Exhibit 99.1

Growing Forward Investor Meetings June 14-15, 2010 Thomas J. Webb Executive Vice President & Chief Financial Officer

This presentation contains "forward-looking statements" as defined in Rule 3b-6 of the Securities Exchange Act of 1934, as amended, Rule 175 of the Securities Act of 1933, as amended, and relevant legal decisions. The forward-looking statements are subject to risks and uncertainties. They should be read in conjunction with "FORWARD-LOOKING STATEMENTS AND INFORMATION" and "RISK FACTORS" sections of CMS Energy's and Consumers Energy's Form 10-K for the year ended December 31 and as updated in subsequent 10-Qs. CMS Energy's and Consumers Energy's "FORWARD-LOOKING STATEMENTS AND INFORMATION" and "RISK FACTORS" sections are incorporated herein by reference and discuss important factors that could cause CMS Energy's and Consumers Energy's results to differ materially from those anticipated in such statements. The presentation also includes non-GAAP measures when describing CMS Energy's results of operations and financial performance. A reconciliation of each of these measures to the most directly comparable GAAP measure is included in the appendix and posted on our website at www.cmsenergy.com. CMS Energy expects 2010 reported earnings to be about the same as adjusted earnings. Reported earnings could vary because of several factors. CMS Energy is not providing reported earnings guidance reconciliation because of the uncertainties associated with those factors.

Visible Utility investment EPS growth of 6%-8% annually Operating cash flow growth of ^$100 million annually Dividend growing NOLs avoid new equity near term Constructive regulatory framework Risks mitigated

Long-term Strategy Consistent financial performance Fair and timely regulation Utility investment Customer value Safe, excellent operations Consistent financial performance

Consumers Energy Fourth largest combination utility in the U.S. 1.8 million electric and 1.7 million gas customers 9,500 MW of owned and purchased generation capacity (summer) 935 MW Zeeland acquisition 307 Bcf of gas storage capacity including 142 Bcf of working storage Ludington Pumped Storage B C Cobb J H Campbell D E Karn J C Weadock J R Whiting Mio Alcona Cooke Foote Loud 5 Channels Hodenpyl Tippy Rogers Hardy Croton Webber Allegan Electric Gas Combination Zeeland Overview Territory Investment growth balances responsible rate increases and healthy capital structure with attractive earnings growth.

Electric Sales Trends (weather adjusted) . . . . 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 August Plan 22145 23722 24572 25237 25707 24533 24875 23916 24893 26051 26305 26977 27928 29143 29623 29894 30325 30877 31868 33177 34465 34622 35462 36355 37234 37463 37301 37792 37746 38017 37586 38372 38098 37339 36123 36958 Revised Potential 37339 36000 Electric Sales Year-to-Year Comparison 0 (7)% Decline over three years ('79 -'82 recession) 2008 2009 -2% -3% . . . . industrial sales showing signs of turnaround. 2010 +2% 2009 2010 2008 2009 2010 Industrial Sales -0.11 0.12 -0.04 -0.06 0.08 Total Sales -0.04 0.02 -0.02 -0.03 0.02 First Quarter Full Year

Economic Indicators -- Autos U.S. auto production up 62% through May 1.

Performance 2006 Baseline 2007 2008 2009 safety incidents 6.1 7 4.5 3.2 47% improvement from 2006. Employee Safety Moved into 1st quartile from 2008. Cost Management - 2009 Recordable Incident Rate FPL Nicor Xcel E.ON CMS Energy Puget Dominion WE Allegheny Alliant First Energy PG&E Ameren SCANA Berkshire Hathaway PPL NiSource PSE&G DTE National Grid Integrys Northeast Util 1.3 1.5 1.5 1.6 2 2.1 2.154 2.214 2.285 2.333 2.334 2.35 2.5 2.51 2.6 2.7 2.833 2.833 3.071 3.345 3.416 3.475 1st Quartile 2nd Quartile 3rd Quartile 4th Quartile Source: Oliver Wyman Benchmarking Study (July 2009) Consumers Energy Movement from 2008 Study

New Investment Plan Utility Investment Drives . . . . . . . . EPS growth at responsible rates. Investment 2010-14 (mils) Base capital $ 4,390 Choices in Plan Renewables $ 900 Smart Grid 650 Gas compression and pipelines 250 Electric generation 250 Electric reliability and other environmental 800 Total Choices in Plan $ 2,850 Total Capital 2010-14 $ 7,240 2008 2009 2010 2011 2012 2013 2014 Depreciation 7.851 8.729 9.2 8.814 8.482 7.999 7.577 7.077 Maintenance 0.583 1.162 1.753 2.342 2.951 Customer growth 0.055 0.112 0.171 0.234 0.301 Environmental 0.106 0.238 0.418 0.685 0.988 Electric generation 0 0 0.031 0.114 0.208 Gas compression and pipelines 0.076 0.155 0.217 0.252 0.275 Energy optimization 0 0.025 0.083 0.15 0.219 Electric reliability and other environmental 0.059 0.168 0.339 0.539 0.737 Smart Grid 0.056 0.144 0.232 0.385 0.578 Renewables 0.02 0.066 0.216 0.416 0.7 6%-8% Bils $ Present Rate Base 2009 2010 2011 2012 2013 2014 Average Rate Base (bils) $9.8 $10.5 $11.4 $12.5 $13.8 0 Rate Base

Balanced Energy Plan Diverse and balanced plan 935 MW natural gas plant purchased in 2008 Energy efficiency reduction of 5.5% by 2015 Incentive achieved in 2009 - $6 million 10% Renewable portfolio standard by 2015 New clean coal plant (deferred)

What's Changed? Peak Demand Long-Term Gas Prices EGAA Current Outlook 2009 9398 8384 2010 9513 8443 2011 9700 8577 2012 9783 8772 2013 9819 8924 2014 9889 9022 2015 10014 9161 2016 10076 9295 2017 10099 9378 2018 10123 9484 2019 10143 9571 2020 10160 9631 2021 10177 9667 2022 10192 9719 2023 10209 9808 2024 10229 9883 2025 10249 9937 2026 10272 9973 2027 10296 10026 2028 10320 10077 2029 10345 10125 2030 10376 10174 2031 10222 2032 10268 2033 10313 2034 10376 2035 10417 2036 10458 2037 10500 2038 10521 2039 10542 2040 10563 MW 0 Present Outlook Air Permit Peak demand down 700 MWs by 2017; "shale" gas lower price. 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 EGAA 9.03475 7.091 7.862 8.013 7.951 7.933 8.48 9.02 9.563 9.997 10.473 11.058 11.788 12.541 13.474 14.344 15.011 15.788 Current Outlook 9.03475 3.99 4.26 5.21 5.65 5.95 6.25 6.57 6.94 7.32 7.7 7.99 8.23 8.48 8.75 8.98 9.18 9.46 Henry Hub Actuals 1.532583333 1.797666667 2.143333333 1.900583333 1.635583333 2.590833333 2.58725 2.10825 2.267833333 3.885666667 4.272666667 3.221166667 5.387916667 6.137583333 8.615666667 7.226333333 6.86025 9.03475 3.99 MMBtu $ Present Outlook (down 33%) Air Permit Actual

Capacity Fuel Mix (2018) With New Coal Plant New Plan With or without new coal plant projected fuel mix balanced.

Renewables - Build Lake Winds Energy Park Cross Winds Energy Park Michigan energy law renewables requirements 10 percent energy, 500 MW of new capacity by 2015 Purchase 50 percent and build 50 percent MPSC approved Renewable Plan (May 2009) Annual surcharge in place (Sept 2009) Lake Winds Energy Park 2012 - 100 MW "build" Cross Winds Energy Park 500 MW potential First wind farm construction authorized; PPAs underway.

Electricity Cost / Disposable Income Highest 25 States - 3.1% - 5.4% Source: Moody's Global Infrastructure - U.S. Regulated Electric Utilities - July 2009 Michigan among the lowest 10 states in terms of electricity cost. State % National Average CO 1.8 UT 2.1 MN 2.3 NM 2.3 WA 2.3 WY 2.4 NH 2.4 ID 2.4 MI 2.4 CA 2.6 IL 2.6 WI 2.6 KS 2.7 RI 2.7 NE 2.7 AK 2.7 OR 2.8 MT 2.8 ND 2.9 DC 2.9 NJ 2.9 IA 2.9 SD 3 MA 3 VT 3 VA 3.1 OH 3.1 WV 3.1 ME 3.1 IN 3.2 MS 3.2 MD 3.4 PA 3.4 NY 3.6 NV 3.7 OK 3.7 GA 3.8 KY 3.9 CT 3.9 DE 4 AZ 4 AR 4.1 HI 4.2 NC 4.2 SC 4.3 TN 4.4 FL 4.9 AL 4.9 LA 5 TX 5.2 MS 5.4 National Average 3.4% Lowest 25 States - 1.8% - 3.0% Lowest 10 States 1.8% - 2.6%

Risk Mitigation through 2008 Energy Law Supply Renewable energy plan Energy optimization Certificate of Necessity process Retail open access cap Ratemaking File and implement ratemaking Forward test year Decoupling Uncollectibles tracker ? ? ? ? ? ? Law Implementation ? ? ? ? ? ? Law mitigated several key risks. Implementation underway. ? ? ? ?

Utility Risk Mitigation . . . . Electric Gas Revenue 0.6 0.4 Sales $6.3 Billion $5.6 Billion Interest expense 5% Tree trimming and UAs "Tracked" . . . . enhanced with decoupling and new electric "UA" tracker. Decoupled Efficiency Economy Weather Cost Fuel 62% O&M & other 21% Investment 11% "Pass Thru" Decoupled Efficiency Economy

Regulatory Timeline Second year under new, comprehensive Michigan energy law. 2009 2010 2010 2010 2010 2010 2010 2010 2010 2011 Fourth Quarter Fourth Quarter First Quarter Second Quarter Third Quarter Fourth Quarter Fourth Quarter First Quarter Gas Rate Case U-15986 Self-implemented $89 M Self-implemented $89 M Final Order May $66 M Electric General Rate Case U-16191 Filed $178 M Filed $178 M Self-implement July Final Order January Big Rock Point U-15611 $85 M refund $85 M refund $85 M refund $85 M refund "Show Cause" U-16113 (forestry and O&M in 2007) MPSC Staff $27 M refund ALJ PFD "no refund" MPSC Staff $27 M refund ALJ PFD "no refund" Electric Decoupling Reconciliation U-15645 File "Cushion"

Key Takeaways . . . . . . . . continued track record of strong results. Utility investment - visible: EPS growth of 6%-8% annually Operating cash flow growth of ^$100 million annually NOLs - avoid new equity near term Regulatory framework -- constructive Risks -- mitigated Dividend payout ratio -- growing

Appendix

ELECTRIC RATE CASE U-16191*

On January 22, 2010, Consumers Energy filed an application with the Michigan Public Service Commission seeking an increase in its electric generation and distribution rates based on a June 2011 test year. The request seeks authority to recover new investment in system reliability, environmental compliance and technology enhancements. These investments are part of the Company’s Growing Forward strategy which calls for investing more than $6 billion in utility operations over the next five years. The proposed overall rate of return is based on an 11.0% authorized return on equity. If approved, the request would increase customer rates by an average of 5.2%. The $178 million request is detailed below.

Item	$ Millions		Explanation
1. O&M	$	49	Generation reliability and environmental: $25
			Technology: $24
2. Gross Margin		5	Reduced third-party revenues; lower sales will be addressed in sales decoupling mechanism.
3. Investment		106	Net plant (distribution and generation reliability, environmental and technology): $72
			Working capital: $29
			Depreciation and property taxes: $21
			DOE Liability: ($5)
			Taxes, AFUDC, and other: ($11)
4. Cost of Capital		18	Higher return on equity (11% vs. 10.7%): $12
			Other capitalization costs: $6
Total	$	178

Ratemaking	Existing			As Filed						After-Tax
Capital Structure	(U-15645)			Percent of Total			Annual Cost			Weighted Costs
Long Term Debt		44.80	%		41.77	%		5.92	%		2.47	%
Short Term Debt		0.78			1.51			3.96			0.06
Preferred Stock		0.48			0.44			4.46			0.02
Common Equity		40.51			41.49	(1)		11.00			4.56
Deferred FIT		12.80			14.26			0.00			0.00
JDITC/Other		0.63			0.53			8.50			0.05
		100.00	%		100.00	%					7.16	%(2)

	Existing
Rate Base and Return	(U-15645)			As Filed
Rate Base ($ billions)	$	6.16		$	6.97
Return on Rate Base		6.98	%		7.16	%
Return on Equity		10.70	%		11.00	%

(1)	Equivalent to 49.57% on a financial basis.
(2)	Equivalent to 10.10% pre-tax basis.

ELECTRIC RATE CASE SCHEDULE

Staff & Intervenors File Testimony	June 10, 2010
Consumers Files Self-implementation Rates	June 28, 2010
Rebuttal Testimony	July 1, 2010
Motions to Strike Testimony	July 8, 2010
Replies to Motions to Strike	July 13, 2010
Self-implementation Under PA 286	July 22, 2010
Cross of all Witnesses	July 15-28, 2010
Initial Briefs	August 26, 2010
Reply Briefs	September 16, 2010
Proposal for Decision	November 1, 2010
Commission Order	By January 21, 2011

* Electric Rate Case U-16191 can be accessed at the Michigan Public Service Commission’s website.

http://efile.mpsc.cis.state.mi.us/efile/electric.html

Appendix 1

GAS RATE CASE U-15986*

On May 17, 2010, the Michigan Public Service Commission (MPSC) issued its final order in Consumers Energy’s Gas Rate Case U-15986, authorizing Consumers to increase its base gas rates by $66 million annually with an authorized ROE of 10.55%. The MPSC approved a sales decoupling mechanism, but did not approve trackers for uncollectibles expense or pension and OPEB expenses. On November 19, 2009, the Company self implemented an $89 million annual rate increase. As a result of the final order, the $23 million annual reduction will be refunded to customers later this year. Compared to rates that were implemented last November, the revenue decrease will reduce the residential class rates by 1.2%. A typical residential customer’s average monthly winter bill will be reduced by about $1 per month.

	Company		MPSC
	Self		Final			B/W Than
	Implement		Order			Self Implement
Item	(mils)		(mils)			(mils)			Explanation of Variance
1. O&M	$	17	$	13		$	(4	)	Uncollectible accounts expense: $(4)
									Standard retirement units: $7
									Corporate: $(3); outside services
									Manufactured gas plant (MGP) amortization: $(4)
									(shift from O&M to capital)
2. Sales		41		28			(13	)	Higher throughput: $(11); (283 Bcf vs. 272 Bcf)
									Miscellaneous revenues: $(2)
3. Investment		23		27			4		Net Plant: $(2); (reduced AMI investment)
									Depreciation expense and taxes: $2
									MGP amortization: $4
4. Cost of Capital		8		(2	)		(10	)	Lower return on equity: $(8); (10.55% vs. 11.00%)
									Lower debt costs: $(2)
Total	$	89	$	66		$	(23	)

Ratemaking	Existing			Company Self			MPSC
Capital Structure	(U-15506)			Implement			Final Order
Long Term Debt		42.71	%		43.43	%		43.58	%
Short Term Debt		0.66			0.58			0.59
Preferred Stock		0.49			0.46			0.46
Common Equity		41.78			41.07	(1)		40.78	(2)
Deferred Taxes		12.94			13.17			13.30
JDITC/Other		1.42			1.29			1.29
		100.00	%		100.00	%		100.00	%

Rate Base and Return	Existing			Company			MPSC
Percentage	(U-15506)			Self Implement			Final Order
Rate Base ($ billions)	$	2.52		$	2.76		$	2.74
Return on Rate Base		7.03	%		7.28	%		7.02	%
Return on Equity		10.55	%		11.00	%		10.55	%

(1)	Equivalent to 48.34% on a financial basis.
(2)	Equivalent to 48.07% on a financial basis.
*	Gas Rate Case U-15986 can be accessed at the Michigan Public Service Commission’s website.

http://efile.mpsc.cis.state.mi.us/efile/gas.html

Appendix 2

Federal Tax Benefits Appendix 3 Year-End Actual Estimate 2009 2010 2011 2012 (bils) (bils) (bils) (bils) Gross NOL carry forwards $ 1.3 $ .7 $ .2 $ 0 Net NOL cash benefit at 35% $ .5 $ .2 $ .1 0 Credit carry forwards .3 .3 .3 .2 Remaining cash benefit $ .8 $ .5 $ .4 $.2

Sales Decoupling (Residential) First Quarter Approved Rate Case Actual Decoupling Surcharge Average monthly sales per customer (kWh) 745 - 723 = (22) Number of customers (mils) 1.6 x 1.6 Average margin per kWh 6¢ x 6¢ Number of months x 3 Surcharge (mils) = $6 First Quarter electric sales lower than rate case levels - resulting in a surcharge. Appendix 4

Sales and Decoupling ? Appendix 5

Retail Open Access Retail Open Access Higher ROA load reduced EPS by about 5¢ in the First Quarter of 2010. First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter 4 5.2 6.1 8.4 10 10 10 10 10 10 % of Total 2010 2009 10% First Quarter Second Quarter Third Quarter Fourth Quarter First Quarter 3185 3160 3204 2865 2607 "Bundled" Customer Demand a MW 2010 2009 (5)¢ Cap _ _ _ _ _ a Industrial and commercial 4% Appendix 6

MATURITY SCHEDULE OF CMS AND CECO LONG-TERM DEBT & PREFERRED SECURITIES
AS OF 05/31/2010
Reflects 5/15/10 maturity of $250MM FMBs (CECo)

		Maturity	Amount
F/V	S/U	or Call Date	(000’s)			DEBT/ CO
SHORT-TERM DEBT:
F	S	06/15/10	$	30,000		3.375% Fixed PCRBs (CECo)
F	S	06/15/10		27,900		4.25% PCRBs (CECo)
F	U	08/01/10		67,291		7.75% Sr Unsec Notes (CMS)
F	U	04/15/11		213,653		8.5% Sr Notes (CMS)
F	U	SHORT-TERM		139,730		*3.375% Convertible Sr Notes Put Date (CMS)
			$	478,574
LONG-TERM DEBT:
F	U	12/01/11	$	287,500		*2.875% Convertible Sr Unsec Notes Put Date (CMS)
				287,500
F	U	02/01/12	$	150,000		6.3% Senior Notes (CMS)
F	S	02/15/12		300,000		5% Series L FMBs (CECo)
			$	450,000
V	U	01/15/13	$	150,000		Floating Rate Sr Notes (CMS)
F	S	04/15/13		375,000		5.375% Series B FMBs (CECo)
			$	525,000
F	S	02/15/14	$	200,000		6% FMBs (CECo)
F	U	06/15/14		172,500		5.5% Convertible Sr Notes Put Date (CMS)
F	S	03/15/15		225,000		5% FMBs Series N (CECo)
F	U	12/15/15		125,000		6.875% Sr Notes (CMS)
F	S	08/15/16		350,000		5.5% Series M FMBs (CECo)
F	S	02/15/17		250,000		5.15% FMBs (CECo)
F	U	07/17/17		250,000		6.55% Sr Notes (CMS)
F	S	03/01/18		180,000		6.875% Sr Notes (CECo)
V	S	04/15/18		67,700		VRDBs to replace PCRBs (CECo)
F	S	09/15/18		250,000		5.65% FMBs (CECo)
F	S	03/15/19		350,000		6.125% FMBs (CECo)
F	U	06/15/19		300,000		8.75% Sr Notes (CMS)
F	S	09/15/19		500,000		6.70% FMBs (CECo)
F	U	2/1/2020		300,000		6.25% Sr Notes (CMS)
F	S	04/15/20		300,000		5.65% FMBs (CECo)
F	U	07/15/27		28,667		QUIPS 7.75%(CMS) Pref Sec
V	S	04/01/35		35,000		PCRBs (CECo)
F	S	04/15/35		137,239		5.65% FMBs IQ Notes (CECo)
F	S	09/15/35		175,000		5.80% FMBs (CECo)
			$	4,196,106
			$	5,937,180		SUBTOTAL
			$	5,908,513		SUBTOTAL EXCLUDING PREFERRED SECURITIES
		Various Maturity Dates/No Maturity Date Available:
			$	226,176		CECo Securitization Bonds (Long-Term & Short-Term) after 04/20/10 payment
				227,118		CECo Capital lease rental commitments (Long-Term & Short-Term) as of 03/31/10
				162,880		CECo DOE Liability as of 05/31/10
				239,698		EnerBank (Long-Term & Short-Term) Discount Brokered CDs as of 03/31/10 (CMS)
				(36,048	)	CMS Net unamortized discount as of 03/31/10
				(4,727	)	CECo Net unamortized discount as of 03/31/10
			$	6,752,276		GRAND TOTAL INCLUDING CMS ENERGY, CONSUMERS & OTHER CMS
						ENTERPRISES SUBSIDIARIES, INCLUDING PREFERRED SECURITIES

* — Date that issue can be put to the Company is used instead of maturity date

Status Codes: F-Fixed rate; V-Variable rate; S-Secured; U-Unsecured

Appendix 7

Fact Sheets

Consumers Electric Utility
Financial & Operating Statistics

Years Ended December 31	2009			2008			2007			2006			2005
ELECTRIC REVENUE AND POWER COSTS (Millions)
Residential	$	1,387		$	1,414		$	1,326		$	1,279		$	1,069
Commercial		1,099			1,129			1,111			1,062			878
Industrial		677			810			775			764			553
Other		36			32			30			29			26
Total revenue from customers	$	3,199		$	3,385		$	3,242		$	3,134		$	2,526
Wholesale		19			22			23			22			18
Intersystem		94			113			92			45			46
Retail open access/direct access		31			15			15			17			28
Miscellaneous		64			59			71			84			83
Total electric utility revenue	$	3,407		$	3,594		$	3,443		$	3,302		$	2,701
Fuel for electric generation	$	460		$	483		$	385		$	436		$	464
Purchased and interchange power		1,232			1,388			1,449			1,135			818
DEPRECIATION AND AMORTIZATION	$	441		$	438		$	397		$	380		$	292
OPERATING INCOME (Millions)	$	488		$	576		$	413		$	411		$	342
NET INCOME (Millions)	$	194		$	271		$	196		$	199		$	153
DELIVERIES (Million kWhs)
System sales
Residential		12,386			12,854			13,206			12,975			13,286
Commercial		11,211			11,969			12,384			12,199			11,221
Industrial		9,290			10,563			11,153			11,143			9,685
Other		230			225			231			227			229
Total sales to ultimate customers		33,117			35,611			36,974			36,544			34,421
Wholesale		328			333			496			498			468
Retail open access/direct access		2,326			1,541			1,364			1,455			4,056
Intersystem		1,277			1,176			1,329			814			3,624
Total electric system deliveries		37,048			38,661			40,163			39,311			42,569
AVERAGE ELECTRIC REVENUE (¢/kWh)
Residential		11.20			11.00			10.04			9.86			8.05
Commerical		9.80			9.43			8.98			8.71			7.82
Industrial		7.29			7.67			6.95			6.86			5.70
Other		15.65			14.22			12.99			12.78			11.45
Total		9.66			9.51			8.77			8.58			7.34
ELECTRIC CUSTOMERS BILLED (At December 31)
Residential		1,566,980			1,584,752			1,575,386			1,570,113			1,565,601
Commercial		210,223			208,931			211,365			211,718			211,273
Industrial		8,770			8,505			8,619			8,638			8,595
Retail Open Access/Direct Access		861			642			642			839			1,307
Other		1,282			2,045			2,025			2,009			1,972
Total		1,788,116			1,804,875			1,798,037			1,793,317			1,788,748
AUTHORIZED RETURN ON EQUITY		10.70	%		10.70	%		11.15	%		11.15	%		11.15	%
EARNED RETURN ON EQUITY-FINANCIAL		6.4%	1		9.4	%		7.5	%		8.9	%		8.0	%
RATE BASE (At December 31) ($ Millions)	$	6,549		$	6,175		$	5,407		$	5,088		$	4,839
COOLING DEGREE DAYS
Normal degree days in calendar year		558			558			558			558			558
Actual degree days		379			542			773			613			916
Percent warmer (colder) than normal		(32.1	)		(2.9	)		38.5			9.9			64.2
Increase (decrease) from normal in:
Electric deliveries (millions of kWh)		(461	)		146			736			118			1,359
EPS	$	(0.09	)	$	0.02		$	0.09		$	0.01		$	0.14

¹ 9.1% excluding Big Rock Decommissioning refund

CMS Energy Investor Relations One Energy Plaza, Jackson, MI 49201 Tel. 517-788-2590 http://www.cmsenergy.com

Consumers Electric Utility
Supplemental Operating Statistics

Years Ended December 31	2009					2008					2007					2006					2005
FUEL COST ($/MMBtu)
Coal		2.37					2.01					2.04					2.09					1.78
Oil		9.59					11.54					8.21					8.68					5.98
Gas		6.57					10.94					10.29					8.92					9.76
Nuclear		0.00					0.00					0.42					0.24					0.34
Weighted average for all fuels		2.56					2.47					2.07					1.72					1.64
FUEL COST FOR GENERATION (%)
Coal		90.6					81.0					97.9					88.2					76.6
Oil and gas		2.5					4.1					9.1					6.7					14.4
Nuclear		0.0					0.0					2.2					3.7					5.4
Combustion turbine		6.8					14.6					0.9					0.8					1.8
Nox allowances		0.1					0.3					(10.2	)				0.6					1.8
POWER GENERATED (Millions of kWhs)
Coal		17,255		47.3	%		17,701		45.5	%		17,903		44.3	%		17,744		44.6	%		19,711		65.8	%
Nuclear		0		0.0	%		0		0.0	%		1,781		4.4	%		5,904		14.9	%		6,636		18.7	%
Oil		14		0.0	%		41		0.1	%		112		0.3	%		48		0.1	%		225		0.7	%
Gas		565		1.5	%		804		2.1	%		129		0.3	%		161		0.4	%		356		0.1	%
Hydro		466		1.3	%		454		1.2	%		416		1.0	%		485		1.2	%		387		1.6	%
Net pumped storage (a)		(303	)	-0.8	%		(382	)	-1.0	%		(478	)	-1.2	%		(426	)	-1.1	%		(516	)	-1.9	%
Total net generation		17,997		49.4	%		18,618		47.8	%		19,863		49.2	%		23,916		60.2	%		26,799		84.9	%
Purchased and interchange:
Non-utility generation		11,538		31.6	%		13,643		35.1	%		12,502		31.0	%		8,594		21.6	%		8,999		3.6	%
Net interchange power		6,925		19.0	%		6,653		17.1	%		8,009		19.8	%		7,244		18.2	%		1,772		11.5	%
Total net purchased and interchange power		18,463		50.6	%		20,296		52.2	%		20,511		50.8	%		15,838		39.8	%		10,771		15.1	%
Total net power supply		36,460		100.0	%		38,914		100.0	%		40,374		100.0	%		39,754		100.0	%		37,570		100.0	%
NET DEMONSTRATED CAPABILITY (MW) AT PEAK / POWER SOURCE (%)
Coal		2,850		31.8	%		2,850		29.7	%		2,841		30.5	%		2,841		30.9	%		2,837		31.8	%
Oil and gas		1,814		20.3	%		1,997		29.7	%		1,459		15.7	%		1,459		15.8	%		1,459		16.4	%
Nuclear		0		0.0	%		0		0.0	%		0		0.0	%		778		0.0	%		778		0.0	%
Combustion turbine		661		7.4	%		661		6.9	%		345		3.7	%		345		3.7	%		332		3.9	%
Hydro		74		0.8	%		73		0.8	%		73		0.8	%		74		0.8	%		74		0.8	%
Pumped storage		955		10.7	%		955		10.0	%		955		10.3	%		955		10.4	%		955		10.7	%
Total owned generation		6,354		71.0	%		6,536		68.2	%		5,673		61.0	%		6,452		70.1	%		6,435		72.2	%
Plus P&I power capability		2,600		29.0	%		3,050		31.8	%		3,627		39.0	%		2,756		29.9	%		2,516		27.8	%
Total owned and P&I		8,954		100.0	%		9,586		100.0	%		9,300		100.0	%		9,208		100.0	%		8,951		100.0	%
Peak load (MW) (b)		7,421					7,488					8,183					8,657					7,845
Reserve capacity (%)		17.0					22.0					12.0					6.0					12.4
Nameplate generating capacity (MW) at peak		6,784					6,784					6,784					6,784					6,784
Load factor (b)		55.9					59.2					56.3					52.4					54.7
Heat rate-average Btu of fuel per net kWh generated		9,522					10,201					10,198					10,123					10,088

(a)	Consumers’ portion of the Ludington pumped storage facility.
(b)	Excluding Retail Open Access loads.

CMS Energy Investor Relations One Energy Plaza, Jackson, MI 49201 Tel. 517-788-2590 http://www.cmsenergy.com

Consumers Gas Utility
Financial & Operating Statistics

	2009			2008			2007			2006			2005
GAS REVENUE AND COST OF GAS ($ Millions)
Residential	$	1,808		$	1,971		$	1,823		$	1,646		$	1,742
Commercial		511			598			552			498			510
Industrial		101			124			113			111			116
Other		3			5			6			4			9
Total sales revenue	$	2,423		$	2,698		$	2,494		$	2,259		$	2,377
Transportation fees		48			45			44			40			43
Miscellaneous		85			84			83			75			63
Total gas utility revenue	$	2,556		$	2,827		$	2,621		$	2,374		$	2,483
Cost of gas sold		1,778			2,079			1,918			1,770			1,844
Gas utility revenue net of cost of gas	$	778		$	748		$	703		$	604		$	639
DEPRECIATION, DEPLETION AND AMORTIZATION	$	118		$	136		$	127		$	122		$	117
OPERATING INCOME	$	201		$	190		$	170		$	113		$	151
NET INCOME	$	96		$	89		$	87		$	37		$	48
SALES AND DELIVERIES (Bcf)
Residential		163			171			167			154			176
Commercial		52			57			55			50			57
Industrial		11			12			12			12			13
Other		—			—			—			—			1
Total gas sales (1)		226			240			234			216			247
Gas transportation deliveries		93			98			107			92			103
Total gas sales and transportation deliveries		319			338			341			308			350
GAS CUSTOMERS BILLED (at December 31)
Residential		1,574,246			1,577,863			1,580,586			1,584,666			1,577,358
Commercial		118,199			118,870			119,703			119,936			121,314
Industrial		7,073			6,961			7,014			6,982			7,081
Transportation		2,725			2,507			2,495			2,483			2,567
Total customers		1,702,243			1,706,201			1,709,798			1,714,067			1,708,320
AVERAGE GAS REVENUE ($ per Mcf)
Residential	$	11.09		$	11.53		$	10.93		$	10.70		$	9.89
Commercial		9.83			10.49			10.09			9.87			8.96
Industrial		9.18			10.33			9.62			9.45			8.68
Transportation (2)		0.82			0.70			0.68			0.61			0.61
GAS SUPPLY (MMcf)
Gas Cost Recovery		206,866			208,296			216,843			207,223			236,978
Gas Customer Choice		31,498			24,177			19,520			15,915			13,989
Total		238,364			232,473			236,363			223,138			250,967
AVERAGE COST OF GAS SOLD ($ per Mcf) (3)
Gas Cost Recovery	$	7.66		$	8.36		$	7.91		$	8.03		$	7.47
Gas Customer Choice		7.98			9.99			9.79			8.94			6.75
AUTHORIZED RETURN ON EQUITY		10.6	%		10.55	%		10.75	%		11.0	%		11.4	%
RATE BASE (at December 31) ($ Millions)	$	2,778		$	2,638		$	2,444		$	2,446		$	2,226
EARNED RETURN ON EQUITY-FINANCIAL		9.9%	4		9.2	%		9.2	%		4.4	%		7.0	%
HEATING DEGREE DAYS
Normal degree days in calendar year		7,098			7,098			7,098			7,098			7,098
Actual degree days		6,815			6,917			6,561			6,119			6,557
Percent colder (warmer) than normal		(4.0	)		(2.6	)		(7.6	)		(13.8	)		(7.6	)
Increase (decrease) from normal in:
Gas deliveries (Bcf)		(0.9	)		4.1			(6.3	)		(30.2	)		(7.4	)
EPS	$	(0.01	)	$	0.02		$	(0.03	)	$	(0.12	)	$	(0.03	)

(1)	Includes Gas Customer Choice sales.
(2)	Average gas revenue for transportation excludes amounts related to MCV and off-system transportation.
(3)	Includes pipeline transportation charges.
(4)	Rate is reflective of exceptionally warm weather

CMS Energy Investor Relations One Energy Plaza, Jackson, MI 49201 Tel. 517-788-2590 http://www.cmsenergy.com

Independent Power Production
Asset List

		Gross				Primary				Percentage of Gross
		Capacity		CMS		Fuel		In-Service		Capacity Under Long-
No.	Project Name	MW		MW		Type	Location	Date		Term Contract
										(%)
Projects in Operation:
* 1	Craven		50		25	Biomass	N. Carolina		1990		0
* 2	DIG		710		710	Natural Gas	Michigan		2001		92
* 3	Exeter		31		31	Tires	Connecticut		1991		0
* 4	Filer City		73		37	Coal/Wood Waste	Michigan		1990		100
* 5	Genesee		38		19	Biomass	Michigan		1996		100
* 6	Grayling		40		20	Biomass	Michigan		1992		100
* 7	Michigan Power		224		224	Natural Gas	Michigan		1999		0
Projects in Operation			1,166		1,066

* Operated by CMS Energy
As of June 2010

     

CMS Energy Investor Relations One Energy Plaza, Jackson, MI 49201 Tel. 517-788-2590 http://www.cmsenergy.com