH
                                                 QUARTER  QUARTER  QUARTER  QUARTER  TOTAL
                                                 -------  -------  -------  -------  -----
                                                                IN MILLIONS

<S>                                              <C>      <C>      <C>      <C>      <C>

Long-term gas contracts........................   $(111)    $(34)    $(16)    $10    $(151)
Related futures, options, and swaps............     (45)      (8)     (12)     12      (53)
                                                  -----     ----     ----     ---    -----
Total..........................................   $(156)    $(42)    $(28)    $22    $(204)
                                                  =====     ====     ====     ===    =====

</Table>


     These derivatives incurred significant mark-to-market losses in the first
three quarters of the year, due to the decrease in natural gas prices during
that time. In the fourth quarter (through the date of the sale), natural gas
prices increased, resulting in a mark-to-market gain. The overall net losses,
shown before consideration of tax effects and minority interest, are included in
the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated
Statements of Income (Loss).

     The remaining futures and swaps held by the MCV Partnership did qualify for
cash flow hedge accounting. As such, we recorded our proportionate share of the
mark-to-market gains and losses from these derivatives in AOCI each quarter. As
of the date of the sale, we had accumulated a net gain of $30 million, net of
tax and minority interest, in AOCI representing our proportionate share of the
mark-to-market gains from these cash flow hedges. After the sale, this amount
was reclassified to and recognized in earnings as a reduction of the total loss
on the sale in our Consolidated Statements of Income (Loss).

     As a result of the sale, we no longer consolidate the MCV Partnership.
Accordingly, we no longer record the fair value of the long-term gas contracts
and related futures, options, and swaps on our Consolidated Balance Sheets and
are not required to record gains or losses related to changes in the fair value
of these contracts in earnings or AOCI. For additional details on the sale of
our interest in the MCV Partnership, see the "Other Electric Business
Uncertainties -- The MCV Partnership" section in this MD&A and Note 2, Asset
Sales and Impairment Charges.

     MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, and equity security
prices. We may use various contracts to manage these risks, including options,
swaps, and forward contracts. We enter into these risk management contracts
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.

     Our intention is to limit our exposure to risk from interest rate and
commodity price volatility.

     These contracts contain credit risk, which is the risk that counterparties,
primarily financial institutions and energy marketers, will fail to perform
their contractual obligations. We reduce this risk through established credit
policies, which include performing financial credit reviews of our
counterparties. We determine our counterparties' credit quality using a number
of factors, including credit ratings, disclosed financial condition, and
collateral requirements. If terms permit, we use standard agreements that allow
us to net positive and negative exposures associated with the same counterparty.
Based on these policies and our current exposures, we do not expect a material
adverse effect on our financial position or future earnings as a result of
counterparty nonperformance.


                                      CE-14

<PAGE>

                                                        Consumers Energy Company

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

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

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


<Table>
<Caption>
DECEMBER 31                                                         2006   2005
-----------                                                         ----   ----
                                                                    IN MILLIONS

<S>                                                                 <C>    <C>

Variable-rate financing -- before tax annual earnings exposure....  $  3   $  3
Fixed-rate financing -- potential REDUCTION in fair value(a)......   134    149
</Table>



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

     Commodity Price Risk:  Operating in the energy industry, we are exposed to
commodity price risk, which arises from fluctuations in the price of
electricity, natural gas, coal, and other commodities. Commodity prices are
influenced by a number of factors, including weather, changes in supply and
demand, and liquidity of commodity markets. In order to manage commodity price
risk, we enter into various non-trading derivative contracts, such as gas supply
call and put options. For additional details on these contracts, see Note 5,
Financial and Derivative Instruments.

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


<Table>
<Caption>
DECEMBER 31                                                          2006   2005
-----------                                                          ----   ----
                                                                     IN MILLIONS

<S>                                                                  <C>    <C>

Potential REDUCTION in fair value:
Gas supply option contracts........................................   $--    $ 1
Fixed fuel price contracts(a)......................................     1     --
Derivative contracts associated with the MCV Partnership:
  Long-term gas contracts(b).......................................    --     39
  Gas futures, options, and swaps(b)...............................    --     48
</Table>



--------------
     (a) We have entered into two contracts that, from January to September
         2007, will fix the prices we pay for gasoline and diesel fuel used in
         our fleet vehicles and equipment. These contracts are derivatives with
         an immaterial fair value at December 31, 2006.

     (b) The potential reduction in fair value for the MCV Partnership's long-
         term gas contracts and gas futures, options, and swaps decreased to $0
         as a result of the sale of our interest in the MCV Partnership. In
         conjunction with that sale, our interest in these contracts was also
         sold and, as a result, we no longer record the fair value of these
         contracts on our Consolidated Balance Sheets at December 31, 2006.

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

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


<Table>
<Caption>
DECEMBER 31                                                          2006   2005
-----------                                                          ----   ----
                                                                     IN MILLIONS

<S>                                                                  <C>    <C>

Potential REDUCTION in fair value of available-for-sale equity
  securities (SERP investments and investment in CMS Energy common
  stock)...........................................................   $6     $6
</Table>




                                      CE-15

<PAGE>

                                                        Consumers Energy Company

     We maintain trust funds, as required by the NRC, for the purpose of funding
certain costs of nuclear plant decommissioning. These funds are invested
primarily in equity securities, fixed-rate, fixed-income debt securities, and
cash and cash equivalents, and are recorded at fair value on our Consolidated
Balance Sheets. These investments are exposed to price fluctuations in equity
markets and changes in interest rates. Because the accounting for nuclear plant
decommissioning recognizes that costs are recovered through our electric rates,
fluctuations in equity prices or interest rates do not affect our consolidated
earnings or cash flows.

     For additional details on market risk and derivative activities, see Note
5, Financial and Derivative Instruments. For additional details on nuclear plant
decommissioning at Big Rock and Palisades, see the "Other Electric Business
Uncertainties -- Nuclear Matters" section included in this MD&A.

ACCOUNTING FOR PENSION AND OPEB

     Pension: We have external trust funds to provide retirement pension
benefits to our employees under a non-contributory, defined benefit Pension
Plan. On September 1, 2005, the defined benefit Pension Plan was closed to new
participants and we implemented the DCCP, which provides an employer
contribution of 5 percent of base pay to the existing Employees' Savings Plan.
An employee contribution is not required to receive the plan's employer cash
contribution. All employees hired on and after September 1, 2005 participate in
this plan as part of their retirement benefit program. Previous cash balance
pension plan participants also participate in the DCCP as of September 1, 2005.
Additional pay credits under the cash balance pension plan were discontinued as
of that date.

     401(k): We resumed the employer's match in CMS Energy Common Stock in our
401(k) Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled
in the company's 401(k) Savings Plan had their employer match increased from 50
percent to 60 percent on eligible contributions up to the first six percent of
an employee's wages.

     Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be
an investment option available for new investments in the 401(k) Savings Plan
and the employer's match will no longer be in CMS Energy Common Stock.
Participants will have the opportunity to reallocate investments in CMS Energy
Stock Fund to other plan investment alternatives. Beginning November 1, 2007 any
remaining shares in the CMS Energy Stock Fund will be sold and the sale proceeds
will be reallocated to other plan investment options. At February 20, 2007,
there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy
Stock Fund.

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

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

     - life expectancies,

     - present-value discount rates,

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

     - rate of compensation increases, and

     - anticipated health care costs.

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


                                      CE-16

<PAGE>

                                                        Consumers Energy Company

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


<Table>
<Caption>
EXPECTED COSTS                                      PENSION COST   OPEB COST   CONTRIBUTIONS
--------------                                      ------------   ---------   -------------
                                                                   IN MILLIONS

<S>                                                 <C>            <C>         <C>

2007..............................................      $103          $45           $153
2008..............................................        99           42             50
2009..............................................       106           40             50
</Table>


     Actual future pension cost and contributions will depend on future
investment performance, changes in future discount rates and various other
factors related to the populations participating in the Pension Plan.

     Lowering the expected long-term rate of return on the Pension Plan assets
by 0.25 percent (from 8.25 percent to 8.00 percent) would increase estimated
pension cost for 2007 by $2 million. Lowering the discount rate by 0.25 percent
(from 5.65 percent to 5.40 percent) would increase estimated pension cost for
2007 by $1 million.

     For additional details on postretirement benefits, see Note 6, Retirement
Benefits.

ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS

     SFAS No. 143, as clarified by FASB Interpretation No. 47, requires
companies to record the fair value of the cost to remove assets at the end of
their useful lives, if there is a legal obligation to remove them. We have legal
obligations to remove some of our assets, including our nuclear plants, at the
end of their useful lives. As required by SFAS No. 71, we accounted for the
implementation of this standard by recording regulatory assets and liabilities
instead of a cumulative effect of a change in accounting principle.

     The fair value of ARO liabilities has been calculated using an expected
present value technique. This technique reflects assumptions such as costs,
inflation, and profit margin that third parties would consider to assume the
settlement of the obligation. Fair value, to the extent possible, should include
a market risk premium for unforeseeable circumstances. No market risk premium
was included in our ARO fair value estimate since a reasonable estimate could
not be made.

     If a reasonable estimate of fair value cannot be made in the period in
which the ARO is incurred, such as for assets with indeterminate lives, the
liability is recognized when a reasonable estimate of fair value can be made.
Generally, gas transmission and electric and gas distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets or associated obligations related to potential future
abandonment. In addition, 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 include use of
decommissioning studies that largely utilize third-party cost estimates. For
additional details see Note 3, Contingencies, "Other Electric
Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase
Agreement," and Note 7, Asset Retirement Obligations.

ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS

     The MPSC and the FERC regulate the recovery of costs to decommission, or
remove from service, our Big Rock and Palisades nuclear plants. 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 assist us in
developing decommissioning cost estimates. We use various inflation rates for
labor, non-labor, and contaminated equipment disposal costs 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 spent
nuclear fuel from the sites, as required by the Nuclear Waste Policy Act of
1982.


                                      CE-17

<PAGE>

                                                        Consumers Energy Company

     We have 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. The decommissioning trust funds include equities and fixed-
income investments. Equities are converted to fixed-income investments during
decommissioning, and fixed-income investments are converted to cash as needed.
The costs of decommissioning these sites and the adequacy of the trust funds
could be affected by:

     - variances from expected trust earnings,

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

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

     Based on current projections, the current level of funds provided by the
trusts is not adequate to fund fully the decommissioning of Big Rock. 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. For
additional details, see Note 3, Contingencies, "Other Electric
Contingencies -- The Sale of Nuclear Assets and the Palisades Power Purchase
Agreement," "Nuclear Plant Decommissioning" and "Nuclear Matters," and Note 7,
Asset Retirement Obligations.

RELATED PARTY TRANSACTIONS

     We enter into a number of significant transactions with related parties.
These transactions include:

     - issuance of trust preferred securities with Consumers' affiliated
       companies,

     - purchase and sale of electricity from and to Enterprises,

     - purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,

     - payment of parent company overhead costs to CMS Energy, and

     - investment in CMS Energy Common Stock.

     Transactions involving CMS Energy and its affiliates generally are based on
regulated prices, market prices, or competitive bidding. Transactions involving
the power supply purchases from certain affiliates of Enterprises are based upon
avoided costs under PURPA and competitive bidding. The payment of parent company
overhead costs is based on the use of accepted industry allocation
methodologies.

     For additional details on related party transactions, see Note 1, Corporate
Structure and Accounting Policies, "Related Party Transactions."

CAPITAL RESOURCES AND LIQUIDITY

     Factors affecting our liquidity and capital requirements are:

     - results of operations,

     - capital expenditures,

     - energy commodity and transportation costs,

     - contractual obligations,

     - regulatory decisions,

     - debt maturities,

     - credit ratings,

     - working capital needs, and

     - collateral requirements.

     During the summer months, we purchase natural gas and store it for resale
primarily during the winter heating season. Although our prudent natural gas
costs are recoverable from our customers, the amount paid for natural gas stored
as inventory requires additional liquidity due to the lag in cost recovery. We
have credit agreements with our commodity suppliers containing terms that have
previously resulted in margin calls. While we currently have no

                                      CE-18

<PAGE>

                                                        Consumers Energy Company

outstanding margin calls associated with our natural gas purchases, they may be
required if agency ratings are lowered or if market conditions become
unfavorable relative to our obligations to those parties.

     Our current financial plan includes controlling operating expenses and
capital expenditures and evaluating market conditions for financing
opportunities, if needed.

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

     - our current level of cash and revolving credit facilities,

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

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

     In the second quarter of 2006, Moody's revised our credit rating outlook to
stable from negative. In the third quarter of 2006, Moody's upgraded our credit
ratings.

CASH POSITION, INVESTING, AND FINANCING

     Our operating, investing, and financing activities meet consolidated cash
needs. At December 31, 2006, $94 million consolidated cash was on hand, which
includes $57 million of restricted cash. We had no cash from entities
consolidated pursuant to FASB Interpretation No. 46(R) due to the sale of the
MCV Partnership and the FMLP.

SUMMARY OF CASH FLOWS:


<Table>
<Caption>
                                                              2006    2005    2004
                                                             -----   -----   -----
                                                                  IN MILLIONS

<S>                                                          <C>     <C>     <C>

Net cash provided by (used in):
  Operating activities.....................................  $ 474   $ 640   $ 595
  Investing activities.....................................   (673)   (662)   (517)
                                                             -----   -----   -----
Net cash provided by (used in) operating and investing
  activities...............................................   (199)    (22)     78
  Financing activities.....................................   (180)    267    (127)
                                                             -----   -----   -----
Net Increase (Decrease) in Cash and Cash Equivalents.......  $(379)  $ 245   $ (49)
                                                             =====   =====   =====

</Table>


OPERATING ACTIVITIES:

     2006: Net cash provided by operating activities was $474 million, a
decrease of $166 million versus 2005. This was the result of decreases in the
MCV Partnership gas supplier funds on deposit, accounts payable and income tax
payments to the parent. These changes were offset partially by a decrease in
accounts receivable and reduced inventory purchases. The decrease in the MCV
Partnership gas supplier funds on deposit was the result of refunds to suppliers
from decreased exposure due to declining gas prices in 2006. The decrease in
accounts payable was mainly due to payments for higher-priced gas that were
accrued at December 31, 2005. The decrease in accounts receivable was primarily
due to the collection of receivables in 2006 reflecting higher gas prices billed
during the latter part of 2005 and reduced billings in the latter part of 2006
due to milder weather.

     2005: Net cash provided by operating activities was $640 million, an
increase of $45 million versus 2004. Cash provided by operations resulted
primarily from a decrease in prepaid gas margin call costs, an increase in tax
liabilities related to a recent IRS ruling regarding the "simplified service
cost" method of tax accounting, the positive effect of rising gas prices on
accounts payable and the MCV Partnership gas supplier funds on deposit, and
other timing differences. These increases were offset partially by the negative
effect of rising gas prices on accounts receivable and inventories.

INVESTING ACTIVITIES:

     2006: Net cash used in investing activities was $673 million, an increase
of $11 million versus 2005. This increase was due to cash relinquished from the
sale of assets, an increase in capital expenditures and cost to retire property
and a decrease in net proceeds from investments. These changes were partially
offset by a decrease in

                                      CE-19

<PAGE>

                                                        Consumers Energy Company

restricted cash and restricted short-term investments. Cash restricted in 2005
was released in February 2006, which we used to extinguish long-term
debt -- related parties.

     2005: Net cash used in investing activities was $662 million, an increase
of $145 million versus 2004. This increase was primarily due to an increase in
restricted cash and restricted short-term investments of $159 million. The
increase in restricted cash and restricted short-term investments was due to a
deposit made with a trustee for extinguishing the current portion of long-term
debt -- related parties.

FINANCING ACTIVITIES:

     2006: Net cash used in financing activities was $180 million, an increase
of $447 million versus 2005. This increase was due to a decrease of $500 million
in contributions from the parent and an increase in net retirement of long-term
debt. These changes were partially offset by a decrease in common stock
dividends payments of $130 million.

     2005: Net cash provided by financing activities was $267 million, an
increase of $394 million versus 2004. This increase was due to an increase of
$450 million in contributions from the parent and an increase in cash due to
lower payments on borrowings of $16 million, offset by an increase in common
stock dividends payments of $87 million.

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

OBLIGATIONS AND COMMITMENTS

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


<Table>
<Caption>
                                                                PAYMENTS DUE
                                          -------------------------------------------------------
CONTRACTUAL OBLIGATIONS                            LESS THAN     ONE TO     THREE TO    MORE THAN
AT DECEMBER 31, 2006                       TOTAL    ONE YEAR  THREE YEARS  FIVE YEARS  FIVE YEARS
-----------------------                    -----   ---------  -----------  ----------  ----------
                                                                IN MILLIONS

<S>                                       <C>      <C>        <C>          <C>         <C>

Long-term debt(a).......................  $ 4,158    $   31      $  825      $  380      $ 2,922
Interest payments on long-term debt(b)..    1,904       209         375         314        1,006
Capital leases(c).......................       55        13          14          10           18
Interest payments on capital leases(d)..       26        --           9           6           11
Operating leases(e).....................      159        23          41          34           61
Purchase obligations(f).................   16,334     2,118       2,109       1,661       10,446
Purchase obligations -- related
  parties(f)............................    1,506        74         148         148        1,136
                                          -------    ------      ------      ------      -------
  Total contractual obligations.........  $24,142    $2,468      $3,521      $2,553      $15,600
                                          =======    ======      ======      ======      =======

</Table>



--------------
(a)    Principal amounts due on outstanding debt obligations, current and long-
       term, at December 31, 2006. For additional details on long-term debt, see
       Note 4, Financings and Capitalization.

(b)    Currently scheduled interest payments on both variable and fixed rate
       long-term debt, current and long-term. Variable are based on contractual
       rates in effect at December 31, 2006.

(c)    Minimum lease payments under our capital leases, comprised mainly of
       leased service vehicles, leased office furniture, and certain power
       purchase agreements.

(d)    Imputed interest in the capital leases.

(e)    Minimum noncancelable lease payments under our leases of railroad cars,
       certain vehicles, and miscellaneous office buildings and equipment, which
       are accounted for as operating leases.

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


                                      CE-20

<PAGE>

                                                        Consumers Energy Company

     - natural gas and associated transportation,

     - electricity, and

     - coal and associated transportation.

     Our purchase obligations include long-term power purchase agreements with
various generating plants, which require us to make monthly capacity payments
based on the plants' availability or deliverability. These payments will
approximate $46 million per month during 2007. If a plant is not available to
deliver electricity, we are not obligated to make these payments to the plant
for that period of time. For additional details on power supply costs, see
"Electric Utility Results of Operations" within this MD&A and Note 3,
Contingencies, "Electric Rate Matters -- Power Supply Costs."

     REVOLVING CREDIT FACILITIES: At December 31, 2006, we had $742 million
available in secured revolving credit facilities. The facilities are available
for general corporate purposes, working capital, and letters of credit. For
additional details on revolving credit facilities, see Note 4, Financings and
Capitalization.

     OFF-BALANCE SHEET ARRANGEMENTS: We enter into various arrangements in the
normal course of business to facilitate commercial transactions with third
parties. These arrangements include indemnifications, letters of credit and
surety bonds.

     We enter into agreements containing indemnifications standard in the
industry and indemnifications specific to a transaction, such as the sale of a
subsidiary. Indemnifications are usually agreements to reimburse other companies
if those companies incur losses due to third-party claims or breach of contract
terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a
third-party. Letters of credit substitute the bank's credit for ours and reduce
credit risk for the third-party beneficiary. We monitor these obligations and
believe it is unlikely that we would be required to perform or otherwise incur
any material losses associated with these guarantees. For additional details on
these arrangements, see Note 3, Contingencies, "Other Contingencies -- FASB
Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others."

     SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. The
highly liquid and efficient market for securitized financial assets provides a
lower cost source of funding compared to unsecured debt. For additional details,
see Note 4, Financings and Capitalization.

     DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4,
Financings and Capitalization.

     CAPITAL EXPENDITURES: We estimate that we will make the following capital
expenditures, including new lease commitments, by expenditure type and by
business segments during 2007 through 2009. We prepare these estimates for
planning purposes. Periodically, we review these estimates and may revise them
due to a number of factors including environmental regulations, business
opportunities, market volatility, economic trends, and the ability to access
capital.


<Table>
<Caption>
YEARS ENDING DECEMBER 31                                       2007  2008  2009
------------------------                                       ----  ----  ----
                                                                  IN MILLIONS

<S>                                                            <C>   <C>   <C>

Construction.................................................  $429  $351  $361
Clean Air(a).................................................    90    29    60
Cost of Removal..............................................    49    50    43
New Customers................................................   108   112   109
Other(b).....................................................   106   161   156
                                                               ----  ----  ----
                                                               $782  $703  $729
                                                               ====  ====  ====
Electric utility operations(a)(b)............................  $618  $487  $455
Gas utility operations(b)....................................   164   216   274
                                                               ----  ----  ----
                                                               $782  $703  $729
                                                               ====  ====  ====

</Table>




                                      CE-21

<PAGE>

                                                        Consumers Energy Company

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

(b)    These amounts include estimates for capital expenditures related to
       information technology projects, facility improvements, and vehicle
       leasing.

OUTLOOK

CORPORATE OUTLOOK

     In November 2006, we announced a reorganization of the company to improve
operating efficiency, reliability, and customer service. The new organization
will streamline operations and will allow us to serve our customers better and
more efficiently.

ELECTRIC BUSINESS OUTLOOK

     GROWTH: Temperatures in the summer of 2006 were higher than historical
averages yet lower than in the summer of 2005. Industrial activity declined
during 2006 compared with 2005. These factors resulted in a decline of one
percent in annual electric deliveries, excluding transactions with other
wholesale market participants and other electric utilities. In 2007, we project
electric deliveries to grow less than one-half of one percent compared to the
levels experienced in 2006. This short-term outlook for 2007 assumes a small
decline in industrial economic activity and normal weather conditions throughout
the year.

     Over the next five years, we expect electric deliveries to grow at an
average rate of less than 1.5 percent a year. However, this is dependent on a
modestly growing customer base and a stabilizing Michigan economy after 2007.
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 the following:

     - fluctuations in weather conditions and

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

     ELECTRIC RESERVE MARGIN: We are planning for a reserve margin of
approximately 11 percent for summer 2007, or supply resources equal to 111
percent of projected firm summer peak load. Of the 2007 supply resources target
of 111 percent, we expect 96 percent to come from our electric generating plants
and long-term power purchase contracts, and 15 percent to come from other
contractual arrangements. We have purchased capacity and energy contracts
covering partially the estimated reserve margin requirements for 2007 through
2010. As a result, we recognized an asset of $62 million for unexpired capacity
and energy contracts at December 31, 2006. Upon the completion of the sale of
the Palisades plant, the 15-year power purchase agreement with Entergy for 100
percent of the plant's current electric output will offset the reduction in the
owned capacity represented by the Palisades plant.

     The MCV PPA is unaffected by the sale of our interest in the MCV
Partnership. After September 15, 2007, we expect to exercise the regulatory out
provision in the MCV PPA. If we are successful, the MCV Partnership has the
right to terminate the MCV PPA, which could affect our reserve margin status.
The MCV PPA represents 13 percent of our 2007 supply resources target.

     ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission
service to us, increased substantially the transmission rates it charged us in
2006. The revenue collected by METC under those rates is subject to refund
pending a FERC ruling. In January 2007, a settlement agreement among the parties
was filed with the FERC resolving all issues associated with the rates METC
charged us in 2006. This settlement, if approved by the FERC, will result in a
refund of 2006 transmission charges of $18 million and a corresponding reduction
of our power supply costs.

     In August 2006, the MPSC approved recovery of the increased METC electric
transmission costs included in our 2006 PSCR plan. Due to the delay in recovery,
we were unable to collect these increased costs in a timely manner

                                      CE-22

<PAGE>

                                                        Consumers Energy Company

and our cash flows from electric utility operations were affected negatively.
For additional details, see Note 3, Contingencies, "Electric Rate
Matters -- Power Supply Costs."

     CUSTOMER REVENUE OUTLOOK: Our electric utility customer base includes a mix
of residential, commercial, and diversified industrial customers. In 2006,
Michigan's automotive industry experienced negative developments resulting in
manufacturing facility closures and restructurings. Our electric utility
operations are not dependent upon a single customer, or even a few customers,
and customers in the automotive sector constitute five percent of our total 2006
electric revenue. In addition, returning former ROA industrial customers benefit
our electric utility revenue. However, we cannot predict the impact of current
or possible future restructuring plans or possible future actions by our
industrial customers.

     21ST CENTURY ENERGY PLAN: In January 2006, the MPSC Staff issued a report
on future electric capacity in the state of Michigan. The report indicated that
existing generation resources are adequate in the short term, but could be
insufficient to maintain reliability standards by 2009. The MPSC Staff
recommended a review process for proposed new power plants. In January 2007, the
chairman of the MPSC expanded on the capacity need work conducted by the MPSC
Staff and proposed three major policy initiatives to the governor of Michigan.
The initiatives involve the use of more renewable energy resources by all load-
serving entities such as Consumers, the creation of an energy efficiency
program, and a procedure for reviewing proposals to construct new generation
facilities. The January 2007 proposal indicated that Michigan needs new baseload
generation by 2015 and recommends regulatory measures to make it easier to
predict customer demand and revenues. The proposed initiatives will require
changes to current legislation. We will continue to participate as the MPSC,
legislature, and other stakeholders addresses future electric capacity needs.

ELECTRIC BUSINESS UNCERTAINTIES

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

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

     Clean Air Act: Compliance with the federal Clean Air Act and resulting
regulations continues to be a significant focus for us. The Nitrogen Oxide State
Implementation Plan requires significant reductions in nitrogen oxide emissions.
To comply with the regulations, we expect to incur capital expenditures totaling
$835 million. These expenditures include installing selective catalytic
reduction control technology on four of our coal-fired electric generating
units. The key assumptions 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

     - an AFUDC capitalization rate.

     Our current capital cost estimates include an escalation rate of 2.6
percent and an AFUDC capitalization rate of 7.8 percent. As of December 2006, we
have incurred $688 million in capital expenditures to comply with the federal
Clean Air Act and resulting regulations and anticipate that the remaining $147
million of capital expenditures will be made in 2007 through 2011.

     In addition to modifying coal-fired electric generating plants, our
compliance plan includes the use of nitrogen oxide emission allowances until all
of the control equipment is operational in 2011. The nitrogen oxide emission
allowance annual expense is projected to be $3 million per year, which we expect
to recover from our customers through the PSCR process. The projected annual
expense is based on market price forecasts and forecasts of regulatory
provisions, known as progressive flow control, that restrict the usage in any
given year of allowances banked from previous years. The allowances and their
cost are accounted for as inventory. The allowance inventory is expensed at the
rolling average cost as the coal-fired electric generating plants emit nitrogen
oxide.


                                      CE-23

<PAGE>

                                                        Consumers Energy Company

     Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air
Interstate Rule that requires additional coal-fired electric generating plant
emission controls for nitrogen oxides and sulfur dioxide. We plan to meet this
rule by year-round operation of our selective catalytic reduction control
technology units and installation of flue gas desulfurization scrubbers at an
estimated total cost of $955 million, to be incurred by 2014. The rule may also
require us to purchase additional nitrogen oxide allowances beginning in 2009.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.4 percent. We will need to acquire additional
sulfur dioxide emission allowances for an average annual cost of $21 million per
year for the years 2011 through 2014.

     Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air
Mercury Rule, which requires initial reductions of mercury emissions from coal-
fired electric generating plants by 2010 and further reductions by 2018. Based
on current technology, we anticipate our capital costs for mercury emissions
reductions required by Phase I of the Clean Air Mercury Rule to be less than $50
million and expect these reductions to be implemented by,  2010. Phase II
requirements of the Clean Air Mercury Rule are not yet known and a cost estimate
has not been determined.

     In April 2006, Michigan's governor announced a plan that would result in
mercury emissions reductions of 90 percent by 2015. We are working with the MDEQ
on the details of these rules. We will develop a cost estimate when the details
of these rules are determined.

     Greenhouse gases: Several legislative proposals have been introduced in the
United States Congress that would require reductions in emissions of greenhouse
gases, including carbon dioxide. We cannot predict whether any of these
proposals will be enacted, or the specific requirements of any of these
proposals and their effect on our future operations and financial results. In
addition, the U.S. Supreme Court has agreed to hear a case claiming that the EPA
is required by the Clean Air Act to consider regulating carbon dioxide emissions
from automobiles. The EPA asserts that it lacks authority to regulate carbon
dioxide emissions. If the Supreme Court finds that the EPA has authority to
regulate carbon dioxide emissions in this case, it could result in new federal
carbon dioxide regulations for other industries, including the utility industry.

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

     Water: In March 2004, the EPA issued rules that govern electric generating
plant cooling water intake systems. The rules require significant reduction in
fish killed by operating equipment. EPA compliance options in the rule were
challenged in court. In January 2007, the court rejected many of the compliance
options favored by industry and remanded the bulk of the rule back to the EPA
for reconsideration. The court's ruling is expected to increase significantly
the cost of complying with this rule. However, the cost to comply will not be
known until the EPA's reconsideration is complete. At this time, the EPA has not
established a schedule to address the court decision.

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

     COMPETITION AND REGULATORY RESTRUCTURING: The Customer Choice Act allows
all of our electric customers to buy electric generation service from us or from
an alternative electric supplier. At December 31, 2006, alternative electric
suppliers were providing 300 MW of generation service to ROA customers. This is
3 percent of our total distribution load and represents a decrease of 46 percent
of ROA load compared to the end of December 2005. In prior orders, the MPSC
approved recovery of Stranded Costs incurred from 2002 through 2003 through a
surcharge assessed to ROA customers. It is difficult to predict future ROA
customer trends and their impact on the timely recovery of our Stranded Costs.

     ELECTRIC RATE CASE: We expect to file an electric rate case in March 2007.


                                      CE-24

<PAGE>

                                                        Consumers Energy Company

     For additional details and material changes relating to the restructuring
of the electric utility industry and electric rate matters, see Note 3,
Contingencies, "Electric Rate Matters."

OTHER ELECTRIC BUSINESS UNCERTAINTIES

     THE MCV PARTNERSHIP: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990.

     Sale of our Interest in the MCV Partnership and the FMLP: In November 2006,
we sold 100 percent of our ownership interest in MCV GP II (the successor of CMS
Midland, Inc.) and 100 percent of our ownership interest in the stock of CMS
Midland Holdings Company to an affiliate of GSO Capital Partners and Rockland
Capital Energy Investments for $60.5 million. These Consumers subsidiaries held
our interests in the MCV Partnership and the FMLP. The sales agreement calls for
the purchaser, an affiliate of GSO Capital Partners and Rockland Capital Energy
Investments, to pay $85 million, subject to certain conditions and reimbursement
rights, if Dow terminates an agreement under which the MCV Partnership provides
it power and steam. The purchaser secured their reimbursement obligation with an
irrevocable letter of credit of up to $85 million. The MCV PPA and the
associated customer rates are unaffected by the sale. The transaction resulted
in a net after-tax loss of $41 million, which includes the reversal of $30
million, into earnings, of certain cumulative amounts of the MCV Partnership
derivative fair value changes that we accounted for in AOCI. For additional
details on the sale of our interests in the MCV Partnership and the FMLP, see
Note 2, Asset Sales and Impairment Charges and Note 5, Financial and Derivative
Instruments, "Derivative Contracts Associated with the MCV Partnership."

     Underrecoveries related to the MCV PPA: The cost that we incur under the
MCV PPA exceeds the recovery amount allowed by the MPSC. As a result, we
incurred cash underrecoveries of capacity and fixed energy payments of $57
million in 2006 and we estimate cash underrecoveries of $39 million in 2007.
However, we use the direct savings from the RCP, after allocating a portion to
customers, to offset a portion of our capacity and fixed energy underrecoveries
expense. After September 15, 2007, we expect to claim relief under the
regulatory out provision in the MCV PPA, thereby limiting our capacity and fixed
energy payments to the MCV Partnership to the amounts that we collect from our
customers. This action would eliminate our underrecoveries of capacity and fixed
energy payments.

     The MCV Partnership has notified us that it takes issue with our intended
exercise of the regulatory out provision after September 15, 2007. We believe
that the provision is valid and fully effective, but cannot assure that it will
prevail in the event of a dispute. If we are successful in exercising the
regulatory out provision, the MCV Partnership has the right to terminate the MCV
PPA. If the MCV Partnership terminates the MCV PPA, we would seek to replace the
lost capacity to maintain an adequate electric reserve margin. This could
involve entering into a new PPA and (or) entering into electric capacity
contracts on the open market. We cannot predict our ability to enter into such
contracts at a reasonable price. We are also unable to predict regulatory
approval of the terms and conditions of such contracts, or that the MPSC would
allow full recovery of our incurred costs.

     For additional details on the MCV Partnership, see Note 3, Contingencies,
"Other Electric Contingencies -- The MCV PPA."

     NUCLEAR MATTERS:

     Sale of Nuclear Assets: In July 2006, we reached an agreement to sell
Palisades to Entergy for $380 million and pay Entergy $30 million to assume
ownership and responsibility for the Big Rock Independent Spent Fuel Storage
Installation (ISFSI). Under the agreement, if the transaction does not close by
March 1, 2007, there is a reduction in the purchase price of approximately
$80,000 per day, with additional costs if the transaction does not close by June
1, 2007. Based on the MPSC's published schedule for the contested case
proceedings regarding this transaction, we target to close on the transaction in
the second quarter of 2007. We estimate that the Palisades sale will result in a
$31 million premium above the Palisades asset values at the anticipated closing
date after accounting for estimated sales-related costs. We expect that this
premium will benefit our customers.

     Entergy will assume responsibility for the future decommissioning of the
plant and for storage and disposal of spent nuclear fuel located at the
Palisades and the Big Rock ISFSI sites. At the anticipated date of close, we
estimate decommissioning trust assets to be $605 million. We will retain $205
million of these funds at the time of close and will be entitled to receive a
return of an additional $147 million, pending either a favorable federal tax
ruling

                                      CE-25

<PAGE>

                                                        Consumers Energy Company

regarding the release of the funds or, if no such ruling is issued, after
decommissioning of the Palisades site is complete. These estimates fluctuate
based on existing market conditions. The disposition of the retained and
receivable nuclear decommissioning funds is subject to regulatory approval. We
expect to use the proceeds to benefit our customers. We plan to use the cash
that we retain from the sale to reduce utility debt.

     As part of the transaction, Entergy will sell us 100 percent of the plant's
output up to its current capacity of 798 MW under a 15-year power purchase
agreement. The sale is subject to various regulatory approvals, including the
MPSC's approval of the power purchase agreement and the NRC's approval of the
transfer of the operating license to Entergy and other related matters. In
February 2007, the FERC issued an order approving the sale of power to us under
the power purchase agreement and granted other related approvals, with what we
believe are minor exceptions and conditions that we believe can be adequately
accepted. In October 2006, the Federal Trade Commission issued a notice that
neither it nor the DOJ's Antitrust Division plan to take enforcement action on
the sale. The final purchase price will be subject to various closing
adjustments such as working capital and capital expenditure adjustments,
adjustments for nuclear fuel usage and inventory, and the date of closing. We
cannot predict with certainty whether or when satisfaction of the closing
conditions will occur or whether or when completion of the transaction will
occur.

     We have notified the NMC that we plan to terminate the NMC's operation of
Palisades, if the sale is completed, which would require us to pay the NMC an
estimated $12 million. Due to the regulatory approvals pending, we have not
recorded this contingent obligation.

     For additional details on sale of Palisades and the Big Rock ISFSI, see
Note 3, Contingencies, "Other Electric Contingencies -- The Sale of Nuclear
Assets and the Palisades Power Purchase Agreement."

     Big Rock: Dismantlement and decommissioning of the Big Rock Plant was
completed in August 2006. In November 2006, we requested the NRC to release
approximately 435 acres from the terms of our operating license. In January
2007, the NRC approved our request to release the 435 acres for unrestricted
public use. An area of approximately 107 acres including the Big Rock ISFSI,
where eight casks loaded with spent fuel and other high-level radioactive
material are stored, is part of the sale of nuclear assets as previously
described.

     Palisades: The amount of spent nuclear fuel at Palisades exceeds the
plant's temporary onsite wet storage pool capacity. We are using dry casks for
temporary onsite dry storage to supplement the wet storage pool capacity.

     Palisades' original license from the NRC was scheduled to expire in 2011.
In March 2005, the NMC, which operates the Palisades plant, applied for a 20-
year license renewal for the plant on behalf of Consumers. In January 2007, the
NRC renewed the Palisades operating license for 20 years, extending it to 2031.

     For additional details on nuclear plant decommissioning at Big Rock and
Palisades, see Note 3, Contingencies, "Other Electric Contingencies -- Nuclear
Plant Decommissioning."

GAS BUSINESS OUTLOOK

     GROWTH: In 2007, we project gas deliveries will decline slightly, on a
weather-adjusted basis, from 2006 levels due to continuing conservation and
overall economic conditions in the state of Michigan. Over the next five years,
we expect gas deliveries to decline by less than one-half of one percent
annually. Actual gas deliveries in future periods may be affected by:

     - fluctuations in weather conditions,

     - use by independent power producers,

     - competition in sales and delivery,

     - changes in gas commodity prices,

     - Michigan economic conditions,

     - the price of competing energy sources or fuels,

     - gas consumption per customer, and

     - improvements in gas appliance efficiency.


                                      CE-26

<PAGE>

                                                        Consumers Energy Company

GAS BUSINESS UNCERTAINTIES

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

     GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. For additional details, see Note 3, Contingencies, "Gas
Contingencies -- Gas Environmental Matters."

     GAS COST RECOVERY: The GCR process is designed to allow us to recover all
of our purchased natural gas costs if incurred under reasonable and prudent
policies and practices. The MPSC reviews these costs, policies, and practices
for prudency in annual plan and reconciliation proceedings. For additional
details on gas cost recovery, see Note 3, Contingencies, "Gas Rate
Matters -- Gas Cost Recovery."

     GAS DEPRECIATION: We are required to file our next gas depreciation case
with the MPSC within 90 days after the MPSC issuance of a final order in the
pending case related to ARO accounting. We cannot predict when the MPSC will
issue a final order in the ARO accounting case.

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

     2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC
seeking an 11.25 percent authorized return on equity along with an $88 million
annual increase in our gas delivery and transportation rates. We have proposed
the use of a Revenue Decoupling and Conservation Incentive Mechanism for
residential and general service rate classes to help assure a reasonable
opportunity to recover costs that do not fluctuate with volumetric changes.

OTHER OUTLOOK

     RULES REGARDING BILLING PRACTICES: In December 2006, the MPSC issued
proposed rule changes to residential customer billing standards and practices.
These changes, if adopted, would provide additional protection to low-income
customers during the winter heating season that will be defined as November 1
through March 31, extend the time between billing date and due date from 17 days
to 22 days, and eliminate estimated metering readings unless actual readings are
not feasible. We are presently evaluating the impacts of these proposed rules
and are working with other Michigan utilities in providing comments to the MPSC
regarding the proposed rule changes.

     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. For additional details regarding
this investigation and litigation, see Note 3, Contingencies.

     PENSION REFORM: In August 2006, the President signed into law the Pension
Protection Act of 2006. The bill reforms the funding rules for employer-provided
pension plans, effective for plan years beginning after 2007. As a result of
this bill, we expect to reduce our contributions to the Pension Plan over the
next 10 years by a present value amount of $53 million.

IMPLEMENTATION OF NEW ACCOUNTING STANDARDS

     SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R)
requires companies to use the fair value of employee stock options and similar
awards at the grant date to value the awards. SFAS No. 123(R) was effective for
us on January 1, 2006. We elected to adopt the modified prospective method
recognition provisions of this Statement instead of retrospective restatement.
We adopted the fair value method of accounting for share-based awards effective
December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on
our consolidated results of operations when it became effective. We applied the
additional guidance provided by SAB No. 107 upon implementation of SFAS No.
123(R).

     STAFF ACCOUNTING BULLETING NO. 108, CONSIDERING THE EFFECTS OF PRIOR YEAR
MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL
STATEMENTS: SAB No. 108 was adopted on December 31, 2006. The

                                      CE-27

<PAGE>

                                                        Consumers Energy Company

standard clarifies how we should assess the materiality of prior period
financial statement errors in the current period. Prior to the adoption of this
standard, we used the "iron-curtain" method to quantify the effects of prior
period financial statement errors. The iron-curtain method focuses on the
effects of correcting the period-end balance sheet with less emphasis on the
effects the correction would have on our consolidated income statement. This
standard requires quantification of financial statement errors based on their
effect on each of our consolidated financial statements. The adoption of this
standard did not have an effect on our financial position or results of
operations.

     SFAS No. 158, EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT PENSION AND OTHER
POSTRETIREMENT PLANS -- AN AMENDMENT OF FASB STATEMENTS NO. 87, 88, 106, AND
132(R): In September 2006, the FASB issued SFAS No. 158. This standard requires
us to recognize the funded status of our defined benefit postretirement plans on
our Consolidated Balance Sheets at December 31, 2006. Upon implementation of
this standard, we recorded an additional postretirement benefit liability of
$643 million, a regulatory asset of $680 million and a reduction of $6 million
to AOCI, after tax. This standard also requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008.
We do not believe that implementation of this provision of the standard will
have a material effect on our consolidated financial statements. We expect to
adopt the measurement date provisions of SFAS No. 158 in 2008.

NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE

     FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006, the FASB
issued FIN 48, effective for us January 2007. This interpretation provides a
two-step approach for the recognition and measurement of uncertain tax positions
taken, or expected to be taken, by a company on its income tax returns. The
first step is to evaluate the tax position to determine if, based on
management's best judgment, it is greater than 50 percent likely that the taxing
authority will sustain the tax position. The second step is to measure the
appropriate amount of the benefit to recognize. This is done by estimating the
potential outcomes and recognizing the greatest amount that has a cumulative
probability of at least 50 percent. FIN 48 requires interest and penalties, if
applicable, to be accrued on differences between tax positions recognized in our
consolidated financial statements and the amount claimed, or expected to be
claimed, on the tax return. Our policy is to include interest and penalties
accrued, if any, on uncertain tax positions as part of the related tax liability
on our consolidated balance sheet and as part of the income tax expense in our
consolidated income statement. The impact from adopting FIN 48 should be
recorded as a cumulative adjustment to the beginning retained earnings balance
and a corresponding adjustment to a current or non-current tax liability.
Although we have not yet determined the full effect of FIN 48, we do not expect
to record a material adjustment to the January 1, 2007 retained earnings
balance.

     SFAS No. 157, FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued
SFAS No. 157, effective for us January 1, 2008. The standard provides a revised
definition of "fair value" and gives guidance on how to measure the fair value
of assets and liabilities. Under the standard, fair value is defined as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly exchange between market participants. The standard does not expand
the use of fair value in any new circumstances. However, additional disclosures
will be required on the impact and reliability of fair value measurements
reflected in our consolidated financial statements. The standard will also
eliminate the existing prohibition of recognizing "day one" gains or losses on
derivative instruments, and will generally require such gains and losses to be
recognized through earnings. We are presently evaluating the impacts, if any, of
implementing SFAS No. 157. We currently do not hold any derivatives that would
involve day one gains or losses.

     SFAS NO. 159, THE FAIR VALUE OPTION FOR FINANCIAL ASSETS AND FINANCIAL
LIABILITIES, INCLUDING AN AMENDMENT TO FASB STATEMENT NO. 115: In February 2007,
the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard
will give us the option to select certain financial instruments and other items,
which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we
would recognize unrealized gains and losses associated with changes in the fair
value of the item over time. The statement will also require disclosures for
items for which the fair value option has been elected. We are presently
evaluating whether we will choose toe elect the fair value option for any
financial instruments of other items.


                                      CE-28

<PAGE>

                                                        Consumers Energy Company

                            CONSUMERS ENERGY COMPANY

                    CONSOLIDATED STATEMENTS OF INCOME (LOSS)


<Table>
<Caption>
                                                              YEARS ENDED DECEMBER
                                                                       31
                                                             ----------------------
                                                              2006    2005    2004
                                                              ----    ----    ----
                                                                   IN MILLIONS

<S>                                                          <C>     <C>     <C>

OPERATING REVENUE..........................................  $5,721  $5,232  $4,711
EARNINGS FROM EQUITY METHOD INVESTEES......................       1       1       1
OPERATING EXPENSES
  Fuel for electric generation.............................     672     605     701
  Fuel costs mark-to-market at the MCV Partnership.........     204    (200)     19
  Purchased and interchange power..........................     647     347     224
  Purchased power -- related parties.......................      74      68      67
  Cost of gas sold.........................................   1,770   1,844   1,468
  Cost of gas sold -- related parties......................      --      --       1
  Other operating expenses.................................     895     841     717
  Maintenance..............................................     284     218     227
  Depreciation, depletion, and amortization................     527     484     391
  General taxes............................................     150     214     223
  Asset impairment charges.................................     218   1,184      --
                                                             ------  ------  ------
                                                              5,441   5,605   4,038
                                                             ------  ------  ------
OPERATING INCOME (LOSS)....................................     281    (372)    674
OTHER INCOME (DEDUCTIONS)
  Accretion expense........................................      (1)     (2)     (3)
  Interest and dividends...................................      62      45      11
  Gain on asset sales, net.................................      79      --       1
  Regulatory return on capital expenditures................      26       4     113
  Other income.............................................      20      20      16
  Other expense............................................     (11)    (13)     (7)
                                                             ------  ------  ------
                                                                175      54     131
                                                             ------  ------  ------
INTEREST CHARGES
  Interest on long-term debt...............................     281     289     284
  Interest on long-term debt -- related parties............       1      15      44
  Other interest...........................................      17       6      13
  Capitalized interest.....................................     (10)    (38)     25
                                                             ------  ------  ------
                                                                289     272     366
                                                             ------  ------  ------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS
  (OBLIGATIONS), NET.......................................     167    (590)    439
MINORITY INTERESTS (OBLIGATIONS), NET......................    (110)   (447)      7
                                                             ------  ------  ------
INCOME (LOSS) BEFORE INCOME TAXES..........................     277    (143)    432
INCOME TAX (BENEFIT) EXPENSE...............................      91     (47)    152
                                                             ------  ------  ------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN
  ACCOUNTING PRINCIPLE.....................................     186     (96)    280
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR RETIREMENT
  BENEFITS, NET OF $- TAX BENEFIT IN 2004..................      --      --      (1)
                                                             ------  ------  ------
NET INCOME (LOSS)..........................................     186     (96)    279
PREFERRED STOCK DIVIDENDS..................................       2       2       2
                                                             ------  ------  ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER..........  $  184  $  (98) $  277
                                                             ======  ======  ======

</Table>



        The accompanying notes are an integral part of these statements.


                                      CE-29

<PAGE>

                                                        Consumers Energy Company

                            CONSUMERS ENERGY COMPANY

                      CONSOLIDATED STATEMENTS OF CASH FLOWS


<Table>
<Caption>
                                                            YEARS ENDED DECEMBER 31
                                                            -----------------------
                                                             2006    2005     2004
                                                             ----    ----     ----
                                                                  IN MILLIONS

<S>                                                         <C>    <C>      <C>

CASH FLOWS FROM OPERATING ACTIVITIES
  Net income (loss).......................................  $ 186  $   (96) $   279
     Adjustments to reconcile net income (loss) to net
       cash provided by operating activities
       Depreciation, depletion, and amortization (includes
          nuclear decommissioning of $6 per year).........    527      484      391
       Deferred income taxes and investment tax credit....   (113)    (225)     137
       Regulatory return on capital expenditures..........    (26)      (4)    (113)
       Minority interests (obligations), net..............   (110)    (447)       7
       Fuel costs mark-to-market at the MCV Partnership...    204     (200)      19
       Asset impairment charges...........................    218    1,184       --
       Capital lease and other amortization...............     37       34       29
       Bad debt expense...................................     30       24       20
       Gain on sale of assets.............................    (79)      --       (1)
       Cumulative effect of changes in accounting.........     --       --        1
       Earnings from equity method investees..............     (1)      (1)      (1)
       Changes in assets and liabilities:
          Increase in accounts receivable, notes
            receivable and accrued revenue................    (67)    (294)    (112)
          Increase in inventories.........................   (114)    (235)    (126)
          Increase (decrease) in accounts payable.........    (32)     154       67
          Increase (decrease) in accrued expenses.........     35      (13)      31
          Increase (decrease) in accrued taxes............   (101)     146       32
          Increase (decrease) in the MCV Partnership gas
            supplier funds on deposit.....................   (147)     173       15
          Increase in other current and non-current
            assets........................................    (63)     (19)     (62)
          Increase (decrease) in other current and non-
            current liabilities...........................     90      (25)     (18)
                                                            -----  -------  -------
       Net cash provided by operating activities..........    474      640      595
                                                            -----  -------  -------
CASH FLOWS FROM INVESTING ACTIVITIES
  Capital expenditures (excludes assets placed under
     capital lease).......................................   (646)    (572)    (508)
  Cost to retire property.................................    (78)     (27)     (28)
  Restricted cash and restricted short-term investments...    126     (162)      (3)
  Investments in Electric Restructuring Implementation
     Plan.................................................     --       --       (7)
  Investments in nuclear decommissioning trust funds......    (21)      (6)      (6)
  Proceeds from nuclear decommissioning trust funds.......     22       39       36
  Proceeds from short-term investments....................     --      145    1,048
  Purchase of short-term investments......................     --     (141)  (1,052)
  Maturity of the MCV Partnership restricted investment
     securities held-to-maturity..........................    130      318      675
  Purchase of the MCV Partnership restricted investment
     securities held-to-maturity..........................   (131)    (270)    (674)
  Cash proceeds from sale of assets.......................     69        2        2
  Cash relinquished from sale of assets...................   (148)      --       --
  Other investing.........................................      4       12       --
                                                            -----  -------  -------
       Net cash used in investing activities..............   (673)    (662)    (517)
                                                            -----  -------  -------
</Table>

                                      CE-30

<PAGE>

                                                        Consumers Energy Company

<Table>
<Caption>
                                                            YEARS ENDED DECEMBER 31
                                                            -----------------------
                                                             2006    2005     2004
                                                             ----    ----     ----
                                                                  IN MILLIONS

<S>                                                         <C>    <C>      <C>
CASH FLOWS FROM FINANCING ACTIVITIES
  Proceeds from issuance of long term debt................     --      910    1,055
  Retirement of long-term debt............................   (217)  (1,028)    (963)
  Payment of common stock dividends.......................   (147)    (277)    (190)
  Payment of capital and finance lease obligations........    (26)     (29)     (44)
  Stockholder's contribution, net.........................    200      700      250
  Payment of preferred stock dividends....................     (2)      (2)      (2)
  Increase (decrease) in notes payable....................     15       27     (200)
  Debt issuance and financing costs.......................     (3)     (34)     (33)
                                                            -----  -------  -------
       Net cash provided by (used in) financing
          activities......................................   (180)     267     (127)
                                                            -----  -------  -------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS......   (379)     245      (49)
CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB
  INTERPRETATION NO. 46 CONSOLIDATION.....................     --       --      174
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD............    416      171       46
                                                            -----  -------  -------
CASH AND CASH EQUIVALENTS, END OF PERIOD..................  $  37  $   416  $   171
                                                            -----  -------  -------
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND
  FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized)................  $ 279  $   250  $   324
  Income taxes paid (net of refunds, $39, $8, and $50,
     respectively)........................................    306       35      (27)
  Pension and OPEB cash contributions.....................     68       62       62
NON-CASH TRANSACTIONS
  Other assets placed under capital lease.................  $   7  $    12  $     3
                                                            =====  =======  =======

</Table>



        The accompanying notes are an integral part of these statements.


                                      CE-31

<PAGE>

                                                        Consumers Energy Company

                            CONSUMERS ENERGY COMPANY

                           CONSOLIDATED BALANCE SHEETS



<Table>
<Caption>
                                                                   DECEMBER 31
                                                                -----------------
                                                                  2006      2005
                                                                  ----      ----
                                                                   IN MILLIONS

<S>                                                             <C>       <C>

ASSETS
PLANT AND PROPERTY (AT COST)
  Electric....................................................  $ 8,504   $ 8,204

  Gas.........................................................    3,273     3,151
  Other.......................................................       15       227
                                                                -------   -------
                                                                 11,792    11,582
  Less accumulated depreciation, depletion, and amortization..    4,983     4,804
                                                                -------   -------
                                                                  6,809     6,778
  Construction work-in-progress...............................      639       509
                                                                -------   -------
                                                                  7,448     7,287
                                                                -------   -------
INVESTMENTS
  Stock of affiliates.........................................       36        33
  Other.......................................................        5         7
                                                                -------   -------
                                                                     41        40
                                                                -------   -------
CURRENT ASSETS
  Cash and cash equivalents at cost, which approximates
     market...................................................       37       416
  Restricted cash and restricted short-term investments at
     cost, which approximates market..........................       57       183
  Accounts receivable, notes receivable and accrued revenue,
     less allowances of $14 in 2006 and $13 in 2005...........      591       674
  Accounts receivable -- related parties......................        5         9
  Inventories at average cost
     Gas in underground storage...............................    1,129     1,068
     Materials and supplies...................................       81        75
     Generating plant fuel stock..............................      105        80
  Deferred property taxes.....................................      150       159
  Regulatory assets -- postretirement benefits................       19        19
  Derivative instruments......................................       --       242
  Prepayments and other.......................................       50        70
                                                                -------   -------
                                                                  2,224     2,995
                                                                -------   -------
NON-CURRENT ASSETS
  Regulatory assets
     Securitized costs........................................      514       560
     Additional minimum pension...............................       --       399
     Postretirement benefits..................................    1,131       116
     Customer Choice Act......................................      190       222
     Other....................................................      462       484
  Nuclear decommissioning trust funds.........................      602       555
  Other.......................................................      233       520
                                                                -------   -------
                                                                  3,132     2,856
                                                                -------   -------
TOTAL ASSETS..................................................  $12,845   $13,178
                                                                =======   =======

</Table>



        The accompanying notes are an integral part of these statements.


                                      CE-32

<PAGE>

                                                        Consumers Energy Company


<Table>
<Caption>
                                                                   DECEMBER 31
                                                                -----------------
                                                                  2006      2005
                                                                  ----      ----
                                                                   IN MILLIONS

<S>                                                             <C>       <C>

STOCKHOLDER'S INVESTMENT AND LIABILITIES
CAPITALIZATION
  Common stockholder's equity
  Common stock, authorized 125.0 shares; outstanding 84.1
     shares for all periods...................................  $   841   $   841
  Paid-in capital.............................................    1,832     1,632
  Accumulated other comprehensive income......................       15        72
  Retained earnings since December 31, 1992...................      270       233
                                                                -------   -------
                                                                  2,958     2,778
  Preferred stock.............................................       44        44
  Long-term debt..............................................    4,127     4,303
  Non-current portion of capital leases and finance lease
     obligations..............................................       42       308
                                                                -------   -------
                                                                  7,171     7,433
                                                                -------   -------
MINORITY INTERESTS............................................       --       259
                                                                -------   -------
CURRENT LIABILITIES
  Current portion of long-term debt, capital leases and
     finance leases...........................................       44       112
  Current portion of long-term debt -- related parties........       --       129
  Notes payable -- related parties............................       42        27
  Accounts payable............................................      421       458
  Accounts payable -- related parties.........................       18        40
  Accrued interest............................................       66        82
  Accrued taxes...............................................      295       400
  Deferred income taxes.......................................       11        55
  MCV Partnership gas supplier funds on deposit...............       --       193
  Other.......................................................      217       171
                                                                -------   -------
                                                                  1,114     1,667
                                                                -------   -------
NON-CURRENT LIABILITIES
  Deferred income taxes.......................................      847     1,027
  Regulatory liabilities
     Regulatory liabilities for cost of removal...............    1,166     1,120
     Income taxes, net........................................      539       455
     Other regulatory liabilities.............................      249       178
  Postretirement benefits.....................................      993       308
  Asset retirement obligations................................      497       494
  Deferred investment tax credit..............................       62        67
  Other.......................................................      207       170
                                                                -------   -------
                                                                  4,560     3,819
                                                                -------   -------
     Commitments and Contingencies (Notes 3, 4, 5, 8, and 10)
TOTAL STOCKHOLDER'S INVESTMENT AND LIABILITIES................  $12,845   $13,178
                                                                =======   =======

</Table>




                                      CE-33

<PAGE>

                                                        Consumers Energy Company

                            CONSUMERS ENERGY COMPANY

             CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY



<Table>
<Caption>
                                                             YEARS ENDED DECEMBER 31
                                                            ------------------------
                                                             2006     2005     2004
                                                             ----     ----     ----
                                                                   IN MILLIONS

<S>                                                         <C>      <C>      <C>

COMMON STOCK
  At beginning and end of period(a).......................  $  841   $  841   $  841
                                                            ------   ------   ------
OTHER PAID-IN CAPITAL
  At beginning of period..................................   1,632      932      682
  Stockholder's contribution..............................     200      700      250
                                                            ------   ------   ------
       At end of period...................................   1,832    1,632      932
                                                            ------   ------   ------
ACCUMULATED OTHER COMPREHENSIVE INCOME
  Retirement benefits liability
     At beginning of period...............................      (2)      (1)      --
     Retirement benefits liability adjustments(b).........      --       (1)      (1)
     Adjustment to initially apply FASB Statement No. 158,
       net of tax.........................................      (6)      --       --
                                                            ------   ------   ------
       At end of period...................................      (8)      (2)      (1)
                                                            ------   ------   ------
  Investments
     At beginning of period...............................      18       12        9
     Unrealized gain on investments(b)....................       5        6        3
                                                            ------   ------   ------
       At end of period...................................      23       18       12
                                                            ------   ------   ------
  Derivative instruments
     At beginning of period...............................      56       20        8
     Unrealized gain (loss) on derivative instruments(b)..     (21)      53       23
     Reclassification adjustments included in net income
       (loss)(b)..........................................     (35)     (17)     (11)
                                                            ------   ------   ------
       At end of period...................................      --       56       20
                                                            ------   ------   ------
Total Accumulated Other Comprehensive Income..............      15       72       31
                                                            ------   ------   ------
RETAINED EARNINGS
  At beginning of period..................................     233      608      521
  Net income (loss).......................................     186      (96)     279
  Cash dividends declared -- Common Stock.................    (147)    (277)    (190)
  Cash dividends declared -- Preferred Stock..............      (2)      (2)      (2)
                                                            ------   ------   ------
       At end of period...................................     270      233      608
                                                            ------   ------   ------
TOTAL COMMON STOCKHOLDER'S EQUITY.........................  $2,958   $2,778   $2,412
                                                            ======   ======   ======

</Table>



        The accompanying notes are an integral part of these statements.


                                      CE-34

<PAGE>

                                                        Consumers Energy Company


<Table>
<Caption>
                                                                   YEARS ENDED
                                                                   DECEMBER 31
                                                               ------------------
                                                               2006   2005   2004
                                                               ----   ----   ----
                                                                   IN MILLIONS

<S>                                                            <C>    <C>    <C>

(a) NUMBER OF SHARES OF COMMON STOCK OUTSTANDING WAS
    84,108,789 FOR ALL PERIODS PRESENTED



(b) DISCLOSURE OF OTHER COMPREHENSIVE INCOME:
     Retirement benefits liability
       Retirement benefits liability adjustment, net of tax
          (tax benefit) of $-- in 2006, $-- in 2005, and $(1)
          in 2004............................................  $ --   $ (1)  $ (1)
     Investments
       Unrealized gain on investments, net of tax of $2 in
          2006, $3 in 2005, and $2 in 2004...................     5      6      3
     Derivative instruments
       Unrealized gain (loss) on derivative instruments, net
          of tax (tax benefit) of $(11) in 2006, $28 in 2005,
          and $12 in 2004....................................   (21)    53     23
       Reclassification adjustments included in net income
          (loss), net of tax benefit of $(19) in 2006, $(10)
          in 2005, and $(6) in 2004..........................   (35)   (17)   (11)
     Net income (loss).......................................   186    (96)   279
                                                               ----   ----   ----
     Total Comprehensive Income (Loss).......................  $135   $(55)  $293
                                                               ====   ====   ====

</Table>




                                      CE-35

<PAGE>

                                                        Consumers Energy Company

                          CONSUMERS ENERGY CORPORATION

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES

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

     PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include
Consumers, and all other entities in which we have a controlling financial
interest or are the primary beneficiary, in accordance with FASB Interpretation
No. 46(R). We use the equity method of accounting for investments in companies
and partnerships that are not consolidated, where we have significant influence
over operations and financial policies, but are not the primary beneficiary. We
eliminate intercompany transactions and balances.

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

     We record estimated liabilities in our consolidated financial statements
when it is probable that a loss will be incurred in the future as a result of a
current event, and when the amount can be reasonably estimated. For additional
details, see Note 3, Contingencies.

     REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of
electricity and natural gas, and the storage of natural gas when services are
provided. We record sales tax on a net basis and exclude it from revenues.

     ACCOUNTING FOR MISO TRANSACTIONS: We account for MISO transactions on a net
basis for all of our generating units combined. We record billing adjustments
when we receive invoices and record an expense accrual for future adjustments
based on historical experience.

     CAPITALIZED INTEREST: We 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
incurred. Our regulated businesses capitalize AFUDC on regulated construction
projects and include such amounts in plant in service.

     CASH EQUIVALENTS AND RESTRICTED CASH: Cash equivalents are all liquid
investments with an original maturity of three months or less.

     At December 31, 2006, our restricted cash on hand was $57 million. We
classify restricted cash dedicated for repayment of Securitization bonds as a
current asset, as the related payments occur within one year.

     COLLECTIVE BARGAINING AGREEMENTS: At December 31, 2006, the Utility Workers
of America Union represented approximately 45 percent of our employees. The
Union represents Consumers' operating, maintenance, and construction employees
and our call center employees.

     DETERMINATION OF PENSION MRV OF PLAN ASSETS: We determine the MRV for
pension plan assets, as defined in SFAS No. 87, as the fair value of plan assets
on the measurement date, adjusted by the gains or losses that will not be
admitted into MRV until future years. We reflect each year's assets gain or loss
in MRV in equal amounts over a five-year period beginning on the date the
original amount was determined. We use the MRV in the calculation of net pension
cost.

     EFFECTS OF PRIOR YEAR MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN
CURRENT YEAR FINANCIAL STATEMENTS: SAB No. 108 was adopted on December 31, 2006.
The standard clarifies how we should assess the materiality of prior period
financial statement errors in the current period. Prior to the adoption, of this
standard we used the "iron-curtain" method to quantify the effects of prior
period financial statement errors. The iron-curtain method focuses on the
effects of correcting the period-end balance sheet with less emphasis on the
effects the correction would have on our consolidated income statement. This
standard requires quantification of financial

                                      CE-36

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



statement errors based on their effect on each of our consolidated financial
statements. The adoption of this standard did not have an effect on our
financial position or results of operations.

     FINANCIAL AND DERIVATIVE INSTRUMENTS: We record debt and equity securities
classified as available-for-sale at fair value determined from quoted market
prices. We record debt and equity securities classified as held-to-maturity at
cost.

     On a specific identification basis, we report unrealized gains or losses
from changes in fair value of certain available-for-sale debt and equity
securities, net of tax, in equity as part of AOCI. We exclude unrealized gains
or losses from earnings unless the related changes in fair value are determined
to be other than temporary. We reflect unrealized gains or losses on our nuclear
decommissioning investments as regulatory liabilities on our Consolidated
Balance Sheets. Realized gains or losses would not affect our consolidated
earnings or cash flows.

     We account for derivative instruments using SFAS No. 133. We report
derivatives on our Consolidated Balance Sheets at their fair value. We record
changes in fair value in AOCI if the derivative qualifies for cash flow hedge
accounting; otherwise, we record the changes in earnings.

     For additional details regarding financial and derivative instruments, see
Note 5, Financial and Derivative Instruments.

     IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: We evaluate the potential
impairment of our investments and other long-lived assets, other than goodwill,
based on various analyses, including the projection of undiscounted cash flows,
whenever events or changes in circumstances indicate that the carrying amount of
the investment or asset may not be recoverable. If the carrying amount of the
investment or asset exceeds its estimated undiscounted future cash flows, we
recognize an impairment loss and write down the investment or asset to its
estimated fair value. For additional details, see Note 2, Asset Sales and
Impairment Charges.

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

     MAINTENANCE AND DEPRECIATION: We charge property repairs and minor property
replacement to maintenance expense. We use the direct expense method to account
for planned major maintenance activities. We charge planned major maintenance
activities to operating expense unless the cost represents the acquisition of
additional components or the replacement of an existing component. We capitalize
the cost of plant additions and replacements. We depreciate utility property
using straight-line rates approved by the MPSC. The composite depreciation rates
for our properties are:


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                      2006     2005     2004
-----------------------                                      ----     ----     ----

<S>                                                          <C>      <C>      <C>

Electric utility property..................................  3.1%     3.1%     3.1%
Gas utility property.......................................  3.6%     3.6%     3.7%
Other property.............................................  8.2%     7.6%     8.4%
</Table>


     NUCLEAR FUEL COST: We amortize nuclear fuel cost to fuel expense based on
the quantity of heat produced for electric generation. For nuclear fuel used
after April 6, 1983, we charge certain disposal costs to nuclear fuel expense,
recover these costs through electric rates, and remit them to the DOE quarterly.
We elected to defer payment for disposal of spent nuclear fuel burned before
April 7, 1983. Our DOE liability is $152 million at December 31, 2006 and $145
million at December 31, 2005. This amount includes interest, which is payable
upon the first delivery of spent nuclear fuel to the DOE. We have recovered,
through electric rates, the amount of this liability, excluding a portion of
interest. In conjunction with the sale of Palisades and the Big Rock ISFSI, we
will retain this obligation and provide security to Entergy for this obligation
in the form of cash, a letter of credit, or other acceptable means. For
additional details on disposal of spent nuclear fuel, see Note 3, Contingencies,
"Other Electric Contingencies -- Nuclear Matters."


                                      CE-37

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                        2006   2005   2004
-----------------------                                        ----   ----   ----
                                                                   IN MILLIONS

<S>                                                            <C>    <C>    <C>

Other income
  Electric restructuring return..............................   $ 4    $ 6    $ 6
  Return on stranded and security costs......................     5      6      9
  Nitrogen oxide allowance sales.............................     8      2     --
  Gain on stock..............................................     1      1     --
  All other..................................................     2      5      1
                                                               ----   ----   ----
Total other income...........................................  $ 20   $ 20   $ 16
                                                               ====   ====   ====

</Table>




<Table>
<Caption>
YEARS ENDED DECEMBER 31                                        2006    2005   2004
-----------------------                                        ----    ----   ----
                                                                   IN MILLIONS

<S>                                                           <C>     <C>     <C>

Other expense
  Loss on reacquired debt...................................   $ --    $ (6)   $--
  Civic and political expenditures..........................     (2)     (2)    (2)
  Donations.................................................     (9)     --     (1)
  Loss on SERP investment...................................     --      (1)    (1)
  All other.................................................     --      (4)    (3)
                                                              -----   -----   ----
Total other expense.........................................  $ (11)  $ (13)  $ (7)
                                                              =====   =====   ====

</Table>


     PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, we charge the original
cost to accumulated depreciation, along with associated cost of removal, net of
salvage. Cost of removal collected from our customers, but not spent, is
recorded as a regulatory liability. We capitalize AFUDC on regulated major
construction projects. We recognize gains or losses on the retirement or
disposal of non-regulated assets in income. For additional details, see Note 7,
Asset Retirement Obligations and Note 11, Property, Plant, and Equipment.

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

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


<Table>
<Caption>
TYPE OF INCOME                   RELATED PARTY              2006   2005   2004
--------------                   -------------              ----   ----   ----
                                                                IN MILLIONS

<S>                   <C>                                   <C>    <C>    <C>

Income from our
  investments in
  related party
  trusts              Consumers' affiliated Trust            $--    $1     $1
                      Preferred Securities companies.....
</Table>




                                      CE-38

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     We recorded expense from related parties as follows:


<Table>
<Caption>
TYPE OF COST                     RELATED PARTY              2006   2005   2004
------------                     -------------              ----   ----   ----
                                                                IN MILLIONS

<S>                   <C>                                   <C>    <C>    <C>

Electric generating
  capacity
  and energy          Affiliates of Enterprises..........    $74    $68    $67
Interest expense on
  long-term debt      Consumers' affiliated Trust              1     15     44
                      Preferred Securities companies.....
Gas purchases         CMS ERM............................     --     --      1
Overhead expense(a)   CMS Energy parent company..........      1      1     --
Gas transportation    CMS Bay Area Pipeline, L.L.C.......      4      4      4
</Table>


--------------
(a)    We base our related party transactions on regulated prices, market
       prices, or competitive bidding. We pay overhead costs to CMS Energy based
       on an industry allocation methodology, such as the Massachusetts Formula.

     We own 2.2 million shares of CMS Energy Common Stock with a fair value of
$36 million at December 31, 2006. For additional details on our investment in
CMS Energy Common Stock, see Note 5, Financial and Derivative Instruments.

     TRADE RECEIVABLES: Accounts receivable is primarily composed of trade
receivables and unbilled receivables. We record our accounts receivable at fair
value. We establish an allowance for uncollectible accounts based on historical
losses and management's assessment of existing economic conditions, customer
trends, and other factors. We assess late payment fees on trade receivables
based on contractual past-due terms established with customers. We charge
accounts deemed uncollectible to operating expense.

     UNAMORTIZED DEBT PREMIUM, DISCOUNT, AND EXPENSE: We capitalize premiums,
discounts, and expenses incurred in connection with the issuance of long-term
debt and amortize those costs over the terms of the debt issues. We expense any
refinancing costs as incurred. For the regulated portions of our businesses, if
we refinance debt, we capitalize any remaining unamortized premiums, discounts,
and expenses and amortize them over the terms of the newly issued debt.

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

     We reflect the following regulatory assets and liabilities, which include
both current and non-current amounts, on our Consolidated Balance Sheets. We
expect to recover these costs through rates over periods of up to 14 years.

                                      CE-39

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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


<Table>
<Caption>
DECEMBER 31                                                        2006     2005
-----------                                                        ----     ----
                                                                    IN MILLIONS

<S>                                                               <C>      <C>

Securitized costs (Note 4)......................................  $  514   $  560
Additional minimum pension liability (Note 6)(a)................      --      399
Postretirement benefits (Note 6)(a).............................   1,150      135
Customer Choice Act.............................................     190      222
Electric restructuring implementation plan......................      40       74
Manufactured gas plant sites (Note 3)...........................      56       62
Abandoned Midland project.......................................       9        9
Unamortized debt costs..........................................      86       93
Asset retirement obligations (Note 7)...........................     177      169
Stranded costs (Note 3).........................................      65       63
Other...........................................................      29       14
                                                                  ------   ------
Total regulatory assets(b)......................................  $2,316   $1,800
                                                                  ======   ======
Cost of removal (Note 7)........................................  $1,166   $1,120
Income taxes, net (Note 8)......................................     539      455
Asset retirement obligations (Note 7)...........................     180      165
Other...........................................................      69       13
                                                                  ------   ------
Total regulatory liabilities(b).................................  $1,954   $1,753
                                                                  ======   ======

</Table>



--------------
(a)    The change from 2005 to 2006 is largely due to the implementation of SFAS
       No. 158, Employers' Accounting for Defined Benefit Pension and Other
       Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106,
       and 132(R). For additional details, see Note 6, Retirement Benefits.

(b)    At December 31, 2006, we classified $19 million of regulatory assets as
       current regulatory assets and we classified $2.297 billion of regulatory
       assets as non-current regulatory assets. At December 31, 2005, we
       classified $19 million of regulatory assets as current regulatory assets
       and we classified $1.781 billion of regulatory assets as non-current
       regulatory assets. At December 31, 2006 and December 31, 2005, all of our
       regulatory liabilities represented non-current regulatory liabilities.

     NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE: SFAS No. 157, Fair Value
Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us
January 1, 2008. The standard provides a revised definition of "fair value" and
gives guidance on how to measure the fair value of assets and liabilities. Under
the standard, fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly exchange between market
participants. The standard does not expand the use of fair value in any new
circumstances. However, additional disclosures will be required on the impact
and reliability of fair value measurements reflected in our consolidated
financial statements. The standard will also eliminate the existing prohibition
of recognizing "day one" gains or losses on derivative instruments, and will
generally require such gains and losses to be recognized through earnings. We
are presently evaluating the impacts, if any, of implementing SFAS No. 157. We
currently do not hold any derivatives that would involve day one gains or
losses.

     SFAS No. 159, The Fair Value Option for Financial Assets and Financial
Liabilities, Including an amendment to FASB Statement No. 115: In February 2007,
the FASB issued SFAS No. 159, effective for us January 1, 2008. This standard
will give us the option to select certain financial instruments and other items,
which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value

                                      CE-40

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



option for an item, we would recognize unrealized gains and losses associated
with changes in the fair value of the item over time. The statement will also
require disclosures for items for which the fair value option has been elected.
We are presently evaluating whether we will choose to elect the fair value
option for any financial instruments or other items.

     FIN 48, Accounting for Uncertainties in Income Taxes: We discuss the
requirements of this new accounting standard in Note 8, Income Taxes.

2: ASSET SALES AND IMPAIRMENT CHARGES

ASSET SALES

     Gross cash proceeds received from the sale of assets totaled $69 million in
2006.

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


<Table>
<Caption>
                                                                      PRETAX   AFTER-TAX
DATE SOLD  BUSINESS/PROJECT                                            GAIN       GAIN
---------  ----------------                                           ------   ---------
                                                                          IN MILLIONS

<S>        <C>                                                        <C>      <C>

October    Land in Ludington, Michigan(a)..........................     $ 2       $ 2
November   MCV GP II(b)............................................      77        38
                                                                        ---       ---
           Total gain on asset sales...............................     $79       $40
                                                                        ===       ===

</Table>


--------------
(a)    Sale of Ludington Land: We sold 36 parcels of land near Ludington,
       Michigan. We held a majority share of the land, which we co-owned with
       DTE Energy. Our portion of the proceeds was approximately $6 million.

(b)    Sale of our Interest in the MCV Partnership and the MCV Facility: We sold
       100 percent of our ownership interest of MCV GP II (the successor to CMS
       Midland, Inc.) and 100 percent of our ownership of the stock of CMS
       Midland Holdings Company to an affiliate of GSO Capital Partners and
       Rockland Capital Energy Investments for $60.5 million. These Consumers
       subsidiaries held our 49 percent interest in the MCV Partnership and our
       35 percent lessor interest in the MCV Facility, held by the FMLP. The
       transaction is composed of non-real estate and real estate components.
       Since the carrying value of the MCV Facility, the real estate component
       of the transaction, exceeded the fair value, we recorded an impairment
       charge of $218 million. After considering tax effects and minority
       interest, the impairment charge reduced our consolidated net income by
       $80 million.

     Because of the MCV PPA, the transaction is a sale and leaseback for
accounting purposes. SFAS No. 98 specifies the accounting required for a
seller's sale and simultaneous leaseback involving real estate. We will have
continuing involvement with the MCV Partnership through an existing guarantee
associated with the future operations of the MCV Facility. As a result, we
accounted for the MCV Facility, which is the asset subject to the leaseback, as
a financing for accounting purposes and not a sale. We accounted for the non-
real estate assets and liabilities associated with the transaction as a sale.

     As a financing, the MCV Facility remains on our Consolidated Balance Sheets
and the related proceeds are recorded as a financing obligation. The value of
the finance obligation is based on an allocation of the sale proceeds to the
fair values of the net assets sold and fair value of the MCV Facility asset
under the financing. The total proceeds of $57 million (net of $3 million of
selling expenses) were less than the fair value of the net assets sold. As a
result, there were no proceeds remaining to allocate to the MCV Facility and a
finance obligation was not recorded.

     The previously described transaction resulted in an after-tax loss of $41
million. This loss includes the reversal of $30 million, into earnings, of
certain cumulative amounts of the MCV Partnership derivative fair value changes
that we accounted for in AOCI, the impairment charge on the MCV Facility, and
gain on the sale of our interests in the MCV Partnership and the FMLP. For
further information, see Note 5, Financial and Derivative Instruments,
"Derivative Contracts Associated with the MCV Partnership."


                                      CE-41

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     The following table summarizes the impacts of the transaction on net income
and stockholder's equity:


<Table>
<Caption>
DESCRIPTION                                                         AFTER-TAX IMPACT
-----------                                                         ----------------
                                                                       IN MILLIONS

<S>                                                                 <C>

Asset impairment charges, net of minority interest of $95 million
  and $43 million in taxes........................................        $(80)
General taxes, net of $1 million in taxes.........................           1
Gain on asset sales, net
  Reclassification of AOCI into earnings, net of $17 million in
     taxes........................................................          30
  Removal of interests in the MCV Partnership and the FMLP, net of
     $22 million in taxes.........................................           8
                                                                          ----
Decrease to consolidated net income...............................        $(41)
  Reclassification of AOCI into earnings, net of $17 million in
     taxes........................................................         (30)
                                                                          ----
Decrease to stockholder's equity..................................        $(71)
                                                                          ====

</Table>


ASSET IMPAIRMENT CHARGES

     As discussed in "Asset Sales," in November 2006, we recorded an impairment
charge of $218 million in our Consolidated Statements of Income (Loss). This
impairment charge recognizes the reduction in fair value of the MCV Facility's
real estate assets and results in an $80 million reduction to our consolidated
net income after considering tax effects and minority interest.

     In the third quarter of 2005, NYMEX forward natural gas price forecasts for
the years 2005 through 2010 increased substantially. Additionally, other
independent natural gas long-term forward price forecasting organizations
indicated their intention to raise their forecasts for the price of natural gas
beyond 2010. As a result, the MCV Partnership determined an impairment analysis
considering revised forward natural gas price assumptions was required. The MCV
Partnership determined the fair value of its fixed assets by discounting a set
of probability-weighted streams of future operating cash flows. The carrying
value of the MCV Partnership's fixed assets exceeded the estimated fair value
resulting in impairment charges of $1.159 billion to recognize the reduction in
fair value of the MCV Facility's fixed assets and $25 million of interest
capitalized during the construction of the MCV Facility. Our 2005 consolidated
net income was reduced by $385 million, after considering tax effects and
minority interest.

     Our interests in the MCV Partnership were reported as a component of our
"other" business segment.

3: CONTINGENCIES

     SEC AND DOJ INVESTIGATIONS: During the period of May 2000 through January
2002, CMS MST engaged in simultaneous, prearranged commodity trading
transactions in which energy commodities were sold and repurchased at the same
price. These so called round-trip trades had no impact on previously reported
consolidated net income, earnings per share or cash flows, but had the effect of
increasing operating revenues and operating expenses by equal amounts.

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

     SECURITIES CLASS ACTION LAWSUITS: Beginning in May 2002, a number of
complaints were filed against CMS Energy, Consumers and certain officers and
directors of CMS Energy and its affiliates in the United States District Court
for the Eastern District of Michigan. The cases were consolidated into a single
lawsuit (the "Shareholder

                                      CE-42

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



Action"), which generally seeks unspecified damages based on allegations that
the defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy's business and
financial condition, particularly with respect to revenues and expenses recorded
in connection with round-trip trading by CMS MST. In January 2005, the court
granted a motion to dismiss Consumers and three of the individual defendants,
but denied the motions to dismiss CMS Energy and the 13 remaining individual
defendants. In March 2006, the court conditionally certified a class consisting
of "all persons who purchased CMS Common Stock during the period of October 25,
2000 through and including May 17, 2002 and who were damaged thereby." The court
excluded purchasers of CMS Energy's 8.75 percent Adjustable Convertible Trust
Securities ("ACTS") from the class and, in response, a new class action lawsuit
was filed on behalf of ACTS purchasers (the "ACTS Action") against the same
defendants named in the Shareholder Action. The settlement described in the
following paragraph, if approved, will resolve both the Shareholder and ACTS
Actions.

     On January 3, 2007, CMS Energy and other parties entered into a Memorandum
of Understanding (the "MOU") dated December 28, 2006, subject to court approval,
regarding settlement of the two class action lawsuits. The settlement was
approved by a special committee of independent directors and by the full board
of directors. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. The MOU is expected to lead to a detailed
stipulation of settlement that will be presented to the assigned federal judge
and the affected class in the first quarter of 2007. Under the terms of the MOU,
the litigation will be settled for a total of $200 million, including the cost
of administering the settlement and any attorney fees the court awards. CMS
Energy will make a payment of approximately $123 million plus an amount
equivalent to interest on the outstanding unpaid settlement balance beginning on
the date of preliminary approval of the court and running until the balance of
the settlement funds is paid into a settlement account. Out of the total
settlement, CMS Energy's insurers will pay approximately $77 million directly to
the settlement account. CMS Energy took an approximately $123 million net pre-
tax charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS
Energy makes no admission of liability under the Shareholder Action and the ACTS
Action.

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.

     Routine Maintenance Classification: The EPA has alleged that some utilities
have incorrectly classified plant modifications as "routine maintenance" rather
than seeking permits to modify the plant 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
generating plants and potentially pay fines. Additionally, the viability of
certain plants remaining in operation could be called into question.

     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 our experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $10 million. At December 31, 2006, we have
recorded a liability for the minimum amount of our estimated probable Superfund
liability. The timing of payments related to the remediation of our Superfund
sites is uncertain. Any significant change in assumptions, such as different
remediation techniques, nature and extent of contamination, and legal and
regulatory requirements, could affect our estimate of remedial action costs and
the timing of our remediation payments.


                                      CE-43

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     In October 1998, during routine maintenance activities, we identified PCB
as a component in certain paint, grout, and sealant materials at Ludington. We
removed and replaced part of the PCB material. Since proposing a plan to deal
with the remaining materials, we have had several conversations with the EPA.
The EPA has proposed a rule, which would authorize continued use of such
material in place, subject to certain restrictions. We are not able to predict
when a final rule will be issued.

     LITIGATION: In 2003, a group of eight PURPA qualifying facilities (the
plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit
Court. The lawsuit alleged that we incorrectly calculated the energy charge
payments made pursuant to power purchase agreements with qualifying facilities.
The judge deferred to the primary jurisdiction of the MPSC, dismissing the
circuit court case without prejudice. In February 2005, the MPSC issued an order
in the 2004 PSCR plan case concluding that we have been correctly administering
the energy charge calculation methodology. The plaintiffs have appealed the MPSC
order to the Michigan Court of Appeals. The plaintiffs also filed suit in the
United States Court for the Western District of Michigan, which the judge
subsequently dismissed. The plaintiffs have appealed the dismissal to the United
States Court of Appeals. We cannot predict the outcome of these appeals.

ELECTRIC RATE MATTERS

     ELECTRIC ROA: In prior orders, the MPSC approved recovery of Stranded Costs
incurred from 2002 through 2003 plus the cost of money through the period of
collection. At December 31, 2006, we had a regulatory asset for Stranded Costs
of $65 million on our Consolidated Balance Sheets. We collect Stranded Costs
through a surcharge on ROA customers. At December 31, 2006, alternative electric
suppliers were providing 300 MW of generation service to ROA customers, which
represent a decrease of 46 percent of ROA load compared to the end of December
2005. If downward ROA trends continue, it may extend the time it takes to
recover fully our Stranded Costs. It is difficult to predict future ROA customer
trends and their effect on the timely recovery of Stranded Costs.

     POWER SUPPLY COSTS: To reduce the risk of high power supply costs during
peak demand periods and to achieve our reserve margin target, we purchase
electric capacity and energy contracts for the physical delivery of electricity
primarily in the summer months and to a lesser degree in the winter months. We
have purchased capacity and energy contracts covering partially the estimated
reserve margin requirements for 2007 through 2010. As a result, we have an asset
of $62 million for unexpired seasonal capacity and energy contracts at December
31, 2006. Capacity cost for these primarily seasonal electric capacity and
energy contracts was $17 million in 2006.

     PSCR: The PSCR process allows recovery of reasonable and prudent power
supply costs. The MPSC reviews these costs for reasonableness and prudency in
annual plan and reconciliation proceedings.

     2005 PSCR Reconciliation: In March 2006, we submitted our 2005 PSCR
reconciliation filing to the MPSC. Our filing indicated that 2005
underrecoveries were $36 million for commercial and industrial customers.

     2006 PSCR Plan: In August 2006, the MPSC issued an order approving our
amended 2006 PSCR plan, which resulted in an increased PSCR factor for the
remainder of 2006. PSCR underrecoveries for 2006 were $119 million. These
underrecoveries are due to the MPSC delaying recovery of our increased METC
costs and coal supply costs, increased bundled sales, and other cost increases
beyond those included in the 2006 PSCR plan filings.

     PSCR 2007 Plan: In December 2006, the MPSC issued a temporary order
allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as
filed in our September 2006 case filing. The order also approved the
incorporation of our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR
monthly factor and allowed us to continue to roll in prior year under and
overrecoveries into future PSCR plans.

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


                                      CE-44

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



OTHER ELECTRIC CONTINGENCIES

     THE MCV PPA: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-
year power purchase agreement beginning in 1990. We estimate that capacity and
energy payments under the MCV PPA will be $620 million per year. The MCV PPA and
the associated customer rates are unaffected by the November 2006 sale of our
interest in the MCV Partnership.

     Underrecoveries related to the MCV PPA: The cost that we incur under the
MCV PPA exceeds the recovery amount allowed by the MPSC. We expensed
underrecoveries of $57 million in 2006 and we estimate cash underrecoveries of
$39 million in 2007. However, we use the direct savings from the RCP, after
allocating a portion to customers, to offset a portion of our capacity and fixed
energy underrecoveries expense.

     RCP: In January 2005, we implemented the MPSC-approved RCP with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV Facility based on natural gas market prices.
This results in fuel cost savings for the MCV Facility, which the MCV
Partnership shares with us. The RCP also requires us to contribute $5 million
annually to a renewable resources program. As of December 2006, we have
contributed $10 million to the renewable resources program. The underlying RCP
agreement between Consumers and the MCV Partnership extends through the term of
the MCV PPA. However, either party may terminate that agreement under certain
conditions. In January 2007, the Michigan Attorney General filed an appeal with
the Michigan Supreme Court regarding the MPSC's order approving the RCP. We
cannot predict the outcome of this matter.

     Regulatory Out Provision in the MCV PPA: After September 15, 2007, we
expect to claim relief under the regulatory out provision in the MCV PPA,
thereby limiting our capacity and fixed energy payments to the MCV Partnership
to the amounts that we collect from our customers. The MCV Partnership has
notified us that it takes issue with our intended exercise of the regulatory out
provision. We believe that the provision is valid and fully effective, but
cannot assure that it will prevail in the event of a dispute. If we are
successful in exercising the regulatory out provision, the MCV Partnership has
the right to terminate the MCV PPA, which could affect our reserve margin. We
anticipate that the MPSC will review our exercise of the regulatory out
provision and the likely consequences of such action in 2007. It is possible
that in the event that the MCV Partnership ceases performance under the MCV PPA,
prior orders could limit recovery of replacement power costs to the amounts that
the MPSC authorized for recovery under the MCV PPA. Depending on the cost of
replacement power, this could result in our costs exceeding the recovery amount
allowed by the MPSC. We cannot predict the outcome these matters.

     THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT: In
July 2006, we reached an agreement to sell Palisades to Entergy for $380 million
and pay Entergy $30 million to assume ownership and responsibility for the Big
Rock ISFSI.

     Palisades Asset Sale: The sale is subject to various regulatory approvals,
including the MPSC's approval of the power purchase agreement and the NRC's
approval of the transfer of the operating license to Entergy and other related
matters. In February 2007, the FERC issued an order approving the sale of power
to us under the power purchase agreement and granted other related approvals,
with what we believe are minor exceptions and conditions that we believe can be
adequately accepted. In October 2006, the Federal Trade Commission issued a
notice that neither it nor the DOJ's Antitrust Division plans to take
enforcement action on the sale. The final purchase price will be subject to
various closing adjustments such as working capital and capital expenditure
adjustments, adjustments for nuclear fuel usage and inventory, and the date of
closing. However, termination of the sale agreement can occur if the closing
does not take place by January 2008. To accommodate delays in receiving
regulatory approval, extension of the closing can occur for up to six months. We
cannot predict with certainty whether or when satisfaction of the closing
conditions will occur or whether or when completion of the transaction will
occur.

     Under the agreement, if the transaction does not close by March 1, 2007, a
reduction in the purchase price occurs of approximately $80,000 per day, with
additional costs if the deal does not close by June 1, 2007. Based on the MPSC's
published schedule for the contested case proceedings regarding this
transaction, we target to close on

                                      CE-45

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



the transaction in the second quarter of 2007. Based on the anticipated closing
date, this delay would result in a purchase price reduction for Palisades of
approximately $5 million. We estimate that the Palisades sale will result in a
$31 million premium above the Palisades asset value at the anticipated closing
date after accounting for estimated sales-related costs. We expect that this
premium will benefit our customers. We cannot predict with certainty whether or
when satisfaction of the closing conditions will occur or whether or when
completion of the transaction will occur.

     We have notified the NMC that we plan to terminate the NMC's operation of
Palisades, if the sale is completed, which would require us to pay the NMC an
estimated $12 million. Due to the regulatory approvals pending, we have not
recorded this contingent obligation.

     Palisades Power Purchase Agreement: As part of the transaction, Entergy
will sell us 100 percent of the plant's output up to its current capacity of 798
MW under a 15-year power purchase agreement. During the term of the power
purchase agreement, Entergy is obligated to supply, and we are obligated to
take, all capacity and energy from the Palisades plant, exclusive of uprates
above the plant's presently specified capacity. When the plant is not operating
or is derated, under certain circumstances Entergy can elect to provide
replacement power from another source at the rates set in the power purchase
agreement. Otherwise, we would have to obtain replacement power from the market.
However, we are only obligated to pay Entergy for capacity and energy actually
delivered by Entergy either from the plant or from an allowable replacement
source chosen by Entergy. If Entergy schedules a plant outage in June, July or
August, Entergy is required to provide replacement power at power purchase
agreement rates. There are significant penalties incurred by Entergy if the
delivered energy fails to achieve a minimum capacity factor level during July
and August. Over the term of the power purchase agreement, the pricing terms are
such that Consumers' ratepayers will retain the benefits of the Palisades
plant's low-cost nuclear generation.

     Because of the power purchase agreement that will be in place between
Consumers and Entergy, the transaction is effectively a sale and leaseback for
accounting purposes. SFAS No. 98 specifies the accounting required for a
seller's sale and simultaneous leaseback transaction involving real estate,
including real estate with equipment. Due to forms of continuing involvement, we
will account for the transaction as a financing for accounting purposes and not
a sale. As such, we have not classified the assets as held for sale on our
Consolidated Balance Sheets.

     NUCLEAR PLANT DECOMMISSIONING: The MPSC and the FERC regulate the recovery
of costs to decommission, or remove from service, our Big Rock and Palisades
nuclear plants. Decommissioning funding practices approved by the MPSC require
us to file a report on the adequacy of funds for decommissioning at three-year
intervals. We prepared and filed updated cost estimates for Big Rock and
Palisades in March 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. Big Rock's estimated cost includes historical
expenditures in nominal dollars and future costs in 2003 dollars, with all
Palisades costs given in 2003 dollars. Updated cost projections for Big Rock
indicate an anticipated decommissioning cost of $390 million as of December
2006.

     BIG ROCK: In December 2000, funding of the Big Rock trust fund stopped
because the MPSC-authorized decommissioning surcharge collection period expired.
In our March 2004 report to the MPSC, we indicated that we would manage the
decommissioning trust fund to meet annual NRC financial assurance requirements
by withdrawing NRC radiological decommissioning costs from the fund and
initially funding non-NRC greenfield costs out of corporate funds. In March
2006, we contributed $16 million to the trust fund from our corporate funds to
support NRC radiological decommissioning costs. Excluding the additional nuclear
fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we
are projecting that the level of funds provided by the trust will fall short of
the amount needed to complete the decommissioning by an additional $37 million.
This total of $53 million, which are costs associated with NRC radiological and
non-NRC greenfield decommissioning work, are being funded out of corporate
funds. We plan to seek recovery of such expenditures recorded on our
consolidated balance sheets in future filings with the MPSC.


                                      CE-46

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     We have incurred Big Rock expenditures, excluding nuclear fuel storage
costs, of $41 million for the year ended December 31, 2006, and cumulative
expenditures through December 31, 2006 of $386 million. These activities had no
material impact on consolidated net income. At December 31, 2006, we have an
investment in nuclear decommissioning corporate funded trust funds of $4 million
for Big Rock. In addition, at December 31, 2006, we have charged $10 million to
our FERC jurisdictional depreciation reserve for the decommissioning of Big
Rock.

     PALISADES: Excluding additional nuclear fuel storage costs due to the DOE's
failure to accept spent fuel on schedule, we concluded, based on the cost
estimates filed in March 2004, that the existing Palisades' surcharge of $6
million needed to be increased to $25 million annually, beginning January 2006.
A settlement agreement was approved by the MPSC, providing for the continuation
of the existing $6 million annual decommissioning surcharge through 2011, which
was our original license expiration date, and for the next periodic review to be
filed in March 2007. Amounts collected from electric retail customers and
deposited in trusts, including trust earnings, are credited to a regulatory
liability.

     At December 31, 2006, we have an investment in the MPSC nuclear
decommissioning trust funds of $587 million for Palisades. In addition, at
December 31, 2006, we have a FERC decommissioning trust fund with a balance of
$11 million. In the FERC's February 2007 order regarding the Pailsades sale, the
FERC granted our request to apply the $11 million FERC decommissioning trust
fund balance toward the Big Rock decommissioning shortfall, subject to the
outcome of the NRC operating license transfer proceedings and completion of the
Palisades sale transaction. For additional details on decommissioning costs
accounted for as asset retirement obligations, see Note 7, Asset Retirement
Obligations.

     In March 2005, the NMC, which operates the Palisades plant, applied for a
20-year license renewal for the plant on behalf of Consumers. In January 2007,
the NRC renewed the Palisades operating license for 20 years, extending it to
2031. At this time, we cannot determine what impact this will have on
decommissioning costs or the adequacy of funding. Initial estimates of
decommissioning costs, assuming a plant retirement date of 2031, show
decommissioning costs of either $818 million or $1.049 billion for Palisades,
depending on the decommissioning methodology assumed. These costs, which exclude
additional costs for spent nuclear fuel storage due to the DOE's failure to
accept spent nuclear fuel on schedule, are given in 2003 dollars.

     NUCLEAR MATTERS:

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

     There are two court decisions that support the right of utilities to pursue
damage claims in the United States Court of Claims against the DOE for failure
to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims. We filed our complaint in
December 2002. If our litigation against the DOE is successful, we plan to use
any recoveries as reimbursement for the incurred costs of spent nuclear fuel
storage. We can make no assurance that the litigation against the DOE will be
successful.

     In 2002, the site at Yucca Mountain, Nevada was designated for the
development of a repository for the disposal of high-level radioactive waste and
spent nuclear fuel. We expect that the DOE, in due course, will submit a final
license application to the NRC for the repository. The application and review
process is estimated to take several years.

     Insurance: We maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain nuclear property insurance from NEIL totaling $2.750
billion and insurance that would partially cover the cost of replacement power
during certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $30 million in any policy
year if insured losses in excess of NEIL's

                                      CE-47

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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 energy
hazard for up to approximately $10.761 billion, the maximum insurance liability
limits established by the Price-Anderson Act. Part of the Price-Anderson Act's
financial protection is a mandatory industry-wide program under which owners of
nuclear generating facilities could be assessed if a nuclear incident occurs at
any nuclear generating facility. The maximum assessment against us could be $101
million per occurrence, limited to maximum annual installment payments of $15
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. This requirement will
end December 31, 2007.

     Big Rock remains insured for nuclear liability up to $544 million through
nuclear insurance and NRC indemnity, and maintains a nuclear property insurance
policy from NEIL.

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

GAS CONTINGENCIES

     GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remediation
costs at a number of sites under the Michigan Natural Resources and
Environmental Protection Act, a Michigan statute that covers environmental
activities including remediation. These sites include 23 former manufactured gas
plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or
may own only a portion of the original site. In 2005, we estimated our remaining
costs to be between $29 million and $71 million, based on 2005 discounted costs,
using a discount rate of three percent. The discount rate represents a 10-year
average of U.S. Treasury bond rates reduced for increases in the consumer price
index. We expect to fund most of these costs through proceeds derived from a
settlement with insurers and MPSC-approved rates. At December 31, 2006, we have
a liability of $24 million, net of $59 million of expenditures incurred to date,
and a regulatory asset of $56 million. The timing of payments related to the
remediation of our manufactured gas plant sites is uncertain. 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 and
the timing our remediation payments.

GAS RATE MATTERS

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


                                      CE-48

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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

GAS COST RECOVERY RECONCILIATION


<Table>
<Caption>
                                    NET OVER-    GCR COST
 GCR YEAR  DATE FILED  ORDER DATE   RECOVERY    OF GAS SOLD     DESCRIPTION OF NET OVERRECOVERY
---------  ----------  ----------  ----------  ------------   ----------------------------------

<S>        <C>         <C>         <C>         <C>            <C>

2004-2005  June 2005   April 2006  $2 million  $1.4 billion   The net overrecovery includes
                                                              interest expense through March
                                                              2005 and refunds that we received
                                                              from our suppliers that are
                                                              required to be refunded to our
                                                              customers.
2005-2006  June 2006   Pending     $3 million  $1.8 billion   The net overrecovery includes $1
                                                              million interest income through
                                                              March 2006, which resulted from a
                                                              net underrecovery position during
                                                              the majority of the GCR period.
</Table>


     GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for
our 2005-2006 GCR Plan year, which resulted in approval of a settlement
agreement and established a fixed price cap of $10.10 per mcf for the December
2005 through March 2006 billing period. We were able to maintain our billing GCR
factor below the authorized level for that period. The order was appealed to the
Michigan Court of Appeals by one intervenor. We are unable to predict the
outcome of this proceeding.

     GCR plan for year 2006-2007: In December 2005, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2006
through March 2007. Our request proposed using a GCR factor consisting of:

     - a base GCR ceiling factor of $11.10 per mcf, plus

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

     In July 2006, all parties signed a partial settlement agreement, which
calls for a base GCR ceiling factor of $9.48 per mcf. The settlement agreement
base GCR ceiling factor is subject to a quarterly GCR ceiling price adjustment
mechanism. The adjustment mechanism allows an adjustment of the base ceiling
factor to reflect a portion of cost increases, if the average NYMEX price for a
specified period is greater than that used in calculating the base GCR factor.
The MPSC approved the settlement agreement in August 2006.

     The GCR billing factor is adjusted monthly in order to minimize the over or
underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor
for the month of February 2007 is $7.63 per mcf.

     GCR plan for year 2007-2008: In December 2006, we filed an application with
the MPSC seeking approval of a GCR plan for the 12-month period of April 2007
through March 2008. Our request proposed using a GCR factor consisting of:

     - a base GCR ceiling factor of $8.47 per mcf, plus

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

     2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC for
an annual gas rate increase of $132 million. In May 2006, the MPSC issued an
order granting us interim rate relief of $18 million annually.

     In November 2006, the MPSC issued an order granting rate relief of $81
million, which included the $18 million of interim relief granted in May 2006.
The MPSC authorized an 11 percent return on common equity, a reduction from our
then current 11.4 percent authorized rate of return. In addition, the order made
permanent the collection of a $58 million surcharge granted in October 2004.

     2007 GAS RATE CASE: In February 2007, we filed an application with the MPSC
for an annual gas rate increase of $88 million and an 11.25 percent authorized
return on equity. We have proposed the use of a Revenue Decoupling

                                      CE-49

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



and Conservation Incentive Mechanism for residential and general service rate
classes to help assure a reasonable opportunity to recover costs that do not
fluctuate with volumetric changes.

OTHER CONTINGENCIES

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

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

     FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE
REQUIREMENTS FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF
OTHERS: The Interpretation requires the guarantor, upon issuance of a guarantee,
to recognize a liability for the fair value of the obligation it undertakes in
issuing the guarantee.

     The following table describes our guarantees at December 31, 2006:


<Table>
<Caption>
                                                             EXPIRATION      MAXIMUM     CARRYING
GUARANTEE DESCRIPTION                         ISSUE DATE        DATE       OBLIGATION     AMOUNT
---------------------                         ----------     ----------    ----------    --------
                                                                                 IN MILLIONS

<S>                                          <C>             <C>           <C>           <C>

Surety bonds and other indemnifications      Various         Various          $  1          --
Guarantee                                    January 1987    March 2016         85          --
Nuclear insurance retrospective premiums     Various         Indefinite        137          --
</Table>


     The following table provides additional information regarding our
guarantees:


<Table>
<Caption>
                                                                         EVENTS THAT WOULD
GUARANTEE DESCRIPTION                        HOW GUARANTEE AROSE        REQUIRE PERFORMANCE
---------------------                        -------------------        -------------------

<S>                                       <C>                        <C>

Surety bonds and other indemnifications   Normal operating           Nonperformance
                                          activity, permits and
                                          licenses
Guarantee                                 Agreement to provide       MCV Partnership's
                                          power and steam to Dow     nonperformance or non-
                                                                     payment under a related
                                                                     contract
Nuclear insurance retrospective premiums  Normal operations of       Call by NEIL and Price-
                                          nuclear plants             Anderson Act for nuclear
                                                                     incident
</Table>


     At December 31, 2006, none of our guarantees contained provisions allowing
us to recover, from third parties, amounts paid under the guarantees with the
exception of the Consumers guarantee to provide power and steam to Dow.

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

     We enter into various agreements containing tax and other indemnification
provisions in connection with a variety of transactions, including the sale of
our interests in the MCV Partnership and the FMLP. While we are unable to
estimate the maximum potential obligation related to these indemnities, we
consider the likelihood that we

                                      CE-50

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



would be required to perform or incur significant losses related to these
indemnities and the guarantees listed in the preceding tables to be remote.

4:  FINANCINGS AND CAPITALIZATION

     Long-term debt at December 31 follows:


<Table>
<Caption>
                                              INTEREST RATE (%)     MATURITY   2006    2005
                                              -----------------     --------   ----    ----
                                                                               (IN MILLIONS)

<S>                                           <C>                  <C>        <C>     <C>

  First mortgage bonds......................         4.250            2008    $  250  $  250
                                                     4.800            2009       200     200
                                                     4.400            2009       150     150
                                                     4.000            2010       250     250
                                                     5.000            2012       300     300
                                                     5.375            2013       375     375
                                                     6.000            2014       200     200
                                                     5.000            2015       225     225
                                                     5.500            2016       350     350
                                                     5.150            2017       250     250
                                                     5.650            2020       300     300
                                                     5.650            2035       147     150
                                                     5.800            2035       175     175
                                                                              ------  ------
                                                                               3,172   3,175
                                                                              ------  ------
  Senior notes..............................         6.375            2008       159     159
                                                     6.875            2018       180     180
                                                                              ------  ------
                                                                                 339     339
                                                                              ------  ------
  Securitization bonds......................         5.384(a)      2007-2015     340     369
                                                                              ------  ------
  FMLP Debt:
     Subordinated secured notes.............        13.250                        --      56
     Tax-exempt subordinated secured notes..         6.875                        --     137
     Tax-exempt subordinated secured notes..         6.750                        --      14
                                                                              ------  ------
                                                                                  --     207
                                                                              ------  ------
  Nuclear fuel disposal liability...........                          (b)        152     145
  Tax-exempt pollution control revenue
     bonds..................................       Various         2010-2035     161     161
                                                                              ------  ------
                                                                                 313     306
                                                                              ------  ------
Total principal amounts outstanding.........                                   4,164   4,396
  Current amounts...........................                                     (31)    (85)
  Net unamortized discount..................                                      (6)     (8)
                                                                              ------  ------
Total Long-term debt........................                                  $4,127  $4,303
                                                                              ======  ======

</Table>


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

(a)     Represents the weighted average interest rate at December 31, 2006
        (5.295 percent at December 31, 2005).

(b)     Maturity date uncertain.

     DEBT RETIREMENTS: The following is a summary of significant long-term debt
retirements during 2006:


<Table>
<Caption>
                                        PRINCIPAL
                                      (IN MILLIONS)  INTEREST RATE (%)  RETIREMENT DATE  MATURITY DATE
                                      -------------  -----------------  ---------------  -------------

<S>                                   <C>            <C>                <C>              <C>

Long-term debt -- related parties...       $129              9.00        February 2006     June 2031
FMLP debt...........................         56             13.25            July 2006     July 2006
FMLP debt(a)........................        151           Various        November 2006     July 2009
                                           ----
  Total.............................       $336
                                           ====

</Table>




                                      CE-51

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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

(a)     FMLP debt of $151 million was removed as part of the November 2006
        transaction in which we sold our interest in the FMLP.

     FIRST MORTGAGE BONDS: We secure our FMB by a mortgage and lien on
substantially all of our property. Our ability to issue FMB is restricted by
certain provisions in the first mortgage bond indenture and the need for
regulatory approvals under federal law. Restrictive new issuance provisions in
our first mortgage bond indenture include achieving a two-times interest
coverage ratio and having sufficient net unfunded property additions.

     SECURITIZATION BONDS: Certain regulatory assets collateralize
Securitization bonds. The bondholders have no recourse to our other assets.
Through our rate structure, we bill customers for securitization surcharges to
fund the payment of principal, interest, and other related expenses on the
Securitization bonds. Securitization surcharges collected are remitted to a
trustee for the Securitization bonds and are not available to our creditors.
Securitization surcharges totaled $50 million in 2006 and 2005.

     DEBT MATURITIES: At December 31, 2006, the aggregate annual contractual
maturities for long-term debt for the next five years are:



<Table>
<Caption>
                                                               PAYMENTS DUE
                                                       ----------------------------
                                                       2007  2008  2009  2010  2011
                                                       ----  ----  ----  ----  ----
                                                               (IN MILLIONS)

<S>                                                    <C>   <C>   <C>   <C>   <C>

Long-term debt.......................................   $31  $441  $384  $343   $37
                                                        ===  ====  ====  ====   ===

</Table>



     REGULATORY AUTHORIZATION FOR FINANCINGS: In May 2006, the FERC issued an
order authorizing us to issue up to $2.0 billion of secured and unsecured short-
term securities for the following purposes:

     - up to $1.0 billion for general corporate purposes,

     - up to $1.0 billion of FMB or other securities to be issued solely as
       collateral for other short-term securities.

     Also in May 2006, the FERC issued an order authorizing us to issue up to
$5.0 billion of secured and unsecured long-term securities for the following
purposes:

     - up to $1.5 billion for general corporate purposes,

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

     - up to $2.5 billion of FMB or other securities to be issued solely as
       collateral for other long-term securities.

     The authorizations are for a two-year period beginning July 1, 2006 and
ending June 30, 2008. Any long-term issuances during the two-year authorization
period are exempt from FERC's competitive bidding and negotiated placement
requirements.

     REVOLVING CREDIT FACILITIES: The following secured revolving credit
facilities with banks are available at December 31, 2006:



<Table>
<Caption>
                                                                            OUTSTANDING
                                                       AMOUNT OF   AMOUNT   LETTERS-OF-    AMOUNT
COMPANY                               EXPIRATION DATE   FACILITY  BORROWED     CREDIT    AVAILABLE
-------                               ---------------  ---------  --------  -----------  ---------
                                                                      (IN MILLIONS)

<S>                                   <C>              <C>        <C>       <C>          <C>

Consumers...........................   March 30, 2007     $300       $--        $--         $300
Consumers...........................     May 18, 2010      500        --         58          442
</Table>



     Effective February 2007, we terminated the $300 million facility.

     DIVIDEND RESTRICTIONS: Under the provisions of our articles of
incorporation, at December 31, 2006, we had $215 million of unrestricted
retained earnings available to pay common stock dividends. Covenants in our debt
facilities cap common stock dividend payments at $300 million in a calendar
year. Provisions of the Federal Power

                                      CE-52

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



Act and the Natural Gas Act effectively restrict dividends to the amount of our
retained earnings. During 2006, we paid $147 million in common stock dividends
to CMS Energy.

     SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we sell certain accounts receivable to a wholly owned, consolidated,
bankruptcy remote special purpose entity. In turn, the special purpose entity
may sell an undivided interest in up to $325 million of the receivables. The
special purpose entity sold $325 million of receivables at December 31, 2006 and
December 31, 2005. 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 no right to any
receivables not sold. We have neither recorded a gain or loss on the receivables
sold nor retained interest in the receivables sold.

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



<Table>
<Caption>
YEARS ENDED DECEMBER 31                                            2006     2005
-----------------------                                            ----     ----
                                                                   (IN MILLIONS)

<S>                                                               <C>      <C>

Net cash flow as a result of accounts receivable financing......  $   --   $   21
Collections from customers......................................  $5,684   $4,859
                                                                  ======   ======

</Table>



     PREFERRED STOCK: Our Preferred Stock outstanding follows:



<Table>
<Caption>
                                                    OPTIONAL   NUMBER OF SHARES
                                                   REDEMPTION  ----------------
DECEMBER 31                                SERIES     PRICE      2006     2005   2006  2005
-----------                                ------  ----------    ----     ----   ----  ----
                                                                                     (IN
                                                                                  MILLIONS)

<S>                                        <C>     <C>         <C>      <C>      <C>   <C>

Preferred Stock
  Cumulative $100 par value, Authorized
     7,500,000 shares, with no mandatory
     redemption..........................   $4.16    $103.25    68,451   68,451   $ 7   $ 7
                                            $4.50    $110.00   373,148  373,148    37    37
                                                                                  ---   ---
Total Preferred Stock....................                                         $44   $44
                                                                                  ===   ===

</Table>



5:  FINANCIAL AND DERIVATIVE INSTRUMENTS

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

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


<Table>
<Caption>
                                                   2006                           2005
                                       ----------------------------   ----------------------------
                                                 FAIR    UNREALIZED             FAIR    UNREALIZED
DECEMBER 31                             COST     VALUE      GAIN       COST     VALUE     (LOSS)
-----------                            ------   ------   ----------   ------   ------   ----------
                                                               IN MILLIONS

<S>                                    <C>      <C>      <C>          <C>      <C>      <C>

Long-term debt(a)....................  $4,158   $4,111       $47      $4,388   $4,393       $(5)
Long-term debt -- related
  parties(b).........................      --       --        --         129      131        (2)
</Table>


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

   (a) Includes current maturities of $31 million at December 31, 2006 and $85
       million at December 31, 2005. Settlement of long-term debt is generally
       not expected until maturity.

   (b) Includes current maturities of $129 million at December 31, 2005.


                                      CE-53

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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


<Table>
<Caption>
                                               2006                                     2005
                              --------------------------------------   --------------------------------------
                                     UNREALIZED   UNREALIZED    FAIR          UNREALIZED   UNREALIZED    FAIR
DECEMBER 31                   COST      GAINS       LOSSES     VALUE   COST      GAINS       LOSSES     VALUE
-----------                   ----   ----------   ----------   -----   ----   ----------   ----------   -----
                                                                IN MILLIONS

<S>                           <C>    <C>          <C>          <C>     <C>    <C>          <C>          <C>

Common stock of CMS
  Energy(a).................  $ 10      $ 26          $--       $ 36   $ 10      $ 23          $--       $ 33
Nuclear decommissioning
  investments(b):
  Equity securities.........   140       150           (4)       286    134       123           (5)       252
  Debt securities...........   307         4           (2)       309    287         6           (2)       291
SERP:
  Equity securities.........    17         9           --         26     16         6           --         22
  Debt securities...........     6        --           --          6      8        --           --          8
</Table>


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

   (a) At December 31, 2006, we held 2.2 million shares, and at December 31,
       2005, we held 2.3 million shares of CMS Energy Common Stock.

   (b) Nuclear decommissioning investments include cash and cash equivalents and
       accrued income totaling $7 million at December 31, 2006 and $12 million
       at December 31, 2005. Unrealized gains and losses on nuclear
       decommissioning investments are reflected as regulatory liabilities.

     The fair value of available-for-sale debt securities by contractual
maturity at December 31, 2006 is follows:


<Table>
<Caption>
                                                                      (IN MILLIONS)

<S>                                                                   <C>

Due in one year or less.............................................       $ 38
Due after one year through five years...............................         94
Due after five years through ten years..............................         73
Due after ten years.................................................        110
                                                                           ----
  Total.............................................................       $315
                                                                           ----

</Table>


     In July 2006, we reached an agreement to sell Palisades and the Big Rock
ISFSI to Entergy. Entergy will assume responsibility for the future
decommissioning of the plant and for storage and disposal of spent nuclear fuel.
Accordingly, upon completion of the sale, we will transfer $400 million of
nuclear decommissioning trust fund assets to Entergy and retain $205 million. We
will also be entitled to receive a return of $147 million, pending either a
favorable federal tax ruling regarding the release of the funds, or if no such
ruling is issued, after decommissioning of the Palisades site is complete. These
estimates fluctuate based on existing market conditions and the closing date of
the transaction. The disposition of the retained and receivable nuclear
decommissioning funds is subject to regulatory proceedings.

     Our held-to-maturity investments consist of debt securities held by the MCV
Partnership totaling $91 million at December 31, 2005. They were removed as part
of the November 2006 transaction in which we sold our interest in the MCV
Partnership. These securities represent funds restricted primarily for future
lease payments and are classified as Other assets on our Consolidated Balance
Sheets. These investments had original maturity dates of approximately one year
or less and, because of their short-term maturities, carrying amounts
approximate fair value.

     DERIVATIVE INSTRUMENTS: In order to limit our exposure to certain market
risks, we may enter into various risk management contracts, such as swaps,
options, futures, and forward contracts. These contracts, used primarily to
manage our exposure to changes in interest rates and commodity prices, are
entered into for purposes other than trading. We enter into these contracts
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.


                                      CE-54

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     The contracts we use to manage market risks may qualify as derivative
instruments that are subject to derivative and hedge accounting under SFAS No.
133. If a contract is a derivative, it is recorded on our consolidated balance
sheet at its fair value. We then adjust the resulting asset or liability each
quarter to reflect any change in the market value of the contract, a practice
known as marking the contract to market. From time to time, we enter into cash
flow hedges. If a derivative qualifies for cash flow hedge accounting treatment,
the changes in fair value (gains or losses) are reported in AOCI; otherwise, the
changes are reported in earnings.

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

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

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

     - the forecasted transaction being hedged must be probable.

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

     To determine the fair value of our derivatives, we use information from
external sources (i.e., quoted market prices and third-party valuations), if
available. For certain contracts, this information is not available and we use
mathematical valuation models to value our derivatives. These models require
various inputs and assumptions, including commodity market prices and
volatilities, as well as interest rates and contract maturity dates. The cash
returns we actually realize on these contracts may vary, either positively or
negatively, from the results that we estimate using these models. As part of
valuing our derivatives at market, we maintain reserves, if necessary, for
credit risks arising from the financial condition of our counterparties.

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

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

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

     - there is not an active market for the commodity.

     Our coal purchase contracts are not derivatives because there is not an
active market for the coal we purchase. If an active market for coal develops in
the future, some of these contracts may qualify as derivatives and the resulting
mark-to-market impact on earnings could be material.

     In 2005, the MISO began operating the Midwest Energy Market. As of December
31, 2006, we have determined that, due to the increased liquidity for
electricity within the Midwest Energy Market since its inception, it is our best
judgment that this market should be considered an active market, as defined by
SFAS No. 133. This conclusion does not impact how we account for our electric
capacity and energy contracts, however, because these contracts qualify for the
normal purchases and sales exception and, as a result, are not required to be
marked-to-market.


                                      CE-55

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk. The following table summarizes our derivative
instruments:



<Table>
<Caption>
DECEMBER 31                                            2006                     2005
-----------                                  -----------------------  ------------------------
                                                    FAIR  UNREALIZED         FAIR   UNREALIZED
DERIVATIVE INSTRUMENTS                       COST  VALUE     GAIN     COST  VALUE  GAIN (LOSS)
----------------------                       ----  -----  ----------  ----  -----  -----------
                                                               (In Millions)

<S>                                          <C>   <C>    <C>         <C>   <C>    <C>

Gas supply option contracts................   $--   $--       $--      $ 1   $ (1)     $ (2)
FTRs.......................................    --    --        --       --      1         1
Derivative contracts associated with the
  MCV Partnership:
  Long-term gas contracts(a)...............    --    --        --       --    205       205
  Gas futures, options, and swaps(a).......    --    --        --       --    223       223
                                              ===   ===       ===      ===   ====      ====

</Table>



--------

(a)     The fair value of the MCV Partnership's long-term gas contracts and gas
        futures, options, and swaps has decreased to $0 as a result of the sale
        of our interest in the MCV Partnership in November 2006. In conjunction
        with that sale, our interest in these contracts was also sold and, as a
        result, we no longer record the fair value of these contracts on our
        Consolidated Balance Sheets.

     At December 31, 2005, we recorded the fair value of our derivative
contracts in Derivative instruments, Other assets, or Other liabilities on our
Consolidated Balance Sheets.

     GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses gas supply call
and put options to meet our regulatory obligation to provide gas to our
customers at a reasonable and prudent cost. As part of regulatory accounting,
the mark-to-market gains and losses associated with these options are reported
directly in earnings as part of Other income, and then immediately reversed out
of earnings and recorded on our consolidated balance sheet as a regulatory asset
or liability.

     FTRS: With the creation of the Midwest Energy Market, FTRs were
established. FTRs are financial instruments that manage price risk related to
electricity transmission congestion. An FTR entitles its holder to receive
compensation (or, conversely, to remit payment) for congestion-related
transmission charges. As part of regulatory accounting, the mark-to-market gains
and losses associated with these instruments are reported directly in earnings
as part of Other income, and then immediately reversed out of earnings and
recorded on our consolidated balance sheet as a regulatory asset or liability.

     DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: In November 2006,
we sold our interest in the MCV Partnership. In conjunction with that sale, our
interest in all of the MCV Partnership's long-term gas contracts and related
futures, options, and swaps was sold. Before the sale, we accounted for certain
long-term gas contracts and all of the related futures, options, and swaps as
derivatives.

     Long-term gas contracts: The MCV Partnership used long-term gas contracts
to purchase and manage the cost of the natural gas it needed to generate
electricity and steam. The MCV Partnership determined that certain of these
contracts qualified as normal purchases under SFAS No. 133. Accordingly, we did
not recognize these contracts at fair value on our Consolidated Balance Sheets.

     The MCV Partnership also held certain long-term gas contracts that did not
qualify as normal purchases because they contained volume optionality or because
the gas was not expected to be used to generate electricity or steam in the
normal course of business. Accordingly, prior to the sale, we accounted for
these contracts as derivatives, with changes in fair value recorded in earnings
each quarter.

     During 2006, through the date of the sale, we recorded a $151 million loss,
before considering tax effects and minority interest, associated with the net
decrease in fair value of these long-term gas contracts. This loss is included
in the total Fuel costs mark-to-market at the MCV Partnership in our
Consolidated Statements of Income

                                      CE-56

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



(Loss). As a result of the sale, we no longer consolidate the MCV Partnership.
Accordingly, we will no longer record the fair value of the long-term gas
contracts on our Consolidated Balance Sheets and will not be required to record
gains or losses related to changes in the fair value of these contracts in
earnings.

     Gas Futures, Options, and Swaps: The MCV Partnership entered into natural
gas futures, options, and over-the-counter swap transactions in order to hedge
against unfavorable changes in the market price of natural gas. The MCV
Partnership used these financial instruments to:

     - ensure an adequate supply of natural gas for the projected generation and
       sales of electricity and steam, and

     - manage price risk by fixing the price to be paid for natural gas on some
       of its long-term gas contracts.

     Certain of the futures and swaps held by the MCV Partnership qualified for
cash flow hedge accounting and, prior to the sale, we recorded our proportionate
share of their mark-to-market gains and losses in AOCI. As of the date of the
sale, we had accumulated a net gain of $30 million, net of tax and minority
interest, in AOCI representing our proportionate share of mark-to-market gains
from these cash flow hedges. After the sale, this amount was reclassified to and
recognized in earnings as a reduction of the total loss on the sale in our
Consolidated Statements of Income (Loss).

     The remaining futures, options, and swap contracts held by the MCV
Partnership did not qualify as cash flow hedges and we recorded any changes in
their fair value in earnings each quarter. During 2006, through the date of the
sale, we recorded a $53 million loss, before considering tax effects and
minority interest, associated with the net decrease in fair value of these
contracts. This loss is included in the total Fuel costs mark-to-market at the
MCV Partnership in our Consolidated Statements of Income (Loss).

     As a result of the sale, we will no longer record the fair value of the
futures, options, and swaps on our Consolidated Balance Sheets and will not be
required to record gains or losses related to changes in the fair value of these
contracts in earnings or AOCI. For additional details on the sale of our
interest in the MCV Partnership, see Note 2, Asset Sales and Impairment Charges.

6: RETIREMENT BENEFITS

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

     - a non-contributory, defined benefit Pension Plan,

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

     - a DCCP for employees hired on or after September 1, 2005,

     - benefits to certain management employees under SERP,

     - a defined contribution 401(k) Savings Plan,

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

     - health care and life insurance benefits under OPEB.

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

     On September 1, 2005, we implemented the DCCP. The DCCP provides an
employer contribution of 5 percent of base pay to the existing employees'
Savings Plan. No employee contribution is required in order to receive the
plan's employer contribution. All employees hired on and after September 1, 2005
participate in this plan as part of their retirement benefit program. Cash
balance pension plan participants also participate in the DCCP as of September
1, 2005. Additional pay credits under the cash balance pension plan were
discontinued as of that date. The DCCP expense was $2 million for the year ended
December 31, 2006 and less than $1 million for the year ended December 31, 2005.


                                      CE-57

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     Effective January 11, 2006, the MPSC electric rate order authorized us to
include $33 million of electric pension expense in our electric rates. Effective
November 21, 2006, the MPSC gas rate order authorized us to include $22 million
of gas pension expense in our gas rates. Due to the volatility of these costs,
the orders also established a pension equalization mechanism to track actual
costs. If actual pension expenses are greater than the amounts included in rate
cases, the difference will be recognized as a regulatory asset for future
recovery from customers. If actual pension expenses are less than the amounts
included in rate cases, the difference will be recognized as a regulatory
liability, and refunded to our customers. The difference between pension
expenses allowed in Consumers' rate cases and Consumers' $66 million net pension
cost under SFAS No. 87 resulted in the recognition of a regulatory asset of $11
million.

     SERP:  SERP benefits are paid from a trust established in 1988. SERP is not
a qualified plan under the Internal Revenue Code. SERP trust earnings are
taxable and trust assets are included in our consolidated assets. Trust assets
were $32 million at December 31, 2006 and $30 million at December 31, 2005. The
assets are classified as Other non-current assets on our Consolidated Balance
Sheets. The ABO for SERP was $37 million at December 31, 2006 and $35 million at
December 31, 2005.

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

     401(k): The employer's match for the 401(k) Savings Plan, which was
suspended on September 1, 2002, resumed on January 1, 2005. The employer's match
is in CMS Energy Common Stock. On September 1, 2005, employees enrolled in the
company's 401(k) Savings Plan had their employer match increased from 50 percent
to 60 percent on eligible contributions up to the first six percent of an
employee's wages. The total 401(k) Savings Plan cost was $14 million for the
year ended December 31, 2006 and $12 million for the year ended December 31,
2005.

     Beginning May 1, 2007 the CMS Energy Common Stock Fund will no longer be an
investment option available for new investments in the 401(k) Savings Plan and
the employer's match will no longer be in CMS Energy Common Stock. Participants
will have the opportunity to reallocate investments in CMS Energy Stock Fund to
other plan investment alternatives. Beginning November 1, 2007 any remaining
shares in the CMS Energy Stock Fund will be sold and the sale proceeds will be
reallocated to other plan investment options. At February 20, 2007, there were
10.7 million shares of CMS Energy Common Stock in the CMS Energy Stock Fund.

     The MCV Partnership sponsors a defined contribution retirement plan and a
401(k) Savings Plan covering all employees. Amounts contributed under these
plans were $1 million for the period January 1, 2006 through November 21, 2006
and $1 million for each of the years ended December 31, 2005 and 2004.

     EISP: We implemented an EISP in 2002 to provide flexibility in separation
of employment by officers, a select group of management, or other highly
compensated employees. Terms of the plan may include payment of a lump sum,
payment of monthly benefits for life, payment of premiums for continuation of
health care, or any other legally permissible term deemed to be in our best
interest to offer. The EISP expense was less than $1 million for each of the
years ended December 31, 2006 and 2005. The ABO for the EISP was less than $1
million at December 31, 2006 and December 31, 2005.

     OPEB: The OPEB plan covers all regular full-time employees covered by the
employee health care plan on a company-subsidized basis the day before they
retire from the company at age 55 or older and who have at least 10 full years
of applicable continuous service. Regular full-time employees who qualify for a
disability retirement and have 15 years of applicable continuous service are
also eligible. Retiree health care costs were based on the assumption that costs
would increase 10 percent in 2006. Starting in 2007, we will use two health care
trend rates:

                                      CE-58

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



one for retirees under 65 and the other for retirees 65 and over. The two health
care trend rates recognize that prescription drug costs are increasing at a
faster pace than other medical claim costs and that prescription drug costs make
up a larger portion of expenses for retirees age 65 and over. The 2007 rate of
increase for OPEB health costs for those under 65 is expected to be 9 percent
and for those over 65 is expected to be 10.5 percent. The rate of increase is
expected to slow to 5 percent for those under 65 by 2011 and for those over 65
by 2013 and thereafter.

     Effective January 11, 2006, the MPSC electric rate order authorized us to
include $28 million of electric OPEB expense in our electric rates. Effective
November 21, 2006, the MPSC gas rate order authorized us to include $21 million
of gas OPEB expense in our gas rates. Due to the volatility of these costs, the
orders also established an OPEB equalization mechanism to track actual costs. If
actual OPEB expenses are greater than the amounts included in rate cases, the
difference will be recognized as a regulatory asset for future recovery from our
customers. If actual OPEB expenses are less than the amounts included in rate
cases, the difference will be recognized as a regulatory liability, and refunded
to our customers. The difference between OPEB expenses allowed in Consumers'
rate cases and Consumers' $51 million net OPEB cost under SFAS No. 106 resulted
in the recognition of a regulatory asset of $2 million.

     The MCV Partnership sponsors defined cost postretirement health care plans
that cover all full-time employees, except key management. The ABO of the MCV
Partnership's postretirement plans was $5 million at December 31, 2005. The MCV
Partnership's net periodic postretirement health care cost for the period
January 1, 2006 through November 21, 2006 and year ended December 31, 2005 was
less than $1 million.

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


<Table>
<Caption>
                                                                               ONE
                                                        ONE PERCENTAGE     PERCENTAGE
                                                        POINT INCREASE   POINT DECREASE
                                                        --------------   --------------
                                                                 (IN MILLIONS)

<S>                                               <C>   <C>              <C>

Effect on total service and interest cost
  component.....................................             $ 18             $ (15)
Effect on postretirement benefit obligation.....             $211             $(179)
</Table>


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

     The measurement date for all CMS Energy plans is November 30 for 2006, 2005
and 2004. We changed our measurement date in 2004 from December 31 to November
30, which resulted in a $1 million cumulative effect of change in accounting for
retirement benefits, net of tax benefit, as a decrease to earnings. We also
increased the amount of accrued benefit cost on our Consolidated Balance Sheets
by $2 million. The measurement date for the MCV Partnership's plan was December
31 for 2005 and 2004.

     SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other
Postretirement Plans -- an amendment of FASB Statements No. 87, 88, 106, and
132(R):  In September 2006, the FASB issued SFAS No. 158. This standard requires
us to recognize the funded status of our defined benefit postretirement plans on
our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 requires us
to recognize changes in the funded status of our plans in the year in which the
changes occur. This standard also requires that we change our plan measurement
date from November 30 to December 31, effective December 31, 2008. We do not
believe that implementation of this provision of the standard will have a
material effect on our consolidated financial statements. We expect to adopt the
measurement date provisions of SFAS No. 158 in 2008.

     The following table recaps the incremental effect of applying SFAS No. 158
on individual line items on our Consolidated Balance Sheets. The adoption of
SFAS No. 158 had no effect on our Consolidated Statements of

                                      CE-59

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



Income (Loss) for the year ended December 31, 2006, or for any prior period
presented, and it will not affect our operating results in future periods. Had
we not been required to adopt SFAS No. 158 at December 31, 2006, we would have
recognized an additional minimum liability pursuant to the provisions of SFAS
No. 87. The effect of recognizing the additional minimum liability is included
in the following table in the column labeled "Before Application of SFAS No.
158:"


<Table>
<Caption>
                                                       BEFORE                         AFTER
                                                   APPLICATION OF                APPLICATION OF
YEAR ENDED DECEMBER 31, 2006                        SFAS NO. 158    ADJUSTMENT    SFAS NO. 158
----------------------------                       --------------   ----------   --------------
                                                                   (IN MILLIONS)

<S>                                                <C>              <C>          <C>

Regulatory asset(a)..............................      $   470         $ 680         $ 1,150
Intangible asset.................................           46           (46)             --
                                                       -------         -----         -------
Total assets.....................................          516           634           1,150
Liability for retirement benefits(b).............         (351)         (643)           (994)
Regulatory liabilities -- Income taxes, net(c)...         (459)          (80)           (539)
Deferred income taxes............................         (941)           83            (858)
                                                       -------         -----         -------
Total liabilities................................       (1,751)         (640)         (2,391)
Accumulated other comprehensive income...........            2             6               8
                                                       -------         -----         -------
Total decrease in stockholders' equity...........            2             6               8
                                                       =======         =====         =======

</Table>


--------

(a)    Consumers recognized the cost of their minimum liability prior to
       application of SFAS No. 158 and the adjustment resulting from adoption of
       SFAS No. 158 as a regulatory asset under SFAS No. 71 based upon guidance
       from the MPSC.

(b)    Liabilities for retirement benefits include $993 million that are non-
       current and $1 million that is current at December 31, 2006.

(C)    The adjustment represents the Medicare D Subsidy tax benefit of
       implementing SFAS No. 158.

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

WEIGHTED AVERAGE FOR BENEFIT OBLIGATIONS:


<Table>
<Caption>
                                              PENSION & SERP               OPEB
                                          ---------------------   ---------------------
YEARS ENDED DECEMBER 31                    2006    2005    2004    2006    2005    2004
-----------------------                   -----   -----   -----   -----   -----   -----

<S>                                       <C>     <C>     <C>     <C>     <C>     <C>

Discount rate...........................  5.65%   5.75%   6.00%   5.65%   5.75%   6.00%
Expected long-term rate of return on
  plan assets(a)........................  8.25%   8.50%   8.75%
  Union.................................                                          8.75%
  Non-Union.............................                                          6.00%
  Combined in 2005......................                          7.75%   8.00%
Mortality table(b)......................   2000    2000    1983    2000    2000    1983
Rate of compensation increase:
  Pension...............................  4.00%   4.00%   3.50%
  SERP..................................  5.50%   5.50%   5.50%
</Table>




                                      CE-60

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



WEIGHTED AVERAGE FOR NET PERIODIC BENEFIT COST:


<Table>
<Caption>
                                              PENSION & SERP               OPEB
                                          ---------------------   ---------------------
YEARS ENDED DECEMBER 31                    2006    2005    2004    2006    2005    2004
-----------------------                   -----   -----   -----   -----   -----   -----

<S>                                       <C>     <C>     <C>     <C>     <C>     <C>

Discount rate...........................  5.75%   5.75%   6.25%   5.75%   5.75%   6.25%
Expected long-term rate of return on
  plan assets(a)........................  8.50%   8.75%   8.75%
  Union.................................                                          8.75%
  Non-Union.............................                                          6.00%
  Combined in 2005......................                          8.00%   8.25%
Mortality table(b)......................   2000    2000    1983    2000    2000    1983
Rate of compensation increase:
  Pension...............................  4.00%   3.50%   3.25%
  SERP..................................  5.50%   5.50%   5.50%
</Table>


--------

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

(b)    Prior to 2005, we utilized the 1983 Group Annuity Mortality Table.
       Starting in 2005, we utilize the Combined Healthy RP-2000 Table from the
       2000 Group Annuity Mortality Tables.

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


<Table>
<Caption>
                                                                  PENSION & SERP
                                                               -------------------
YEARS ENDED DECEMBER 31                                        2006   2005    2004
-----------------------                                        ----   ----   -----
                                                                  (IN MILLIONS)

<S>                                                            <C>    <C>    <C>

Net periodic pension cost
  Service cost...............................................  $ 47   $ 41   $  36
  Interest expense...........................................    81     76      77
  Expected return on plan assets.............................   (80)   (89)   (109)
  Amortization of:
     Net loss................................................    41     33      14
     Prior service cost......................................     7      5       6
                                                               ----   ----   -----
  Net periodic pension cost..................................    96     66      24
  Regulatory adjustment......................................   (11)    --      --
                                                               ----   ----   -----
Net periodic pension cost after regulatory adjustment........  $ 85   $ 66   $  24
                                                               ====   ====   =====

</Table>




                                      CE-61

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)




<Table>
<Caption>
                                                                       OPEB
                                                                ------------------
YEARS ENDED DECEMBER 31                                         2006   2005   2004
-----------------------                                         ----   ----   ----
                                                                   (IN MILLIONS)

<S>                                                             <C>    <C>    <C>

Net periodic OPEB cost
  Service cost................................................  $ 22   $ 21   $ 18
  Interest expense............................................    60     58     54
  Expected return on plan assets..............................   (53)   (49)   (45)
  Amortization of:
     Net loss.................................................    20     20     11
     Prior service credit.....................................   (10)    (9)    (8)
                                                                ----   ----   ----
  Net periodic OPEB cost......................................    39     41     30
  Regulatory adjustment.......................................    (2)    --     --
                                                                ----   ----   ----
Net periodic OPEB cost after regulatory adjustment............  $ 37   $ 41   $ 30
                                                                ====   ====   ====

</Table>


     The estimated net loss and prior service cost for the defined benefit
pension plans that will be amortized from regulatory asset into net periodic
benefits cost over the next fiscal year is $50 million. The estimated net loss
and prior service credit for OPEB plans that will be amortized from regulatory
asset into net periodic benefit cost over the next fiscal year is $12 million.

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


<Table>
<Caption>
                                             PENSION PLAN        SERP            OPEB
                                           ---------------   -----------   ---------------
YEARS ENDED DECEMBER 31                     2006     2005    2006   2005    2006     2005
-----------------------                    ------   ------   ----   ----   ------   ------
                                                            (IN MILLIONS)

<S>                                        <C>      <C>      <C>    <C>    <C>      <C>

Benefit obligation at beginning of
  period.................................  $1,510   $1,328   $ 46   $ 40   $1,065   $1,013
Service cost.............................      49       42      1      1       22       21
Interest cost............................      83       78      3      3       60       58
Plan amendment...........................      --       39     --      1       --      (19)
Actuarial loss (gain)....................      51      146     (1)     2       79       39
Benefits paid............................    (117)    (123)    (2)    (1)     (47)     (47)
                                           ------   ------   ----   ----   ------   ------
Benefit obligation at end of period(a)...   1,576    1,510     47     46    1,179    1,065
                                           ------   ------   ----   ----   ------   ------
Plan assets at fair value at beginning of
  period.................................   1,018    1,040     --     --      655      598
Actual return on plan assets.............     126      101     --     --       67       42
Company contribution.....................      13       --      2      2       57       62
Actual benefits paid(b)..................    (117)    (123)    (2)    (2)     (45)     (47)
                                           ------   ------   ----   ----   ------   ------
Plan assets at fair value at end of
  period.................................   1,040    1,018     --     --      734      655
                                           ------   ------   ----   ----   ------   ------
Funded status at end of measurement
  period.................................    (536)    (492)   (47)   (46)    (445)    (410)
Additional VEBA Contributions or
Non-Trust Benefit Payments...............      --       --     --     --       14       15
                                           ------   ------   ----   ----   ------   ------
Funded status at December 31(c)..........  $ (536)  $ (492)  $(47)  $(46)  $ (431)  $ (395)
                                           ======   ======   ====   ====   ======   ======

</Table>




                                      CE-62

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



--------

(a)    The Medicare Prescription Drug, Improvement and Modernization Act of 2003
       establishes a prescription drug benefit under Medicare (Medicare Part D),
       and a federal subsidy, which is tax-exempt, to sponsors of retiree health
       care benefit plans that provide a benefit that is actuarially equivalent
       to Medicare Part D. The Medicare Part D annualized reduction in net OPEB
       cost was $27 million for 2006 and $23 million for 2005. The reduction
       includes $7 million for the year ended December 31, 2006 and $6 million
       for the year ended December 31, 2005 in capitalized OPEB costs.

(b)    We received $2 million in Medicare Part D Subsidy payments for the year
       ended December 31, 2006.

(c)    Of the $536 million funded status of the Pension Plan at December 31,
       2006, $507 million is attributable to Consumers and of the $492 million
       funded status of the Pension Plan at December 31, 2005, $465 million is
       attributable to Consumers, based on allocation of expenses.

     The following table provides a reconciliation of benefit obligations, plan
assets and funded status of the plans as of December 31, 2005 for all plans
combined. (In accordance with SFAS No. 158, we recognized the underfunded status
of our defined benefit postretirement plans as a liability on our consolidated
balance sheets as of December 31, 2006.)


<Table>
<Caption>
                                                          PENSION PLAN   SERP    OPEB
                                                          ------------   ----   ------
YEAR ENDED DECEMBER 31                                        2005       2005    2005
----------------------                                    ------------   ----   ------
                                                                  (IN MILLIONS)

<S>                                                       <C>            <C>    <C>

Fair value of plan assets...............................     $1,018      $ --   $  655
Net benefit obligations.................................      1,510        46    1,065
                                                             ------      ----   ------
Funded status (plan assets less plan obligations).......       (492)      (46)    (410)
Amounts not recognized
  Net actuarial loss....................................        747         8      374
  Prior service cost (credit)...........................         56         2     (109)
Additional VEBA Contributions or Non-Trust Benefit
  Payments..............................................         --        --       15
                                                             ------      ----   ------
Net amount recognized(a)................................     $  311      $(36)  $ (130)
                                                             ======      ====   ======

</Table>



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

(a)    Of the $311 million net amount recognized, $293 million was attributable
       to Consumers based on the allocation of expenses.

     The following table provides a reconciliation of the amounts recognized on
our Consolidated Balance Sheets as of December 31, 2005 for all plans combined:


<Table>
<Caption>
                                                     PENSION PLAN   SERP    OPEB
                                                     ------------   ----   -----
YEAR ENDED DECEMBER 31                                   2005       2005    2005
----------------------                               ------------   ----   -----
                                                            (IN MILLIONS)

<S>                                                  <C>            <C>    <C>

Prepaid benefit cost...............................      $ 293      $ --   $  --
Accrued benefit cost...............................         --       (36)   (130)
Additional minimum liability.......................       (451)       --      --
Intangible asset...................................         52        --      --
Regulatory asset...................................        399        --      --
                                                         -----      ----   -----
Net amount recognized..............................      $ 293      $(36)  $(130)
                                                         =====      ====   =====

</Table>




                                      CE-63

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                      2006     2005
-----------------------                                     ------   ------
                                                             (IN MILLIONS)

<S>                                                         <C>      <C>

Pension ABO...............................................  $1,240   $1,188
Fair value of pension plan assets.........................   1,040    1,018
                                                            ------   ------
Pension ABO in excess of pension plan assets..............  $  200   $  170
                                                            ======   ======

</Table>


     SFAS No. 158 Recognized:  The following table recaps the amounts recognized
in SFAS No. 158 regulatory assets and AOCI that have not been recognized as
components of net periodic benefit cost. For additional details on regulatory
assets, see Note 1, Corporate Structure and Accounting Policies, "Utility
Regulation."


<Table>
<Caption>
                                                        PENSION & SERP   OPEB
                                                        --------------   ----
YEAR ENDED DECEMBER 31                                       2006        2006
----------------------                                  --------------   ----
                                                            (IN MILLIONS)

<S>                                                     <C>              <C>

Regulatory assets
  Net loss............................................       $676        $416
  Prior service cost (credit).........................         45         (99)
AOCI
  Net loss (gain).....................................          7          --
  Prior service cost (credit).........................          1          --
                                                             ----        ----
Total amounts recognized in regulatory assets and
  AOCI................................................       $729        $317
                                                             ====        ====

</Table>


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


<Table>
<Caption>
                                                             PENSION         OPEB
                                                           -----------   -----------
NOVEMBER 30                                                2006   2005   2006   2005
-----------                                                ----   ----   ----   ----

<S>                                                        <C>    <C>    <C>    <C>

Asset Category:
  Fixed Income...........................................   28%    33%    37%    58%
  Equity Securities:.....................................   62%    65%    63%    40%
     CMS Energy Common Stock(a)..........................    --     --     --     1%
     Alternative Strategy................................   10%     2%     --     1%
</Table>


--------

(a)    At November 30, 2006, there were no shares of CMS Energy Common Stock in
       the Pension Plan assets, and 143,200 shares in the OPEB plan assets with
       a fair value of $2 million. At November 30, 2005, there were no shares of
       CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in
       the OPEB plan assets with a fair value of $2 million.

     We contributed $55 million to our OPEB plan in 2006 and we plan to
contribute $50 million to our OPEB plan in 2007. We contributed $13 million to
our Pension Plan in 2006 and we plan to contribute $103 million to our Pension
plan in 2007.

     We have established a target asset allocation for our Pension Plan assets
of 60 percent equity, 30 percent fixed income, and 10 percent alternative
strategy investments to maximize the long-term return on plan assets, while
maintaining a prudent level of risk. The level of acceptable risk is a function
of the liabilities of the plan. Equity investments are diversified mostly across
the Standard & Poor's 500 Index, with lesser allocations to the Standard &
Poor's Mid Cap Index, the Small Cap Indexes and a Foreign Equity Index Fund.
Fixed-income investments are diversified across investment grade instruments of
both government and corporate issuers. Alternative strategies are diversified
across absolute return investment approaches and global tactical asset
allocation. Annual liability

                                      CE-64

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



measurements, quarterly portfolio reviews, and periodic asset/liability studies
are used to evaluate the need for adjustments to the portfolio allocation.

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

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


<Table>
<Caption>
                                                             PENSION  SERP  OPEB(A)
                                                             -------  ----  -------
                                                                  (IN MILLIONS)

<S>                                                          <C>      <C>   <C>

2007.......................................................    $ 58    $2     $ 54
2008.......................................................      65     2       56
2009.......................................................      73     2       58
2010.......................................................      81     2       60
2011.......................................................      93     2       62
2012-2016..................................................     652     9      333
</Table>



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

(a)     OPEB benefit payments are net of employee contributions and expected
        Medicare Part D prescription drug subsidy payments. The subsidies to be
        received are estimated to be $5 million for 2007, $6 million each year
        for 2008 through 2011 and $33 million combined for 2012 through 2016.

7: ASSET RETIREMENT OBLIGATIONS

     SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard
requires companies to record the fair value of the cost to remove assets at the
end of their useful life, if there is a legal obligation to remove them. 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 $25
million.

     If a reasonable estimate of fair value cannot be made in the period in
which the ARO is incurred, such as for assets with indeterminate lives, the
liability is to be recognized when a reasonable estimate of fair value can be
made. Generally, gas transmission and electric and gas distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets or associated obligations related to potential future
abandonment. 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 include use of
decommissioning studies that largely utilize third-party cost estimates.

     FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarified the term "conditional asset
retirement obligation" as used in SFAS No. 143. The term refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event. We determined that
abatement of asbestos included in our plant investments qualifies as a
conditional ARO, as defined by FASB Interpretation No. 47.


                                      CE-65

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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



<Table>
<Caption>
                                      IN SERVICE
ARO DESCRIPTION                          DATE         LONG-LIVED ASSETS       TRUST FUND
---------------                       ----------      -----------------       ----------
                                                                            (IN MILLIONS)

<S>                                   <C>         <C>                       <C>

December 31, 2006
Palisades-decommission plant site...       1972   Palisades nuclear plant        $598
Big Rock-decommission plant site....       1962   Big Rock nuclear plant            4
JHCampbell intake/discharge water
  line..............................       1980   Plant intake/discharge           --
                                                  water line
Closure of coal ash disposal areas..    Various   Generating plants coal           --
                                                  ash areas
Closure of wells at gas storage
  fields............................    Various   Gas storage fields               --
Indoor gas services equipment
  relocations.......................    Various   Gas meters located               --
                                                  inside structures
Asbestos abatement..................       1973   Electric and gas                 --
                                                  utility plant
</Table>





<Table>
<Caption>
                                          ARO                                                    ARO
                                       LIABILITY                                   CASH FLOW  LIABILITY
ARO DESCRIPTION                        1/1/05(A)  INCURRED  SETTLED(B)  ACCRETION  REVISIONS   12/31/05
---------------                        ---------  --------  ----------  ---------  ---------  ---------
                                                                 (IN MILLIONS)

<S>                                    <C>        <C>       <C>         <C>        <C>        <C>

Palisades-decommission...............     $350       $--       $ --        $25        $--        $375
Big Rock-decommission................       30        --        (42)        15         24          27
JHCampbell intake line...............       --        --         --         --         --          --
Coal ash disposal areas..............       54        --         (5)         5         --          54
Wells at gas storage fields..........        1        --         --         --         --           1
Indoor gas services relocations......        1        --         --         --         --           1
Asbestos abatement...................       33        --         --          3         --          36
                                          ----       ---       ----        ---        ---        ----
Total................................     $469       $--       $(47)       $48        $24        $494
                                          ====       ===       ====        ===        ===        ====

</Table>





<Table>
<Caption>
                                          ARO                                                    ARO
                                       LIABILITY                                   CASH FLOW  LIABILITY
ARO DESCRIPTION                         12/31/05  INCURRED  SETTLED(B)  ACCRETION  REVISIONS   12/31/06
---------------                        ---------  --------  ----------  ---------  ---------  ---------
                                                                 (IN MILLIONS)

<S>                                    <C>        <C>       <C>         <C>        <C>        <C>

Palisades-decommission...............     $375       $--       $ --        $26        $--        $401
Big Rock-decommission................       27        --        (28)         3         --           2
JHCampbell intake line...............       --        --         --         --         --          --
Coal ash disposal areas..............       54        --         (2)         5         --          57
Wells at gas storage fields..........        1        --         --         --         --           1
Indoor gas services relocations......        1        --         --         --         --           1
Asbestos abatement...................       36        --         (3)         2         --          35
                                          ----       ---       ----        ---        ---        ----
Total................................     $494       $--       $(33)       $36        $--        $497
                                          ====       ===       ====        ===        ===        ====

</Table>


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

(a)   The ARO liability at January 1, 2005 in the preceding table reflects the
      ARO liability as if FASB Interpretation No. 47 had been in effect at that
      time, as required by the Interpretation. Our consolidated financial
      statements for that period do not reflect the asbestos abatement ARO. As
      required by SFAS No. 71, we accounted for the implementation of this
      Interpretation by recording a regulatory asset instead of a cumulative
      effect of a change in accounting principle. There was no effect on
      consolidated net income.
(b)   These cash payments are included in the Other current and non-current
      liabilities line in Net cash provided by operating activities in our
      Consolidated Statements of Cash Flows.

     In October 2004, the MPSC initiated a generic proceeding to review SFAS No.
143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing
Requirements for Asset Retirement Obligations, and related accounting and
ratemaking issues for MPSC-jurisdictional electric and gas utilities. In
December 2005, the ALJ issued a Proposal for Decision recommending that the MPSC
dismiss the proceeding. In March 2006, the MPSC

                                      CE-66

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



remanded the case to the ALJ for findings and recommendations. In August 2006,
the ALJ issued a second Proposal for Decision that included recommendations that
the MPSC:

     - adopt SFAS No. 143 and FERC Order No. 631 for accounting purposes but not
       for ratemaking purposes,

     - consider adopting standardized retirement units for certain accounts,

     - consider revising the method of determining cost of removal, and

     - withhold approving blanket regulatory asset and regulatory liability
       accounting treatment related to AROs, stating that modifications to the
       MPSC's Uniform System of Accounts should precede any such accounting
       approval.

     We consider the proceeding a clarification of accounting and reporting
issues that relate to all Michigan utilities. We cannot predict the outcome of
the proceeding.

8: INCOME TAXES

     We join in the filing of a consolidated federal income tax return with CMS
Energy and its subsidiaries. Income taxes generally are allocated based on each
company's separate taxable income in accordance with the CMS Energy tax sharing
agreement. We had tax related payables to CMS Energy of $31 million in 2006 and
$128 million in 2005.

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

     AMT paid generally becomes a tax credit that we can carry forward
indefinitely to reduce regular tax liabilities in future periods when regular
taxes paid exceed the tax calculated for AMT. At December 31, 2006, we had AMT
credit carryforwards of $66 million that do not expire and tax loss
carryforwards of $339 million that expire from 2023 through 2025. We do not
believe that a valuation allowance is required, as we expect to utilize the loss
carryforwards prior to their expiration. In addition, we had general business
credit carryforwards of $11 million, charitable contribution carryforwards of $7
million that expire from 2007 through 2009, and a capital loss carryforward of
$31 million that expires in 2011, for which valuation allowances have been
provided.

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                       2006    2005   2004
-----------------------                                       ----    ----   ----
                                                                 (IN MILLIONS)

<S>                                                          <C>     <C>     <C>

Current federal income taxes...............................  $ 212   $ 176   $ 26
Current federal income tax benefit of operating loss
  carryforwards............................................     (8)     (9)   (11)
Deferred federal income taxes..............................   (109)   (201)   142
Deferred ITC, net..........................................     (4)    (13)    (5)
                                                             -----   -----   ----
Income tax expense (benefit)...............................  $  91   $ (47)  $152
                                                             =====   =====   ====

</Table>


     Current tax expense includes the settlement of income tax audits for prior
years, as well as the provision for 2006 income taxes prior to the use of loss
carryforwards. Deferred tax assets and liabilities are recognized for the
estimated future tax effect of temporary differences between the tax basis of
assets or liabilities and the reported amounts in our consolidated financial
statements. Deferred tax assets and liabilities are classified as current or
non-current according to the classification of the related assets or
liabilities. Deferred tax assets and liabilities not related to assets or
liabilities are classified according to the expected reversal date of the
temporary differences.


                                      CE-67

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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


<Table>
<Caption>
DECEMBER 31                                                        2006     2005
-----------                                                        ----     ----
                                                                   (IN MILLIONS)

<S>                                                              <C>      <C>

Property.......................................................  $  (814) $  (748)
Securitized costs..............................................     (177)    (172)
Gas inventories................................................     (168)    (148)
Employee benefits..............................................       36      (61)
Consolidated investments.......................................       --      (54)
SFAS No. 109 regulatory liability, net.........................      189      159
Nuclear decommissioning........................................       57       59
Tax loss and credit carryforwards..............................      209       60
Valuation allowances...........................................      (15)      --
Other, net.....................................................     (175)    (177)
                                                                 -------  -------
Net deferred tax liabilities...................................  $  (858) $(1,082)
                                                                 =======  =======
Deferred tax liabilities.......................................  $(2,272) $(2,093)
Deferred tax assets, net of valuation allowance................    1,414    1,011
                                                                 -------  -------
Net deferred tax liabilities...................................  $  (858) $(1,082)
                                                                 =======  =======

</Table>


     In June 2006, the IRS concluded its most recent audit of CMS Energy and its
subsidiaries, and proposed changes to taxable income for the years ended
December 31, 1987 through December 31, 2001. The proposed overall cumulative
increase to taxable income related primarily to the disallowance of the
simplified service cost method with respect to certain self-constructed utility
assets. CMS Energy has accepted these proposed adjustments to taxable income,
which have been allocated based upon Consumers' separate taxable income in
accordance with CMS Energy's tax sharing agreement. We made a payment to CMS
Energy for our share of these audit adjustments of $232 million, and reduced our
2006 income tax provision by $19 million, primarily for the restoration and
utilization of previously written off income tax credits.


                                      CE-68

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                        2006    2005    2004
-----------------------                                       -----   -----   -----
                                                                  (IN MILLIONS)

<S>                                                           <C>     <C>     <C>

Income (loss) before cumulative effect of change in
  accounting principle.....................................   $ 186   $ (96)  $ 280
Income tax expense (benefit)...............................      91     (47)    152
                                                              -----   -----   -----
Income (loss) before income taxes..........................     277    (143)    432
Statutory federal income tax rate..........................    x 35%   x 35%   x 35%
                                                              -----   -----   -----
Expected income tax expense (benefit)......................      97     (50)    151
Increase (decrease) in taxes from:
  Property differences.....................................      19      15      13
  IRS Settlement/Credit Restoration........................     (19)     --      --
  Return to accrual adjustments............................      (7)      3      --
  Medicare Part D exempt income............................     (10)     (6)     (5)
  ITC amortization.........................................      (4)     (4)     (6)
  Expiration of general business credits...................      --       6      --
  Valuation allowance......................................      15      (9)      1
  Other, net...............................................      --      (2)     (2)
                                                              -----   -----   -----
Recorded income tax expense (benefit)......................   $  91   $ (47)  $ 152
                                                              =====   =====   =====
Effective tax rate.........................................    32.9%   32.9%   35.2%
                                                              =====   =====   =====

</Table>


     During 2006, the valuation allowance increased by $15 million. In November
2006, we sold our interests in the MCV Partnership and the FMLP triggering a
capital loss. A $12 million valuation allowance has been provided against the
related deferred tax asset. Additionally, valuation allowances have been
provided against charitable contributions and tax credits that are expected to
expire unused.

     The amount of income taxes we pay is subject to ongoing audits by federal,
state and foreign tax authorities, which can result in proposed assessments. Our
estimate for the potential outcome for any uncertain tax issue is highly
judgmental. We believe that our accrued tax liabilities at December 31, 2006 are
adequate for all years.

     FIN 48, Accounting for Uncertainty in Income Taxes: In June 2006, the FASB
issued FIN 48, effective for us January 2007. This interpretation provides a
two-step approach for the recognition and measurement of uncertain tax positions
taken, or expected to be taken, by a company on its income tax returns. The
first step is to evaluate the tax position to determine if, based on
management's best judgment, it is greater than 50 percent likely that the taxing
authority will sustain the tax position. The second step is to measure the
appropriate amount of the benefit to recognize. This is done by estimating the
potential outcomes and recognizing the greatest amount that has a cumulative
probability of at least 50 percent. FIN 48 requires interest and penalties, if
applicable, to be accrued on differences between tax positions recognized in our
consolidated financial statements and the amount claimed, or expected to be
claimed, on the tax return. Our policy is to include interest and penalties
accrued, if any, on uncertain tax positions as part of the related tax liability
on our consolidated balance sheet and as part of the income tax expense in our
consolidated income statement. The impact from adopting FIN 48 should be
recorded as a cumulative adjustment to the beginning retained earnings balance
and a corresponding adjustment to a current or non-current tax liability. At
this time, we are continuing to evaluate the impact of FIN 48 on our
consolidated financial statements.

9: EXECUTIVE INCENTIVE COMPENSATION

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


                                      CE-69

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     All grants under the Plan for 2006 and 2005 were in the form of restricted
stock. Restricted stock awards are outstanding shares to which the recipient has
full voting and dividend rights and vest 100 percent after three years of
continued employment. Restricted stock awards granted to officers in 2006, 2005,
and 2004 are also subject to the achievement of specified levels of total
shareholder return, including a comparison to a peer group of companies. All
restricted stock awards are subject to forfeiture if employment terminates
before vesting. However, if certain minimum service requirements are met,
restricted shares may continue to vest upon retirement or disability and vest
fully if control of CMS Energy changes, as defined by the Plan. In April 2006,
we amended the Plan to allow awards not subject to achievement of total
shareholder return to vest fully upon retirement, subject to the participant not
accepting employment with a direct competitor. This modification did not have a
material impact on our consolidated financial statements.

     The Plan also allows for stock options, stock appreciation rights, phantom
shares, and performance units. None of which were granted in 2006 or 2005.

     Select participants may elect to receive all or a portion of their
incentive payments under the Officer's Incentive Compensation Plan in the form
of cash, shares of restricted common stock, shares of restricted stock units, or
any combination of these. These participants may also receive awards of
additional restricted common stock or restricted stock units, provided the total
value of these additional grants does not exceed $2.5 million for any fiscal
year.

     Shares awarded or subject to stock options, phantom shares, and performance
units may not exceed 6 million shares from June 2004 through May 2009, nor may
such awards to any participant exceed 250,000 shares in any fiscal year. We may
issue awards of up to 4,382,800 shares of common stock under the Plan at
December 31, 2006. Shares for which payment or exercise is in cash, as well as
forfeited shares or stock options may be awarded or granted again under the
Plan.

     The following table summarizes restricted stock activity under the Plan:


<Table>
<Caption>
                                                                           WEIGHTED-AVERAGE
RESTRICTED STOCK                                     NUMBER OF SHARES   GRANT DATE FAIR VALUE
----------------                                     ----------------   ---------------------

<S>                                                  <C>                <C>

Nonvested at December 31, 2005.....................      1,154,316              $10.87
  Granted..........................................        460,880              $13.82
  Vested...........................................       (174,783)             $ 7.32
  Forfeited........................................        (18,413)             $11.17
                                                         ---------              ------
Nonvested at December 31, 2006.....................      1,422,000              $12.26
</Table>


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

     We expense the fair value over the required service period of the awards.
As a result, we recognize all compensation expense for share-based awards with
accelerated service provisions upon retirement by the period in which the
employee becomes eligible to retire.

     The total fair value of shares vested was $2 million in 2006, $2 million in
2005, and $1 million in 2004. We calculate the fair value of restricted shares
granted based on the price of our common stock on the grant date and expense the
fair value over the required service period. Compensation expense related to
restricted stock was $7 million in 2006, $3 million in 2005, and $2 million in
2004. The total related income tax benefit recognized in income was $2 million
in 2006, $1 million in 2005, and $1 million of in 2004. At December 31, 2006,
there was $8 million of total unrecognized compensation cost related to
restricted stock. We expect to recognize this cost over a weighted-average
period of 1.3 years.


                                      CE-70

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     The following table summarizes stock option activity under the Plan:


<Table>
<Caption>
                                                                           WEIGHTED-
                                                OPTIONS       WEIGHTED-     AVERAGE
                                              OUTSTANDING,     AVERAGE     REMAINING      AGGREGATE
                                             FULLY VESTED,     EXERCISE   CONTRACTUAL     INTRINSIC
STOCK OPTIONS                               AND EXERCISABLE     PRICE         TERM          VALUE
-------------                               ---------------   ---------   -----------   -------------
                                                                                        (IN MILLIONS)

<S>                                         <C>               <C>         <C>           <C>

Outstanding at December 31, 2005..........     1,714,787        $18.13     5.9 years         $(6)
  Granted.................................            --            --
  Exercised...............................       (61,095)         7.07
  Cancelled or Expired....................       (51,908)        30.09
Outstanding at December 31, 2006..........     1,601,784        $18.16     5.0 years         $(2)
</Table>


     Stock options give the holder the right to purchase common stock at a price
equal to the fair value of our common stock on the grant date. Stock options are
exercisable upon grant, and expire up to 10 years and one month from the grant
date. We issue new shares when participants exercise stock options. The total
intrinsic value of stock options exercised was $1 million in 2006, 2005, and
2004. Cash received from exercise of these stock options was less than $1
million in 2006. Since we have utilized tax loss carryforwards, we were not able
to realize the excess tax benefits upon exercise of stock options. Therefore, we
did not recognize the related excess tax benefits in equity.

10: LEASES

     We lease various assets, including service vehicles, railcars, construction
equipment, office furniture, and buildings. We purchase renewable energy under
certain power purchase agreements, as required by the MPSC. In accordance with
SFAS No. 13, we account for these power purchase agreements as capital and
operating leases.

     Operating leases for coal-carrying railcars have lease terms expiring over
the next 15 years. These leases contain fair market value extension and buyout
provisions, with some providing for predetermined extension period rentals.
Capital leases for our vehicle fleet operations have a maximum term of 120
months and TRAC end-of-life provisions. The capital lease for furniture
terminates in 2013, but provides for an early buyout in April 2008. Power
purchase agreements range from 7 to 20 years. Most of our power purchase
agreements contain options at the end of the initial contract term to renew the
agreement annually.

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


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                          2006   2005   2004
-----------------------                                          ----   ----   ----
                                                                    (IN MILLIONS)

<S>                                                              <C>    <C>    <C>

Capital lease expense..........................................   $15    $14    $13
Operating lease expense........................................    19     17     13
</Table>




                                      CE-71

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



     Minimum annual rental commitments under our non-cancelable leases at
December 31, 2006 are:


<Table>
<Caption>
                                                                 CAPITAL   OPERATING
                                                                  LEASES     LEASES
                                                                 -------   ---------
                                                                    (IN MILLIONS)

<S>                                                              <C>       <C>

2007...........................................................    $13        $ 23
2008...........................................................     12          22
2009...........................................................     11          19
2010...........................................................      9          17
2011...........................................................      7          17
2012 and thereafter............................................     29          61
                                                                   ---        ----
Total minimum lease payments...................................     81        $159
                                                                              ====
Less imputed interest..........................................     26
                                                                   ---
Present value of net minimum lease payments....................     55
Less current portion...........................................     13
                                                                   ---
Non-current portion............................................    $42
</Table>


11: PROPERTY, PLANT, AND EQUIPMENT

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


<Table>
<Caption>
                                                           ESTIMATED
                                                          DEPRECIABLE
DECEMBER 31                                              LIFE IN YEARS    2006     2005
-----------                                              -------------   ------   ------
                                                                          (IN MILLIONS)

<S>                                                      <C>             <C>      <C>

Electric:
  Generation...........................................      13-85       $3,573   $3,487
  Distribution.........................................      12-75        4,425    4,226
  Other................................................       7-40          421      404
  Capital leases(a)....................................                      85       87
Gas:
  Underground storage facilities(b)....................      30-65          263      262
  Transmission.........................................      15-75          465      416
  Distribution.........................................      40-75        2,216    2,141
  Other................................................       7-50          300      306
  Capital leases(a)....................................                      29       26
Other: MCV Facility(c).................................       5-35           --      211
  Non-utility property.................................       7-71           15       15
  Construction work-in-progress........................                     639      509
  Other................................................                      --        1
Less accumulated depreciation, depletion, and
  amortization(d)......................................                   4,983    4,804
                                                                         ------   ------
Net property, plant, and equipment(e)(f)...............                  $7,448   $7,287
                                                                         ======   ======

</Table>



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

(a)   Capital leases presented in this table are gross amounts. Accumulated
      amortization of capital leases was $59 million at December 31, 2006 and
      $54 million at December 31, 2005. Capital lease additions were $7 million
      and capital lease retirements and adjustments were $6 million during 2006.
      Capital lease additions were $12 million and capital lease retirements and
      adjustments were $7 million during 2005.

(b)   Includes unrecoverable base natural gas in underground storage of $26
      million at December 31, 2006 and December 31, 2005, which is not subject
      to depreciation.


                                      CE-72

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)





(c)   In November 2006, we sold 100 percent of our ownership interest of MCV GP
      II (the successor to CMS Midland, Inc.) and 100 percent of our ownership
      of the stock of CMS Midland Holdings Company to an affiliate of GSO
      Capital Partners and Rockland Capital Energy Investments. For additional
      details on our sale of the MCV Partnership and the MCV facility, see Note
      2, Asset Sales and Impairment Charges.

(d)   At December 31, 2006, accumulated depreciation, depletion, and
      amortization included $4.982 billion from our public utility plant and $1
      million related to our non-utility plant assets. At December 31, 2005,
      accumulated depreciation, depletion, and amortization included $4.803
      billion from our public utility plant and $1 million related to our non-
      utility plant assets.

(e)   At December 31, 2006, public utility plant additions were $470 million and
      public utility plant retirements, including other plant adjustments, were
      $82 million. At December 31, 2005, public utility plant additions were
      $450 million and public utility plant retirements, including other plant
      adjustments, were $64 million.

(f)   Included in net property, plant and equipment are intangible assets
      primarily related to software development costs, consents, leasehold
      improvements, and rights of way. The estimated amortization lives for
      software development costs range from seven to twelve years. The estimated
      amortization life for leasehold improvements is the life of the lease.
      Other intangible amortization lives range from 50 to 75 years.

     The following tables summarize our intangible assets:


<Table>
<Caption>
                                                                                  INTANGIBLE
                                                                    ACCUMULATED     ASSET,
DECEMBER 31, 2006                                     GROSS COST   AMORTIZATION       NET
-----------------                                     ----------   ------------   ----------
                                                                   (IN MILLIONS)

<S>                                                   <C>          <C>            <C>

Software development................................     $204          $153          $ 51
Rights of way.......................................      114            31            83
Leasehold improvements..............................       19            15             4
Franchises and consents.............................       19            10             9
Other intangibles...................................       18            13             5
                                                         ----          ----          ----
Total...............................................     $374          $222          $152
                                                         ====          ====          ====

</Table>




<Table>
<Caption>
                                                                                  INTANGIBLE
                                                                    ACCUMULATED     ASSET,
DECEMBER 31, 2005                                     GROSS COST   AMORTIZATION       NET
-----------------                                     ----------   ------------   ----------
                                                                   (IN MILLIONS)

<S>                                                   <C>          <C>            <C>

Software development................................     $200          $135          $ 65
Rights of way.......................................      102            29            73
Leasehold improvements..............................       19            14             5
Franchises and consents.............................       19             9            10
Other intangibles...................................       18            13             5
                                                         ----          ----          ----
Total...............................................     $358          $200          $158
                                                         ====          ====          ====

</Table>


     Pre-tax amortization expense related to these intangible assets was $22
million for the year ended December 31, 2006, $19 million for the year ended
December 31, 2005, and $19 million for the year ended December 31, 2004.
Intangible assets amortization is forecasted to range from $13 million to $23
million per year over the next five years.


                                      CE-73

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



12: JOINTLY OWNED REGULATED UTILITY FACILITIES

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


<Table>
<Caption>
                                                        NET       ACCUMULATED    CONSTRUCTION
                                                      INVEST-      DEPRECIA-       WORK IN
                                                      MENT(A)         TION         PROGRESS
                                        OWNERSHIP   -----------   -----------   -------------
DECEMBER 31                               SHARE     2006   2005   2006   2005   2006     2005
-----------                             ---------   ----   ----   ----   ----   ----     ----
                                        (percent)                 (In Millions)

<S>                                     <C>         <C>    <C>    <C>    <C>    <C>      <C>

Campbell Unit 3.......................      93.3    $262   $270   $370   $354   $353     $258
Ludington.............................      51.0      68     72     95     92      1        1
Distribution..........................   Various      98    100     47     45      4        9
</Table>


--------

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

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

13: REPORTABLE SEGMENTS

     Our reportable segments are strategic business units organized and managed
by the nature of the products and services each provides. We evaluate
performance based upon the net income of each segment. Our two principal
segments are 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 our segments are the same as we describe in the
summary of significant accounting policies. Our consolidated 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 (loss) available to common
stockholder by segment. The "Other" segment includes our consolidated special
purpose entity for the sale of trade receivables, the MCV Partnership and the
FMLP.

     The following table shows our financial information by reportable segment:


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                    2006     2005      2004
-----------------------                                    ----     ----      ----
                                                                (IN MILLIONS)

<S>                                                      <C>      <C>       <C>

Operating Revenues
  Electric.............................................  $ 3,302  $ 2,701   $ 2,586
  Gas..................................................    2,374    2,483     2,081
  Other................................................       45       48        44
                                                         -------  -------   -------
                                                         $ 5,721  $ 5,232   $ 4,711
                                                         =======  =======   =======
Earnings from Equity Method Investees
  Electric.............................................  $     1  $    --   $    --
  Other................................................       --        1         1
                                                         -------  -------   -------
                                                         $     1  $     1   $     1
                                                         =======  =======   =======
</Table>

                                      CE-74

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



<Table>
<Caption>
YEARS ENDED DECEMBER 31                                    2006     2005      2004
-----------------------                                    ----     ----      ----
                                                                (IN MILLIONS)

<S>                                                      <C>      <C>       <C>
Depreciation, Depletion and Amortization
  Electric.............................................  $   380  $   292   $   189
  Gas..................................................      122      117       112
  Other................................................       25       75        90
                                                         -------  -------   -------
                                                         $   527  $   484   $   391
                                                         =======  =======   =======
Interest Charges
  Electric.............................................  $   167  $   133   $   204
  Gas..................................................       73       68        65
  Other................................................       49       71        97
                                                         -------  -------   -------
                                                         $   289  $   272   $   366
                                                         =======  =======   =======
Income Tax (Benefit) Expense
  Electric.............................................  $    95  $    85   $   120
  Gas..................................................       18       39        40
  Other................................................      (22)    (171)       (8)
                                                         -------  -------   -------
                                                         $    91  $   (47)  $   152
                                                         =======  =======   =======
Net Income (Loss) Available to Common Stockholder
  Electric.............................................  $   199  $   153   $   222
  Gas..................................................       37       48        71
  Other................................................      (52)    (299)      (16)
                                                         -------  -------   -------
                                                         $   184  $   (98)  $   277
                                                         =======  =======   =======
Investments in Equity Method Investees
  Electric.............................................  $     5  $     3   $     3
  Other................................................       --        4        16
                                                         -------  -------   -------
                                                         $     5  $     7   $    19
                                                         =======  =======   =======
Total Assets
  Electric(a)..........................................  $ 8,516  $ 7,755   $ 7,289
  Gas(a)...............................................    3,950    3,609     3,187
  Other................................................      379    1,814     2,335
                                                         -------  -------   -------
                                                         $12,845  $13,178   $12,811
                                                         =======  =======   =======
Capital Expenditures(b)
  Electric.............................................  $   462  $   384   $   360
  Gas..................................................      172      168       137
  Other................................................       19       32        21
                                                         -------  -------   -------
                                                         $   653  $   584   $   518
                                                         =======  =======   =======

</Table>



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

(a)    Amounts include a portion of our other common assets attributable to both
       the electric and gas utility businesses.
(b)    Amounts include electric restructuring implementation plan, purchase of
       nuclear fuel, and capital lease additions. Amounts also include a portion
       of capital expenditures for plant and equipment attributable to both the
       electric and gas utility businesses.


                                      CE-75

<PAGE>

                            CONSUMERS ENERGY COMPANY


             NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)



14: CONSOLIDATION OF VARIABLE INTEREST ENTITIES

     Until their sale in November 2006, we had a 49 percent partnership interest
in the MCV Partnership and a 46.4 percent partnership interest in the FMLP.
Prior to their sale, we were the primary beneficiary of both the MCV Partnership
and the FMLP because Consumers is the primary purchaser of power from the MCV
Partnership through a long-term power purchase agreement and Consumers, through
its ownership interest in the FMLP, held a 35 percent lessor interest in the MCV
Facility. Therefore, we consolidated these partnerships into our consolidated
financial statements as of and for the year ended December 31, 2005. Upon the
sale of our interests in the MCV Partnership and the FMLP, we are no longer the
primary beneficiary of these entities and the entities were deconsolidated. For
additional details on the sale of our interests in the MCV Partnership and the
FMLP, see Note 2, Asset Sales and Impairment Charges.

     These partnerships had third-party obligations totaling $482 million at
December 31, 2005. Property, plant, and equipment serving as collateral for
these obligations had a carrying value of $224 million at December 31, 2005. The
creditors of these partnerships did not have recourse to the general credit of
Consumers. At December 31, 2005, the MCV Partnership had total assets of $1.318
billion and a net loss of $917 million for the year.

15: QUARTERLY FINANCIAL AND COMMON STOCK INFORMATION (UNAUDITED)


<Table>
<Caption>
                                                                2006
                                             ------------------------------------------
QUARTERS ENDED                               MARCH 31   JUNE 30   SEPT. 30   DEC. 31(A)
--------------                               --------   -------   --------   ----------
                                                             IN MILLIONS

<S>                                          <C>        <C>       <C>        <C>

Operating revenue..........................   $1,782     $1,138    $1,191      $1,610
Operating income (loss)....................        7         78       239         (43)
Net income.................................       10         36        99          41
Preferred stock dividends..................       --          1        --           1
Net income available to common
  stockholder..............................       10         35        99          40
</Table>




<Table>
<Caption>
                                                                2005
                                              ---------------------------------------
QUARTERS ENDED                                MARCH 31   JUNE 30   SEPT. 30   DEC. 31
--------------                                --------   -------   --------   -------
                                                            IN MILLIONS

<S>                                           <C>        <C>       <C>        <C>

Operating revenue...........................   $1,632     $1,016    $1,025     $1,559
Operating income (loss).....................      416         86      (865)        (9)
Net income (loss)...........................      157         33      (276)       (10)
Preferred stock dividends...................       --          1        --          1
Net income (loss) available to common
  stockholder...............................      157         32      (276)       (11)
</Table>



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

(a)    The quarter ended December 31, 2006 includes a $41 million net loss on
       the sale of our investment in the MCV Partnership including the negative
       impact of the associated impairment charge. For further information see
       Note 2, Asset Sales and Impairment Charges.


                                      CE-76

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder of Consumers Energy Company

     We have audited the accompanying consolidated balance sheets of Consumers
Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy
Corporation) as of December 31, 2006 and 2005, and the related consolidated
statements of income (loss), common stockholder's equity, and cash flows for
each of the three years in the period ended December 31, 2006. Our audits also
included the financial statement schedule listed in the Index at Item 15(a)(2).
These financial statements and schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements, and schedule based on our audits. We did not audit the financial
statements of Midland Cogeneration Venture Limited Partnership, a former 49%
owned variable interest entity which has been consolidated through the date of
sale, November 21, 2006 (Note 2), which statements reflect total assets
constituting 10.0% in 2005, and total revenues constituting 9.5% in 2006, 11.3%
in 2005 and 13.8% in 2004 of the related consolidated totals. Those statements
were audited by other auditors whose report has been furnished to us, and our
opinion, insofar as it relates to the amounts included for the periods indicated
above for Midland Cogeneration Venture Limited Partnership, is based solely on
the report of the other auditors.

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

     In our opinion, based on our audits and the report of other auditors, the
financial statements referred to above present fairly, in all material respects,
the consolidated financial position of Consumers Energy Company at December 31,
2006 and 2005, and the consolidated results of their operations and their cash
flows for each of the three years in the period ended December 31, 2006, in
conformity with U.S. generally accepted accounting principles. Also, in our
opinion, the related financial statement schedule, when considered in relation
to the basic financial statements taken as a whole, presents fairly in all
material respects the information set forth therein.

     As discussed in Note 6 to the consolidated financial statements, in 2006,
the Company adopted Financial Accounting Standards Board (FASB) Statement of
Financial Accounting Standards No. 158, "Employers' Accounting for Defined
Benefit Pension and Other Postretirement Plans -- an amendment of FASB
Statements No. 87, 88, 106 and 132(R)." As discussed in Note 9 to the
consolidated financial statements, in 2006, the Company adopted FASB Statement
of Financial Accounting Standards No. 123(R) "Share-Based Payment." In addition,
as discussed in Note 7 to the consolidated financial statements, in 2005 the
Company adopted FASB Interpretation No. 47, "Accounting for Conditional Asset
Retirement Obligations." As discussed in Note 6 to the consolidated financial
statements, in 2004 the Company changed its measurement date for all Consumers
Energy Company pension and postretirement plans.

     We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the effectiveness of
Consumers Energy Company's internal control over financial reporting as of
December 31, 2006, based on criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission and our report dated February 21, 2007,
expressed an unqualified opinion thereon.

                                        /s/ Ernst & Young LLP

Detroit, Michigan
February 21, 2007


                                      CE-77

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Partners and the Management Committee of Midland Cogeneration Venture
Limited Partnership:

     In our opinion, the accompanying balance sheets and the related statements
of operations, of partners' equity (deficit) and comprehensive income (loss) and
of cash flows present fairly, in all material respects, the financial position
of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and
December 31, 2005, and the results of its operations and its cash flows for the
period ended November 21, 2006 and the two years in the period ended December
31, 2005 in conformity with accounting principles generally accepted in the
United States of America. These financial statements are the responsibility of
the Partnership's management. Our responsibility is to express an opinion on
these financial statements based on our audits. We conducted our audits of these
statements in accordance with the standards of the Public Company Accounting
Oversight Board (United States). Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements, assessing the accounting principles used and significant estimates
made by management, and evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.

                                        /s/ PricewaterhouseCoopers LLP

February 19, 2007


                                      CE-78

<PAGE>

              ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
                     ON ACCOUNTING AND FINANCIAL DISCLOSURE

CMS ENERGY

     On November 30, 2006, CMS Energy dismissed Ernst & Young LLP ("Ernst &
Young") as its independent registered public accounting firm. The decision to
dismiss Ernst & Young was recommended and approved by the Audit Committee of the
Board of Directors of CMS Energy (the "Audit Committee") and was the result of a
competitive bidding process conducted in the ordinary course of business. Ernst
& Young continued as the auditors for the consolidated financial statements of
CMS Energy for the fiscal year ended December 31, 2006.

     During CMS Energy's two most recent fiscal years ended December 31, 2006
and December 31, 2005 and the subsequent interim period through February 23,
2007, there were no disagreements with Ernst & Young on any matters of
accounting principles or practices, financial statement disclosure, or auditing
scope or procedures which disagreement(s), if not resolved to the satisfaction
of Ernst & Young, would have caused them to make reference to the subject matter
of the disagreement(s) in connection with their reports on CMS Energy's
consolidated financial statements for such years.

     During CMS Energy's two most recent fiscal years ended December 31, 2006
and December 31, 2005 and the subsequent interim period through February 23,
2007, there have been no "reportable events" as defined in Regulation S-K, Item
304(a)(1)(v), except for a material weakness at CMS Energy regarding internal
controls over financial reporting relating to accounting for income taxes as of
December 31, 2005, which has been remediated.

CONSUMERS

     On November 30, 2006, Consumers dismissed Ernst & Young LLP ("Ernst &
Young") as its independent registered public accounting firm. The decision to
dismiss Ernst & Young was recommended and approved by the Audit Committee of the
Board of Directors of Consumers (the "Audit Committee") and was the result of a
competitive bidding process conducted in the ordinary course of business. Ernst
& Young continued as the auditors for the consolidated financial statements of
Consumers for the fiscal year ended December 31, 2006.

     During Consumers' two most recent fiscal years ended December 31, 2006 and
December 31, 2005 and the subsequent interim period through February 23, 2007,
there were no disagreements with Ernst & Young on any matters of accounting
principles or practices, financial statement disclosure, or auditing scope or
procedures which disagreement(s), if not resolved to the satisfaction of Ernst &
Young, would have caused them to make reference to the subject matter of the
disagreement(s) in connection with their reports on Consumers' consolidated
financial statements for such years.

     During Consumers' two most recent fiscal years ended December 31, 2006 and
December 31, 2005 and the subsequent interim period through February 23, 2007,
there have been no "reportable events" as defined in Regulation S-K, Item
304(a)(1)(v).

                  ITEM 9A. CMS ENERGY'S CONTROLS AND PROCEDURES

     CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND
PROCEDURES: Under the supervision and with the participation of management,
including its CEO and CFO, CMS Energy conducted an evaluation of its disclosure
controls and procedures (as such term is defined in Rules 13a-15(e) and 15d-
15(e) under the Exchange Act). Based on such evaluation, CMS Energy's CEO and
CFO have concluded that its disclosure controls and procedures were effective as
of December 31, 2006.

     MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: CMS
Energy's management is responsible for establishing and maintaining adequate
internal control over financial reporting, as defined in Exchange Act Rule 13a-
15(f). CMS Energy's internal control over financial reporting is a process
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles in the United States of
America and includes policies and procedures that:

     - pertain to the maintenance of records that in reasonable detail,
       accurately and fairly reflect the transactions and dispositions of the
       assets of CMS Energy;


                                      CO-1

<PAGE>

     - provide reasonable assurance that transactions are recorded as necessary
       to permit preparation of financial statements in accordance with
       generally accepted accounting principles in the United States of America,
       and that receipts and expenditures of CMS Energy are being made only in
       accordance with authorizations of management and directors of CMS Energy;
       and

     - provide reasonable assurance regarding prevention or timely detection of
       unauthorized acquisition, use or disposition of CMS Energy's assets that
       could have a material effect on its financial statements.

     Management, including its CEO and CFO, does not expect that its internal
controls will prevent or detect all errors and all fraud. A control system, no
matter how well designed and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met. Further,
the design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their
costs. In addition, any evaluation of the effectiveness of controls is subject
to risks that those internal controls may become inadequate in future periods
because of changes in business conditions, or that the degree of compliance with
the policies or procedures deteriorates.

     Under the supervision and with the participation of management, including
its CEO and CFO, CMS Energy conducted an evaluation of the effectiveness of its
internal control over financial reporting as of December 31, 2006. In making
this evaluation, management used the criteria set forth in the framework in
Internal Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on such evaluation, CMS Energy's
management concluded that its internal control over financial reporting was
effective as of December 31, 2006.

     CMS Energy's management's assessment of the effectiveness of CMS Energy's
internal control over financial reporting as of December 31, 2006 has been
audited by Ernst & Young LLP, an independent registered public accounting firm,
which audited the consolidated financial statements of CMS Energy included in
this Form 10-K. Ernst & Young LLP's attestation report on CMS Energy's
management's assessment of internal control over financial reporting is provided
elsewhere in this Item 9A.

     CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING: There have been no
changes in CMS Energy's internal control over financial reporting during the
most recently completed fiscal quarter that have materially affected, or are
reasonably likely to materially affect, its internal control over financial
reporting.


                                      CO-2

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of CMS Energy Corporation

     We have audited management's assessment, included in the accompanying
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that CMS
Energy Corporation (a Michigan Corporation) maintained effective internal
control over financial reporting as of December 31, 2006, based on criteria
established in Internal Control -- Integrated Framework issued by the Committee
of Sponsoring Organizations of the Treadway Commission (the COSO criteria). CMS
Energy Corporation's management is responsible for maintaining effective
internal control over financial reporting and for its assessment of the
effectiveness of internal control over financial reporting. Our responsibility
is to express an opinion on management's assessment and an opinion on the
effectiveness of the company's internal control over financial reporting based
on our audit.

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

     A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

     In our opinion, management's assessment that CMS Energy Corporation
maintained effective internal control over financial reporting as of December
31, 2006, is fairly stated, in all material respects, based on the COSO
criteria. Also, in our opinion, CMS Energy Corporation maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2006, based on the COSO criteria.

     We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of CMS Energy Corporation as of December 31, 2006 and 2005, and the
related consolidated statements of income (loss), common stockholders' equity,
and cash flows for the each of the three years in the period ended December 31,
2006 of CMS Energy Corporation and our report dated February 21, 2007 expressed
an unqualified opinion thereon.

                                        /s/ Ernst & Young LLP

Detroit, Michigan
February 21, 2007


                                      CO-3

<PAGE>

               ITEM 9A. CONSUMERS ENERGY'S CONTROLS AND PROCEDURES

     CONCLUSION REGARDING THE EFFECTIVENESS OF DISCLOSURE CONTROLS AND
PROCEDURES: Under the supervision and with the participation of management,
including its CEO and CFO, Consumers Energy conducted an evaluation of its
disclosure controls and procedures (as such term is defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act). Based on such evaluation, Consumers
Energy's CEO and CFO have concluded that its disclosure controls and procedures
were effective as of December 31, 2006.

     MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING: Consumers
Energy's management is responsible for establishing and maintaining adequate
internal control over financial reporting, as defined in Exchange Act Rule 13a-
15(f). Consumers Energy's internal control over financial reporting is a process
designed to provide reasonable assurance regarding the reliability of financial
reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles in the United States of
America and includes policies and procedures that:

     - pertain to the maintenance of records that in reasonable detail,
       accurately and fairly reflect the transactions and dispositions of the
       assets of Consumers Energy;

     - provide reasonable assurance that transactions are recorded as necessary
       to permit preparation of financial statements in accordance with
       generally accepted accounting principles in the United States of America,
       and that receipts and expenditures of Consumers Energy are being made
       only in accordance with authorizations of management and directors of
       Consumers Energy; and

     - provide reasonable assurance regarding prevention or timely detection of
       unauthorized acquisition, use or disposition of Consumers' assets that
       could have a material effect on its financial statements.

     Management, including its CEO and CFO, does not expect that its internal
controls will prevent or detect all errors and all fraud. A control system, no
matter how well designed and operated, can provide only reasonable, not
absolute, assurance that the objectives of the control system are met. Further,
the design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their
costs. In addition, any evaluation of the effectiveness of controls is subject
to risks that those internal controls may become inadequate in future periods
because of changes in business conditions, or that the degree of compliance with
the policies or procedures deteriorates.

     Under the supervision and with the participation of management, including
its CEO and CFO, Consumers Energy conducted an evaluation of the effectiveness
of its internal control over financial reporting as of December 31, 2006. In
making this evaluation, management used the criteria set forth in the framework
in Internal Control -- Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission. Based on such evaluation,
Consumers' management concluded that its internal control over financial
reporting was effective as of December 31, 2006.

     Consumers Energy's management's assessment of the effectiveness of
Consumers Energy's internal control over financial reporting as of December 31,
2006 has been audited by Ernst & Young LLP, an independent registered public
accounting firm, which audited the consolidated financial statements of
Consumers Energy included in this Form 10-K. Ernst & Young LLP's attestation
report on Consumers Energy's management's assessment of internal control over
financial reporting is provided elsewhere in this Item 9A.

     CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING:  There have been no
changes in Consumers Energy's internal control over financial reporting during
the most recently completed fiscal quarter that have materially affected, or are
reasonably likely to materially affect, its internal control over financial
reporting.


                                      CO-4

<PAGE>

             REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholder of Consumers Energy Company

     We have audited management's assessment, included in the accompanying
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING, that Consumers
Energy Company (a Michigan Corporation and wholly-owned subsidiary of CMS Energy
Corporation) maintained effective internal control over financial reporting as
of December 31, 2006, based on criteria established in Internal
Control -- Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (the COSO criteria). Consumers Energy
Company's management is responsible for maintaining effective internal control
over financial reporting and for its assessment of the effectiveness of internal
control over financial reporting. Our responsibility is to express an opinion on
management's assessment and an opinion on the effectiveness of the company's
internal control over financial reporting based on our audit.

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

     A company's internal control over financial reporting is a process designed
to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company's internal control over
financial reporting includes those policies and procedures that (1) pertain to
the maintenance of records that, in reasonable detail, accurately and fairly
reflect the transactions and dispositions of the assets of the company; (2)
provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted
accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of
the company; and (3) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.

     Because of its inherent limitations, internal control over financial
reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that
controls may become inadequate because of changes in conditions, or that the
degree of compliance with the policies or procedures may deteriorate.

     In our opinion, management's assessment that Consumers Energy Company
maintained effective internal control over financial reporting as of December
31, 2006, is fairly stated, in all material respects, based on the COSO
criteria. Also in our opinion, Consumers Energy Company maintained, in all
material respects, effective internal control over financial reporting as of
December 31, 2006, based on the COSO criteria.

     We also have audited, in accordance with the standards of the Public
Company Accounting Oversight Board (United States), the consolidated balance
sheets of Consumers Energy Company as of December 31, 2006 and 2005, and the
related consolidated statements of income (loss), common stockholder's equity,
and cash flows for the each of the three years in the period ended December 31,
2006 of Consumers Energy Company and our report dated February 21, 2007
expressed an unqualified opinion thereon.

                                        /s/ Ernst & Young LLP

Detroit, Michigan
February 21, 2007


                                      CO-5

<PAGE>

                           ITEM 9B. OTHER INFORMATION

CMS ENERGY

     None.

CONSUMERS

     None.


                                      CO-6

<PAGE>

                                    PART III

         ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

CMS ENERGY

     Information that is required in Item 10 regarding directors, executive
officers and corporate governance is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.

CONSUMERS

     Information that is required in Item 10 regarding Consumers' directors,
executive officers and corporate governance is included in CMS Energy's
definitive proxy statement, which is incorporated by reference herein.

                         ITEM 11. EXECUTIVE COMPENSATION

     Information that is required in Item 11 regarding executive compensation of
CMS Energy's and Consumers' executive officers is included in CMS Energy's
definitive proxy statement, which is incorporated by reference herein.

     The following disclosure describes 2007 compensation issues for officers.

OFFICER INCENTIVE COMPENSATION PLAN

     On February 20, 2007, the Compensation and Human Resources Committees (the
"C&HR Committees") of the Boards of Directors of CMS Energy and Consumers (the
"Boards") approved the payout of cash bonuses under the 2006 Annual Officer
Incentive Compensation Plan as well as the material terms of the 2007 Annual
Officer Incentive Compensation Plan (the "Plan"), including the corporate
performance goals thereunder. The Plan includes the material terms detailed
below, although the specific target levels for the corporate performance goals
vary from year to year.

     CORPORATE PERFORMANCE GOALS: The composite plan performance factor will
depend on corporate performance in two areas: (1) the adjusted net income per
outstanding CMS Energy common share ("Plan EPS"); and (2) the corporate free
cash flow of CMS Energy ("CFCF"). Plan EPS performance shall constitute one-half
of the composite plan performance factor and CFCF performance shall constitute
one-half of the composite plan performance factor. There will be a payout under
the Plan if either a Plan EPS performance factor of at least 94.1 percent of the
target Plan EPS or a CFCF performance factor of at least 92 percent of the
target CFCF is achieved. Even if only one but not both of these target minimums
is achieved, a partial payout would result. The composite plan performance
factor to be used for payouts will be capped at a maximum of 200 percent. Annual
awards under the Plan to Consumers' officers may be reduced by 25 percent in the
event that there is no payout to non-officer, non-union employees under a
separate Consumers' employee incentive plan.

     ANNUAL AWARD FORMULA: Annual awards for each eligible officer will be based
upon a standard award percentage of the officer's base salary as in effect on
January 1 of the performance year. The maximum amount that can be awarded under
the Plan for any Internal Revenue Code Section 162(m) employee will not exceed
$2.5 million in any one performance year. Annual awards for officers will be
calculated and made as follows: Individual Award = Base Salary times Standard
Award % times Performance Factor %.

     The standard award percentages for officers are based on individual salary
grade levels and remain unchanged from the 2006 plan.

     PAYMENT OF ANNUAL AWARDS: All annual awards for a performance year will be
paid in cash no later than March 15th of the calendar year following the
performance year provided that they first have been reviewed and approved by the
C&HR Committees, and provided further that the annual award for a particular
performance year has not been deferred voluntarily. The amounts required by law
to be withheld for income and employment taxes will be deducted from the annual
award payments. All annual awards become the obligation of the company on whose
payroll the employee is enrolled at the time the C&HR Committees make the annual
award.


                                      CO-7

<PAGE>

          ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
                   MANAGEMENT AND RELATED STOCKHOLDER MATTERS

CMS ENERGY

     Information that is required in Item 12 regarding securities authorized for
issuance under equity compensation plans and security ownership of certain
beneficial owners and management is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.

CONSUMERS

     Information that is required in Item 12 regarding securities authorized for
issuance under equity compensation plans and security ownership of certain
beneficial owners and management of Consumers is included in CMS Energy's
definitive proxy statement, which is incorporated by reference herein.

            ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,
                            AND DIRECTOR INDEPENDENCE

CMS ENERGY

     Information that is required in Item 13 regarding certain relationships and
related transactions, and director independence is included in CMS Energy's
definitive proxy statement, which is incorporated by reference herein.

CONSUMERS

     Information that is required in Item 13 regarding certain relationships and
related transactions, and director independence regarding Consumers is included
in CMS Energy's definitive proxy statement, which is incorporated by reference
herein.

                 ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

CMS ENERGY

     Information that is required in Item 14 regarding principal accountant fees
and services is included in CMS Energy's definitive proxy statement, which is
incorporated by reference herein.

CONSUMERS

     Information that is required in Item 14 regarding principal accountant fees
and services relating to Consumers is included in CMS Energy's definitive proxy
statement, which is incorporated by reference herein.

                                     PART IV

               ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)(1)      Financial Statements and Reports of Independent Public Accountants
            for CMS Energy and Consumers are included in each company's ITEM 8.
            FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA and are incorporated by
            reference herein.


                                      CO-8

<PAGE>

(a)(2)      Index to Financial Statement Schedules.


<Table>
<Caption>
                                                                              PAGE
                                                                            -------

<S>           <C>                                                           <C>

Schedule I    Condensed Financial Information of Registrant
                   CMS Energy-Parent Company
                     Condensed Statements of Income (Loss)..............    CO-14
                     Statements of Cash Flows...........................    CO-15
                     Condensed Balance Sheets...........................    CO-16
                     Notes to Condensed Financial Statements............    CO-17
Schedule II   Valuation and Qualifying Accounts and Reserves
                   CMS Energy Corporation...............................    CO-19
                   Consumers Energy Company.............................    CO-19
Report of Independent Registered Public Accounting Firm
                   CMS Energy Corporation...............................    CMS-105
                   Consumers Energy Company.............................    CE-77
</Table>


     Schedules other than those listed above are omitted because they are either
not required, not applicable or the required information is shown in the
financial statements or notes thereto. Columns omitted from schedules filed have
been omitted because the information is not applicable.

(a)(3)      Exhibits for CMS Energy and Consumers are listed after Item 15(b)
            below and are incorporated by reference herein.

(b)         Exhibits, including those incorporated by reference.


                                      CO-9

<PAGE>

                      CMS ENERGY'S AND CONSUMERS' EXHIBITS



<Table>
<Caption>
                   PREVIOUSLY FILED
              --------------------------
                WITH FILE    AS EXHIBIT
  EXHIBITS       NUMBER        NUMBER          DESCRIPTION
  --------      ---------    ----------        -----------

<S>           <C>           <C>           <C>  <C>

(3)(a)        1-9513        (99)(a)       --   Restated Articles of Incorporation of CMS Energy
                                               (Form 8-K filed June 3, 2004)
(3)(b)        1-9513        (3)(a)        --   Bylaws of CMS Energy (Form 8-K filed October 6,
                                               2004)
(3)(c)        1-5611        3(c)          --   Restated Articles of Incorporation dated May 26,
                                               2000, of Consumers (2000 Form 10-K)
(3)(d)        1-5611        (3)(b)        --   Bylaws of Consumers (Form 8-K filed October 6,
                                               2004)
(4)(a)        2-65973       (b)(1)-4      --   Indenture dated as of September 1, 1945, between
                                               Consumers and Chemical Bank (successor to
                                               Manufacturers Hanover Trust Company), as Trustee,
                                               including therein indentures supplemental thereto
                                               through the Forty-third Supplemental Indenture
                                               dated as of May 1, 1979
                                          --   Indentures Supplemental thereto:
              1-5611        (4)(a)        --   70th dated as of 2/01/98 (1997 Form 10-K)
              1-5611        (4)(a)        --   71st dated as of 3/06/98 (1997 Form 10-K)
              1-5611        (4)(b)        --   75th dated as of 10/1/99 (1999 Form 10-K)
              1-5611        (4)(d)        --   77th dated as of 10/1/99 (1999 Form 10-K)
              1-5611        (4)(d)        --   90th dated as of 4/30/03 (1st qtr. 2003 Form 10-Q)
              1-5611        (4)(a)        --   91st dated as of 5/23/03 (3rd qtr. 2003 Form 10-Q)
              1-5611        (4)(b)        --   92nd dated as of 8/26/03 (3rd qtr. 2003 Form 10-Q)
              1-5611        (4)(a)        --   96th dated as of 8/17/04 (Form 8-K filed August
                                               20, 2004)
              333-120611    (4)(e)(xv)    --   97th dated as of 9/1/04 (Consumers Form S-3 dated
                                               November 18, 2004)
              1-5611        4.4           --   98th dated as of 12/13/04 (Form 8-K filed December
                                               13, 2004)
              1-5611        (4)(a)(i)     --   99th dated as of 1/20/05 (2004 Form 10-K)
              1-5611        4.2           --   100th dated as of 3/24/05 (Form 8-K filed March
                                               30, 2005)
              1-5611        (4)(a)        --   101st dated as of 4/1/05 (1st qtr 2005 Form 10-Q)
              1-5611        4.2           --   102nd dated as of 4/13/05 (Form 8-K filed April
                                               13, 2005)
              1-5611        4.2           --   104th dated as of 8/11/05 (Form 8-K filed August
                                               11, 2005)
(4)(b)        1-5611        (4)(b)        --   Indenture dated as of January 1, 1996 between
                                               Consumers and The Bank of New York, as Trustee
                                               (1995 Form 10-K)
(4)(c)        1-5611        (4)(c)        --   Indenture dated as of February 1, 1998 between
                                               Consumers and JPMorgan Chase Bank, N.A. (formerly
                                               The Chase Manhattan Bank), as Trustee (1997 Form
                                               10-K)
(4)(d)        33-47629      (4)(a)        --   Indenture dated as of September 15, 1992 between
                                               CMS Energy and NBD Bank, as Trustee (Form S-3
                                               filed May 1, 1992) Indentures Supplemental
                                               thereto:
              1-9513        (4)(d)(i)     --   7th dated as of 1/25/99 (1998 Form 10-K)
              333-48276     (4)           --   10th dated as of 10/12/00 (Form S-3 filed October
                                               19, 2000)
              333-58686     (4)(a)        --   11th dated as of 3/29/01 (Form S-8 filed April 11,
                                               2001)
              333-51932     (4)(a)        --   12th dated as of 7/02/01 (Form POS AM filed August
                                               3, 2001)
              1-9513        (4)(d)(i)     --   15th dated as of 9/29/04 (2004 Form 10-K)
              1-9513        (4)(d)(ii)    --   16th dated as of 12/16/04 (2004 Form 10-K)
              1-9513        4.2           --   17th dated as of 12/13/04 (Form 8-K filed December
                                               13, 2004)
              1-9513        4.2           --   18th dated as of 1/19/05 (Form 8-K filed January
                                               20, 2005)
              1-9513        4.2           --   19th dated as of 12/13/05 (Form 8-K filed December
                                               15, 2005)
(4)(e)        1-9513        (4a)          --   Indenture dated as of June 1, 1997, between CMS
                                               Energy and The Bank of New York, as trustee (Form
                                               8-K filed July 1, 1997)
</Table>

                                      CO-10

<PAGE>

<Table>
<Caption>
                   PREVIOUSLY FILED
              --------------------------
                WITH FILE    AS EXHIBIT
  EXHIBITS       NUMBER        NUMBER          DESCRIPTION
  --------      ---------    ----------        -----------

<S>           <C>           <C>           <C>  <C>
                                          --   Indentures Supplemental thereto:
              1-9513        (4)(b)        --   1st dated as of 6/20/97 (Form 8-K filed July 1,
                                               1997)
(4)(f)        1-9513        (4)(i)        --   Certificate of Designation of 4.50% Cumulative
                                               Convertible Preferred Stock dated as of December
                                               2, 2003 (2003 Form 10-K)
(10)(a)       333-125553    (4)(j)        --   $300 million Sixth Amended and Restated Credit
                                               Agreement dated as of May 18, 2005 among CMS
                                               Energy, Enterprises, the Banks, and the
                                               Administrative Agent and Collateral Agent, all
                                               defined therein (Form S-3 filed June 6, 2005)
(10)(b)       333-125553    (4)(k)        --   Reaffirmation of grant of a security interest
                                               dated as of May 18, 2005 among CMS Energy, CMS
                                               Enterprises, and the Administrative Agent and
                                               Collateral Agent, as defined therein (Form S-3
                                               filed June 6, 2005)
(10)(c)       1-9513        (4)(l)        --   Cash Collateral Agreement dated as of August 3,
                                               2004 made by CMS Energy to the Administrative
                                               Agent for the lenders and Collateral Agent, as
                                               defined therein (2004 Form 10-K)
(10)(d)       1-5611        (4)(b)        --   $500 million Third Amended and Restated Credit
                                               Agreement dated as of May 18, 2005 among
                                               Consumers, the Banks, the Administrative Agent,
                                               the Syndication Agent and the Co-Documentation
                                               Agents, all as defined therein (2nd qtr
                                               2005 Form 10-Q)
                                          --   Indenture Supplemental thereto:
              1-5611        (10)(e)       --   103rd Supplemental Indenture to the Indenture
                                               dated as of September 1, 1945 between Consumers
                                               and Chemical Bank (successor to Manufacturers
                                               Hanover Trust Company), as Trustee (2005 Form 10-
                                               K)
(10)(e)       1-5611        (10)(a)       --   $300 million Credit Agreement dated as of March
                                               31, 2006 among Consumers, the Banks, the
                                               Administrative Agent, the Syndication Agent, the
                                               Co-Documentation Agents, and the Co-Managing
                                               Agents, all as defined therein (1st qtr 2006 Form
                                               10-Q)
(10)(f)                                   --   CMS Energy's Performance Incentive Stock Plan
                                               effective February 3, 1988, as amended June 1,
                                               2004 and as further amended effective February 20,
                                               2007
(10)(g)       1-9513        (10)(m)       --   CMS Deferred Salary Savings Plan effective January
                                               1, 1994 (1993 Form 10-K)
(10)(h)                                   --   Annual Officer Incentive Compensation Plan for CMS
                                               Energy Corporation and its Subsidiaries effective
                                               January 1, 2006
(10)(i)       1-9513        (10)(h)       --   Supplemental Executive Retirement Plan for
                                               Employees of CMS Energy/Consumers Energy Company
                                               effective January 1, 1982, as amended December 3,
                                               1999 (1999 Form 10-K)
(10)(j)       1-9513        (10)(v)       --   Amended and Restated Investor Partner Tax
                                               Indemnification Agreement dated as of June 1, 1990
                                               among Investor Partners, CMS Midland as Indemnitor
                                               and CMS Energy as Guarantor (1990 Form 10-K)
(10)(k)       1-9513        (19)(d)*      --   Environmental Agreement dated as of June 1, 1990
                                               made by CMS Energy to The Connecticut National
                                               Bank and Others (1990 Form 10-K)
(10)(l)       1-9513        (10)(z)*      --   Indemnity Agreement dated as of June 1, 1990 made
                                               by CMS Energy to Midland Cogeneration Venture
                                               Limited Partnership (1990 Form 10-K)
</Table>

                                      CO-11

<PAGE>

<Table>
<Caption>
                   PREVIOUSLY FILED
              --------------------------
                WITH FILE    AS EXHIBIT
  EXHIBITS       NUMBER        NUMBER          DESCRIPTION
  --------      ---------    ----------        -----------

<S>           <C>           <C>           <C>  <C>
(10)(m)       1-9513        (10)(aa)*     --   Environmental Agreement dated as of June 1, 1990
                                               made by CMS Energy to United States Trust Company
                                               of New York, Meridian Trust Company, each
                                               Subordinated Collateral Trust Trustee and Holders
                                               from time to time of Senior Bonds and Subordinated
                                               Bonds and Participants from time to time in Senior
                                               Bonds and Subordinated Bonds (1990 Form 10-K)
(10)(n)       33-3797       10.4          --   Power Purchase Agreement dated as of July 17, 1986
                                               between MCV Partnership and Consumers (MCV
                                               Partnership) Amendments thereto:
              33-37977      10.5          --   Amendment No. 1 dated September 10, 1987 (MCV
                                               Partnership)
              33-37977      10.6          --   Amendment No. 2 dated March 18, 1988 (MCV
                                               Partnership)
              33-37977      10.7          --   Amendment No. 3 dated August 28, 1989 (MCV
                                               Partnership)
              33-37977      10.8          --   Amendment No. 4A dated May 25, 1989 (MCV
                                               Partnership)
(10)(o)       1-5611        (10)(y)       --   Unwind Agreement dated as of December 10, 1991 by
                                               and among CMS Energy, Midland Group, Ltd.,
                                               Consumers, CMS Midland, Inc., MEC Development
                                               Corp. and CMS Midland Holdings Company (1991 Form
                                               10-K)
(10)(p)       1-5611        (10)(z)       --   Stipulated AGE Release Amount Payment Agreement
                                               dated as of June 1, 1990, among CMS Energy,
                                               Consumers and The Dow Chemical Company (1991 Form
                                               10-K)
(10)(q)       1-5611        (10)(aa)*     --   Parent Guaranty dated as of June 14, 1990 from CMS
                                               Energy to MCV, each of the Owner Trustees, the
                                               Indenture Trustees, the Owner Participants and the
                                               Initial Purchasers of Senior Bonds in the MCV Sale
                                               Leaseback transaction, and MEC Development (1991
                                               Form 10-K)
(10)(r)       1-8157        10.41         --   Contract for Firm Transportation of Natural Gas
                                               between Consumers Power Company and Trunkline Gas
                                               Company, dated November 1, 1989, and Amendment,
                                               dated November 1, 1989 (1989 Form 10-K of
                                               PanEnergy Corp.)
(10)(s)       1-8157        10.41         --   Contract for Firm Transportation of Natural Gas
                                               between Consumers Power Company and Trunkline Gas
                                               Company, dated November 1, 1989 (1991 Form 10-K of
                                               PanEnergy Corp.)
(10)(t)       1-2921        10.03         --   Contract for Firm Transportation of Natural Gas
                                               between Consumers Power Company and Trunkline Gas
                                               Company, dated September 1, 1993 (1993 Form 10-K)
(10)(u)       1-5611        10            --   First Amended and Restated Employment Agreement
                                               between Kenneth Whipple and CMS Energy Corporation
                                               effective as of September 1, 2003 (8-K dated
                                               October 24, 2003)
(10)(v)       1-5611        (10)(a)       --   Asset Sale Agreement dated as of July 11, 2006 by
                                               and among Consumers Energy Company as Seller and
                                               Entergy Nuclear Palisades, LLC as Buyer (2nd qtr
                                               2006 Form 10-Q)
(10)(w)       1-5611        (10)(b)       --   Palisades Nuclear Power Plant Power Purchase
                                               Agreement dated as of July 11, 2006 between
                                               Entergy Nuclear Palisades, LLC and Consumers
                                               Energy Company (2nd qtr 2006 Form 10-Q)
(10)(x)       1-9513        99.2          --   Letter of Intent dated January 31, 2007 between
                                               CMS Enterprises Company and Lucid Energy LLC (Form
                                               8-K filed February 1, 2007)
(10)(y)       1-9513        99.2          --   Agreement of Purchase and Sale by and between CMS
                                               Enterprises Company and Abu Dhabi National Energy
                                               Company PJSC dated as of February 3, 2007 (Form 8-
                                               K filed February 6, 2007)
</Table>

                                      CO-12

<PAGE>

<Table>
<Caption>
                   PREVIOUSLY FILED
              --------------------------
                WITH FILE    AS EXHIBIT
  EXHIBITS       NUMBER        NUMBER          DESCRIPTION
  --------      ---------    ----------        -----------

<S>           <C>           <C>           <C>  <C>
(10)(z)       1-9513        99.2          --   Memorandum of Understanding dated February 13,
                                               2007 between CMS Energy Corporation and Petroleos
                                               de Venezuela, S.A. (Form 8-K filed February 14,
                                               2007)
(12)(a)                                   --   Statement regarding computation of CMS Energy's
                                               Ratio of Earnings to Fixed Charges and Preferred
                                               Dividends
(12)(b)                                   --   Statement regarding computation of Consumers'
                                               Ratio of Earnings to Fixed Charges and Preferred
                                               Dividends and Distributions
(21)                                      --   Subsidiaries of CMS Energy and Consumers
(23)(a)                                   --   Consent of Ernst & Young LLP for CMS Energy
(23)(b)                                   --   Consent of PricewaterhouseCoopers LLP for CMS
                                               Energy re: MCV
(23)(c)                                   --   Consent of Ernst & Young for CMS Energy re: Jorf
                                               Lasfar
(23)(d)                                   --   Consent of Price Waterhouse for CMS Energy re:
                                               Jorf Lasfar
(23)(e)                                   --   Consent of Ernst & Young LLP for Consumers
(23)(f)                                   --   Consent of PricewaterhouseCoopers LLP for
                                               Consumers re: MCV
(24)(a)                                   --   Power of Attorney for CMS Energy
(24)(b)                                   --   Power of Attorney for Consumers
(31)(a)                                   --   CMS Energy's certification of the CEO pursuant to
                                               Section 302 of the Sarbanes-Oxley Act of 2002
(31)(b)                                   --   CMS Energy's certification of the CFO pursuant to
                                               Section 302 of the Sarbanes-Oxley Act of 2002
(31)(c)                                   --   Consumers' certification of the CEO pursuant to
                                               Section 302 of the Sarbanes-Oxley Act of 2002
(31)(d)                                   --   Consumers' certification of the CFO pursuant to
                                               Section 302 of the Sarbanes-Oxley Act of 2002
(32)(a)                                   --   CMS Energy's certifications pursuant to Section
                                               906 of the Sarbanes-Oxley Act of 2002
(32)(b)                                   --   Consumers' certifications pursuant to Section 906
                                               of the Sarbanes-Oxley Act of 2002
(99)(a)                                   --   Financial Statements for Jorf Lasfar for the years
                                               ended December 31, 2004, 2005, and 2006
</Table>



--------------
*    Obligations of only CMS Holdings and CMS Midland, second tier subsidiaries
     of Consumers, and of CMS Energy but not of Consumers.

     Exhibits listed above that have heretofore been filed with the Securities
and Exchange Commission pursuant to various acts administered by the Commission,
and which were designated as noted above, are hereby incorporated herein by
reference and made a part hereof with the same effect as if filed herewith.


                                      CO-13

<PAGE>

                             CMS ENERGY CORPORATION
           SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

                          CMS ENERGY -- PARENT COMPANY
                      CONDENSED STATEMENTS OF INCOME (LOSS)


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                       2006    2005    2004
-----------------------                                      -----   -----   -----
                                                                 (IN MILLIONS)

<S>                                                          <C>     <C>     <C>

Dividends from Consolidated Subsidiaries...................  $ 147   $ 573   $ 413
Other Operating Deductions.................................   (115)    (33)    (12)
                                                             -----   -----   -----
  Total Operating Income...................................     32     540     401
                                                             -----   -----   -----
Other Income (Deductions)
  Equity in undistributed earnings of subsidiaries.........    (55)   (514)   (124)
  Interest income (expense)................................     --     (14)    (12)
  Gain on sale of assets...................................     --      --       3
  Other....................................................     (6)    (11)     (1)
                                                             -----   -----   -----
                                                               (61)   (539)   (134)
                                                             -----   -----   -----
Fixed Charges
  Interest on long-term debt...............................    173     184     213
  Interest on preferred securities.........................     14      14      14
  Intercompany interest expense and other..................     24       7      30
                                                             -----   -----   -----
                                                               211     205     257
                                                             -----   -----   -----
Income (Loss) Before Income Taxes..........................   (240)   (204)     10
  Income Tax Benefit.......................................   (161)   (121)   (110)
                                                             -----   -----   -----
Income (Loss) From Continuing Operations...................    (79)    (83)    120
  Income (Loss) From Discontinued Operations...............     --      (1)      1
                                                             -----   -----   -----
Net Income (Loss)..........................................    (79)    (84)    121
Preferred Dividends........................................     11      10      11
                                                             -----   -----   -----
Net Income (Loss) Available to Common Stockholders.........  $ (90)  $ (94)  $ 110
                                                             =====   =====   =====

</Table>



   The accompanying condensed notes are an integral part of these statements.


                                      CO-14

<PAGE>

                             CMS ENERGY CORPORATION

           SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

                          CMS ENERGY -- PARENT COMPANY
                            STATEMENTS OF CASH FLOWS


<Table>
<Caption>
YEARS ENDED DECEMBER 31                                       2006    2005    2004
-----------------------                                      -----   -----   -----
                                                                 (IN MILLIONS)

<S>                                                          <C>     <C>     <C>

Cash Flows From Operating Activities
  Net income (loss)........................................  $ (79)  $ (84)  $ 121
     Adjustments to reconcile net income (loss) to net cash
       provided by operating activities:
       Equity earnings of subsidiaries.....................    (92)    (59)   (289)
       Dividends received from subsidiaries................    147     573     413
       Depreciation........................................      3       2       1
       Gain on sale of assets..............................     --      --      (3)
       Decrease (increase) in accounts receivable..........    (77)     --       9
       Increase (decrease) in accounts payable.............      2      (9)    (11)
       Increase in legal settlement liability..............    200      --      --
       Change in other assets and liabilities..............    (13)    (10)    (69)
                                                             -----   -----   -----
     Net cash provided by operating activities.............     91     413     172
                                                             -----   -----   -----
Cash Flows From Investing Activities
  Investment in subsidiaries...............................   (216)   (855)   (462)
  Return of investment.....................................     --      --     113
  Changes in notes receivable, net.........................    (15)    267      21
                                                             -----   -----   -----
     Net cash used in investing activities.................   (231)   (588)   (328)
                                                             -----   -----   -----
Cash Flows From Financing Activities
  Proceeds from bank loans and notes.......................     --     275     287
  Proceeds from issuance of common stock...................     23     295     290
  Retirement of bank loans and notes.......................    (75)   (323)   (632)
  Payment of preferred stock dividends.....................    (11)    (11)    (11)
  Debt issuance costs and financing fees...................     (5)    (16)     --
  Changes in notes payable, net............................    208     (45)    222
                                                             -----   -----   -----
     Net cash provided by financing activities.............    140     175     156
                                                             -----   -----   -----
Net Change in Cash and Temporary Cash Investments..........  $  --   $  --   $  --
Cash and Temporary Cash Investments, Beginning of Period...  $  --   $  --   $  --
Cash and Temporary Cash Investments, End of Period.........  $  --   $  --   $  --
                                                             =====   =====   =====

</Table>



   The accompanying condensed notes are an integral part of these statements.


                                      CO-15

<PAGE>

                             CMS ENERGY CORPORATION

           SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

                          CMS ENERGY -- PARENT COMPANY
                            CONDENSED BALANCE SHEETS


<Table>
<Caption>
DECEMBER 31                                                         2006     2005
-----------                                                        ------   ------
                                                                    (IN MILLIONS)

<S>                                                                <C>      <C>

                                      ASSETS
Property, Plant and Equipment, at cost...........................  $   16   $   16
  Less accumulated depreciation..................................      (9)      (6)
                                                                   ------   ------
                                                                        7       10
                                                                   ------   ------
Investment in Subsidiaries.......................................   5,205    5,051
                                                                   ------   ------
Current Assets
  Cash and temporary cash investments............................      --       --
  Notes and accrued interest receivable..........................      44       28
  Accrued taxes receivable.......................................      --       19
  Accounts receivable, including intercompany and related
     parties.....................................................      90       13
  Deferred income taxes..........................................     102       --
  Prepayments and other current assets...........................       2        2
                                                                   ------   ------
                                                                      238       62
                                                                   ------   ------
Non-current Assets
  Preferred income taxes.........................................     286      309
  Other investment -- SERP.......................................      17       17
  Other..........................................................      29       37
                                                                   ------   ------
                                                                      332      363
                                                                   ------   ------
TOTAL ASSETS.....................................................  $5,782   $5,486
                                                                   ======   ======
                     STOCKHOLDERS' INVESTMENT AND LIABILITIES
Capitalization
  Common stockholders' equity....................................  $2,234   $2,322
  Nonredeemable preferred stock..................................     250      250
  Intercompany notes payable.....................................     128      187
  Long-term debt
     Senior Notes................................................   1,833    2,199
     Related Party...............................................     178      178
     Unamortized Discount........................................      (8)     (11)
                                                                   ------   ------
                                                                    4,615    5,125
                                                                   ------   ------
Current Liabilities
  Current portion of long-term debt..............................     439      150
  Accounts and notes payable, including intercompany and related
     parties.....................................................     323       54
  Accrued interest, including intercompany.......................      60       59
  Accrued taxes..................................................      53       --
  Legal settlement liability.....................................     200       --
  Other..........................................................      11       21
                                                                   ------   ------
                                                                    1,086      284
                                                                   ------   ------
Non-Current Liabilities
  Postretirement benefits........................................      24       20
  Other..........................................................      57       57
                                                                   ------   ------
                                                                       81       77
                                                                   ------   ------
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES...................  $5,782   $5,486
                                                                   ======   ======

</Table>



   The accompanying condensed notes are an integral part of these statements.


                                      CO-16

<PAGE>

                             CMS ENERGY CORPORATION

           SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

                          CMS ENERGY -- PARENT COMPANY
                     NOTES TO CONDENSED FINANCIAL STATEMENTS

1: SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     CORPORATE STRUCTURE AND BASIS OF PRESENTATION: CMS Energy is an energy
company operating primarily in Michigan. We are the parent holding company of
Consumers Energy and Enterprises. The condensed financial statements of CMS
Energy -- Parent Company reflect the investments in wholly owned subsidiaries
using the equity method of accounting.

     USE OF ESTIMATES: CMS Energy is required to make estimates using
assumptions that may affect the reported amounts and disclosures. Actual results
could differ from those estimates. We record estimated liabilities for
contingencies in our condensed financial statements when it is probable that a
loss will be incurred in the future as a result of a current event, and when an
amount can be reasonably estimated.

2: CONTINGENCIES

     SECURITIES CLASS ACTION LAWSUITS: On January 3, 2007, CMS Energy and other
parties entered into a Memorandum of Understanding (the "MOU") dated December
28, 2006, subject to court approval, regarding settlement of the two class
action lawsuits. The settlement was approved by a special committee of
independent directors and by the full board of directors. Both judged that it
was in the best interests of shareholders to eliminate this business
uncertainty. The MOU is expected to lead to a detailed stipulation of settlement
that will be presented to the assigned federal judge and the affected class in
the first quarter of 2007. Under the terms of the MOU, the litigation will be
settled for a total of $200 million, including the cost of administering the
settlement and any attorney fees the court awards. CMS Energy will make a
payment of approximately $123 million plus an amount equivalent to interest on
the outstanding unpaid settlement balance beginning on the date of preliminary
approval of the court and running until the balance of the settlement funds is
paid into a settlement account. Out of the total settlement, CMS Energy's
insurers will pay approximately $77 million directly to the settlement account.
CMS Energy took an approximately $123 million net pre-tax charge to 2006
earnings in the fourth quarter. In entering into the MOU, CMS Energy makes no
admission of liability under the Shareholder Action and the ACTS Action. At
December 31, 2006, we have recorded the $77 million as an accounts receivable
and the $200 million as a legal settlement liability on our CMS Energy -- Parent
Company Condensed Balance Sheets. Additional details are included in Note 3,
Contingencies to the Annual Report.

3: FINANCINGS

     Long-term debt, including current maturities was $2,272 million at December
31, 2006 and $2,349 million at December 31, 2005. Long-term debt -- related
parties was $178 million at December 31, 2006 and December 31, 2005.

     At December 31, 2006, the annual maturities for long-term debt and long-
term debt -- related parties for the next five years are:


<Table>
<Caption>
                                                               PAYMENTS DUE
                                                     --------------------------------
                                                     2007   2008   2009   2010   2011
                                                     ----   ----   ----   ----   ----
                                                               (IN MILLIONS)

<S>                                                  <C>    <C>    <C>    <C>    <C>

Long-term debt and long-term debt -- related
  parties..........................................  $289   $260   $409   $300   $300
                                                     ====   ====   ====   ====   ====

</Table>


     Additional details on long-term debt, dividend restrictions and
capitalization are included in Note 4, Financings and Capitalization to the
Annual Report.

4: RELATED PARTY TRANSACTIONS

     COMMON STOCK: Consumers Energy held 2.2 million shares of CMS Energy's
common stock at December 31, 2006 and 2.3 million shares at December 31, 2005.


                                      CO-17

<PAGE>

                             CMS ENERGY CORPORATION

           SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

                          CMS ENERGY -- PARENT COMPANY
             NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

     CASH DIVIDENDS PAID: Our consolidated subsidiaries, Consumers Energy and
Enterprises paid the following common stock dividends to CMS Energy for the
years ended December 31:


<Table>
<Caption>
                                                               2006   2005   2004
                                                               ----   ----   ----
                                                                  (IN MILLIONS)

<S>                                                            <C>    <C>    <C>

Dividends:
  Consumers Energy...........................................  $147   $277   $190
  Enterprises................................................    --    296    223
                                                               ----   ----   ----
Total........................................................  $147   $573   $413
                                                               ====   ====   ====

</Table>




                                      CO-18

<PAGE>

                             CMS ENERGY CORPORATION

          SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                  YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004


<Table>
<Caption>
                                                                   CHARGED/
                                         BALANCE AT                 ACCRUED                 BALANCE
                                          BEGINNING     CHARGED    TO OTHER                  AT END
DESCRIPTION                               OF PERIOD   TO EXPENSE   ACCOUNTS   DEDUCTIONS   OF PERIOD
-----------                              ----------   ----------   --------   ----------   ---------
                                                                (IN MILLIONS)

<S>                                      <C>          <C>          <C>        <C>          <C>

Accumulated provision for uncollectible
  accounts:
  2006.................................      $31          $28         $--         $26         $ 33
  2005.................................      $38          $23         $--         $30         $ 31
  2004.................................      $40          $19         $--         $21         $ 38
Deferred tax valuation allowance:
  2006.................................      $10          $31         $86         $11         $116
  2005.................................      $42          $ 1         $--         $33         $ 10
  2004.................................      $42          $ 1         $--         $ 1         $ 42
Allowance for notes receivable,
  including related parties:
  2006.................................      $49          $55         $--         $ 4         $100
  2005.................................      $40          $ 9         $--         $--         $ 49
  2004.................................      $40          $--         $--         $--         $ 40
</Table>


                            CONSUMERS ENERGY COMPANY

          SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
                  YEARS ENDED DECEMBER 31, 2006, 2005 AND 2004


<Table>
<Caption>
                                                                   CHARGED/
                                         BALANCE AT                 ACCRUED                 BALANCE
                                          BEGINNING     CHARGED    TO OTHER                  AT END
DESCRIPTION                               OF PERIOD   TO EXPENSE   ACCOUNTS   DEDUCTIONS   OF PERIOD
-----------                              ----------   ----------   --------   ----------   ---------
                                                                (IN MILLIONS)

<S>                                      <C>          <C>          <C>        <C>          <C>

Accumulated provision for uncollectible
  accounts:
  2006.................................      $13          $30         $--         $29         $14
  2005.................................      $10          $24         $--         $21         $13
  2004.................................      $ 8          $20         $--         $18         $10
Deferred tax valuation allowance:
  2006.................................      $--          $16         $--         $ 1         $15
  2005.................................      $ 9          $ 1         $--         $10         $--
  2004.................................      $ 8          $ 1         $--         $--         $ 9
</Table>




                                      CO-19

<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, CMS Energy Corporation has duly caused this Annual Report
to be signed on its behalf by the undersigned, thereunto duly authorized, on the
23rd day of February 2007.

                                        CMS ENERGY Corporation

                                        By         /s/ DAVID W. JOOS
                                           -------------------------------------
                                                       David W. Joos
                                           President and Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report has been signed below by the following persons on behalf of CMS
Energy Corporation and in the capacities and on the 23rd day of February 2007.


<Table>
<Caption>
              SIGNATURE                                    TITLE
              ---------                                    -----

<S>    <C>                               <C>

  (i)  Principal executive officer:


                                           President and Chief Executive Officer
            /s/ DAVID W. JOOS

       ------------------------------
                David W. Joos



 (ii)  Principal financial officer:


                                               Executive Vice President and
           /s/ THOMAS J. WEBB                     Chief Financial Officer

       ------------------------------
               Thomas J. Webb



(iii)  Controller or principal
       accounting officer:


                                              Vice President, Controller and
           /s/ GLENN P. BARBA                    Chief Accounting Officer

       ------------------------------
               Glenn P. Barba



 (iv)  A majority of the Directors
       including those named above:


                                                         Director
                      *

       ------------------------------
              Merribel S. Ayres


                                                         Director
                      *
       ------------------------------
               Jon E. Barfield


                                                         Director
                      *
       ------------------------------
              Richard M. Gabrys


                                                         Director
                      *
       ------------------------------
                David W. Joos


                                                         Director
                      *
       ------------------------------
           Philip R. Lochner, Jr.


                                                         Director
                      *
       ------------------------------
             Michael T. Monahan


                                                         Director
                      *
       ------------------------------
           Joseph F. Paquette, Jr.
</Table>

                                      CO-20

<PAGE>

<Table>
<Caption>
              SIGNATURE                                    TITLE
              ---------                                    -----

<S>    <C>                               <C>


                                                         Director
                      *
       ------------------------------
               Percy A. Pierre


                                                         Director
                      *
       ------------------------------
               Kenneth L. Way


                                                         Director
                      *
       ------------------------------
               Kenneth Whipple


                                                         Director
                      *
       ------------------------------
              John B. Yasinsky



  *By      /s/ THOMAS J. WEBB
       ------------------------------
               Thomas J. Webb,
              Attorney-in-Fact
</Table>




                                      CO-21

<PAGE>

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, Consumers Energy Company has duly caused this Annual
Report to be signed on its behalf by the undersigned, thereunto duly authorized,
on the 23rd day of February 2007.

                                        CONSUMERS ENERGY COMPANY

                                        By         /s/ DAVID W. JOOS
                                           -------------------------------------
                                                       David W. Joos
                                                  Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report has been signed below by the following persons on behalf of
Consumers Energy Company and in the capacities and on the 23rd day of February
2007.


<Table>
<Caption>
              SIGNATURE                                    TITLE
              ---------                                    -----

<S>    <C>                               <C>

  (i)  Principal executive officer:


                                                  Chief Executive Officer
            /s/ DAVID W. JOOS

       ------------------------------
                David W. Joos



 (ii)  Principal financial officer:


                                               Executive Vice President and
           /s/ THOMAS J. WEBB                     Chief Financial Officer

       ------------------------------
               Thomas J. Webb



(iii)  Controller or principal
       accounting officer:


                                              Vice President, Controller and
           /s/ GLENN P. BARBA                    Chief Accounting Officer

       ------------------------------
               Glenn P. Barba



 (iv)  A majority of the Directors
       including those named above:


                                                         Director
                      *

       ------------------------------
              Merribel S. Ayres


                                                         Director
                      *
       ------------------------------
               Jon E. Barfield


                                                         Director
                      *
       ------------------------------
              Richard M. Gabrys


                                                         Director
                      *
       ------------------------------
                David W. Joos


                                                         Director
                      *
       ------------------------------
           Philip R. Lochner, Jr.


                                                         Director
                      *
       ------------------------------
             Michael T. Monahan


                                                         Director
                      *
       ------------------------------
           Joseph F. Paquette, Jr.
</Table>

                                      CO-22

<PAGE>

<Table>
<Caption>
              SIGNATURE                                    TITLE
              ---------                                    -----

<S>    <C>                               <C>


                                                         Director
                      *
       ------------------------------
               Percy A. Pierre


                                                         Director
                      *
       ------------------------------
               Kenneth L. Way


                                                         Director
                      *
       ------------------------------
               Kenneth Whipple


                                                         Director
                      *
       ------------------------------
              John B. Yasinsky



  *By      /s/ THOMAS J. WEBB
       ------------------------------
               Thomas J. Webb,
              Attorney-in-Fact
</Table>




                                      CO-23

<PAGE>

                    CMS ENERGY'S AND CONSUMERS' EXHIBIT INDEX

<TABLE>
<CAPTION>
EXHIBITS        DESCRIPTION
--------        -----------
<S>             <C>
(10)(f)    --   CMS Energy's Performance Incentive Stock Plan effective
                February 3, 1988, as amended June 1, 2004 and as further
                amended effective February 20, 2007.

(10)(h)    --   Annual Officer Incentive Compensation Plan for CMS Energy
                Corporation and its Subsidiaries effective January 1, 2006

(12)(a)    --   Statement regarding computation of CMS Energy's Ratio of
                Earnings to Fixed Charges and Preferred Dividends

(12)(b)    --   Statement regarding computation of Consumers' Ratio of Earnings
                to Fixed Charges and Preferred Dividends and Distributions

(21)       --   Subsidiaries of CMS Energy and Consumers

(23)(a)    --   Consent of Ernst & Young LLP for CMS Energy

(23)(b)    --   Consent of PricewaterhouseCoopers LLP for CMS Energy re: MCV

(23)(c)    --   Consent of Ernst & Young for CMS Energy re: Jorf Lasfar

(23)(d)    --   Consent of Price Waterhouse for CMS Energy re: Jorf Lasfar

(23)(e)    --   Consent of Ernst & Young LLP for Consumers

(23)(f)    --   Consent of PricewaterhouseCoopers LLP for Consumers re: MCV

(24)(a)    --   Power of Attorney for CMS Energy

(24)(b)    --   Power of Attorney for Consumers

(31)(a)    --   CMS Energy's certification of the CEO pursuant to Section 302 of
                the Sarbanes-Oxley Act of 2002

(31)(b)    --   CMS Energy's certification of the CFO pursuant to Section 302 of
                the Sarbanes-Oxley Act of 2002

(31)(c)    --   Consumers' certification of the CEO pursuant to Section 302 of
                the Sarbanes-Oxley Act of 2002

(31)(d)    --   Consumers' certification of the CFO pursuant to Section 302 of
                the Sarbanes-Oxley Act of 2002

(32)(a)    --   CMS Energy's certifications pursuant to Section 906 of the
                Sarbanes-Oxley Act of 2002

(32)(b)    --   Consumers' certifications pursuant to Section 906 of the
                Sarbanes-Oxley Act of 2002

(99)(a)    --   Financial Statements for Jorf Lasfar for the years ended
                December 31, 2004, 2005, and 2006
</TABLE>