Exhibit 99.4

CMS Energy Corporation
Consolidated Statements of Cash Flows

								In Millions
Years Ended December 31		2006			2005			2004
Cash Flows from Operating Activities
	Net income (loss)	$	(79	)	$	(84	)	$	121
	Adjustments to reconcile net income (loss) to net cash provided by operating activities
	Depreciation, depletion and amortization (includes nuclear decommissioning of $6 per year)		576			525			431
	Deferred income taxes and investment tax credit		(271	)		(199	)		67
	Regulatory return on capital expenditures		(26	)		(4	)		(113	)
	Minority interests (obligations), net		(100	)		(440	)		15
	Fuel costs mark-to-market at the MCV Partnership		204			(200	)		19
	Asset impairment charges		459			1,184			160
	Capital lease and other amortization		44			40			28
	Accretion expense		4			18			23
	Bad debt expense		28			23			19
	Gain on the sale of assets		(79	)		(20	)		(50	)
	Cumulative effect of accounting changes		—			—			2
	Earnings from equity method investees		(89	)		(125	)		(115	)
	Cash distributions from equity method investees		75			108			27
	Changes in other assets and liabilities:
	Increase in accounts receivable, notes receivable, and accrued revenues		(91	)		(311	)		(144	)
	Increase in inventories		(105	)		(245	)		(109	)
	Increase (decrease) in accounts payable		(43	)		170			109
	Increase in legal settlement liability		200			—			—
	Increase in accrued taxes		3			19			16
	Increase (decrease) in accrued expenses		36			(11	)		21
	Increase (decrease) in the MCV Partnership gas supplier funds on deposit		(147	)		173			15
	Decrease (increase) in other current and non-current assets		45			(37	)		(117	)
	Increase (decrease) in other current and non-current liabilities		44			15			(72	)
	Net cash provided by operating activities		688			599			353
Cash Flows from Investing Activities
	Capital expenditures (excludes assets placed under capital lease)		(670	)		(593	)		(525	)
	Investments in partnerships and unconsolidated subsidiaries		—			—			(71	)
	Cost to retire property		(78	)		(27	)		(28	)
	Restricted cash and restricted short-term investments		124			(151	)		145
	Investments in Electric Restructuring Implementation Plan		—			—			(7	)
	Investments in nuclear decommissioning trust funds		(21	)		(6	)		(6	)
	Proceeds from nuclear decommissioning trust funds		22			39			36
	Proceeds from short-term investments		—			295			2,267
	Purchase of short-term investments		—			(186	)		(2,376	)
	Maturity of the MCV Partnership restricted investment securities held-to-maturity		130			318			675
	Purchase of the MCV Partnership restricted investment securities held-to-maturity		(131	)		(270	)		(674	)
	Proceeds from sale of assets		69			61			219
	Cash relinquished from sale of assets		(148	)		—			—
	Decrease (increase) in non-current notes receivable		(50	)		1			(10	)
	Other investing		2			25			8
	Net cash used in investing activities		(751	)		(494	)		(347	)
Cash Flows from Financing Activities
	Proceeds from notes, bonds, and other long-term debt		100			1,385			1,392
	Issuance of common stock		8			295			290
	Retirement of bonds and other long-term debt		(493	)		(1,509	)		(1,631	)
	Payment of preferred stock dividends		(11	)		(11	)		(11	)
	Payment of capital lease and finance lease obligations		(26	)		(29	)		(44	)
	Increase in notes payable		2			—			—
	Debt issuance costs, financing fees, and other		(14	)		(57	)		(39	)
	Net cash provided by (used in) financing activities		(434	)		74			(43	)
Effect of Exchange Rates on Cash			1			(1	)		—
Net Increase (Decrease) in Cash and Cash Equivalents			(496	)		178			(37	)
Cash and Cash Equivalents from Effect of Revised FASB Interpretation No. 46 Consolidation			—			—			174
Cash and Cash Equivalents, Beginning of Period			847			669			532
Cash and Cash Equivalents, End of Period		$	351		$	847		$	669

CMS-46

						In Millions
Other cash flow activities and non-cash investing and financing activities were:	2006		2005			2004
Cash transactions
Interest paid (net of amounts capitalized)	$	487	$	454		$	601
Income taxes paid (net of refunds)		—		(9	)		—
Pension and OPEB cash contribution		69		63			63
Non-cash transactions
Other assets placed under capital lease	$	7	$	12		$	3

The accompanying notes are an integral part of these statements.

CMS-47

CMS Energy Corporation
Consolidated Balance Sheets

ASSETS

				In Millions
December 31		2006		2005
Plant and Property (at cost)
	Electric utility	$	8,504	$	8,204
	Gas utility		3,273		3,151
	Enterprises		552		790
	Other		31		25
			12,360		12,170
	Less accumulated depreciation, depletion and amortization		5,233		5,030
			7,127		7,140
	Construction work-in-progress		646		518
			7,773		7,658
Investments
	Enterprises		588		712
	Other		10		13
			598		725
Current Assets
	Cash and cash equivalents at cost, which approximates market		263		794
	Restricted cash and restricted short-term investments at cost, which approximates market		71		198
	Accounts receivable, notes receivable, and accrued revenue, less allowances of $29 in 2006 and $28 in 2005		575		728
	Accrued power supply and gas revenue		156		65
	Accounts receivable and notes receivable — related parties		63		54
	Inventories at average cost
	Gas in underground storage		1,129		1,069
	Materials and supplies		87		82
	Generating plant fuel stock		126		108
	Assets held for sale		189		130
	Price risk management assets		45		113
	Regulatory assets — postretirement benefits		19		19
	Derivative instruments		—		242
	Deferred income taxes		155		—
	Deferred property taxes		150		160
	Prepayments and other		115		158
			3,143		3,920
Non-current Assets
	Regulatory assets
	Securitized costs		514		560
	Additional minimum pension		—		399
	Postretirement benefits		1,131		116
	Customer Choice Act		190		222
	Other		497		497
	Nuclear decommissioning trust funds		602		555
	Assets held for sale		280		296
	Price risk management assets		19		165
	Goodwill		26		27
	Notes receivable		137		77
	Notes receivable — related parties		125		187
	Other		336		637
			3,857		3,738
Total Assets		$	15,371	$	16,041

CMS-48

STOCKHOLDERS’ INVESTMENT AND LIABILITIES

					In Millions
December 31		2006			2005
Capitalization
	Common stockholders’ equity
	Common stock, authorized 350.0 shares; outstanding 222.8 shares in 2006 and 220.5 shares in 2005	$	2		$	2
	Other paid-in capital		4,468			4,436
	Accumulated other comprehensive loss		(318	)		(288	)
	Retained deficit		(1,918	)		(1,828	)
			2,234			2,322
	Preferred stock of subsidiary		44			44
	Preferred stock		261			261
	Long-term debt		6,202			6,780
	Long-term debt — related parties		178			178
	Non-current portion of capital and finance lease obligations		42			308
			8,961			9,893
Minority Interests			77			319
Current Liabilities
	Current portion of long-term debt, capital and finance leases		564			308
	Current portion of long-term debt — related parties		—			129
	Notes payable		2			—
	Accounts payable		499			559
	Accrued rate refunds		37			—
	Accounts payable — related parties		2			15
	Accrued interest		126			145
	Accrued taxes		312			307
	Liabilities held for sale		101			78
	Price risk management liabilities		70			80
	Current portion of gas supply contract obligations		—			10
	Deferred income taxes		—			55
	MCV Partnership gas supplier funds on deposit		—			193
	Legal settlement liability		200			—
	Other		243			255
			2,156			2,134
Non-current Liabilities
	Regulatory liabilities
	Regulatory liabilities for cost of removal		1,166			1,120
	Income taxes, net		539			455
	Other regulatory liabilities		249			178
	Postretirement benefits		1,066			379
	Deferred income taxes		111			282
	Deferred investment tax credit		62			67
	Asset retirement obligations		498			494
	Liabilities held for sale		39			62
	Price risk management liabilities		31			161
	Gas supply contract obligations		—			61
	Other		416			436
			4,177			3,695
Commitments and Contingencies (Notes 3,4,6,9 and 11)
Total Stockholders’ Investment and Liabilities		$	15,371		$	16,041

The accompanying notes are an integral part of these statements.

CMS-49

CMS Energy Corporation
Consolidated Statements of Common Stockholders’ Equity

		Number of Shares in Thousands															In Millions
Years Ended December 31		2006			2005			2004			2006			2005			2004
Common Stock	At beginning and end of period										$	2		$	2		$	2
Other Paid-in Capital
	At beginning of period		220,497			194,997			161,130			4,436			4,140			3,846
	Common stock repurchased		(98	)		(88	)		(43	)		(2	)		(1	)		(1	)
	Common stock reacquired		(59	)		—			(270	)		—			—			(5	)
	Common stock issued		2,375			25,493			34,180			33			296			301
	Common stock reissued		68			95			—			1			1			—
	Issuance cost of preferred stock		—			—			—			—			—			(1	)
	At end of period		222,783			220,497			194,997			4,468			4,436			4,140
Accumulated Other Comprehensive Loss
	Retirement benefits liability
	At beginning of period											(19	)		(17	)		—
	Retirement benefits liability adjustments (a)											3			(2	)		(17	)
	Adjustment to initially apply FASB Statement No. 158											(7	)		—			—
	At end of period											(23	)		(19	)		(17	)
	Investments
	At beginning of period											9			9			8
	Unrealized gain on investments (a)											5			—			1
	At end of period											14			9			9
	Derivative instruments
	At beginning of period											35			(9	)		(8	)
	Unrealized gain (loss) on derivative instruments (a)											(15	)		51			5
	Reclassification adjustments included in net income (loss) (a)											(32	)		(7	)		(6	)
	At end of period											(12	)		35			(9	)
	Foreign currency translation
	At beginning of period											(313	)		(319	)		(419	)
	Loy Yang sale											—			—			110
	Other foreign currency translations (a)											16			6			(10	)
	At end of period											(297	)		(313	)		(319	)
	At end of period											(318	)		(288	)		(336	)
Retained Deficit
	At beginning of period											(1,828	)		(1,734	)		(1,844	)
	Net income (loss) (a)											(79	)		(84	)		121
	Preferred stock dividends declared											(11	)		(10	)		(11	)
	At end of period											(1,918	)		(1,828	)		(1,734	)
Total Common Stockholders’ Equity											$	2,234		$	2,322		$	2,072

CMS-50

CMS Energy Corporation
Consolidated Statements of Common Stockholders’ Equity

							In Millions
Years Ended December 31	2006			2005			2004
(a) Disclosure of Other Comprehensive Income (Loss):
Retirement benefits liability
Retirement benefits liability adjustments, net of tax (tax benefit) of $1 in 2006, $(1) in 2005 and $(9) in 2004	$	3		$	(2	)	$	(17	)
Investments
Unrealized gain on investments, net of tax of $2 in 2006, $- in 2005 and $1 in 2004		5			—			1
Derivative instruments
Unrealized gain (loss) on derivative instruments, net of tax (tax benefit) of $(11) in 2006, $29 in 2005 and $12 in 2004		(15	)		51			5
Reclassification adjustments included in net income (loss), net of tax benefit of $(19) in 2006, $(9) in 2005 and $(6) in 2004		(32	)		(7	)		(6	)
Loy Yang sale		—			—			110
Other foreign currency translations		16			6			(10	)
Net income (loss)		(79	)		(84	)		121
Total Other Comprehensive Income (Loss)	$	(102	)	$	(36	)	$	204

The accompanying notes are an integral part of these statements.

CMS-51

CMS Energy Corporation

CMS Energy Corporation
Notes to Consolidated Financial Statements

1: Corporate Structure and Accounting Policies

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

Principles of Consolidation: The consolidated financial statements include CMS Energy, Consumers, Enterprises, and all other entities in which we have a controlling financial interest or are the primary beneficiary, in accordance with FASB Interpretation No. 46(R). We use the equity method of accounting for investments in companies and partnerships that are not consolidated, where we have significant influence over operations and financial policies, but are not the primary beneficiary. We eliminate intercompany transactions and balances.

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

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

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

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

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

CMS-52

CMS Energy Corporation

Capitalized Interest: We capitalize interest on certain qualifying assets that are undergoing activities to prepare them for their intended use. Capitalization of interest for the period is limited to the actual interest cost incurred. Our regulated businesses capitalize AFUDC on regulated construction projects and include such amounts in plant in service.

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

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

Collective Bargaining Agreements: At December 31, 2006, the Utility Workers of America Union represented approximately 45 percent of Consumers employees. The Union represents Consumers’ operating, maintenance, and construction employees and call center employees.

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

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

Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements: SAB No. 108 was adopted on December 31, 2006. The standard clarifies how we should assess the materiality of prior period financial statement errors in the current period. Prior to the adoption of this standard, we used the “iron-curtain” method to quantify the effects of prior period financial statement errors. The iron-curtain method focuses on the effects of correcting the period-end balance sheet with less emphasis on the effects the correction would have on our 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.

Financial and Derivative Instruments: We record debt and equity securities classified as available-for-sale at fair value determined from quoted market prices. We record debt and equity securities classified as held-to-maturity at cost.

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

CMS-53

CMS Energy Corporation

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

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

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

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

	In Millions
Balance at January 1, 2005	$	23
Currency translation adjustment		4
Balance at December 31, 2005	$	27
Currency translation adjustment		(1	)
Balance at December 31, 2006	$	26

Impairment of Long-Lived Assets and Equity Method Investments: We evaluate potential impairments of our long-lived assets, other than goodwill, based on various analyses, including the projection of undiscounted cash flows, whenever events or changes in circumstances indicate that the carrying amount of the assets may not be recoverable. If the carrying amount of the investment or asset exceeds its estimated undiscounted future cash flows, we recognize an impairment loss and write-down the investment or asset to its estimated fair value.

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

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

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

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

CMS-54

CMS Energy Corporation

2.136 reais per U.S. dollar was $45 million, net of tax.

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

Maintenance and Depreciation: We charge property repairs and minor property replacement to maintenance expense. We use the direct expense method to account for planned major maintenance activities. We charge planned major maintenance activities to operating expense unless the cost represents the acquisition of additional components or the replacement of an existing component. We capitalize the cost of plant additions and replacements. We depreciate utility property using straight-line rates approved by the MPSC. The composite depreciation rates for our properties are:

Years Ended December 31	2006			2005			2004
Electric utility property		3.1	%		3.1	%		3.1	%
Gas utility property		3.6	%		3.6	%		3.7	%
Other property		8.2	%		7.6	%		8.4	%

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

Other Income and Other Expense: The following tables show the components of Other income and Other expense:

					In Millions
Years Ended December 31	2006		2005		2004
Other income
Interest and dividends — related parties	$	9	$	10	$	6
Return on stranded and security costs		5		6		9
Nitrogen oxide allowance sales		8		2		—
Electric restructuring return		4		6		6
Investment sale gain		1		—		3
Reversal of contingent liability		—		3		—
Refund of surety bond premium		1		—		—
All other		3		8		1
Total other income	$	31	$	35	$	25

CMS-55

CMS Energy Corporation

In Millions
Years Ended December 31	2006			2005			2004
Other expense
Loss on SERP investment	$	—		$	(2	)	$	(3	)
Loss on reacquired and extinguished debt		(5	)		(16	)		—
Civic and political expenditures		(2	)		(2	)		(2	)
Donations		(9	)		—			(1	)
All other		(3	)		(7	)		(3	)
Total other expense	$	(19	)	$	(27	)	$	(9	)

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

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

Related Party Transactions: We recorded income and expense from related parties as follows:

Type	Related Party	2006			2005			2004
Income from our investments in related party trusts	Trust Preferred Securities Companies	$	—		$	1		$	2
Interest expense on long-term debt	Trust Preferred Securities Companies		(15	)		(29	)		(58	)

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

Unamortized Debt Premium, Discount, and Expense: We capitalize premiums, discounts, and expenses incurred in connection with the issuance of long-term debt and amortize those costs over the terms of the debt issues. We expense any refinancing costs as incurred. For the regulated portions of our businesses, if we refinance debt, we capitalize any remaining unamortized premiums, discounts, and expenses and amortize them over the terms of the newly issued debt.

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

CMS-56

CMS Energy Corporation

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

In Millions
December 31	2006		2005
Securitized costs (Note 4)	$	514	$	560
Additional minimum pension liability (Note 7) (a)		—		399
Postretirement benefits (Note 7) (a)		1,150		135
Customer Choice Act		190		222
Electric restructuring implementation plan		40		74
Manufactured gas plant sites (Note 3)		56		62
Abandoned Midland project		9		9
Unamortized debt costs		86		93
Asset retirement obligations (Note 8)		177		169
Stranded costs		65		63
Other		64		27
Total regulatory assets (b)	$	2,351	$	1,813
Cost of removal (Note 8)	$	1,166	$	1,120
Income taxes, net (Note 9)		539		455
Asset retirement obligations (Note 8)		180		165
Other		69		13
Total regulatory liabilities (b)	$	1,954	$	1,753

(a)

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

(b)

At December 31, 2006, we classified $19 million of regulatory assets as current regulatory assets and we classified $2.332 billion of regulatory assets as non-current regulatory assets. At December 31, 2005, we classified $19 million of regulatory assets as current regulatory assets and we classified $1.794 billion of regulatory assets as non-current regulatory assets. At December 31, 2006 and December 31, 2005, all of our regulatory liabilities represented non-current regulatory liabilities.

CMS-57

CMS Energy Corporation

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

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

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

2: Asset Sales, Impairment Charges and Discontinued Operations

Asset Sales

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

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

In Millions
		Pretax		After-tax
Date sold	Business/Project	Gain		Gain
October	Land in Ludington, Michigan (a)	$	2	$	2
November	MCV GP II (b)		77		38
	Total gain on asset sales	$	79	$	40

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

CMS-58

CMS Energy Corporation

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

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

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

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

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

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

CMS-59

CMS Energy Corporation

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

In Millions
		Pretax		After-tax
Date sold	Business/Project	Gain		Gain
February	GVK	$	4	$	3
April	Scudder Latin American Power Fund		2		1
April	Gas turbine and auxiliary equipment		—		—
	Total gain on asset sales	$	6	$	4

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

In Millions
		Pretax		After-tax
Date sold	Business/Project	Gain		Gain
February	Bluewater Pipeline	$	1	$	1
April	Loy Yang		—		—
May	American Gas Index fund		1		1
August	Goldfields		45		29
December	Moapa		3		2
Various	Other		2		1
	Total gain on asset sales	$	52	$	34

2007 Asset Sales: In January 2007, we signed a binding letter of intent with Lucid Energy, LLC to sell a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets for $180 million. The assets being sold include all of our electric generating plant interests in Argentina and our interest in the TGM natural gas pipeline business in Argentina. We will maintain our interest in the TGN natural gas business in Argentina, which remains subject to a potential sale to the government of Argentina. We presently plan to retain our interest in TGN until such time as any interest or option held by the Argentine government expires. In Michigan, the sale includes the Antrim natural gas processing plant, 155 miles of associated gathering lines, and interests in three special purpose gas transmission pipelines that total 110 miles. In March 2007, we completed the sale to Lucid Energy for $130 million. We also sold our interest in El Chocon, an Argentine hydroelectric generating business, to Endesa, S.A. for $50 million. Our interest in El Chocon was originally part of the asset group that Lucid Energy agreed to purchase; however, Endesa, S.A. had a right of first offer on our interest in El Chocon that it exercised.

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 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.

CMS-60

CMS Energy Corporation

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

Asset Impairment Charges

The following table summarizes our asset impairments:

In Millions
	Pretax		After-tax		Pretax		After-tax		Pretax		After-tax
Years Ended December 31	2006		2006		2005		2005		2004		2004
Asset impairments:
Enterprises:
MCV Partnership(a)	$	218	$	80	$	1,184	$	385	$	—	$	—
GasAtacama (b)		239		169		—		—		—		—
Loy Yang (c)		—		—		—		—		125		81
GVK		—		—		—		—		30		20
SLAP		—		—		—		—		5		3
Other		2		1		—		—		—		—
Total asset impairments	$	459	$	250	$	1,184	$	385	$	160	$	104

(a)     As discussed in “Asset Sales,” in November of 2006, we recorded an impairment charge of $218 million in our Consolidated Statements of Income (Loss). This impairment charge recognizes the reduction in fair value of the MCV Facility’s real estate assets and results in an $80 million reduction to our consolidated net income after considering tax effects and minority interest.

In the third quarter of 2005, NYMEX forward natural gas price forecasts for the years 2005 through 2010 increased substantially. Additionally, other independent natural gas long-term forward price forecasting organizations indicated their intention to raise their forecasts for the price of natural gas beyond 2010. As a result, the MCV Partnership determined an impairment analysis considering revised forward natural gas price assumptions was required. The MCV Partnership determined the fair value of its fixed assets by discounting a set of probability-weighted streams of future operating cash flows. The carrying value of the MCV Partnership’s fixed assets exceeded the estimated fair value resulting in impairment charges of $1.159 billion to recognize the reduction in fair value of the MCV Facility’s fixed assets and $25 million of interest capitalized during the construction of the MCV Facility. Our 2005 consolidated net income was reduced by $385 million, after considering tax effects and minority interest.

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

On May 1, 2006, the Bolivian government announced its intention to nationalize the natural gas industry and raise prices under its existing gas export contracts. Since May, gas flow from Bolivia has been restricted while Argentina and Bolivia renegotiated the price for gas. Simultaneously, gas supply to GasAtacama was restricted. In July 2006, Argentina agreed to increase the price it pays for gas from Bolivia through the term of the existing contract. Argentina also announced that it would recover all of this price increase by a special tax on its gas exports. The decision of Argentina to increase the cost of

CMS-61

CMS Energy Corporation

its gas exports, in addition to maintaining the gas restriction, increased the risk and cost of GasAtacama’s fuel supply.

In August 2006, a major gas supplier notified GasAtacama that it would no longer deliver gas to GasAtacama under the Argentine government’s current policy. We performed an impairment analysis to determine the fair value of our investment in GasAtacama and concluded that the fair value of our investment, which includes notes receivable-related party from GasAtacama, was lower than the carrying amount and that this decline was other than temporary. In the third quarter of 2006, we recorded an impairment charge of $239 million in our Consolidated Statements of Income (Loss). As a result, our consolidated net income was reduced by $169 million after considering tax effects and minority interest.

Our remaining investment in GasAtacama consists of $117 million of notes receivable, which includes a $49 million valuation allowance recognized due to the impairment. We report the notes under the Enterprises business segment and classify them as Notes receivable-related parties on our Consolidated Balance Sheets. Our proportionate share of earnings or losses at GasAtacama is first applied to the notes receivable valuation allowance. We apply all cash received on the notes, whether for principal or interest, to the principal of the notes. If we receive cash payments on the notes after the principal amount has been fully collected, we will record interest income.

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

Discontinued Operations

In accordance with SFAS No. 144, our consolidated financial statements have been reclassified for all periods presented to reflect the operations, assets and liabilities of our consolidated subsidiaries that meet the criteria of discontinued operations. The assets and liabilities of these subsidiaries have been classified as “Assets held for sale” and “Liabilities held for sale” on our December 31, 2006 and 2005 consolidated balance sheets. Subsidiaries classified as “held for sale” include our Argentine businesses sold in March 2007, a majority of our Michigan non-utility businesses sold in March 2007, SENECA, Takoradi, and certain associated holding companies sold in the second quarter of 2007.

As a result of these financial statement reclassifications, we have also made changes to Notes 3, 4, 5, 6, 7, 8, 9, 11, 12, 15 and 17 to conform these notes to the revised financial statement presentation.

The major classes of assets and liabilities “held for sale” on our Consolidated Balance Sheets are as follows:

In Millions
As of December 31	2006		2005
Assets
Cash	$	88	$	53
Accounts receivable, net		80		51
Notes receivable		110		111
Property, plant and equipment, net		168		174
Other		23		37
Total assets	$	469	$	426

CMS-62

CMS Energy Corporation

In Millions
As of December 31	2006		2005
Liabilities
Accounts payable	$	66	$	39
Accrued taxes		19		24
Current and long-term debt		—		28
Minority interest		14		14
Other		41		35
Total liabilities	$	140	$	140

Our discontinued operations are a component of our Enterprises business segment. We reflect the following amounts in the Income From Discontinued Operations line, in our Consolidated Statements of Income (Loss):

In Millions
Years Ended December 31	2006		2005		2004
Revenues	$	507	$	270	$	216
Discontinued operations:
Pretax income from discontinued operations	$	70	$	59	$	40	(a)
Income tax expense		27		10		32
Income From Discontinued Operations	$	43	$	49	$	8

(a) Includes a $15 million gain on disposal of discontinued operations primarily related to Parmelia.

Income From Discontinued Operations includes a provision for anticipated closing costs and a portion of CMS Energy’s parent company interest expense. Interest expense of $12 million for 2006, $12 million for 2005, and $24 million for 2004 has been allocated based on the net book value of the asset to be sold divided by CMS Energy’s total capitalization of each discontinued operation multiplied by CMS Energy’s interest expense.

3: CONTINGENCIES

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

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

Securities Class Action Lawsuits: Beginning in May 2002, a number of complaints were filed against CMS Energy, Consumers and certain officers and directors of CMS Energy and its affiliates in the

CMS-63

CMS Energy Corporation

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

On January 3, 2007, CMS Energy and other parties entered into a Memorandum of Understanding (the “MOU”) dated December 28, 2006, subject to court approval, regarding settlement of the two class action lawsuits. The settlement was approved by a special committee of independent directors and by the full board of directors. Both judged that it was in the best interests of shareholders to eliminate this business uncertainty. The MOU is expected to lead to a detailed stipulation of settlement that will be presented to the assigned federal judge and the affected class in the first quarter of 2007. Under the terms of the MOU, the litigation will be settled for a total of $200 million, including the cost of administering the settlement and any attorney fees the court awards. CMS Energy will make a payment of approximately $123 million plus an amount equivalent to interest on the outstanding unpaid settlement balance beginning on the date of preliminary approval of the court and running until the balance of the settlement funds is paid into a settlement account. Out of the total settlement, CMS Energy’s insurers will pay approximately $77 million directly to the settlement account. CMS Energy took an approximately $123 million net pre-tax charge to 2006 earnings in the fourth quarter. In entering into the MOU, CMS Energy makes no admission of liability under the Shareholder Action and the ACTS Action. At December 31, 2006, we have recorded the $77 million as an accounts receivable and the $200 million as a legal settlement liability on our Consolidated Balance Sheets.

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

CMS-64

CMS Energy Corporation

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

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

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

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

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

CMS Energy recorded charges related to this matter in 2004, 2005, and 2006 totaling $93 million, of which $9 million was recorded in 2006. At December 31, 2006, CMS Energy has a liability recorded of $52 million for its remaining obligations We based the liability on 2006 discounted costs, using a discount rate of 4.7 percent and an inflation rate of 1 percent on annual operating and maintenance costs. We used the interest rate for 30-year U.S. Treasury securities for the discount rate. The undiscounted amount of the remaining obligation is $65 million. We expect to pay $18 million in 2007, $17 million in 2008, $3 million in 2009, and the remaining expenditures as part of long-term operating and maintenance costs. Any significant change in assumptions, such as an increase in the number of

CMS-65

CMS Energy Corporation

sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could impact our estimate of remedial action costs and the timing of the expenditures. An adverse outcome of this matter could, depending on the size of any indemnification obligation or liability under environmental laws, have a potentially significant adverse effect on CMS Energy’s financial condition and liquidity and could negatively impact CMS Energy’s financial results. CMS Energy cannot predict the ultimate cost or outcome of this matter.

Consumers’ Electric Utility Contingencies

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

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

Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental Protection Act, we expect that we will ultimately incur investigation and remedial action costs at a number of sites. We believe that these costs will be recoverable in rates under current ratemaking policies.

We are a potentially responsible party at several contaminated sites administered under Superfund. Superfund liability is joint and several, meaning that many other creditworthy parties with substantial assets are potentially responsible with respect to the individual sites. Based on our experience, we estimate that our share of the total liability for the known Superfund sites will be between $1 million and $10 million. At December 31, 2006, we have recorded a liability for the minimum amount of our estimated probable Superfund liability. The timing of payments related to the remediation of our Superfund sites is uncertain. Any significant change in assumptions, such as different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs and the timing of our remediation payments.

In October 1998, during routine maintenance activities, we identified PCB as a component in certain paint, grout, and sealant materials at Ludington. We removed and replaced part of the PCB material. Since proposing a plan to deal with the remaining materials, we have had several conversations with the EPA. The EPA has proposed a rule which would authorize continued use of such material in place, subject to certain restrictions. We are not able to predict when a final rule will be issued.

CMS-66

CMS Energy Corporation

Litigation: In 2003, a group of eight PURPA qualifying facilities (the plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit alleged that we incorrectly calculated the energy charge payments made pursuant to power purchase agreements with qualifying facilities. The judge deferred to the primary jurisdiction of the MPSC, dismissing the circuit court case without prejudice. In February 2005, the MPSC issued an order in the 2004 PSCR plan case concluding that we have been correctly administering the energy charge calculation methodology. The plaintiffs have appealed the MPSC order to the Michigan Court of Appeals. The plaintiffs also filed suit in the United States Court for the Western District of Michigan, which the judge subsequently dismissed. The plaintiffs have appealed the dismissal to the United States Court of Appeals. We cannot predict the outcome of these appeals.

Consumers’ Electric Utility Rate Matters

Electric ROA: In prior orders, the MPSC approved recovery of Stranded Costs incurred from 2002 through 2003 plus the cost of money through the period of collection. At December 31, 2006, we had a regulatory asset for Stranded Costs of $65 million on our Consolidated Balance Sheets. We collect Stranded Costs through a surcharge on ROA customers. At December 31, 2006, alternative electric suppliers were providing 300 MW of generation service to ROA customers, which represent a decrease of 46 percent of ROA load compared to the end of December 2005. If downward ROA trends continue, it may extend the time it takes to recover fully our Stranded Costs. It is difficult to predict future ROA customer trends and their effect on the timely recovery of Stranded Costs.

Power Supply Costs: To reduce the risk of high power supply costs during peak demand periods and to achieve our reserve margin target, we purchase electric capacity and energy contracts for the physical delivery of electricity primarily in the summer months and to a lesser degree in the winter months. We have purchased capacity and energy contracts covering partially the estimated reserve margin requirements for 2007 through 2010. As a result, we have an asset of $62 million for unexpired seasonal capacity and energy contracts at December 31, 2006. Capacity cost for these primarily seasonal electric capacity and energy contracts was $17 million in 2006.

PSCR: The PSCR process allows recovery of reasonable and prudent power supply costs. The MPSC reviews these costs for reasonableness and prudency in annual plan and reconciliation proceedings.

2005 PSCR Reconciliation: In March 2006, we submitted our 2005 PSCR reconciliation filing to the MPSC. Our filing indicated that 2005 underrecoveries were $36 million for commercial and industrial customers.

2006 PSCR Plan: In August 2006, the MPSC issued an order approving our amended 2006 PSCR plan, which resulted in an increased PSCR factor for the remainder of 2006. PSCR underrecoveries for 2006 were $119 million. These underrecoveries are due to the MPSC delaying recovery of our increased METC costs and coal supply costs, increased bundled sales, and other cost increases beyond those included in the 2006 PSCR plan filings.

PSCR 2007 Plan: In December 2006, the MPSC issued a temporary order allowing us to implement our 2007 PSCR monthly factor on January 1, 2007, as filed in our September 2006 case filing. The order also approved the incorporation of our 2005 and 2006 PSCR underrecoveries into our 2007 PSCR monthly factor and allowed us to continue to roll in prior year under and overrecoveries into future PSCR plans.

CMS-67

CMS Energy Corporation

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

Other Consumers’ Electric Utility Contingencies

The MCV PPA: The MCV Partnership, which leases and operates the MCV Facility, contracted to sell 1,240 MW of electricity to Consumers under a 35-year power purchase agreement beginning in 1990. We estimate that capacity and energy payments under the MCV PPA will be $620 million per year. The MCV PPA and the associated customer rates are unaffected by the November 2006 sale of our interest in the MCV Partnership.

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

RCP: In January 2005, we implemented the MPSC-approved RCP with modifications. The RCP allows us to recover the same amount of capacity and fixed energy charges from customers as approved in prior MPSC orders. However, we are able to dispatch the MCV Facility based on natural gas market prices. This results in fuel cost savings for the MCV Facility, which the MCV Partnership shares with us. The RCP also requires us to contribute $5 million annually to a renewable resources program. As of December 2006, we have contributed $10 million to the renewable resources program. The underlying RCP agreement between Consumers and the MCV Partnership extends through the term of the MCV PPA. However, either party may terminate that agreement under certain conditions. In January 2007, the Michigan Attorney General filed an appeal with the Michigan Supreme Court regarding the MPSC’s order approving the RCP. We cannot predict the outcome of this matter.

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

The Sale of Nuclear Assets and the Palisades Power Purchase Agreement: In July 2006, we reached an agreement to sell Palisades to Entergy for $380 million and pay Entergy $30 million to assume ownership and responsibility for the Big Rock ISFSI.

Palisades Asset Sale: The sale is subject to various regulatory approvals, including the MPSC’s approval of the power purchase agreement and the NRC’s approval of the transfer of the operating license to Entergy and other related matters. In February 2007, the FERC issued an order approving the sale of power to us under the power purchase agreement and granted other related approvals, with what

CMS-68

CMS Energy Corporation

we believe are minor exceptions and conditions that we believe can be adequately accepted. In October 2006, the Federal Trade Commission issued a notice that neither it nor the DOJ’s Antitrust Division plans to take enforcement action on the sale. The final purchase price will be subject to various closing adjustments such as working capital and capital expenditure adjustments, adjustments for nuclear fuel usage and inventory, and the date of closing. However, termination of the sale agreement can occur if the closing does not take place by January 2008. To accommodate delays in receiving regulatory approval, extension of the closing can occur for up to six months. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur.

Under the agreement, if the transaction does not close by March 1, 2007, a reduction in the purchase price occurs of approximately $80,000 per day, with additional costs if the deal does not close by June 1, 2007. Based on the MPSC’s published schedule for the contested case proceedings regarding this transaction, we target to close on the transaction in the second quarter of 2007. Based on the anticipated closing date, this delay would result in a purchase price reduction for Palisades of approximately $5 million. We estimate that the Palisades sale will result in a $31 million premium above the Palisades asset value at the anticipated closing date after accounting for estimated sales-related costs. We expect that this premium will benefit our customers. We cannot predict with certainty whether or when satisfaction of the closing conditions will occur or whether or when completion of the transaction will occur.

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

Palisades Power Purchase Agreement: As part of the transaction, Entergy will sell us 100 percent of the plant’s output up to its current capacity of 798 MW under a 15-year power purchase agreement. During the term of the power purchase agreement, Entergy is obligated to supply, and we are obligated to take, all capacity and energy from the Palisades plant, exclusive of uprates above the plant’s presently specified capacity. When the plant is not operating or is derated, under certain circumstances Entergy can elect to provide replacement power from another source at the rates set in the power purchase agreement. Otherwise, we would have to obtain replacement power from the market. However, we are only obligated to pay Entergy for capacity and energy actually delivered by Entergy either from the plant or from an allowable replacement source chosen by Entergy. If Entergy schedules a plant outage in June, July or August, Entergy is required to provide replacement power at power purchase agreement rates. There are significant penalties incurred by Entergy if the delivered energy fails to achieve a minimum capacity factor level during July and August. Over the term of the power purchase agreement, the pricing terms are such that Consumers’ ratepayers will retain the benefits of the Palisades plant’s low-cost nuclear generation.

Because of the power purchase agreement that will be in place between Consumers and Entergy, the transaction is effectively a sale and leaseback for accounting purposes. SFAS No. 98 specifies the accounting required for a seller’s sale and simultaneous leaseback transaction involving real estate, including real estate with equipment. Due to forms of continuing involvement, we will account for the transaction as a financing for accounting purposes and not a sale. As such, we have not classified the assets as held for sale on our Consolidated Balance Sheets.

Nuclear Plant Decommissioning: The MPSC and the FERC regulate the recovery of costs to decommission, or remove from service, our Big Rock and Palisades nuclear plants. Decommissioning funding practices approved by the MPSC require us to file a report on the adequacy of funds for decommissioning at three-year intervals. We prepared and filed updated cost estimates for Big Rock and

CMS-69

CMS Energy Corporation

Palisades in March 2004. Excluding additional costs for spent nuclear fuel storage due to the DOE’s failure to accept this spent nuclear fuel on schedule, these reports show a decommissioning cost of $361 million for Big Rock and $868 million for Palisades. Big Rock’s estimated cost includes historical expenditures in nominal dollars and future costs in 2003 dollars, with all Palisades costs given in 2003 dollars. Updated cost projections for Big Rock indicate an anticipated decommissioning cost of $390 million as of December 2006.

Big Rock: In December 2000, funding of the Big Rock trust fund stopped because the MPSC-authorized decommissioning surcharge collection period expired. In our March 2004 report to the MPSC, we indicated that we would manage the decommissioning trust fund to meet annual NRC financial assurance requirements by withdrawing NRC radiological decommissioning costs from the fund and initially funding non-NRC greenfield costs out of corporate funds. In March 2006, we contributed $16 million to the trust fund from our corporate funds to support NRC radiological decommissioning costs. Excluding the additional nuclear fuel storage costs due to the DOE’s failure to accept spent fuel on schedule, we are projecting that the level of funds provided by the trust will fall short of the amount needed to complete the decommissioning by an additional $37 million. This total of $53 million, which are costs associated with NRC radiological and non-NRC greenfield decommissioning work, are being funded out of corporate funds. We plan to seek recovery of such expenditures recorded on our consolidated balance sheets in future filings with the MPSC.

We have incurred Big Rock expenditures, excluding nuclear fuel storage costs, of $41 million for the year ended December 31, 2006, and cumulative expenditures through December 31, 2006 of $386 million. These activities had no material impact on consolidated net income. At December 31, 2006, we have an investment in nuclear decommissioning corporate funded trust funds of $4 million for Big Rock. In addition, at December 31, 2006, we have charged $10 million to our FERC jurisdictional depreciation reserve for the decommissioning of Big Rock.

Palisades: Excluding additional nuclear fuel storage costs due to the DOE’s failure to accept spent fuel on schedule, we concluded, based on the cost estimates filed in March 2004, that the existing Palisades’ surcharge of $6 million needed to be increased to $25 million annually, beginning January 2006. A settlement agreement was approved by the MPSC, providing for the continuation of the existing $6 million annual decommissioning surcharge through 2011, which was our original license expiration date, and for the next periodic review to be filed in March 2007. Amounts collected from electric retail customers and deposited in trusts, including trust earnings, are credited to a regulatory liability.

At December 31, 2006, we have an investment in the MPSC nuclear decommissioning trust funds of $587 million for Palisades. In addition, at December 31, 2006, we have a FERC decommissioning trust fund with a balance of $11 million. In the FERC’s February 2007 order regarding the Palisades sale, the FERC granted our request to apply the $11 million FERC decommissioning trust fund balance toward the Big Rock decommissioning shortfall, subject to the outcome of the NRC operating license transfer proceedings and completion of the Palisades sale transaction. For additional details on decommissioning costs accounted for as asset retirement obligations, see Note 8, Asset Retirement Obligations.

In March 2005, the NMC, which operates the Palisades plant, applied for a 20-year license renewal for the plant on behalf of Consumers. In January 2007, the NRC renewed the Palisades operating license for 20 years, extending it to 2031. At this time, we cannot determine what impact this will have on decommissioning costs or the adequacy of funding. Initial estimates of decommissioning costs, assuming a plant retirement date of 2031, show decommissioning costs of either $818 million or $1.049 billion for Palisades, depending on the decommissioning methodology assumed. These costs, which exclude additional costs for spent nuclear fuel storage due to the DOE’s failure to accept spent

CMS-70

CMS Energy Corporation

nuclear fuel on schedule, are given in 2003 dollars.

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

There are two court decisions that support the right of utilities to pursue damage claims in the United States Court of Claims against the DOE for failure to take delivery of spent nuclear fuel. Over 60 utilities have initiated litigation in the United States Court of Claims. We filed our complaint in December 2002. If our litigation against the DOE is successful, we plan to use any recoveries as reimbursement for the incurred costs of spent nuclear fuel storage. We can make no assurance that the litigation against the DOE will be successful.

In 2002, the site at Yucca Mountain, Nevada was designated for the development of a repository for the disposal of high-level radioactive waste and spent nuclear fuel. We expect that the DOE, in due course, will submit a final license application to the NRC for the repository. The application and review process is estimated to take several years.

Insurance: We maintain nuclear insurance coverage on our nuclear plants. At Palisades, we maintain nuclear property insurance from NEIL totaling $2.750 billion and insurance that would partially cover the cost of replacement power during certain prolonged accidental outages. Because NEIL is a mutual insurance company, we could be subject to assessments of up to $30 million in any policy year if insured losses in excess of NEIL’s maximum policyholders surplus occur at our, or any other member’s, nuclear facility. NEIL’s policies include coverage for acts of terrorism.

At Palisades, we maintain nuclear liability insurance for third-party bodily injury and off-site property damage resulting from a nuclear energy hazard for up to approximately $10.761 billion, the maximum insurance liability limits established by the Price-Anderson Act. Part of the Price-Anderson Act’s financial protection is a mandatory industry-wide program under which owners of nuclear generating facilities could be assessed if a nuclear incident occurs at any nuclear generating facility. The maximum assessment against us could be $101 million per occurrence, limited to maximum annual installment payments of $15 million.

We also maintain insurance under a program that covers tort claims for bodily injury to nuclear workers caused by nuclear hazards. The policy contains a $300 million nuclear industry aggregate limit. Under a previous insurance program providing coverage for claims brought by nuclear workers, we remain responsible for a maximum assessment of up to $6 million. This requirement will end December 31, 2007.

Big Rock remains insured for nuclear liability up to $544 million through nuclear insurance and NRC indemnity, and maintains a nuclear property insurance policy from NEIL.

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

Consumers’ Gas Utility Contingencies

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

CMS-71

CMS Energy Corporation

plant facilities. We operated the facilities on these sites for some part of their operating lives. For some of these sites, we have no current ownership or may own only a portion of the original site. In 2005, we estimated our remaining costs to be between $29 million and $71 million, based on 2005 discounted costs, using a discount rate of three percent. The discount rate represents a 10-year average of U.S. Treasury bond rates reduced for increases in the consumer price index. We expect to fund most of these costs through proceeds derived from a settlement with insurers and MPSC-approved rates. At December 31, 2006, we have a liability of $24 million, net of $59 million of expenditures incurred to date, and a regulatory asset of $56 million. The timing of payments related to the remediation of our manufactured gas plant sites is uncertain. Any significant change in assumptions, such as an increase in the number of sites, different remediation techniques, nature and extent of contamination, and legal and regulatory requirements, could affect our estimate of remedial action costs and the timing our remediation payments.

Consumers’ Gas Utility Rate Matters

Gas Cost Recovery: The GCR process is designed to allow us to recover all of our purchased natural gas costs if incurred under reasonable and prudent policies and practices. The MPSC reviews these costs, policies, and practices for prudency in annual plan and reconciliation proceedings.

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

Gas Cost Recovery Reconciliation

			Net Over-	GCR Cost
GCR Year	Date Filed	Order Date	recovery	of Gas Sold	Description of Net Overrecovery
2004-2005	June 2005	April 2006	$2 million	$1.4 billion	The net overrecovery includes interest expense through March 2005 and refunds that we received from our suppliers that are required to be refunded to our customers.
2005-2006	June 2006	Pending	$3 million	$1.8 billion	The net overrecovery includes $1 million interest income through March 2006, which resulted from a net underrecovery position during the majority of the GCR period.

GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our 2005-2006 GCR Plan year, which resulted in approval of a settlement agreement and established a fixed price cap of $10.10 per mcf for the December 2005 through March 2006 billing period. We were able to maintain our billing GCR factor below the authorized level for that period. The order was appealed to the Michigan Court of Appeals by one intervenor. We are unable to predict the outcome of this proceeding.

GCR plan for year 2006-2007: In December 2005, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2006 through March 2007. Our request proposed using a GCR factor consisting of:

• a base GCR ceiling factor of $11.10 per mcf, plus

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

CMS-72

CMS Energy Corporation

In July 2006, all parties signed a partial settlement agreement, which calls for a base GCR ceiling factor of $9.48 per mcf. The settlement agreement base GCR ceiling factor is subject to a quarterly GCR ceiling price adjustment mechanism. The adjustment mechanism allows an adjustment of the base ceiling factor to reflect a portion of cost increases, if the average NYMEX price for a specified period is greater than that used in calculating the base GCR factor. The MPSC approved the settlement agreement in August 2006.

The GCR billing factor is adjusted monthly in order to minimize the over or underrecovery amounts in our annual GCR reconciliation. Our GCR billing factor for the month of February 2007 is $7.63 per mcf.

GCR plan for year 2007-2008: In December 2006, we filed an application with the MPSC seeking approval of a GCR plan for the 12-month period of April 2007 through March 2008. Our request proposed using a GCR factor consisting of:

• a base GCR ceiling factor of $8.47 per mcf, plus

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

2005 Gas Rate Case: In July 2005, we filed an application with the MPSC for an annual gas rate increase of $132 million. In May 2006, the MPSC issued an order granting us interim rate relief of $18 million annually.

In November 2006, the MPSC issued an order granting rate relief of $81 million, which included the $18 million of interim relief granted in May 2006. The MPSC authorized an 11 percent return on common equity, a reduction from our then current 11.4 percent authorized rate of return. In addition, the order made permanent the collection of a $58 million surcharge granted in October 2004.

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

Other Contingencies

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

Dearborn Industrial Generation: In October 2001, Duke/Fluor Daniel (DFD), the primary construction contractor for the DIG facility, presented DIG with a change order to their construction contract and filed an action in Michigan state court against DIG, claiming contractual damages in the amount of $110 million, plus interest and costs. DFD also filed a construction lien for the $110 million.

CMS-73

CMS Energy Corporation

DIG contested both of the claims made by DFD. In addition to drawing down on three letters of credit totaling $30 million that it obtained from DFD, DIG filed an arbitration claim against DFD asserting in excess of an additional $75 million in claims against DFD. The judge in the Michigan state court case entered an order staying DFD’s prosecution of its claims in the court case and permitting the arbitration to proceed. The arbitration hearing concluded on September 28, 2006 and the arbitration panel issued its award on December 21, 2006. The arbitration panel awarded DIG approximately $25 million, including interest, on its various claims against DFD presented in the arbitration. The panel also awarded DFD approximately $5 million on its claims and credited DFD approximately $30 million for the three letters of credit DIG drew against DFD, plus $2 million in interest on the award amount. This resulted in a net amount due DFD, inclusive of interest, in the amount of approximately $12 million, which DIG has paid. CMS Energy had previously accrued a liability of approximately $30 million relating to the three letters of credit. In December 2006, we recorded $20 million pre-tax as a reduction of Operating Expenses in our Consolidated Statements of Income (Loss). The arbitration between DIG and DFD is now complete.

Former CMS Oil and Gas Operations: A Michigan trial judge granted Star Energy, Inc. and White Pine Enterprises, LLC a declaratory judgment in an action filed in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas subsidiary, violated an oil and gas lease and other arrangements by failing to drill wells it had committed to drill. A jury then awarded the plaintiffs a $7.6 million award. Appeals were filed of the original verdict and a subsequent decision of the court on remand. The court of appeals issued an opinion on May 26, 2005 remanding the case to the trial court for a new trial on damages. At a status conference on April 10, 2006, the judge set a six-month discovery period. The case is set for a new trial on damages in August 2007. The parties attended a court-ordered mediation on July 14, 2006 and the matter was not resolved. Enterprises has an indemnity obligation with regard to losses to Terra that might result from this litigation.

CMS Ensenada Customer Dispute: Pursuant to a long-term power purchase agreement, CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery in La Plata, Argentina. As a result of the so-called “Emergency Laws,” payments by YPF Repsol under the power purchase agreement have been converted to pesos at the exchange rate of one U.S. dollar to one Argentine peso. Such payments are currently insufficient to cover CMS Ensenada’s operating costs.

The Argentine commercial court granted injunctive relief to CMS Ensenada pursuant to an ex parte action, and such relief remained in effect until completion of arbitration on the matter, administered by the International Chamber of Commerce (ICC). The arbitration hearing was held in July 2005. The ICC released the arbitral tribunal’s partial award dated August 22, 2006. The partial award is generally favorable to CMS Ensenada. Following the arbitration decision, CMS Ensenada reached agreement with YPF Repsol, under which YPF Repsol paid approximately $24 million for the period through December 31, 2006, and the parties agreed to revert substantially to the terms and conditions of the original contract. We recorded $21 million as Operating Revenue and $3 million as Other interest in our Consolidated Statements of Income (Loss). The parties have notified the ICC that all outstanding issues relating to the arbitral tribunal’s partial award have been resolved fully by mutual agreement between the parties.

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

CMS-74

CMS Energy Corporation

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

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

The ICSID Convention provides that either party may seek annulment of the award based upon five possible grounds specified in the Convention. Argentina’s Application for Annulment was formally registered by ICSID on September 27, 2005 and will be considered by a newly constituted panel.

On December 28, 2005, certain insurance underwriters paid the sum of $75 million to CMS Gas Transmission in respect of their insurance obligations resulting from non-payment of the ICSID award. The payment, plus interest, is subject to repayment by CMS Gas Transmission in the event that the ICSID award is annulled. Pending the outcome of the annulment proceedings, CMS Energy has recorded the $75 million payment as a long-term deferred credit.

Quicksilver Resources, Inc.: Quicksilver sued CMS MST for breach of contract in connection with a Contract for Sale and Purchase of natural gas, pursuant to which Quicksilver agreed to sell, and CMS MST to buy, natural gas. Quicksilver believes that it is entitled to more payments for natural gas than it has received. CMS MST disagrees with Quicksilver’s analysis and believes that it has paid all amounts owed for delivery of gas pursuant to the contract. Quicksilver is seeking damages of up to approximately $126 million, plus prejudgment interest and attorney fees, which in our judgment is totally unsupported by the facts.

T.E.S. Filer City Air Permit Issue: In January 2007, we received a Notice of Violation (NOV) from the EPA alleging that TES Filer City, a generating facility in which we have a 50 percent partnership interest, exceeded certain air permit limits. We are in discussions with the EPA with regard to these allegations, but cannot predict the financial impact or outcome of this issue.

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

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

CMS-75

CMS Energy Corporation

FASB Interpretation No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others: The Interpretation requires the guarantor, upon issuance of a guarantee, to recognize a liability for the fair value of the obligation it undertakes in issuing the guarantee.

The following table describes our guarantees at December 31, 2006:

In Millions
	Issue	Expiration	Maximum		Carrying
Guarantee Description	Date	Date	Obligation		Amount
Indemnifications from asset sales and other agreements (a)	October 1995	Indefinite	$	1,133	$	1
Standby letters of credit and loans (b)	Various	Various through May 2010		85	—
Surety bonds and other indemnifications	Various	Indefinite		10	—
Guarantees and put options (c)	Various	Various through September 2027		209		1
Nuclear insurance retrospective premiums	Various	Indefinite		137	—

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

(b) Standby letters of credit include letters of credit issued under an amended credit agreement with Citicorp USA, Inc. In May 2007, letters of credit issued on behalf of certain unconsolidated affiliates in the Middle East, Africa, and India totaling $65 million were replaced by TAQA.

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

Maximum obligation includes $102 million in performance and financial guarantees issued on behalf of certain unconsolidated affiliates in the Middle East, Africa, and India. In May 2007, these guarantees were replaced by TAQA.

CMS-76

CMS Energy Corporation

The following table provides additional information regarding our guarantees:

Guarantee Description	How Guarantee Arose	Events That Would Require Performance
Indemnifications from asset sales and other agreements	Stock and asset sales agreements	Findings of misrepresentation, breach of warranties, and other specific events or circumstances
Standby letters of credit and loans	Credit agreement	Non-payment by CMS Energy and Enterprises of obligations under the credit agreement
Surety bonds and other indemnifications	Normal operating activity, permits and licenses	Nonperformance
Guarantees and put options	Normal operating activity	Nonperformance or non-payment by a subsidiary under a related contract
	Agreement to provide power and steam to Dow	MCV Partnership’s nonperformance or non-payment under a related contract
	Bay Harbor remediation efforts	Owners exercising put options requiring us to purchase property
Nuclear insurance retrospective premiums	Normal operations of nuclear plants	Call by NEIL and Price-Anderson Act for nuclear incident

At December 31, 2006, certain contracts contained provisions allowing us to recover, from third parties, amounts paid under the guarantees. For example, if we are required to purchase a property under a put option agreement, we may sell the property to recover the amount paid under the option.

We enter into various agreements containing tax and other indemnification provisions in connection with a variety of transactions, including the sale of our interests in the MCV Partnership and the FMLP. While we are unable to estimate the maximum potential obligation related to these indemnities, we consider the likelihood that we would be required to perform or incur significant losses related to these indemnities and the guarantees listed in the preceding tables to be remote.

Project Financing: We enter into various project-financing security arrangements such as equity pledge agreements and share mortgage agreements to provide financial or performance assurance to third parties on behalf of certain unconsolidated affiliates. Expiration dates for these agreements vary from March 2015 to June 2020 or terminate upon payment or cancellation of the obligation. Non-payment or other act of default by an unconsolidated affiliate would trigger enforcement of the security. If we were required to perform under these agreements, the maximum amount of our obligation under these agreements would be equal to the value of the shares relinquished to the guaranteed party at the time of default.

In 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 Charges and Discontinued Operations.

CMS-77

CMS Energy Corporation

4: Financings and Capitalization

Long-term debt at December 31 follows:

In Millions
	Interest Rate (%)			Maturity	2006			2005
CMS Energy Corporation
Senior notes		9.875		2007	$	289		$	365
		8.900		2008		260			260
		7.500		2009		409			409
		7.750		2010		300			300
		8.500		2011		300			300
		6.300		2012		150			150
		6.875		2015		125			125
		3.375	(a)	2023		150			150
		2.875	(a)	2024		288			288
						2,271			2,347
Other						1			2
Total — CMS Energy Corporation						2,272			2,349
Consumers Energy Company
First mortgage bonds		4.250		2008		250			250
		4.800		2009		200			200
		4.400		2009		150			150
		4.000		2010		250			250
		5.000		2012		300			300
		5.375		2013		375			375
		6.000		2014		200			200
		5.000		2015		225			225
		5.500		2016		350			350
		5.150		2017		250			250
		5.650		2020		300			300
		5.650		2035		147			150
		5.800		2035		175			175
						3,172			3,175
Senior notes		6.375		2008		159			159
		6.875		2018		180			180
						339			339
Securitization bonds		5.384	(b)	2007-2015		340			369
FMLP debt						—			207
Nuclear fuel disposal liability				(c)		152			145
Tax-exempt pollution control revenue bonds	Various			2010-2035		161			161
Total — Consumers Energy Company						4,164			4,396
Other Subsidiaries						331			335
Total principal amount outstanding						6,767			7,080
Current amounts						(551	)		(281	)
Net unamortized discount						(14	)		(19	)
Total long-term debt					$	6,202		$	6,780

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

CMS-78

CMS Energy Corporation

(b) Represents the weighted average interest rate at December 31, 2006 (5.295 percent at December 31, 2005).

(c) Maturity date uncertain.

Retirements: The following is a summary of significant long-term debt retirements during 2006:

	Principal		Interest Rate
	(In millions)		(%)		Retirement Date	Maturity Date
CMS Energy
Senior notes	$	76		9.875	January through April 2006	October 2007
Consumers
Long-term debt – related parties		129		9.00	February 2006	June 2031
FMLP debt		56		13.25	July 2006	July 2006
FMLP debt (a)		151	Various		November 2006	July 2009
Enterprises
CMS Generation Investment Co. IV Bank Loan		49	Variable		June through December 2006	December 2008
Total	$	461

(a) FMLP debt of $151 million was removed as part of the November 2006 transaction in which Consumers sold its interest in the FMLP.

First Mortgage Bonds: Consumers secures its FMB by a mortgage and lien on substantially all of its property. Its ability to issue FMB is restricted by certain provisions in the first mortgage bond indenture and the need for regulatory approvals under federal law. Restrictive new issuance provisions in the first mortgage bond indenture include achieving a two-times interest coverage ratio and having sufficient unfunded net property additions.

Securitization Bonds: Certain regulatory assets collateralize Securitization bonds. The bondholders have no recourse to our other assets. Through Consumers’ rate structure, we bill customers for securitization surcharges to fund the payment of principal, interest, and other related expenses on the Securitization bonds. Securitization surcharges collected are remitted to a trustee for the Securitization bonds and are not available to creditors of Consumers or its affiliates. Securitization surcharges totaled $50 million in 2006 and 2005.

Long-Term Debt – Related Parties: CMS Energy and Consumers each formed various statutory wholly-owned business trusts for the sole purpose of issuing preferred securities and lending the gross proceeds to themselves. The sole assets of the trusts consist of the debentures described in the following table. These debentures have terms similar to those of the mandatorily redeemable preferred securities the trusts issued. We determined that we do not hold the controlling financial interest in our trust preferred security structures. Accordingly, those entities are reflected in Long-term debt – related parties.

CMS-79

CMS Energy Corporation

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

In Millions
Debenture and related party	Interest Rate (%)		Maturity		2006		2005
Convertible subordinated debentures, CMS Energy Trust I		7.75		2027	$	178	$	178
Subordinated debentures:
Consumers Energy Company Financing IV		9.00				—		129
Total principal amounts outstanding						178		307
Current amounts						—		(129	)
Total Long-term debt – related parties					$	178	$	178

In the event of default, holders of the Trust Preferred Securities would be entitled to exercise and enforce the trusts’ creditor rights against us, which may include acceleration of the principal amount due on the debentures. CMS Energy and Consumers, as applicable, have issued certain guarantees with respect to payments on the preferred securities. These guarantees, when taken together with our obligations under the debentures, related indenture and trust documents, provide full and unconditional guarantees for the trusts’ obligations under the preferred securities.

Debt Maturities: At December 31, 2006, the aggregate annual contractual maturities for long-term debt and long-term debt – related parties for the next five years are:

In Millions
	Payments Due
	2007		2008		2009		2010		2011
Long-term debt and long-term debt – related parties	$	401	$	837	$	814	$	660	$	353

Regulatory Authorization for Financings: In May 2006, the FERC issued an order authorizing Consumers to issue up to $2.0 billion of secured and unsecured short-term securities for the following purposes:

• up to $1.0 billion for general corporate purposes, and

• up to $1.0 billion of FMB or other securities to be issued solely as collateral for other short-term securities.

Also in May 2006, the FERC issued an order authorizing Consumers to issue up to $5.0 billion of secured and unsecured long-term securities for the following purposes:

• up to $1.5 billion for general corporate purposes,

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

• up to $2.5 billion of FMB or other securities to be issued solely as collateral for other long-term securities.

The authorizations are for a two-year period beginning July 1, 2006 and ending June 30, 2008. Any long-term issuances during the two-year authorization period are exempt from the FERC’s competitive bidding and negotiated placement requirements.

CMS-80

CMS Energy Corporation

Revolving Credit Facilities: The following secured revolving credit facilities with banks are available at December 31, 2006:

In Millions
						Outstanding
		Amount of		Amount		Letters-of-		Amount
Company	Expiration Date	Facility		Borrowed		Credit		Available
CMS Energy	May 18, 2010	$	300	$	—	$	98	$	202
Consumers	March 30, 2007		300		—		—		300
Consumers	May 18, 2010		500		—		58		442

Effective February 2007, Consumers terminated their $300 million facility.

Dividend Restrictions: CMS Energy’s $300 million secured revolving credit facility restricts payments of dividends on our common stock during a 12-month period to $150 million, dependent on the aggregate amounts of unrestricted cash and unused commitments under the facility.

Under the provisions of its articles of incorporation, at December 31, 2006, Consumers had $215 million of unrestricted retained earnings available to pay common stock dividends. Covenants in Consumers’ debt facilities restrict its ability to pay dividends to us by capping common stock dividend payments at $300 million in a calendar year. At December 31, 2006, $2.702 billion of net assets were subject to such restrictions. Provisions of the Federal Power Act and the Natural Gas Act effectively restrict dividends to the amount of Consumers’ retained earnings. During 2006, we received $147 million of common stock dividends from Consumers.

Sale of Accounts Receivable: Under a revolving accounts receivable sales program, Consumers sells certain accounts receivable to a wholly owned, consolidated, bankruptcy remote special purpose entity. In turn, the special purpose entity may sell an undivided interest in up to $325 million of the receivables. The special purpose entity sold $325 million of receivables at December 31, 2006 and December 31, 2005. Consumers continues to service the receivables sold to the special purpose entity. The purchaser of the receivables has no recourse against Consumers’ other assets for failure of a debtor to pay when due and no right to any receivables not sold. Consumers has neither recorded a gain or loss on the receivables sold nor retained interest in the receivables sold.

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

In Millions
Years Ended December 31	2006		2005
Net cash flow as a result of accounts receivable financing	$	—	$	21
Collections from customers	$	5,684	$	4,859

CMS-81

CMS Energy Corporation

Capitalization: The authorized capital stock of CMS Energy consists of:

• 350 million shares of CMS Energy Common Stock, par value $0.01 per share, and

• 10 million shares of CMS Energy Preferred Stock, par value $0.01 per share.

Preferred Stock: Our Preferred Stock outstanding follows:

	Number of Shares				In Millions
December 31	2006		2005		2006		2005
Preferred Stock 4.50% convertible, Authorized 10,000,000 shares (a)		5,000,000		5,000,000	$	250	$	250
Preferred subsidiary interest						11		11
Total Preferred stock					$	261	$	261

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

Preferred Stock of Subsidiary: Consumers’ Preferred Stock outstanding follows:

				Optional
				Redemption		Number of Shares				In Millions
December 31	Series			Price		2006		2005		2006		2005
Preferred Stock Cumulative $100 par value, Authorized 7,500,000 shares, with no mandatory redemption		$	4.16	$	103.25		68,451		68,451	$	7	$	7
		$	4.50	$	110.00		373,148		373,148		37		37
Total Preferred stock of subsidiary										$	44	$	44

Contingently Convertible Securities: At December 31, 2006, the significant terms of our contingently convertible securities were as follows:

Contingently Convertible			Number		Outstanding		Conversion		Trigger
Security	Maturity		of Units		(In Millions)		Price		Price
4.50% preferred stock		N/A		5,000,000	$	250	$	9.89	$	11.87
3.375% senior notes		2023		150,000	$	150	$	10.67	$	12.81
2.875% senior notes		2024		287,500	$	288	$	14.75	$	17.70

The note holders have the right to require us to purchase the 3.375 percent convertible senior notes at par on July 15, 2008, 2013, and 2018. The note holders have the right to require us to purchase the 2.875 percent convertible senior notes at par on December 1, 2011, 2014, and 2019. On or after December 5, 2008, we may cause the 4.50 percent convertible preferred stock to convert if the closing price of our common stock remains at or above $12.86 for 20 of any 30 consecutive trading days.

The securities become convertible for a calendar quarter if the price of our common stock remains at or above the trigger price for 20 of 30 consecutive trading days ending on the last trading day of the previous quarter. The trigger price at which these securities become convertible is 120 percent of the conversion price. The conversion and trigger prices are subject to an adjustment under certain circumstances, including payments or distributions to our common stockholders. The conversion and trigger price adjustment will be made only when the cumulative change in conversion and trigger prices

CMS-82

CMS Energy Corporation

is at least one percent.

All of our contingently convertible securities require us, if converted, to pay cash up to the principal (or par) amount of the securities and any conversion value in excess of that amount in shares of our common stock. In December 2006, the trigger price contingency was met for our 4.50 percent convertible preferred stock and our 3.375 percent convertible senior notes. As a result, these securities are convertible at the option of the security holders during the three months ended March 31, 2007. As of February 2007, none of the security holders have notified us of their intention to convert these securities.

Because the 3.375 percent senior notes are convertible on demand, they are classified as current liabilities.

5: Earnings Per Share

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

In Millions, Except Per Share Amounts
Years Ended December 31	2006			2005			2004
Earnings Available to Common Stockholders
Income (Loss) from Continuing Operations	$	(122	)	$	(133	)	$	115
Less Preferred Dividends		(11	)		(10	)		(11	)
Income (Loss) from Continuing Operations Available to Common Stockholders — Basic		(133	)		(143	)		104
Add dilutive impact of Contingently Convertible Securities (net of tax)		—			—			1
Income (Loss) from Continuing Operations Available to Common Stockholders - Diluted	$	(133	)	$	(143	)	$	105
Average Common Shares Outstanding Applicable to Basic and Diluted EPS
Weighted Average Shares – Basic		219.9			211.8			168.6
Add dilutive impact of Contingently Convertible Securities		—			—			3.0
Add dilutive Stock Options and Warrants		—			—			0.5
Weighted Average Shares – Diluted		219.9			211.8			172.1
Earnings (Loss) Per Average Common Share Available to Common Stockholders
Basic	$	(0.61	)	$	(0.68	)	$	0.61
Diluted	$	(0.61	)	$	(0.68	)	$	0.60

Contingently Convertible Securities: Due to accounting EPS dilution principles, there was no impact to diluted EPS from our contingently convertible securities for the years ended December 31, 2006 and 2005. Assuming positive income from continuing operations, our contingently convertible securities dilute EPS to the extent that the conversion value, which is based on the average market price of our common stock, exceeds the principal or par value. Had there been positive income from continuing operations, our contingently convertible securities would have contributed an additional 11.3 million shares to the calculation of diluted EPS for 2006 and 10.9 million shares for 2005. For additional details on our contingently convertible securities, see Note 4, Financings and Capitalization.

CMS-83

CMS Energy Corporation

Stock Options and Warrants: For the year ended December 31, 2006, due to accounting EPS dilution principles, there was no impact to diluted EPS for options and warrants to purchase 2.9 million shares of common stock and 1.9 million shares of restricted stock. For the year ended December 31, 2005 there was no impact to diluted EPS for options and warrants to purchase 3.5 million shares of common stock and 1.7 million shares of restricted stock, due to accounting EPS dilution principles. For the year ended December 31, 2004, since the exercise price was greater than the average market price of common stock, there was no impact to diluted EPS from options and warrants to purchase 4.5 million shares of common stock.

Convertible Debentures: Due to accounting EPS dilution principles, for the years ended December 31, 2006, 2005, and 2004, there was no impact to diluted EPS from our 7.75 percent convertible subordinated debentures. Using the if-converted method, the debentures would have:

• increased the numerator of diluted EPS by $9 million for the years ended December 31, 2006, 2005 and 2004, from an assumed reduction of interest expense, net of tax, and

• increased the denominator of diluted EPS by 4.2 million shares.

We can revoke the conversion rights if certain conditions are met.

6: financial and derivative instruments

Financial Instruments: The carrying amounts of cash, short-term investments, and current liabilities approximate their fair values because of their short-term nature. We estimate the fair values of long-term financial instruments based on quoted market prices or, in the absence of specific market prices, on quoted market prices of similar instruments, or other valuation techniques.

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

In Millions
December 31	2006							2005
			Fair		Unrealized					Fair		Unrealized
	Cost		Value		Gain (Loss)			Cost		Value		Gain (Loss)
Long-term debt (a)	$	6,753	$	6,949	$	(196	)	$	7,061	$	7,287	$	(226	)
Long-term debt - related parties (b)		178		155		23			307		280		27

(a) Includes current maturities of $551 million at December 31, 2006 and $281 million at December 31, 2005. Settlement of long-term debt is generally not expected until maturity.

(b) Includes current maturities of $129 million at December 31, 2005.

CMS-84

CMS Energy Corporation

The summary of our available-for-sale investment securities is as follows:

In Millions
December 31	2006									2005
			Unrealized		Unrealized			Fair				Unrealized		Unrealized			Fair
	Cost		Gains		Losses			Value		Cost		Gains		Losses			Value
Nuclear decommissioning investments (a):
Equity securities	$	140	$	150	$	(4	)		286		134		123		(5	)		252
Debt securities		307		4		(2	)		309		287		6		(2	)		291
SERP:
Equity securities		36		21		—			57		34		15		—			49
Debt securities		13		—		—			13		17		—		—			17

(a) Nuclear decommissioning investments include cash and cash equivalents and accrued income totaling $7 million at December 31, 2006 and $12 million at December 31, 2005. Unrealized gains and losses on nuclear decommissioning investments are reflected as regulatory liabilities.

The fair value of available-for-sale debt securities by contractual maturity at December 31, 2006 is as follows:

	In Millions
Due in one year or less	$	38
Due after one year through five years		97
Due after five years through ten years		76
Due after ten years		111
Total	$	322

In July 2006, we reached an agreement to sell Palisades and the Big Rock ISFSI to Entergy. Entergy will assume responsibility for the future decommissioning of the plant and for storage and disposal of spent nuclear fuel. Accordingly, upon completion of the sale, we will transfer $400 million of nuclear decommissioning trust fund assets to Entergy and retain $205 million. We will also be entitled to receive a return of $147 million, pending either a favorable federal tax ruling regarding the release of the funds, or if no such ruling is issued, after decommissioning of the Palisades site is complete. These estimates fluctuate based on existing market conditions and the closing date of the transaction. The disposition of the retained and receivable nuclear decommissioning funds is subject to regulatory proceedings.

Our held-to-maturity investments consist of debt securities held by the MCV Partnership totaling $91 million at December 31, 2005. They were removed as part of the November 2006 transaction in which we sold our interest in the MCV Partnership. These securities represent funds restricted primarily for future lease payments and are classified as Other assets on our Consolidated Balance Sheets. These investments had original maturity dates of approximately one year or less and, because of their short-term maturities, carrying amounts approximate fair value.

Derivative Instruments: In order to limit our exposure to certain market risks, we may enter into various risk management contracts, such as swaps, options, futures, and forward contracts. These contracts, used primarily to manage our exposure to changes in interest rates, commodity prices, and currency exchange rates, are classified as either non-trading or trading. We enter into these contracts using established policies and procedures, under the direction of both:

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

CMS-85

CMS Energy Corporation

• a risk committee consisting of business unit managers.

The contracts we use to manage market risks may qualify as derivative instruments that are subject to derivative and hedge accounting under SFAS No. 133. If a contract is a derivative, it is recorded on our consolidated balance sheet at its fair value. We then adjust the resulting asset or liability each quarter to reflect any change in the market value of the contract, a practice known as marking the contract to market. From time to time, we enter into cash flow hedges. If a derivative qualifies for cash flow hedge accounting treatment, the changes in fair value (gains or losses) are reported in AOCL; otherwise, the changes are reported in earnings.

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

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

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

• the forecasted transaction being hedged must be probable.

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

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

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

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

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

• there is not an active market for the commodity.

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

In 2005, the MISO began operating the Midwest Energy Market. As of December 31, 2006, we have determined that, due to the increased liquidity for electricity within the Midwest Energy Market since its inception, it is our best judgment that this market should be considered an active market, as defined

CMS-86

CMS Energy Corporation

by SFAS No. 133. This conclusion does not impact how we account for our electric capacity and energy contracts held in Michigan, however, because these contracts qualify for the normal purchases and sales exception and, as a result, are not required to be marked-to-market.

Derivative accounting is required for certain contracts used to limit our exposure to interest rate risk, commodity price risk, and foreign exchange risk. The following table summarizes our derivative instruments:

In Millions
December 31	2006									2005
				Fair			Unrealized						Fair			Unrealized
Derivative Instruments	Cost			Value			Gain (Loss)			Cost			Value			Gain (Loss)
Non-trading:
Gas supply option contracts	$	—		$	—		$	—		$	1		$	(1	)	$	(2	)
FTRs		—			—			—			—			1			1
Derivative contracts associated with the MCV Partnership:
Long-term gas contracts (a)		—			—			—			—			205			205
Gas futures, options, and swaps (a)		—			—			—			—			223			223
CMS ERM contracts:
Non-trading electric / gas contracts (b)		—			31			31			—			(63	)		(63	)
Trading electric / gas contracts (c)		(11	)		(68	)		(57	)		(3	)		100			103
Derivative contracts associated with equity investments in:
Shuweihat		—			(14	)		(14	)		—			(20	)		(20	)
Taweelah		(35	)		(11	)		24			(35	)		(17	)		18
Jorf Lasfar		—			(5	)		(5	)		—			(8	)		(8	)
Other		—			1			1			—			1			1

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

(b) The fair value of CMS ERM’s non-trading electric and gas contracts has increased significantly from December 31, 2005 due to the termination of certain gas contracts. CMS ERM had recorded derivative liabilities, representing cumulative unrealized mark-to-market losses, associated with these gas contracts. As the contracts are now settled, the related derivative liabilities are no longer included in the balance of CMS ERM’s non-trading electric and gas contracts.

(c) The fair value of CMS ERM’s trading electric and gas contracts has decreased significantly from December 31, 2005 due to the termination of certain gas contracts. CMS ERM had recorded derivative assets, representing cumulative unrealized mark-to-market gains, associated with these gas contracts. As the contracts are now settled, the related derivative assets are no longer included in the balance of CMS ERM’s trading electric and gas contracts.

At December 31, 2005, we recorded the fair value of our gas supply option contracts, FTRs, and the derivative contracts associated with the MCV Partnership in Derivative instruments, Other assets, or Other liabilities on our Consolidated Balance Sheets. We include the fair value of the derivative contracts held by CMS ERM in either Price risk management assets or Price risk management liabilities on our Consolidated Balance Sheets. The fair value of derivative contracts associated with our equity

CMS-87

CMS Energy Corporation

investments is included in Investments – Enterprises on our Consolidated Balance Sheets.

Gas Supply Option Contracts: Our gas utility business uses gas supply call and put options to meet our regulatory obligation to provide gas to our customers at a reasonable and prudent cost. As part of regulatory accounting, the mark-to-market gains and losses associated with these options are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on our consolidated balance sheet as a regulatory asset or liability.

FTRs: With the creation of the Midwest Energy Market, FTRs were established. FTRs are financial instruments that manage price risk related to electricity transmission congestion. An FTR entitles its holder to receive compensation (or, conversely, to remit payment) for congestion-related transmission charges. As part of regulatory accounting, the mark-to-market gains and losses associated with these instruments are reported directly in earnings as part of Other income, and then immediately reversed out of earnings and recorded on our consolidated balance sheet as a regulatory asset or liability.

Derivative Contracts Associated with the MCV Partnership: In November 2006, we sold our interest in the MCV Partnership. In conjunction with that sale, our interest in all of the MCV Partnership’s long-term gas contracts and related futures, options, and swaps was sold. Before the sale, we accounted for certain long-term gas contracts and all of the related futures, options, and swaps as derivatives.

Long-term gas contracts: The MCV Partnership used long-term gas contracts to purchase and manage the cost of the natural gas it needed to generate electricity and steam. The MCV Partnership determined that certain of these contracts qualified as normal purchases under SFAS No. 133. Accordingly, we did not recognize these contracts at fair value on our Consolidated Balance Sheets.

The MCV Partnership also held certain long-term gas contracts that did not qualify as normal purchases because they contained volume optionality or because the gas was not expected to be used to generate electricity or steam in the normal course of business. Accordingly, prior to the sale, we accounted for these contracts as derivatives, with changes in fair value recorded in earnings each quarter.

During 2006, through the date of the sale, we recorded a $151 million loss, before considering tax effects and minority interest, associated with the net decrease in fair value of these long-term gas contracts. This loss is included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss). As a result of the sale, we no longer consolidate the MCV Partnership. Accordingly, we will no longer record the fair value of the long-term gas contracts on our Consolidated Balance Sheets and will not be required to record gains or losses related to changes in the fair value of these contracts in earnings.

Gas Futures, Options, and Swaps: The MCV Partnership entered into natural gas futures, options, and over-the-counter swap transactions in order to hedge against unfavorable changes in the market price of natural gas. The MCV Partnership used these financial instruments to:

• ensure an adequate supply of natural gas for the projected generation and sales of electricity and steam, and

• manage price risk by fixing the price to be paid for natural gas on some of its long-term gas contracts.

Certain of the futures and swaps held by the MCV Partnership qualified for cash flow hedge accounting and, prior to the sale, we recorded our proportionate share of their mark-to-market gains and losses in AOCL. As of the date of the sale, we had accumulated a net gain of $30 million, net of tax and

CMS-88

CMS Energy Corporation

minority interest, in AOCL representing our proportionate share of mark-to-market gains from these cash flow hedges. After the sale, this amount was reclassified to and recognized in earnings as a reduction of the total loss on the sale in our Consolidated Statements of Income (Loss).

The remaining futures, options, and swap contracts held by the MCV Partnership did not qualify as cash flow hedges and we recorded any changes in their fair value in earnings each quarter. During 2006, through the date of the sale, we recorded a $53 million loss, before considering tax effects and minority interest, associated with the net decrease in fair value of these contracts. This loss is included in the total Fuel costs mark-to-market at the MCV Partnership in our Consolidated Statements of Income (Loss).

As a result of the sale, we will no longer record the fair value of the futures, options, and swaps on our Consolidated Balance Sheets and will not be required to record gains or losses related to changes in the fair value of these contracts in earnings or AOCL. For additional details on the sale of our interest in the MCV Partnership, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

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

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

Derivative Contracts Associated with Equity Investments: At December 31, 2006, some of our equity method investees held:

• interest rate contracts that hedged the risk associated with variable-rate debt, and

• foreign exchange contracts that hedged the foreign currency risk associated with payments to be made under operating and maintenance service agreements.

We record our proportionate share of the change in fair value of these contracts in AOCL if the contracts qualify for cash flow hedge accounting; otherwise, we record our share in Earnings from Equity Method Investees. There was no ineffectiveness associated with any of the contracts that qualify for cash flow hedge accounting.

Foreign Exchange Derivatives: At times, we use forward exchange and option contracts to hedge the value of investments in foreign operations. These contracts limit the risk from currency exchange rate movements because gains and losses on such contracts offset losses and gains, respectively, on the hedged investments. At December 31, 2006, we had no outstanding foreign exchange contracts. However, the impact of previous hedges on our investments in foreign operations is reflected in AOCL as a component of the foreign currency translation adjustment on our Consolidated Balance Sheets. Gains or losses from the settlement of these hedges are maintained in the foreign currency translation adjustment until we sell or liquidate the hedged investments. At December 31, 2006, our total foreign

CMS-89

CMS Energy Corporation

currency translation adjustment was a net loss of $297 million, which included a net hedging loss of $26 million, net of tax, related to the settlement of these contracts.

Credit Risk: Our swaps, options, and forward contracts contain credit risk, which is the risk that counterparties will fail to perform their contractual obligations. We reduce this risk through established credit policies. For each counterparty, we assess credit quality by using credit ratings, financial condition, and other available information. We then establish a credit limit for each counterparty based upon our evaluation of credit quality. We monitor the degree to which we are exposed to potential loss under each contract and take remedial action, if necessary.

CMS ERM enters into contracts primarily with companies in the electric and gas industry. This industry concentration may have an impact on our exposure to credit risk, either positively or negatively, based on how these counterparties are affected by similar changes in economic conditions, the weather, or other conditions. CMS ERM typically uses industry-standard agreements that allow for netting positive and negative exposures associated with the same counterparty, thereby reducing exposure. These contracts also typically provide for the parties to demand adequate assurance of future performance when there are reasonable grounds for doing so.

The following table illustrates our exposure to potential losses at December 31, 2006, if each counterparty within this industry concentration failed to perform its contractual obligations. This table includes contracts accounted for as financial instruments. It does not include trade accounts receivable, derivative contracts that qualify for the normal purchases and sales exception under SFAS No. 133, or other contracts that are not accounted for as derivatives.

In Millions
							Net Exposure		Net Exposure
	Exposure						from Investment		from Investment
	Before		Collateral		Net		Grade		Grade
	Collateral (a)		Held		Exposure		Companies (b)		Companies (%)
CMS ERM	$	56	$	—	$	56	$	13		23	%

(a) Exposure is reflected net of payables or derivative liabilities if netting arrangements exist.

(b) The majority of the remaining balance of CMS ERM’s net exposure was from a counterparty whose credit rating fell below investment grade after December 31, 2005.

Based on our credit policies, our current exposures, and our credit reserves, we do not expect a material adverse effect on our financial position or future earnings as a result of counterparty nonperformance.

7: Retirement Benefits

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

• a non-contributory, defined benefit Pension Plan,

• a cash balance Pension Plan for certain employees hired between July 1, 2003 and August 31, 2005,

• a DCCP for employees hired on or after September 1, 2005,

• benefits to certain management employees under SERP,

• a defined contribution 401(k) Savings Plan,

• benefits to a select group of management under the EISP, and

CMS-90

CMS Energy Corporation

• health care and life insurance benefits under OPEB.

Pension Plan: The Pension Plan includes funds for most of our current employees, the employees of our subsidiaries, and Panhandle, a former subsidiary. The Pension Plan’s assets are not distinguishable by company.

On September 1, 2005, we implemented the DCCP. The DCCP provides an employer contribution of 5 percent of base pay to the existing employees’ Savings Plan. No employee contribution is required in order to receive the plan’s employer contribution. All employees hired on and after September 1, 2005 participate in this plan as part of their retirement benefit program. Cash balance pension plan participants also participate in the DCCP as of September 1, 2005. Additional pay credits under the cash balance pension plan were discontinued as of that date. The DCCP expense was $2 million for the year ended December 31, 2006 and less than $1 million for the year ended December 31, 2005.

Effective January 11, 2006, the MPSC electric rate order authorized Consumers to include $33 million of electric pension expense in its electric rates. Effective November 21, 2006, the MPSC gas rate order authorized Consumers to include $22 million of gas pension expense in its gas rates. Due to the volatility of these costs, the orders also established a pension equalization mechanism to track actual costs. If actual pension expenses are greater than the amounts included in rate cases, the difference will be recognized as a regulatory asset for future recovery from customers. If actual pension expenses are less than the amounts included in rate cases, the difference will be recognized as a regulatory liability, and refunded to our customers. The difference between pension expenses allowed in Consumers’ rate cases and Consumers’ $66 million net pension cost under SFAS No. 87 resulted in the recognition of a regulatory asset of $11 million.

SERP: SERP benefits are paid from a trust established in 1988. SERP is not a qualified plan under the Internal Revenue Code. SERP trust earnings are taxable and trust assets are included in our consolidated assets. Trust assets were $71 million at December 31, 2006 and $66 million at December 31, 2005. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The ABO for SERP was $78 million at December 31, 2006 and $74 million at December 31, 2005.

On April 1, 2006, we implemented a Defined Contribution Supplemental Executive Retirement Plan (DC SERP) and froze further new participation in the defined benefit SERP. The DC SERP provides participants benefits ranging from 5 percent to 15 percent of total compensation. The DC SERP requires a minimum of five years of participation before vesting. Our contributions to the plan, if any, will be placed in a grantor trust. Trust assets were less than $1 million at December 31, 2006. The assets are classified as Other non-current assets on our Consolidated Balance Sheets. The DC SERP expense was less than $1 million for the year ended December 31, 2006.

401(k): The employer’s match for the 401(k) Savings Plan, which was suspended on September 1, 2002, resumed on January 1, 2005. The employer’s match is in CMS Energy Common Stock. On September 1, 2005, employees enrolled in the company’s 401(k) Savings Plan had their employer match increased from 50 percent to 60 percent on eligible contributions up to the first six percent of an employee’s wages. The total 401(k) Savings Plan cost was $15 million for the year ended December 31, 2006 and $13 million for the year ended December 31, 2005.

Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be an investment option available for new investments in the 401(k) Savings Plan and the employer’s match will no longer be in CMS Energy 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

CMS-91

CMS Energy Corporation

in the CMS Energy Stock Fund will be sold and the sale proceeds will be reallocated to other plan investment options. At February 20, 2007, there were 10.7 million shares of CMS Energy Common Stock in the CMS Energy Stock Fund.

The MCV Partnership sponsors a defined contribution retirement plan and a 401(k) Savings Plan covering all employees. Amounts contributed under these plans were $1 million for the period January 1, 2006 through November 21, 2006 and $1 million for each of the years ended December 31, 2005 and 2004.

EISP: We implemented an EISP in 2002 to provide flexibility in separation of employment by officers, a select group of management, or other highly compensated employees. Terms of the plan may include payment of a lump sum, payment of monthly benefits for life, payment of premiums for continuation of health care, or any other legally permissible term deemed to be in our best interest to offer. The EISP expense was $1 million for each of the years ended December 31, 2006 and 2005. The ABO for the EISP was $5 million at December 31, 2006 and $4 million at December 31, 2005.

OPEB: The OPEB plan covers all regular full-time employees covered by the employee health care plan on a company-subsidized basis the day before they retire from the company at age 55 or older and who have at least 10 full years of applicable continuous service. Regular full-time employees who qualify for a disability retirement and have 15 years of applicable continuous service are also eligible. Retiree health care costs were based on the assumption that costs would increase 10 percent in 2006. Starting in 2007, we will use two health care trend rates: one for retirees under 65 and the other for retirees 65 and over. The two health care trend rates recognize that prescription drug costs are increasing at a faster pace than other medical claim costs and that prescription drug costs make up a larger portion of expenses for retirees age 65 and over. The 2007 rate of increase for OPEB health costs for those under 65 is expected to be 9 percent and for those over 65 is expected to be 10.5 percent. The rate of increase is expected to slow to 5 percent for those under 65 by 2011 and for those over 65 by 2013 and thereafter.

Effective January 11, 2006, the MPSC electric rate order authorized Consumers to include $28 million of electric OPEB expense in its electric rates. Effective November 21, 2006, the MPSC gas rate order authorized Consumers to include $21 million of gas OPEB expense in its gas rates. Due to the volatility of these costs, the orders also established an OPEB equalization mechanism to track actual costs. If actual OPEB expenses are greater than the amounts included in rate cases, the difference will be recognized as a regulatory asset for future recovery from our customers. If actual OPEB expenses are less than the amounts included in rate cases, the difference will be recognized as a regulatory liability, and refunded to our customers. The difference between OPEB expenses allowed in Consumers’ rate cases and Consumers’ $51 million net OPEB cost under SFAS No. 106 resulted in the recognition of a regulatory asset of $2 million.

The MCV Partnership sponsors defined cost postretirement health care plans that cover all full-time employees, except key management. The ABO of the MCV Partnership’s postretirement plans was $5 million at December 31, 2005. The MCV Partnership’s net periodic postretirement health care cost for the period January 1, 2006 through November 21, 2006 and year ended December 31, 2005 was less than $1 million.

CMS-92

CMS Energy Corporation

The health care cost trend rate assumption affects the estimated costs recorded. A one percentage point change in the assumed health care cost trend assumption would have the following effects:

In Millions
	One Percentage		One Percentage
	Point Increase		Point Decrease
Effect on total service and interest cost component	$	19	$	(15	)
Effect on postretirement benefit obligation	$	220	$	(186	)

Upon adoption of SFAS No. 106, at the beginning of 1992, we recorded a liability of $466 million for the accumulated transition obligation and a corresponding regulatory asset for anticipated recovery in utility rates. For additional details, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation.” The MPSC authorized recovery of the electric utility portion of these costs in 1994 over 18 years and the gas utility portion in 1996 over 16 years.

The measurement date for all CMS Energy plans is November 30 for 2006, 2005 and 2004. We changed our measurement date in 2004 from December 31 to November 30, which resulted in a $2 million cumulative effect of change in accounting for retirement benefits, net of tax benefit, as a decrease to earnings. We also increased the amount of accrued benefit cost on our Consolidated Balance Sheets by $4 million. The measurement date for the MCV Partnership’s plan was December 31 for 2005 and 2004.

SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106, and 132(R): In September 2006, the FASB issued SFAS No. 158. This standard requires us to recognize the funded status of our defined benefit postretirement plans on our Consolidated Balance Sheets at December 31, 2006. SFAS No. 158 requires us to recognize changes in the funded status of our plans in the year in which the changes occur. This standard also requires that we change our plan measurement date from November 30 to December 31, effective December 31, 2008. We do not believe that implementation of this provision of the standard will have a material effect on our consolidated financial statements. We expect to adopt the measurement date provisions of SFAS No. 158 in 2008.

The following table recaps the incremental effect of applying SFAS No. 158 on individual line items on our Consolidated Balance Sheets. The adoption of SFAS No. 158 had no effect on our Consolidated Statements of Income (Loss) for the year ended December 31, 2006, or for any prior period presented, and it will not affect our operating results in future periods. Had we not been required to adopt SFAS No. 158 at December 31, 2006, we would have recognized an additional minimum liability pursuant to the provisions of SFAS No. 87. The effect of recognizing the additional minimum liability is included in the following table in the column labeled “Before Application of SFAS No. 158:”

CMS-93

CMS Energy Corporation

								In Millions
	Before						After
	Application of						Application of
Year ended December 31, 2006	SFAS No. 158			Adjustment			SFAS No. 158
Regulatory asset (a)	$	470		$	680		$	1,150
Intangible asset		48			(48	)		—
Total assets		518			632			1,150
Liability for retirement benefits (b)		(420	)		(647	)		(1,067	)
Regulatory liabilities – Income taxes, net (c)		(459	)		(80	)		(539	)
Deferred income taxes		(199	)		88			(111	)
Total liabilities		(1,078	)		(639	)		(1,717	)
Accumulated other comprehensive loss		16			7			23
Total decrease in stockholders’ equity		16			7			23

(a) Consumers recognized the cost of their minimum liability prior to the application of SFAS No. 158 and the adjustment resulting from adoption of SFAS No. 158 as a regulatory asset under SFAS No. 71, based upon guidance from the MPSC.

(b) Liabilities for retirement benefits include $1.066 billion that are non-current and $1 million that is current at December 31, 2006.

(c) The adjustment represents the Medicare D Subsidy tax benefit of implementing SFAS No. 158.

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

Weighted average for benefit obligations:

	Pension & SERP									OPEB
Years Ended December 31	2006			2005			2004			2006			2005			2004
Discount rate		5.65	%		5.75	%		6.00	%		5.65	%		5.75	%		6.00	%
Expected long-term rate of return on plan assets (a)		8.25	%		8.50	%		8.75	%
Union																	8.75	%
Non-Union																	6.00	%
Combined in 2005											7.75	%		8.00	%
Mortality table (b)		2000			2000			1983			2000			2000			1983
Rate of compensation increase:
Pension		4.00	%		4.00	%		3.50	%
SERP		5.50	%		5.50	%		5.50	%

CMS-94

CMS Energy Corporation

Weighted average for net periodic benefit cost:

	Pension & SERP									OPEB
Years Ended December 31	2006			2005			2004			2006			2005			2004
Discount rate		5.75	%		5.75	%		6.25	%		5.75	%		5.75	%		6.25	%
Expected long-term rate of return on plan assets (a)		8.50	%		8.75	%		8.75	%
Union																	8.75	%
Non-Union																	6.00	%
Combined in 2005											8.00	%		8.25	%
Mortality table (b)		2000			2000			1983			2000			2000			1983
Rate of compensation increase:
Pension		4.00	%		3.50	%		3.25	%
SERP		5.50	%		5.50	%		5.50	%

(a) We determine our long-term rate of return by considering historical market returns, the current and future economic environment, the capital market principles of risk and return, and the expert opinions of individuals and firms with financial market knowledge. We use the asset allocation of the portfolio to forecast the future expected total return of the portfolio. The goal is to determine a long-term rate of return that can be incorporated into the planning of future cash flow requirements in conjunction with the change in the liability. The use of forecasted returns for various classes of assets used to construct an expected return model is reviewed annually for reasonableness and appropriateness.

(b) Prior to 2005, we utilized the 1983 Group Annuity Mortality Table. Starting in 2005, we utilize the Combined Healthy RP-2000 Table from the 2000 Group Annuity Mortality Tables.

Costs: The following tables recap the costs, other changes in plan assets and benefit obligations incurred in our retirement benefits plans:

							In Millions
	Pension & SERP
Years Ended December 31	2006			2005				2004
Net periodic pension cost
Service cost	$	51		$	44			$	37
Interest expense		88			83				79
Expected return on plan assets		(85	)		(97	)			(109	)
Amortization of:
Net loss		43			35				14
Prior service cost		7			6				6
Net periodic pension cost		104			71				27
Regulatory adjustment		(11	)		—				—
Net periodic pension cost after regulatory adjustment	$	93		$	71			$	27

CMS-95

CMS Energy Corporation

In Millions
	OPEB
Years Ended December 31	2006			2005			2004
Net periodic OPEB cost
Service cost	$	23		$	23		$	19
Interest expense		64			61			58
Expected return on plan assets		(57	)		(54	)		(48	)
Amortization of:
Net loss		20			20			10
Prior service credit		(10	)		(9	)		(9	)
Net periodic OPEB cost		40			41			30
Regulatory adjustment		(2	)		—			—
Net periodic OPEB cost after regulatory adjustment		38		$	41		$	30

The estimated net loss and prior service cost for the defined benefit pension plans that will be amortized into net periodic benefits cost over the next fiscal year from regulatory asset is $50 million and from AOCL is $3 million. The estimated net loss and prior service credit for OPEB plans that will be amortized into net periodic benefit cost over the next fiscal year from regulatory asset is $12 million and from AOCL is $1 million.

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

In Millions
	Pension Plan						SERP						OPEB
Years Ended December 31	2006			2005			2006			2005			2006			2005
Benefit obligation at beginning of period	$	1,510		$	1,328		$	91		$	83		$	1,136		$	1,073
Service cost		49			42			2			2			23			23
Interest cost		83			78			5			5			64			61
Plan amendment		—			39			—			1			—			(19	)
Actuarial loss (gain)		51			146			(2	)		4			70			47
Benefits paid		(117	)		(123	)		(4	)		(4	)		(50	)		(49	)
Benefit obligation at end of period (a)		1,576			1,510			92			91			1,243			1,136
Plan assets at fair value at beginning of period		1,018			1,040			—			—			714			654
Actual return on plan assets		126			101			—			—			73			45
Company contribution		13			—			4			4			58			63
Actual benefits paid (b)		(117	)		(123	)		(4	)		(4	)		(47	)		(48	)
Plan assets at fair value at end of period		1,040			1,018			—			—			798			714
Funded status at end of measurement period		(536	)		(492	)		(92	)		(91	)		(445	)		(422	)
Additional VEBA Contributions or Non-Trust Benefit Payments		—			—			—			—			14			16
Funded status at December 31	$	(536	)	$	(492	)	$	(92	)	$	(91	)	$	(431	)	$	(406	)

(a) The Medicare Prescription Drug, Improvement and Modernization Act of 2003 establishes a prescription drug benefit under Medicare (Medicare Part D), and a federal subsidy, which is tax-exempt, to sponsors of retiree health care benefit plans that provide a benefit that is actuarially equivalent to Medicare Part D. The Medicare Part D annualized reduction in net OPEB cost was

CMS-96

CMS Energy Corporation

$28 million for 2006 and $24 million for 2005. The reduction includes $7 million for the year ended December 31, 2006 and $6 million for the year ended December 31, 2005 in capitalized OPEB costs.

(b) We received $3 million in Medicare Part D Subsidy payments for the year ended December 31, 2006.

The following table provides a reconciliation of benefit obligations, plan assets and funded status of the plans as of December 31, 2005 for all plans combined. (In accordance with SFAS No. 158, we recognized the underfunded status of our defined benefit postretirement plans as a liability on our consolidated balance sheets as of December 31, 2006.)

In Millions
	Pension Plan			SERP			OPEB
Year Ended December 31	2005			2005			2005
Fair value of plan assets	$	1,018		$	—		$	714
Net benefit obligations		1,510			91			1,136
Funded status (plan assets less plan obligations)		(492	)		(91	)		(422	)
Amounts not recognized
Net actuarial loss		747			8			375
Prior service cost (credit)		56			2			(113	)
Additional VEBA Contributions or Non-Trust Benefit Payments		—			—			16
Net amount recognized	$	311		$	(81	)	$	(144	)

The following table provides a reconciliation of the amounts recognized on our Consolidated Balance Sheets as of December 31, 2005 for all plans combined:

In Millions
	Pension Plan			SERP			OPEB
Year Ended December 31	2005			2005			2005
Prepaid benefit cost	$	311		$	—		$	—
Accrued benefit cost		—			(81	)		(144	)
Additional minimum liability		(481	)		—			—
Intangible asset		56			—			—
AOCL		26			—			—
Regulatory asset		399			—			—
Net amount recognized	$	311		$	(81	)	$	(144	)

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

In Millions
Years Ended December 31	2006		2005
Pension ABO	$	1,240	$	1,188
Fair value of pension plan assets		1,040		1,018
Pension ABO in excess of pension plan assets	$	200	$	170

CMS-97

CMS Energy Corporation

SFAS No. 158 Recognized: The following table recaps the amounts recognized in SFAS No. 158 regulatory assets and AOCL that have not been recognized as components of net periodic benefit cost. For additional details on regulatory assets, see Note 1, Corporate Structure and Accounting Policies, “Utility Regulation:”

In Millions
	Pension & SERP		OPEB
Year ended December 31	2006		2006
Regulatory assets
Net loss	$	676	$	416
Prior service cost (credit)		45		(99	)
AOCI
Net loss (gain)		46		(11	)
Prior service cost (credit)		4		(4	)
Total amounts recognized in regulatory assets and AOCL	$	771	$	302

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

	Pension						OPEB
November 30	2006			2005			2006			2005
Asset Category:
Fixed Income		28	%		33	%		37	%		58	%
Equity Securities:		62	%		65	%		63	%		40	%
CMS Energy Common Stock (a)		—			—			—			1	%
Alternative Strategy		10	%		2	%		—			1	%

(a) At November 30, 2006, there were no shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million. At November 30, 2005, there were no shares of CMS Energy Common Stock in the Pension Plan assets, and 143,200 shares in the OPEB plan assets with a fair value of $2 million.

We contributed $56 million to our OPEB plan in 2006 and we plan to contribute $51 million to our OPEB plan in 2007. We contributed $13 million to our Pension Plan in 2006 and we plan to contribute $109 million to our Pension plan in 2007.

We have established a target asset allocation for our Pension Plan assets of 60 percent equity, 30 percent fixed income, and 10 percent alternative strategy investments to maximize the long-term return on plan assets, while maintaining a prudent level of risk. The level of acceptable risk is a function of the liabilities of the plan. Equity investments are diversified mostly across the Standard & Poor’s 500 Index, with lesser allocations to the Standard & Poor’s Mid Cap Index, the Small Cap Indexes and a Foreign Equity Index Fund. Fixed-income investments are diversified across investment grade instruments of both government and corporate issuers. Alternative strategies are diversified across absolute return investment approaches and global tactical asset allocation. Annual liability measurements, quarterly portfolio reviews, and periodic asset/liability studies are used to evaluate the need for adjustments to the portfolio allocation.

CMS-98

CMS Energy Corporation

We have established union and non-union VEBA trusts to fund our future retiree health and life insurance benefits. These trusts are funded through the ratemaking process for Consumers, and through direct contributions from the non-utility subsidiaries. The equity portions of the union and non-union health care VEBA trusts are invested in a Standard & Poor’s 500 Index fund. The fixed-income portion of the union health care VEBA trust is invested in domestic investment grade taxable instruments. The fixed-income portion of the non-union health care VEBA trust is invested in a diversified mix of domestic tax-exempt securities. The investment selections of each VEBA are influenced by the tax consequences, as well as the objective of generating asset returns that will meet the medical and life insurance costs of retirees.

SFAS No. 132(R) Benefit Payments: The expected benefit payments for each of the next five years and the five-year period thereafter are as follows:

In Millions
	Pension		SERP		OPEB(a)
2007	$	58	$	4	$	54
2008		65		4		56
2009		73		4		58
2010		81		4		60
2011		93		4		62
2012-2016		652		21		333

(a) OPEB benefit payments are net of employee contributions and expected Medicare Part D prescription drug subsidy payments. The subsidies to be received are estimated to be $5 million for 2007, $6 million each year for 2008 through 2011 and $33 million combined for 2012 through 2016.

8: Asset Retirement Obligations

SFAS No. 143, Accounting for Asset Retirement Obligations: This standard requires companies to record the fair value of the cost to remove assets at the end of their useful life, if there is a legal obligation to remove them. Fair value, to the extent possible, should include a market risk premium for unforeseeable circumstances. No market risk premium was included in our ARO fair value estimate since a reasonable estimate could not be made. If a five percent market risk premium were assumed, our ARO liability would increase by $25 million.

If a reasonable estimate of fair value cannot be made in the period in which the ARO is incurred, such as for assets with indeterminate lives, the liability is to be recognized when a reasonable estimate of fair value can be made. Generally, electric and gas transmission and distribution assets have indeterminate lives. Retirement cash flows cannot be determined and there is a low probability of a retirement date. Therefore, no liability has been recorded for these assets or associated obligations related to potential future abandonment. Also, no liability has been recorded for assets that have insignificant cumulative disposal costs, such as substation batteries. The measurement of the ARO liabilities for Palisades and Big Rock include use of decommissioning studies that largely utilize third-party cost estimates.

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations: This Interpretation clarified the term “conditional asset retirement obligation” as used in SFAS No. 143. The term refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event. We determined that abatement of asbestos included in our plant investments qualifies as a conditional ARO, as defined by FASB Interpretation No. 47.

CMS-99

CMS Energy Corporation

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

December 31, 2006			In Millions
	In Service			Trust
ARO Description	Date		Long-Lived Assets	Fund
Palisades-decommission plant site		1972	Palisades nuclear plant	$	598
Big Rock-decommission plant site		1962	Big Rock nuclear plant		4
JHCampbell intake/discharge water line		1980	Plant intake/discharge water line		—
Closure of coal ash disposal areas	Various		Generating plants coal ash areas		—
Closure of wells at gas storage fields	Various		Gas storage fields		—
Indoor gas services equipment relocations	Various		Gas meters located inside structures		—
Asbestos abatement		1973	Electric and gas utility plant		—
Close gas treating plant and gas wells	Various		Gas transmission and storage		—

In Millions
	ARO											ARO
	Liability									Cash flow		Liability
ARO Description	1/1/05 (a)		Incurred		Settled (b)			Accretion		Revisions		12/31/05
Palisades – decommission	$	350	$	—	$	—		$	25	$	—	$	375
Big Rock – decommission		30		—		(42	)		15		24		27
JHCampbell intake line		—		—		—			—		—		—
Coal ash disposal areas		54		—		(5	)		5		—		54
Wells at gas storage fields		1		—		—			—		—		1
Indoor gas services relocations		1		—		—			—		—		1
Close gas treating plant and gas wells		1		—		(1	)		—		—		—
Asbestos abatement		33		—		—			3		—		36
Total	$	470	$	—	$	(48	)	$	48	$	24	$	494

In Millions
	ARO											ARO
	Liability									Cash flow		Liability
ARO Description	1/1/06		Incurred		Settled (b)			Accretion		Revisions		12/31/06
Palisades – decommission	$	375	$	—	$	—		$	26	$	—	$	401
Big Rock – decommission		27		—		(28	)		3		—		2
JHCampbell intake line		—		—		—			—		—		—
Coal ash disposal areas		54		—		(2	)		5		—		57
Wells at gas storage fields		1		—		—			—		—		1
Indoor gas services relocations		1		—		—			—		—		1
Close gas treating plant and gas wells		—		—		—			1		—		1
Asbestos abatement		36		—		(3	)		2		—		35
Total	$	494	$	—	$	(33	)	$	37	$	—	$	498

(a) The ARO liability at January 1, 2005 in the preceding table reflects the ARO liability as if FASB Interpretation No. 47 had been in effect at that time, as required by the Interpretation. Our consolidated financial statements for that period do not reflect the asbestos abatement ARO. As required by SFAS No. 71, we accounted for the implementation of this Interpretation by recording a regulatory asset

CMS-100

CMS Energy Corporation

instead of a cumulative effect of a change in accounting principle. There was no effect on consolidated net income.

(b) These cash payments are included in the Other current and non-current liabilities line in Net cash provided by operating activities in our Consolidated Statements of Cash Flows.

In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143, FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing Requirements for Asset Retirement Obligations, and related accounting and ratemaking issues for MPSC-jurisdictional electric and gas utilities. In December 2005, the ALJ issued a Proposal for Decision recommending that the MPSC dismiss the proceeding. In March 2006, the MPSC remanded the case to the ALJ for findings and recommendations. In August 2006, the ALJ issued a second Proposal for Decision that included recommendations that the MPSC:

• adopt SFAS No. 143 and FERC Order No. 631 for accounting purposes but not for ratemaking purposes,

• consider adopting standardized retirement units for certain accounts,

• consider revising the method of determining cost of removal, and

• withhold approving blanket regulatory asset and regulatory liability accounting treatment related to ARO, stating that modifications to the MPSC’s Uniform System of Accounts should precede any such accounting approval.

We consider the proceeding a clarification of accounting and reporting issues that relate to all Michigan utilities. We cannot predict the outcome of the proceeding.

9: Income Taxes

CMS Energy and its subsidiaries file a consolidated federal income tax return. Income taxes generally are allocated based on each company’s separate taxable income in accordance with the CMS Energy tax sharing agreement.

We utilize deferred tax accounting for temporary differences. These occur when there are differences between the book and tax carrying amounts of assets and liabilities. ITC has been deferred and is being amortized over the estimated service life of the related properties. We use ITC to reduce current income taxes payable.

AMT paid generally becomes a tax credit that we can carry forward indefinitely to reduce regular tax liabilities in future periods when regular taxes paid exceed the tax calculated for AMT. At December 31, 2006, we had AMT credit carryforwards of $271 million that do not expire, tax loss carryforwards of $1.616 billion that expire from 2023 through 2025, including SRLY tax loss carryforwards of $15 million that expire from 2018 through 2020. We do not believe that a valuation allowance is required, as we expect to utilize the loss carryforwards prior to their expiration. In addition, we had general business credit carryforwards of $16 million, capital loss carryforwards of $36 million that expire in 2010 and 2011 and charitable contribution carryforwards of $7 million that expire from 2007 through 2009, for which valuation allowances in each case have been provided.

U.S. income taxes are not recorded on the undistributed earnings of foreign subsidiaries that have been or are intended to be reinvested indefinitely. Upon distribution, those earnings may be subject to both U.S. income taxes (adjusted for foreign tax credits or deductions) and withholding taxes payable to various foreign countries. Cumulative undistributed earnings of foreign subsidiaries for which income taxes have not been provided totaled approximately $180 million at December 31, 2006. In 2007, we

CMS-101

CMS Energy Corporation

announced we had signed agreements or plans to sell substantially all of our foreign assets or subsidiaries. These potential sales would result in the recognition in 2007 of approximately $63 million of U.S. tax associated with the change in our determination of our permanent reinvestment of these undistributed earnings. Also, we presently cannot estimate the amount of unrecognized withholding taxes that may result. For additional information, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

The American Jobs Creation Act (AJCA) of 2004 created a one-time opportunity to receive a tax benefit for U.S. corporations that reinvest, in the U.S., dividends received in a year (2005 for CMS Energy) from controlled foreign corporations. During 2005, we repatriated $370 million of foreign earnings that qualified for the tax benefit. The net effect of the repatriated earnings were tax benefits of $29 recorded in income from continuing operations and $16 million in income from discontinued operations for 2005. In 2004, a tax benefit of $21 million was recorded in income from continuing operations.

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

In Millions
Years Ended December 31	2006			2005			2004
Current income taxes:
Federal	$	131		$	80		$	(8	)
Federal income tax benefit of operating loss carryforwards		(31	)		(70	)		—
State and local		1			(3	)		3
Foreign		2			6			4
	$	103		$	13		$	(1	)
Deferred income taxes:
Federal	$	(276	)	$	(144	)	$	10
Federal tax benefit of American Jobs Creation Act of 2004		—			(29	)		(21	)
State		—			—			(5	)
Foreign		(7	)		3			3
	$	(283	)	$	(170	)	$	(13	)
Deferred ITC, net		(4	)		(13	)		(5	)
Tax expense (benefit)	$	(184	)	$	(170	)	$	(19	)

Current tax expense includes the settlement of income tax audits for prior years, as well as the provision for 2006 income taxes prior to the use of loss carryforwards. Deferred tax assets and liabilities are recognized for the estimated future tax effect of temporary differences between the tax basis of assets or liabilities and the reported amounts in our consolidated financial statements. Deferred tax assets and liabilities are classified as current or noncurrent according to the classification of the related assets or liabilities. Deferred tax assets and liabilities not related to assets or liabilities are classified according to the expected reversal date of the temporary differences.

CMS-102

CMS Energy Corporation

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

In Millions
December 31	2006			2005
Property	$	(790	)	$	(764	)
Securitized costs		(177	)		(172	)
Employee benefits		38			(67	)
Gas inventories		(168	)		(148	)
Tax loss and credit carryforwards		867			648
SFAS No. 109 regulatory liabilities, net		189			159
Valuation allowances		(30	)		(10	)
Other, net		115			17
Net deferred tax assets/(liabilities)	$	44		$	(337	)
Deferred tax liabilities	$	(1,323	)	$	(1,308	)
Deferred tax assets, net of valuation reserves		1,367			971
Net deferred tax assets/(liabilities)	$	44		$	(337	)

In June 2006, the IRS concluded its most recent audit of CMS Energy and its subsidiaries and proposed changes to taxable income for the years ended December 31, 1987 through December 31, 2001. The proposed overall cumulative increase to taxable income related primarily to the disallowance of the simplified service cost method with respect to certain self-constructed utility assets. We have accepted these proposed adjustments to taxable income, which resulted in the payment of $76 million of tax and a reduction of our income tax provision of $62 million, net of interest expense, primarily for the restoration and utilization of previously written off income tax credits.

CMS-103

CMS Energy Corporation

The actual income tax expense (benefit) on continuing operations differs from the amount computed by applying the statutory federal tax rate of 35 percent to income (loss) before income taxes as follows:

In Millions
Years Ended December 31	2006			2005			2004
Income (loss) from continuing operations before income taxes
Domestic	$	(135	)	$	(469	)	$	190
Foreign		(171	)		166			(94	)
Total		(306	)		(303	)		96
Statutory federal income tax rate		x 35	%		x 35	%		x 35	%
Expected income tax expense (benefit)		(107	)		(106	)		34
Increase (decrease) in taxes from:
Property differences		19			15			13
Income tax effect of foreign investments		(32	)		(29	)		(31	)
AJCA foreign dividends benefit		—			(29	)		(21	)
ITC amortization		(4	)		(4	)		(6	)
State and local income taxes, net of federal benefit		—			(2	)		(1	)
Return to accrual adjustments		(7	)		(1	)		(5	)
Medicare Part D exempt income		(10	)		(6	)		(6	)
Tax exempt income		(3	)		(3	)		(3	)
Tax contingency reserves		—			(5	)		5
Valuation allowance		20			—			—
IRS Settlement / Credit Restoration		(62	)		—			—
Other, net		2			—			2
Recorded income tax benefit	$	(184	)	$	(170	)	$	(19	)
Effective tax rate		60.1	%		56.1	%		(19.8	)%

During 2006, the valuation allowance increased by $20 million. The increase was due to a $12 million increase in the allowance attributable to the capital loss on our November 2006 disposition of the MCV Partnership and a $14 million increase for the anticipated future capital loss on our GasAtacama investment. These increases were offset by a $3 million reduction in the valuation allowance for the anticipated use of prior year capital loss carryovers as well as for $3 million of allowance attributable to charitable contributions and tax credits that expired on December 31, 2006.

The amount of income taxes we pay is subject to ongoing audits by federal, state and foreign tax authorities, which can result in proposed assessments. Our estimate for the potential outcome for any uncertain tax issue is highly judgmental. We believe that our accrued tax liabilities at December 31, 2006 are adequate for all years.

FIN 48, Accounting for Uncertainty in Income Taxes: In June 2006, the FASB issued FIN 48, effective for us January 2007. This interpretation provides a two-step approach for the recognition and measurement of uncertain tax positions taken, or expected to be taken, by a company on its income tax returns. The first step is to evaluate the tax position to determine if, based on management’s best judgment, it is greater than 50 percent likely that the taxing authority will sustain the tax position. The second step is to measure the appropriate amount of the benefit to recognize. This is done by estimating the potential outcomes and recognizing the greatest amount that has a cumulative probability of at least 50 percent. FIN 48 requires interest and penalties, if applicable, to be accrued on differences between tax positions recognized in our consolidated financial statements and the amount claimed, or expected to be claimed, on the tax return. Our policy is to include interest and penalties accrued on uncertain tax positions as part of the related tax liability on our consolidated balance sheet and as part of the income tax expense in our consolidated income statement. The impact from adopting FIN 48 should be recorded as a cumulative adjustment to the beginning retained earnings balance and a

CMS-104

CMS Energy Corporation

corresponding adjustment to a current or non-current tax liability. At this time, we are continuing to evaluate the impact of FIN 48 on our consolidated financial statements.

10: Executive Incentive Compensation

We provide a Performance Incentive Stock Plan (the Plan) to key employees and non-employee directors based on their contributions to the successful management of the company. The Plan has a five-year term, expiring in May 2009.

All grants under the Plan for 2006 and 2005 were in the form of restricted stock. Restricted stock awards are outstanding shares to which the recipient has full voting and dividend rights and vest 100 percent after three years of continued employment. Restricted stock awards granted to officers in 2006, 2005, and 2004 are also subject to the achievement of specified levels of total shareholder return, including a comparison to a peer group of companies. All restricted stock awards are subject to forfeiture if employment terminates before vesting. However, if certain minimum service requirements are met, restricted shares may continue to vest upon retirement or disability and vest fully if control of CMS Energy changes, as defined by the Plan. In April 2006, we amended the Plan to allow awards not subject to achievement of total shareholder return to vest fully upon retirement, subject to the participant not accepting employment with a direct competitor. This modification did not have a material impact on our consolidated financial statements.

The Plan also allows for stock options, stock appreciation rights, phantom shares, and performance units. None of which were granted in 2006 or 2005.

Select participants may elect to receive all or a portion of their incentive payments under the Officer’s Incentive Compensation Plan in the form of cash, shares of restricted common stock, shares of restricted stock units, or any combination of these. These participants may also receive awards of additional restricted common stock or restricted stock units, provided the total value of these additional grants does not exceed $2.5 million for any fiscal year.

Shares awarded or subject to stock options, phantom shares, and performance units may not exceed 6 million shares from June 2004 through May 2009, nor may such awards to any participant exceed 250,000 shares in any fiscal year. We may issue awards of up to 4,382,800 shares of common stock under the Plan at December 31, 2006. Shares for which payment or exercise is in cash, as well as forfeited shares or stock options may be awarded or granted again under the Plan.

The following table summarizes restricted stock activity under the Plan:

				Weighted-Average
Restricted Stock	Number of Shares			Grant Date Fair Value
Nonvested at December 31, 2005		1,682,056		$	10.64
Granted		587,830		$	13.84
Vested		(308,698	)	$	7.71
Forfeited		(58,750	)	$	10.82
Nonvested at December 31, 2006		1,902,438		$	12.10

CMS-105

CMS Energy Corporation

SFAS No. 123(R) requires companies to use the fair value of employee stock options and similar awards at the grant date to value the awards. SFAS No. 123(R) was effective for us on January 1, 2006. We elected to adopt the modified prospective method recognition provisions of this Statement instead of retrospective restatement. We adopted the fair value method of accounting for share-based awards effective December 2002. Therefore, SFAS No. 123(R) did not have a significant impact on our results of operations when it became effective.

We expense the fair value over the required service period of the awards. As a result, we recognize all compensation expense for share-based awards with accelerated service provisions upon retirement by the period in which the employee becomes eligible to retire.

The total fair value of shares vested was $4 million in 2006, $4 million in 2005, and $1 million in 2004. We calculate the fair value of restricted shares granted based on the price of our common stock on the grant date and expense the fair value over the required service period. Compensation expense related to restricted stock was $9 million in 2006, $4 million in 2005, and $2 million in 2004. The total related income tax benefit recognized in income was $3 million in 2006, $2 million in 2005, and $1 million in 2004. At December 31, 2006, there was $10 million of total unrecognized compensation cost related to restricted stock. We expect to recognize this cost over a weighted-average period of 1.3 years.

The following table summarizes stock option activity under the Plan:

						Weighted-
	Options			Weighted-		Average	Aggregate
	Outstanding,			Average		Remaining	Intrinsic
	Fully Vested,			Exercise		Contractual	Value
Stock Options	and Exercisable			Price		Term	(In Millions)
Outstanding at December 31, 2005		3,541,338		$	21.21	5.4 years	$	(24	)
Granted		—			—
Exercised		(137,500	)	$	7.39
Cancelled or Expired		(490,568	)	$	30.53
Outstanding at December 31, 2006		2,913,270		$	20.29	4.7 years	$	(10	)

Stock options give the holder the right to purchase common stock at a price equal to the fair value of our common stock on the grant date. Stock options are exercisable upon grant, and expire up to 10 years and one month from the grant date. We issue new shares when participants exercise stock options. The total intrinsic value of stock options exercised was $1 million in 2006, $2 million in 2005, and $2 million in 2004. Cash received from exercise of these stock options was $1 million for the year ended December 31, 2006. Since we have utilized tax loss carryforwards, we were not able to realize the excess tax benefits upon exercise of stock options. Therefore, we did not recognize the related excess tax benefits in equity.

11: Leases

Lessee: We lease various assets, including service vehicles, railcars, construction equipment, office furniture, and buildings. We purchase renewable energy under certain power purchase agreements, as required by the MPSC. In accordance with SFAS No. 13, we account for these power purchase agreements as capital and operating leases.

CMS-106

CMS Energy Corporation

Operating leases for coal-carrying railcars have lease terms expiring over the next 15 years. These leases contain fair market value extension and buyout provisions, with some providing for predetermined extension period rentals. Capital leases for our vehicle fleet operations have a maximum term of 120 months and TRAC end-of-life provisions. The capital lease for furniture terminates in 2013, but provides for an early buyout in April 2008. Power purchase agreements range from 7 to 20 years. Most of our power purchase agreements contain options at the end of the initial contract term to renew the agreement annually.

Consumers is authorized by the MPSC to record both capital and operating lease payments as operating expense and recover the total cost from our customers. The following table summarizes our capital and operating lease expenses:

In Millions
Years Ended December 31	2006			2005			2004
Capital lease expense	$	15		$	14		$	13
Operating lease expense		19			18			14
Income from subleases		(2	)		(2	)		(1	)

Minimum annual rental commitments under our non-cancelable leases at December 31, 2006 are:

In Millions
	Capital		Operating
	Leases		Leases
2007	$	13	$	25
2008		12		24
2009		11		20
2010		9		17
2011		7		17
2012 and thereafter		29		61
Total minimum lease payments (a)		81	$	164
Less imputed interest		26
Present value of net minimum lease payments		55
Less current portion		13
Non-current portion	$	42

(a) Minimum payments have not been reduced by minimum sublease rentals of $4 million due in the future under noncancelable subleases.

Lessor: We have a 44 percent ownership interest in a 31-mile intrastate pipeline that runs from Coldwater Township, Michigan to Hanover Township, Michigan. We lease our interest in the pipeline through a direct finance lease. The lease expires in October 2031, with an annual option to extend the lease.

In March 2007, we sold a portfolio of our businesses in Argentina and our northern Michigan non-utility natural gas assets to Lucid Energy, LLC. The sale included our ownership interest in a 31-mile intrastate pipeline that runs from Coldwater Township, Michigan to Hanover Township, Michigan.

We sell power, through the Takoradi power plant located in the Republic of Ghana, Africa, under a power purchase agreement with the Volta River Authority. In accordance with SFAS No. 13, we

CMS-107

CMS Energy Corporation

account for this transaction as a direct finance lease. The initial lease term of the agreement expires in 2025.

In May 2007, we sold our ownership interest in businesses in the Middle East, Africa, and India. Included in the sale was our ownership interest in the Takoradi power plant. For more details on the sale of our ownership interests to TAQA, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

The following table summarizes the net investment in direct finance leases classified as “held for sale” on our Consolidated Balance Sheets at December 31, 2006:

In Millions
	Direct Finance Leases
2007	$	25
2008		25
2009		25
2010		24
2011		24
2012 and thereafter		333
Total minimum lease payments		456
Less unearned income		346
Net investment in direct finance leases		110
Less current portion		1
Non-current portion	$	109

CMS-108

CMS Energy Corporation

12: Property, Plant, and Equipment

The following table is a summary of our property, plant, and equipment:

In Millions
		Estimated
		Depreciable
December 31		Life in Years	2006		2005
Electric:
	Generation	13-85	$	3,573	$	3,487
	Distribution	12-75		4,425		4,226
	Other	7-40		421		404
	Capital leases (a)			85		87
Gas:
	Underground storage facilities (b)	30-65		263		262
	Transmission	15-75		465		416
	Distribution	40-75		2,216		2,141
	Other	7-50		300		306
	Capital leases (a)			29		26
Enterprises:
	IPP	3-40		415		662
	CMS Gas Transmission	3-40		25		41
	CMS Electric and Gas	2-30		99		82
	Other	4-25		13		5
Other:		7-71		31		25
Construction work-in-progress				646		518
Less accumulated depreciation, depletion, and amortization (c)				5,233		5,030
Net property, plant, and equipment (d) (e)			$	7,773	$	7,658

(a) Capital leases presented in this table are gross amounts. Amortization of capital leases was $59 million in 2006 and $54 million in 2005. Capital lease additions were $7 million and capital lease retirements and adjustments were $6 million in 2006. Capital lease additions were $12 million and capital lease retirements and adjustments were $7 million in 2005.

(b) Includes unrecoverable base natural gas in underground storage of $26 million at December 31, 2006 and December 31, 2005, which is not subject to depreciation.

(c) At December 31, 2006, accumulated depreciation, depletion, and amortization included $4.982 billion from our public utility plant assets and $251 million from other plant assets. At December 31, 2005, accumulated depreciation, depletion, and amortization included $4.804 billion from our public utility plant assets and $226 million from other plant assets.

(d) At December 31, 2006, public utility plant additions were $470 million and public utility plant retirements, including other plant adjustments, were $82 million. At December 31, 2005, public utility plant additions were $450 million and public utility plant retirements, including other plant adjustments, were $64 million.

CMS-109

CMS Energy Corporation

(e) Included in net property, plant and equipment are intangible assets related primarily to software development costs, consents, leasehold improvements, and rights of way. The estimated amortization lives for software development costs range from seven to twelve years. The estimated amortization life for leasehold improvements is the life of the lease. Other intangible amortization lives range from 13 to 75 years.

The following tables summarize our intangible assets:

In Millions
			Accumulated		Intangible Asset,
December 31, 2006	Gross Cost		Amortization		Net
Software development	$	204	$	153	$	51
Rights of way		114		31		83
Leasehold improvements		19		15		4
Franchises and consents		19		10		9
Other intangibles		23		14		9
Total	$	379	$	223	$	156

In Millions
			Accumulated		Intangible Asset,
December 31, 2005	Gross Cost		Amortization		Net
Software development	$	200	$	135	$	65
Rights of way		102		29		73
Leasehold improvements		19		14		5
Franchises and consents		19		9		10
Other intangibles		42		19		23
Total	$	382	$	206	$	176

Pretax amortization expense related to these intangible assets was $22 million for the year ended December 31, 2006, $21 million for the year ended December 31, 2005, and $21 million for the year ended December 31, 2004. Amortization of intangible assets is forecasted to range between $13 million and $23 million per year over the next five years.

CMS-110

CMS Energy Corporation

13: Equity Method Investments

We account for certain investments in other companies, partnerships, and joint ventures by the equity method of accounting in accordance with APB Opinion No. 18, where ownership is more than 20 percent but less than a majority. Earnings from equity method investments was $89 million in 2006, $125 million in 2005, and $115 million in 2004. The amount of consolidated retained earnings that represents undistributed earnings from these equity method investments was $14 million as of December 31, 2006 and $17 million as of December 31, 2005.

Our most significant equity method investments are:

• a 50 percent interest in Jorf Lasfar, and

• a 40 percent interest in Taweelah.

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

At December 31, 2006, Jorf Lasfar exceeded the 10 percent and 20 percent thresholds. At December 31, 2005, Jorf Lasfar exceeded the 10 percent threshold and no equity method investments exceeded the 20 percent threshold. At December 31, 2004, Jorf Lasfar exceeded the 20 percent threshold and both Jorf Lasfar and Taweelah exceeded the 10 percent threshold.

CMS-111

CMS Energy Corporation

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

Income Statement Data

In Millions
Year Ended December 31, 2006	Jorf Lasfar (a)		All Others		Total
Operating revenue	$	482	$	1,611	$	2,093
Operating expenses		317		1,283		1,600
Operating income		165		328		493
Other expense, net		57		195		252
Net income	$	108	$	133	$	241

In Millions
Year Ended December 31, 2005	Jorf Lasfar (a)		All Others		Total
Operating revenue	$	508	$	1,550	$	2,058
Operating expenses		340		1,190		1,530
Operating income		168		360		528
Other expense, net		56		187		243
Net income	$	112	$	173	$	285

In Millions
Year Ended December 31, 2004	Jorf Lasfar (a)		Taweelah		All Others		Total
Operating revenue	$	461	$	99	$	1,448	$	2,008
Operating expenses		282		40		1,207		1,529
Operating income		179		59		241		479
Other expense, net		53		23		140		216
Net income	$	126	$	36	$	101	$	263

Balance Sheet Data

In Millions
December 31, 2006	Jorf Lasfar (a)		All Others		Total
Assets
Current assets	$	239	$	555	$	794
Property, plant and equipment, net		15		2,931		2,946
Other assets		1,047		480		1,527
	$	1,301	$	3,966	$	5,267
Liabilities
Current liabilities	$	272	$	546	$	818
Long-term debt and other non-current liabilities		403		2,721		3,124
Equity		626		699		1,325
	$	1,301	$	3,966	$	5,267

December 31, 2005	Jorf Lasfar (a)		All Others		Total
Assets
Current assets	$	264	$	554	$	818
Property, plant and equipment, net		15		3,372		3,387
Other assets		1,022		516		1,538
	$	1,301	$	4,442	$	5,743
Liabilities
Current liabilities	$	241	$	458	$	699
Long-term debt and other non-current liabilities		441		2,914		3,355
Equity		619		1,070		1,689
	$	1,301	$	4,442	$	5,743

(a) Our investment in Jorf Lasfar was $313 million at December 31, 2006 and $310 million at December 31, 2005. Our share of net income from Jorf Lasfar was $54 million for the year ended

CMS-112

CMS Energy Corporation

December 31, 2006, $56 million for the year ended December 31, 2005, and $63 million for the year ended December 31, 2004.

In May 2007, we sold our ownership interests in businesses in the Middle East, Africa, and India, including Jorf Lasfar and Taweelah. For additional details on the sale of our interest in certain equity method investees, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

14: Jointly Owned Regulated Utility Facilities

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

In Millions
	Ownership						Accumulated				Construction
	Share		Net Investment (a)				Depreciation				Work in Progress
December 31	(percent)		2006		2005		2006		2005		2006		2005
Campbell Unit 3		93.3	$	262	$	270	$	370	$	354	$	353	$	258
Ludington		51.0		68		72		95		92		1		1
Distribution	Various			98		100		47		45		4		9

(a) Net investment is the amount of utility plant in service less accumulated depreciation.

The direct expenses of the jointly owned plants are included in operating expenses. Operation, maintenance, and other expenses of these jointly owned utility facilities are shared in proportion to each participant’s undivided ownership interest. We are required to provide only our share of financing for the jointly owned utility facilities.

15: Reportable Segments

Our reportable segments consist of business units organized and managed by their products and services. We evaluate performance based upon the net income of each segment. We operate principally in three reportable segments: electric utility, gas utility, and enterprises.

The electric utility segment consists of regulated activities associated with the generation and distribution of electricity in the state of Michigan through our subsidiary, Consumers. The gas utility segment consists of regulated activities associated with the transportation, storage, and distribution of natural gas in the state of Michigan through our subsidiary, Consumers. The enterprises segment consists of:

• investing in, acquiring, developing, constructing, managing, and operating non-utility power generation plants, electric distribution assets, and natural gas facilities in the United States and abroad, and

• providing gas, oil, and electric marketing services to energy users.

Accounting policies of our segments are the same as we describe in the summary of significant accounting policies. Our consolidated financial statements reflect the assets, liabilities, revenues, and expenses directly related to the individual segments where it is appropriate. We allocate accounts between the segments where common accounts are attributable to more than one segment. The allocations are based on certain measures of business activities, such as revenue, labor dollars, customers, other operation and maintenance expense, construction expense, leased property, taxes or

CMS-113

CMS Energy Corporation

functional surveys. For example, customer receivables are allocated based on revenue. Pension provisions are allocated based on labor dollars.

We account for inter-segment sales and transfers at current market prices and eliminate them in consolidated net income (loss) by segment. The “Other” segment includes corporate interest and other, certain deferred income taxes and the cumulative effect of accounting changes. The following tables show our financial information by reportable segment:

In Millions
Years Ended December 31	2006			2005			2004
Operating Revenues
Electric utility	$	3,302		$	2,695		$	2,583
Gas utility		2,373			2,483			2,081
Enterprises		628			840			592
	$	6,303		$	6,018		$	5,256
Earnings from Equity Method Investees
Enterprises	$	87		$	124		$	113
Other		2			1			2
	$	89		$	125		$	115
Depreciation, Depletion, and Amortization
Electric utility	$	380		$	292		$	189
Gas utility		122			117			112
Enterprises		49			97			112
Other		3			1			1
	$	554		$	507		$	414
Interest Charges
Electric utility	$	164		$	132		$	203
Gas utility		73			68			64
Enterprises		76			74			85
Other		177			196			251
	$	490		$	470		$	603
Income Tax Expense (Benefit)
Electric utility	$	95		$	85		$	120
Gas utility		18			39			40
Enterprises		(133	)		(182	)		(69	)
Other		(164	)		(112	)		(110	)
	$	(184	)	$	(170	)	$	(19	)
Net Income (Loss) Available to Common Stockholders
Electric utility	$	199		$	153		$	223
Gas utility		37			48			71
Enterprises		(209	)		(200	)		(5	)
Discontinued operations		43			49			8
Other		(160	)		(144	)		(187	)
	$	(90	)	$	(94	)	$	110

CMS-114

CMS Energy Corporation

In Millions
Years Ended December 31	2006		2005		2004
Investments in Equity Method Investees
Enterprises	$	588	$	712	$	729
Other		10		13		23
	$	598	$	725	$	752
Total Assets
Electric utility (a)	$	8,516	$	7,755	$	7,289
Gas utility (a)		3,950		3,609		3,187
Enterprises (b)		2,339		4,130		4,980
Other		566		547		416
	$	15,371	$	16,041	$	15,872
Capital Expenditures (c)
Electric utility	$	462	$	384	$	360
Gas utility		172		168		137
Enterprises		42		50		37
Other		1		3		1
	$	677	$	605	$	535

Geographic Areas(b)(d)

In Millions
	2006			2005			2004
United States
Operating Revenue	$	6,140		$	5,894		$	5,163
Operating Income (Loss)		(13	)		(461	)		586
Total Assets	$	14,123		$	14,675		$	14,419
International
Operating Revenue	$	163		$	124		$	93
Operating Income (Loss)		(93	)		134			(51	)
Total Assets	$	1,248		$	1,366		$	1,453

(a) Amounts include a portion of Consumers’ other common assets attributable to both the electric and gas utility businesses.

(b) Total Assets includes $469 million of assets classified as held for sale at December 31, 2006, $426 million at December 31, 2005 and $491 million at December 31, 2004.

(c) Amounts include electric restructuring implementation plan, purchase of nuclear fuel, and capital lease additions. Amounts also include a portion of Consumers’ capital expenditures for plant and equipment attributable to both the electric and gas utility businesses.

(d) Revenues are based on the country location of customers.

16: Consolidation of Variable Interest Entities

Until their sale in November 2006, we had a 49 percent partnership interest in the MCV Partnership and a 46.4 percent partnership interest in the FMLP. Prior to their sale, we were the primary beneficiary of both the MCV Partnership and the FMLP because Consumers is the primary purchaser of power from

CMS-115

CMS Energy Corporation

the MCV Partnership through a long-term power purchase agreement and Consumers, through its ownership interest in the FMLP, held a 35 percent lessor interest in the MCV Facility. Therefore, we consolidated these partnerships into our consolidated financial statements as of and for the year ended December 31, 2005. Upon the sale of our interests in the MCV Partnership and the FMLP, we are no longer the primary beneficiary of these entities and the entities were deconsolidated. For additional details on the sale of our interests in the MCV Partnership and the FMLP, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

These partnerships had third-party obligations totaling $482 million at December 31, 2005. Property, plant, and equipment serving as collateral for these obligations had a carrying value of $224 million at December 31, 2005. The creditors of these partnerships did not have recourse to the general credit of Consumers. At December 31, 2005, the MCV Partnership had total assets of $1.318 billion and a net loss of $917 million for the year.

We are the primary beneficiary of three other variable interest entities. We have 50 percent partnership interests each in the T.E.S. Filer City Station Limited Partnership, the Grayling Generating Station Limited Partnership, and the Genesee Power Station Limited Partnership. Additionally, we have operating and management contracts and are the primary purchaser of power from each partnership through long-term power purchase agreements. Collectively, these interests make us the primary beneficiary of these entities. Therefore, we consolidated these partnerships into our consolidated financial statements for all periods presented. These partnerships have third-party obligations totaling $97 million at December 31, 2006 and $108 million at December 31, 2005. Property, plant, and equipment serving as collateral for these obligations has a carrying value of $157 million at December 31, 2006 and $163 million at December 31, 2005. Other than through outstanding letters of credit and guarantees of $5 million, the creditors of these partnerships do not have recourse to the general credit of CMS Energy.

Additionally, we hold interests in variable interest entities in which we are not the primary beneficiary. The following chart details our involvement in these entities at December 31, 2006:

Name				Investment		Operating	Total
(Ownership	Nature of the		Involvement	Balance		Agreement with	Generating
Interest)	Entity	Country	Date	(In Millions)		CMS Energy	Capacity
Taweelah (40%)	Generator	United Arab Emirates	1999	$	83	Yes	777 MW
Jubail (25%)	Generator	Saudi Arabia	2001		—	No	250 MW
Shuweihat (20%)	Generator	United Arab Emirates	2001		56	Yes	1,500 MW
Total				$	139		2,527 MW

Our maximum exposure to loss through our interests in these variable interest entities is limited to our investment balance of $139 million, and letters of credit, guarantees, and indemnities totaling $47 million.

In February 2007, we entered into an Agreement of Purchase and Sale with TAQA to sell our ownership interest in businesses in the Middle East, Africa, and India for $900 million. Businesses

CMS-116

CMS Energy Corporation

included in the sale are Taweelah, Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We closed on the sale in May 2007. For additional details on the sale of our interest in these entities, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations.

17: Quarterly financial and common stock information (unaudited)

	In Millions, Except Per Share Amounts
	2006
Quarters Ended	March 31			June 30		Sept. 30			Dec. 31(d)
Operating revenue	$	1,937		$	1,263	$	1,333		$	1,770
Operating income (loss)		(19	)		77		(18	)		(146	)
Income (loss) from continuing operations (a)		(32	)		65		(109	)		(46	)
Income from discontinued operations (b)		8			10		8			17
Net income (loss)		(24	)		75		(101	)		(29	)
Preferred dividends		3			3		2			3
Net income (loss) available to common stockholders		(27	)		72		(103	)		(32	)
Income (loss) from continuing operations per average common share – basic		(0.16	)		0.28		(0.51	)		(0.22	)
Income (loss) from continuing operations per average common share – diluted		(0.16	)		0.27		(0.51	)		(0.22	)
Basic earnings (loss) per average common share (a)		(0.12	)		0.33		(0.47	)		(0.15	)
Diluted earnings (loss) per average common share (a)		(0.12	)		0.31		(0.47	)		(0.15	)
Common stock prices (c)
High		15.22			13.66		14.79			16.95
Low		12.95			12.46		12.92			14.55

	In Millions, Except Per Share Amounts
	2005
Quarters Ended	March 31		June 30		Sept. 30			Dec. 31(e)
Operating revenue	$	1,785	$	1,168	$	1,238		$	1,827
Operating income (loss)		437		84		(819	)		(29	)
Income (loss) from continuing operations (a)		146		25		(271	)		(33	)
Income from discontinued operations (b)		6		5		8			30
Net income (loss)		152		30		(263	)		(3	)
Preferred dividends		2		3		2			3
Net income (loss) available to common stockholders		150		27		(265	)		(6	)
Income (loss) from continuing operations per average common share – basic		0.74		0.10		(1.25	)		(0.17	)
Income (loss) from continuing operations per average common share – diluted		0.71		0.10		(1.25	)		(0.17	)
Basic earnings (loss) per average common share (a)		0.77		0.12		(1.21	)		(0.03	)
Diluted earnings (loss) per average common share (a)		0.74		0.12		(1.21	)		(0.03	)
Common stock prices (c)
High		13.38		15.16		16.71			16.48
Low		9.81		12.56		14.98			13.39

(a)	Sum of the quarters may not equal the annual earnings (loss) per share due to changes in shares outstanding.
(b)	Net of tax.
(c)	Based on New York Stock Exchange — Composite transactions.

CMS-117

CMS Energy Corporation

(d)

The quarter ended December 31, 2006 includes a $41 million net loss on the sale of our investment in the MCV Partnership including the negative impact of the associated asset impairment charge. The quarter also includes an $80 million net after-tax charge resulting from our agreement to settle shareholder class action lawsuits. For additional details, see Note 2, Asset Sales, Impairment Charges and Discontinued Operations and Note 3, Contingencies.

(e)

The quarter ended December 31, 2005 includes a $26 million after-tax charge related to environmental remediation at Bay Harbor. For additional details, see Note 3, Contingencies.

CMS-118

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholders of CMS Energy Corporation

We have audited the accompanying consolidated balance sheets of CMS Energy Corporation (a Michigan Corporation) as of December 31, 2006 and 2005, and the related consolidated statements of income (loss), common stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the financial statements of Midland Cogeneration Venture Limited Partnership, a former 49% owned variable interest entity which has been consolidated through the date of sale, November 21, 2006 (Note 2), which statements reflect total assets constituting 8.2% in 2005, and total revenues constituting 8.6% in 2006, 9.8% in 2005 and 12.4% in 2004 of the related consolidated totals. We also did not audit the 2004 financial statements of Jorf Lasfar Energy Company S.C.A. (which represents an investment accounted for under the equity method of accounting). CMS Energy Corporation’s equity in the net income of Jorf Lasfar Energy Company S.C.A. is stated at $63 million for the year ended December 31, 2004. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion on the consolidated financial statements, insofar as it relates to the amounts included for the periods indicated above for Midland Cogeneration Venture Limited Partnership and Jorf Lasfar Energy Company S.C.A., respectively, is based solely on the reports of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of CMS Energy Corporation at December 31, 2006 and 2005, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, in conformity with U.S. generally accepted accounting principles.

CMS-119

As discussed in Note 7 to the consolidated financial statements, in 2006, the Company adopted Financial Accounting Standards Board (FASB) Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – an amendment of FASB Statements No. 87, 88, 106 and 132(R).” As discussed in Note 10 to the consolidated financial statements, in 2006, the Company adopted FASB Statement of Financial Accounting Standards No. 123(R) “Share-Based Payment.” In addition, as discussed in Note 8 to the consolidated financial statements, in 2005 the Company adopted FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations.” As discussed in Note 7 to the consolidated financial statements, in 2004 the Company changed its measurement date for all CMS Energy Corporation pension and postretirement plans.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of CMS Energy Corporation’s internal control over financial reporting as of December 31, 2006, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 21, 2007, expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Detroit, Michigan
February 21, 2007, except for Note 2 as to
which the date is May 31, 2007

CMS-120

Report of Independent Registered Public Accounting Firm

To the Partners and the Management Committee of
Midland Cogeneration Venture Limited Partnership:

In our opinion, the accompanying balance sheets and the related statements of operations, of partners’ equity (deficit) and comprehensive income (loss) and of cash flows present fairly, in all material respects, the financial position of Midland Cogeneration Venture Limited Partnership at November 21, 2006 and December 31, 2005, and the results of its operations and its cash flows for the period ended November 21, 2006 and the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

/s/ PricewaterhouseCoopers LLP

February 19, 2007

CMS-121

Report of Independent Auditors

To the Management Committee
and Stockholders of Jorf Lasfar
Energy Company S.C.A.
B.P. 99 Sidi Bouzid
El Jadida

We have audited the accompanying balance sheets of Jorf Lasfar Energy Company S.C,A (the “Company”) as of December 31, 2004, 2003 and 2002, and the related statements of income, of stockholders’ equity and of cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States of America). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statements presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Jorf Lasfar Energy Company S.C.A at December 31, 2004, 2003 and 2002, and the results of its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

/s/ Price Waterhouse

Casablanca, Morocco,
February 11, 2005

CMS-122