CMS Energy Corporation 5.875% J (CMS) 8-K Certain terms used in the text and financial statements are defined below

Exhibit 99.3

CMS Energy Corporation

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.

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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 closed on the sale in April 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 Enterprises Outlook section within in this MD&A.

In March 2007, we completed the sale of a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy for $130 million. In March 2007, we also sold our interest in El Chocon, an Argentine hydroelectric generating business, to Endesa, S.A. for $50 million. We used the cash proceeds to invest in our utility business and reduce debt.

In May 2007, we completed the sale of our ownership interest in businesses in the Middle East, Africa, and India to TAQA for $900 million. We plan to use the proceeds to invest in our utility business and reduce debt.

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

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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,

• 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,

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• 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,

• 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,

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• 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 outcome of the planned auction of 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

In Millions (except for per share amounts)
Years ended December 31	2006			2005			2004
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

In Millions
Years ended December 31	2006			2005			Change			2005			2004			Change
Electric Utility	$	199		$	153		$	46		$	153		$	223		$	(70	)
Gas Utility		37			48			(11	)		48			71			(23	)
Enterprises		(203	)		(185	)		(18	)		(185	)		(9	)		(176	)
Corporate Interest and Other		(166	)		(159	)		(7	)		(159	)		(181	)		22
Discontinued Operations		43			49			(6	)		49			8			41
Accounting Changes		—			—			—			—			(2	)		2
Net Income (Loss) Available to Common Stockholders	$	(90	)	$	(94	)	$	4		$	(94	)	$	110		$	(204	)

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.

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

	In Millions
•decrease in asset impairment charges as the $385 million impairment related to the MCV Partnership recorded in 2005 exceeded the $169 million impairment related to GasAtacama recorded in 2006,	$	216
•increase in earnings from our electric utility primarily due to an increase in revenue from an electric rate order, the return to full service-rates of customers previously using alternative energy suppliers, and the expiration of rate caps in December 2005 offset partially by higher operating expense and lower deliveries due to milder weather,		46
•increase in corporate tax benefits as the restoration and utilization of income tax credits due to the resolution of an IRS income tax audit and other tax benefits recorded in 2006 were larger than various tax benefits recorded in 2005,		40
•decrease in corporate interest and other expenses primarily due to an insurance reimbursement received for previously incurred legal expenses, and a reduction in debt retirement charges and other expenses,		33
•other increases at Enterprises primarily due to a favorable property tax award and lower depreciation expense,		29
•lower estimate of environmental remediation expenses recorded in 2006 related to our involvement in Bay Harbor,		20
•decrease in earnings from mark-to-market valuation adjustments primarily at the MCV Partnership and CMS ERM as losses recorded in 2006 replaced gains recorded in 2005,		(203	)
•net charge resulting from our agreement to settle shareholder class action lawsuits,		(80	)
•net loss on the sale of our investment in the MCV Partnership including the negative impact of the associated impairment charge recorded in 2006 and the positive impact of the recognition of certain derivative instruments,		(41	)
•decrease in Enterprises tax benefits due primarily to the absence of tax benefits recorded in 2005 related to the American Jobs Creation Act of 2004,		(39	)
•decrease in earnings from our gas utility primarily due to a reduction in deliveries resulting from increased customer conservation efforts and warmer weather in 2006 partially offset by other gas revenue associated with pipeline capacity optimization and a reduction in operation and maintenance expenses, and		(11	)
•reduced earnings from discontinued operations as the positive impact of an arbitration award and a reduction of contingent liabilities recorded in 2005 exceeded income recorded in 2006 from the favorable resolution of certain accrued liabilities.		(6	)
Total Change	$	4

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 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 the impact of favorable tax benefits recorded in 2005.

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

	In Millions
•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
•increase in income from discontinued operations primarily due to tax benefits related to the American Jobs Creation Act of 2004, an arbitration award related to the 2003 sale of Marysville, and favorable litigation,		41
•reduction in corporate interest expense due to lower debt levels and a reduction in average interest rates,		21
•increase in other corporate tax benefits,		17
•increase in earnings from other Enterprises subsidiaries,		11
•increase in earnings from Shuweihat,		10
•increase in tax benefits at Enterprises related to the American Jobs Creation Act of 2004, and a		8
•decrease in debt retirement charges.		8
Total Change	$	(204	)

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ELECTRIC UTILITY RESULTS OF OPERATIONS

In Millions
Years Ended December 31	2006		2005		Change			2005		2004		Change
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	)

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 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.

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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 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.

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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.

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.

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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

In Millions
Years Ended December 31	2006		2005		Change			2005		2004		Change
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	)

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.

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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.

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.

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ENTERPRISES RESULTS OF OPERATIONS

In Millions
Years Ended December 31	2006			2005			Change			2005			2004			Change
Net loss	$	(203	)	$	(185	)	$	(18	)	$	(185	)	$	(9	)	$	(176	)
Reasons for the change:
Operating revenues							$	(134	)							$	111
Cost of gas and purchased power								(28	)								(62	)
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								9									(19	)
General taxes, depreciation, and other income, net								119									35
Asset impairment charges								726									(1,015	)
Environmental remediation								31									5
Fixed charges								19									13
Minority interest								(340	)								455
Income taxes								(50	)								113
Total change							$	(18	)							$	(176	)

Operating revenues:For 2006, operating revenues decreased versus 2005 due to the impact of 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. These decreases were partially offset by higher sales at CMS Brasil.

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 due to higher fuel prices at the MCV Partnership and CMS Brasil.

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.

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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 decreased versus 2005 due a favorable arbitration settlement related to DIG. The decrease was partially offset by higher salaries and benefits, primarily at CMS Brasil, and increased expenditures related to prospecting initiatives in North America.

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 contributing to the increase were higher maintenance costs related to scheduled outages and prospecting initiatives in North America.

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.

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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.

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CORPORATE INTEREST AND OTHER NET EXPENSES

In Millions
Years ended December 31	2006			2005			Change			2005			2004			Change
Net loss	$	(166	)	$	(159	)	$	(7	)	$	(159	)	$	(181	)	$	22

For 2006, corporate interest and other net expenses were $166 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 $159 million, a decrease of $22 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 $43 million in net income for 2006, a decrease of $6 million compared to the same period in 2005. Net income for 2006 decreased compared to 2005 as a 2006 arbitration award was more than offset by the absence of tax benefits related to the American Jobs Creation Act and the absence of benefits related to favorable litigation and arbitration awards in 2005. Net income of $49 million recorded in 2005 exceeded 2004 net income by $41 million primarily due to tax benefits related to the American Jobs Creation Act, 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. 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

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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 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.

Discontinued Operations:We have determined that certain consolidated subsidiaries meet the criteria of assets held for sale under SFAS No. 144. At December 31, 2006 and December 31, 2005, these subsidiaries include our Argentine businesses sold in March 2007, a majority of our Michigan non-utility businesses sold in March 2007, Takoradi, SENECA, and certain associated holding companies sold in the second quarter of 2007. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

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, 54 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.

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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 $2.351 billion recorded as regulatory assets and $1.954 billion recorded as regulatory liabilities.

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.

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

	Interest Rates (%)		Volatility Rates (%)
Gas-related option contracts		5.00		51 – 62
Electricity-related option contracts		5.00		44 – 104

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 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:

	In Millions
	2006
	First			Second			Third			Fourth
	Quarter			Quarter			Quarter			Quarter		Total
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	)

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).

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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).

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:

	In Millions
	Non-
	Trading					Trading					Total
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	)

(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.

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(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.

Fair Value of Non-Trading Contracts at December 31, 2006					In Millions
	Total					Maturity (in years)
Source of Fair Value	Fair Value		Less than 1			1 to 3		4 to 5		Greater than 5
Prices actively quoted	$	—	$	—		$	—	$	—	$	—
Prices obtained from external sources or based on models and other valuation methods		31		12			19		—		—
Total	$	31	$	12		$	19	$	—	$	—

Fair Value of Trading Contracts at December 31, 2006							In Millions
	Total							Maturity (in years)
Source of Fair Value	Fair Value			Less than 1				1 to 3			4 to 5		Greater than 5
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	)	$	—	$	—

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

• 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

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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):

	In Millions
December 31	2006		2005
Variable-rate financing – before-tax annual earnings exposure	$	4	$	3
Fixed-rate financing – potentialreductionin fair value (a)		193		223

(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. We sold our ownership interest in these entities in May 2007.

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.

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

	In Millions
December 31	2006		2005
Potentialreductionin 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

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(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. We completed the sale of these investments in May 2007.

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):

	In Millions
December 31	2006		2005
Potentialreductionin fair value of available-for-sale equity securities (primarily SERP investments):	$	6	$	5

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.

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.

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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 Stock. Participants will have an 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:

	In Millions
Expected Costs	Pension Cost		OPEB Cost		Contributions
2007	$	109	$	44	$	160
2008		105		41		51
2009		113		39		51

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.

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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 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.

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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 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

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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, $334 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.

Summary of Cash Flows:

	In Millions
	2006			2005			2004
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	)

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.

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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.

Our cash flow statements include amounts related to discontinued operations through the date of disposal. For additional details on discontinued operations, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

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.

Contractual Obligations at December 31, 2006							In Millions
	Payments Due
			Less Than		One to			Three to		More Than
	Total		One Year		Three Years			Five Years		Five Years
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

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(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 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.

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 May 2007, we sold our ownership interests in businesses in the Middle East, Africa, and India to TAQA. TAQA assumed all contingent obligations related to our project-financing security agreements. For more details on the sale of our ownership interests to TAQA, see Note 2, Asset Sales, Impairment

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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.

	In Millions
Years Ending December 31	2007		2008		2009
Electric utility operations (a)(b)	$	618	$	487	$	455
Gas utility operations (b)		164		216		274
Enterprises		65		92		124
	$	847	$	795	$	853

(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.

Our primary focus with respect to our non-utility businesses has been to optimize cash flow and further

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reduce our business risk and leverage through the sale of non-strategic assets. In 2007, we have begun to exit the international marketplace. 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.

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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 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.

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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.

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 implements 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.

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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.

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.”

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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 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

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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,

• gas consumption per customer, and

• improvements in gas appliance efficiency.

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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 closed on the sale in March 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 closed on the sale in May 2007.

In February 2007, we signed a memorandum of understanding with Petroleos de Venezuela, S.A. to sell

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our ownership interest in SENECA and certain associated generating equipment for $106 million. We closed on the sale in April 2007.

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. 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:

• the outcome of the planned auction of 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.

In February 2007, we announced plans to conduct an auction to sell GasAtacama. We expect to complete

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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.

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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 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 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

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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.

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.

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Consolidated Statements of Income (Loss)

	In Millions
Years Ended December 31	2006			2005			2004
Operating Revenue	$	6,303		$	6,018		$	5,256
Earnings from Equity Method Investees		89			125			115
Operating Expenses
Fuel for electric generation		711			644			729
Fuel costs mark-to-market at the MCV Partnership		204			(200	)		19
Purchased and interchange power		774			494			312
Cost of gas sold		2,131			2,296			1,785
Other operating expenses		1,173			1,056			911
Maintenance		300			232			240
Depreciation and amortization		554			507			414
General taxes		192			257			266
Asset impairment charges		459			1,184			160
		6,498			6,470			4,836
Operating Income (Loss)		(106	)		(327	)		535
Other Income (Deductions)
Accretion expense		(4	)		(18	)		(23	)
Gain on asset sales, net		79			6			52
Interest and dividends		80			63			26
Regulatory return on capital expenditures		26			4			113
Foreign currency losses, net		—			(7	)		(3	)
Other income		31			35			25
Other expense		(19	)		(27	)		(9	)
		193			56			181
Fixed Charges
Interest on long-term debt		453			463			476
Interest on long-term debt — related parties		15			29			58
Other interest		32			16			44
Capitalized interest		(10	)		(38	)		25
Preferred dividends of subsidiaries		5			5			5
		495			475			608
Income (Loss) Before Minority Interests (Obligations), Net		(408	)		(746	)		108
Minority Interests (Obligations), Net		(102	)		(443	)		12
Income (Loss) Before Income Taxes		(306	)		(303	)		96
Income Tax Benefit		(184	)		(170	)		(19	)
Income (Loss) From Continuing Operations		(122	)		(133	)		115
Income From Discontinued Operations, Net of $27 Tax Expense in 2006, $10 Tax Expense in 2005 and $32 Tax Expense in 2004		43			49			8
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

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	In Millions, Except Per Share Amounts
Years Ended December 31	2006			2005			2004
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	$	(0.61	)	$	(0.68	)	$	0.61
Income from Discontinued Operations		0.20			0.24			0.05
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	$	(0.61	)	$	(0.68	)	$	0.60
Income from Discontinued Operations		0.20			0.24			0.05
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	$	—		$	—		$	—

The accompanying notes are an integral part of these statements.

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