exv99w1

EX-99.1 2 k47897exv99w1.htm EX-99.1 exv99w1

Exhibit 99.1

Growing Forward EEI Finance Committee May 20, 2009

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" each found in the MANAGEMENT'S DISCUSSION AND ANALYSIS 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 2009 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.

Consistent financial performance Fair and timely regulation Utility investment Customer value Safe, excellent operations 2 Long-term Objectives

Consumers Energy Overview Excellent operations Customer value Investment Responsible rate increases Healthy capital structure Fair and timely regulation Consistent strong financial performance 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 New coal plant Focus Territory Investment growth balances responsible rate increases and healthy capital structure with attractive earnings growth.

Regulatory Update Renewable Energy Plan Capital investment over $1 billion Annual surcharge $85-$90 million Order expected in May Energy Optimization Plan Investment $.5 billion Annual surcharge $90 million Order expected in May Gas Rate Case Filing expected in May Electric Rate Case Filed November 14, 2008 Self-implemented $179 million on May 14 Electric Rate Case Comparison Filings Filings support balance of customer interest and investor certainty.

Electric Rate Case Rebuttal Testimony Filed Cross Examination June PFD Target Date September 2 MPSC Final Order mid-November Rate increase (with decommissioning refund and "deskewing") 3.5% for residential and 0.4% decrease for industrial. Self Implementation Next Steps Residential customer rates reduced by $36 million during self-implementation period Use "deskewing" rate design filed in November

Oct-07 Nov-07 Dec-07 Jan-08 Feb-08 Mar-08 Apr-08 May-08 Jun-08 Jul-08 Aug-08 Sep-08 Oct-08 Nov-08 Dec-08 Jan-09 Feb- 09 Mar-09 Regulatory Timeline November December April May June September November Electric Rate Case U-15645 Filed Staff and intervenors file Rebuttals Self implemented Cross examination PFD target date Final order New Gas General Rate Case To Be Filed Self implement 2008 2009 Legislation provides for more timely rate relief.

Sales and Unemployment Electric Sales (weather adjusted) Sales decline still similar to recession in early 1980s; unemployment varies across the state. Michigan Unemployment 2009 1975 1986 1997 2008 (7)% Decline over three years ('79 -'82 recession) 2008 2009 (3)% 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 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 36536 Revised Potential 37339 36208 0 Electric Gas Combination Midland 10% Flint 15% Detroit 23% Grand Rapids 11% Kalamazoo 10% Budget (2)% New Forecast (3)%

Full Year Forecast Industrial Sales by Quarter Prior Present Fourth 2008 -2 2009 Budget -3 -5 2009 Forecast First Quarter sales were equal to budget. Forecast industrial sales, however, revised downward. 2008 2009 Budget 2009 Forecast -2 First -11 0 -3 Second -10 -5 0 -5 Third -6 -5 0 -6 Fourth -5 First Second Third Fourth (all customers) Full Year 2009 Forecast -11% 2009 Budget - 7 2008 - 4 2009 Electric Sales Outlook a (vs. prior year) _ _ _ _ a Weather adjusted

Uncollectible Accounts An "auto-wide" bankruptcy would have an incremental "one time write off" impact. Utility Uncollectible Accounts Millions $ 2007 2008 2009 Bankruptcies 2.6 2.6 5 2009 Budget 29.4 43.4 43 2009 Forecast 0 0 10 Pct of Revenue 0.5% 0.7% 0.9% "Auto-wide" Bankruptcy Exposure "SAP"

Diversified Customer Base Hemlock Semiconductor General Motors Delphi Corporation Pfizer Incorporated Meijer Incorporated State of Michigan Quanex Corporation Packaging Corporation of America Dow Corning Corporation Denso International Percent of 2008 total Company 3% Top Ten Customers 2008 Gross Margin Residential Commercial Autos Industrial Other 0.48 0.33 0.03 0.15 0.01 $1.6 Billion

BEI - Electric Resource Plan (Peak Load) 0 Generation gap needs to be addressed. Existing generation and long-term purchases

Balanced Energy Plan Summary Extensive analysis of alternatives and risks Diverse and balanced plan Meets 10% renewable portfolio standard by 2015 Meets energy efficiency target of 5.5% by 2015 Includes demand management programs Purchase of Zeeland natural gas plant Build new clean coal facility Renewables (Nominal) Energy Efficiency and Demand Management Clean Coal Gas Combined Cycle 32 31 18 19 New Resources 2008 - 2018 New generation from diversified fuel sources.

2008 2009 2010 2011 2012 2031 Depreciation 7.851 8.729 8.486 7.922 7.592 7.123 6.597 Maintenance 0.574 1.132 1.644 2.117 2.616 Customer growth 0.077 0.156 0.244 0.337 0.431 Environmental 0.057 0.19 0.341 0.501 0.797 Zeeland plant 0.481 0.481 0.481 0.481 0.481 Gas compression and pipelines 0.064 0.143 0.211 0.279 0.342 Electric reliability and other 0.022 0.077 0.137 0.254 0.444 Renewables 0.005 0.023 0.039 0.122 0.26 AMI 0.006 0.011 0.019 0.095 0.348 Clean coal plant 0.029 0.096 0.238 0.408 0.556 7% Utility Growth Rate Base Bils $ Present Rate Base 2008 2009 2010 2011 2012 2013 Average Rate Base (bils) $9.3 $9.7 $10.5 $11.2 $12.4 New investment based on balancing responsible rate increases, strong capital structure, as well as earnings and cash flow growth. 0 Investment 2009-13 (mils) Base capital $ 3,950 Choices in Plan Clean coal plant $ 530 ? AMI 620 Renewables 310 Electric reliability and other 550 Gas compression and pipelines 340 Total Choices in Plan $ 2,350 Total Capital 2009-13 $ 6,300 Examples of Coal Plant Alternative Plant life extensions/new gas generation $200 Accelerated wind investment 250 Reliability 75 Total $525 ? Investment Plan

What Makes CMS Different? Recent State legislation provides framework for growth Diversified Utility investment opportunities boost rate base and EPS Solid liquidity position, no need to issue equity in near term NOL and AMT credits add value Track record of predictability

Appendix

RATE BASE (At December 31) ($ Millions)) 2008 2007 2006 2005 2004 —— —— —— —— —— — ELECTRIC REVENUE AND POWER COSTS (Millions) Residential $ 1,414 $ 1,326 $ 1,279 $ 1,069 $ 996 Commercial 1,129 1,111 1,062 878 814 Industrial 810 775 764 553 523 Other 32 30 29 26 27 Total revenue from ultimate customers $ 3,385 $ 3,242 $ 3,134 $ 2,526 $ 2,360 Wholesale 22 23 22 18 17 Intersystem 113 92 45 46 100 Retail open access/direct access 15 15 17 28 28 Miscellaneous 59 71 84 83 81 Total electric utility revenue $ 3,594 $ 3,443 $ 3,302 $ 2,701 $ 2,586 Fuel for electric generation $ 483 $ 385 $ 436 $ 464 $ 319 Purchased and interchange power 1,388 1,449 1,135 818 893 DEPRECIATION AND AMORTIZATION $ 438 $ 397 $ 380 $ 292 $ 189 OPERATING INCOME (Millions) $ 576 $ 413 $ 411 $ 342 $ 424 NET INCOME (Millions) $ 271 $ 196 $ 199 $ 153 $ 222 DELIVERIES (Million kWhs) System sales Residential 12,854 13,206 12,975 13,286 12,346 Commercial 11,969 12,384 12,199 11,221 10,785 Industrial 10,563 11,153 11,143 9,685 9,678 Other 225 231 227 229 230 Total sales to ultimate customers 35,611 36,974 36,544 34,421 33,039 Wholesale 333 496 498 468 461 Retail open access/direct access 1,541 1,364 1,455 4,056 4,152 Intersystem 1,176 1,329 814 3,624 2,481 Total electric system deliveries 38,661 40,163 39,311 42,569 40,133 AVERAGE ELECTRIC REVENUE (¢/kWh) Residential 11.00 10.04 9.86 8.05 8.07 Commerical 9.43 8.98 8.71 7.82 7.55 Industrial 7.67 6.95 6.86 5.70 5.39 Other 14.22 12.99 12.78 11.45 11.38 Total 9.51 8.77 8.58 7.34 7.14 ELECTRIC CUSTOMERS BILLED (At December 31) Residential 1,584,752 1,575,386 1,570,113 1,565,601 1,550,298 Commercial 208,931 211,365 211,718 211,273 210,623 Industrial 8,505 8,619 8,638 8,595 8,411 Retail Open Access/Direct Access 642 642 839 1,307 1,404 Other 2,045 2,025 2,009 1,972 1,195 Total 1,804,875 1,798,037 1,793,317 1,788,748 1,771,931 AUTHORIZED RETURN ON EQUITY 10.70% 11.15% 11.15% 11.15% 12.25% RATE BASE (At December 31) ($ Millions)) $ 6,175 $ 5,407 $ 5,088 $ 4,839 $ 4,681 EARNED RETURN ON EQUITY-RATEMAKING 10.3% 9.4% 12.8% 10.5% 12.9% POWER SOURCES (%) Coal 45.5 42.9 43.7 47.8 48.6 Nuclear 0.0 4.3 14.6 16.1 13.8 Oil 0.1 0.3 0.1 0.5 0.5 Gas 2.1 0.3 0.4 0.9 0.1 Hydro 1.2 1.0 1.2 0.9 1.2 Net pumped storage (Consumers’ portion) (1.1) (1.2) (1.1) (1.3) (1.4) Total net generation 47.8 47.6 59.0 65.0 62.8 Total purchased and interchange 52.2 52.4 41.0 35.0 37.3 COOLING DEGREE DAYS Normal degree days in calendar year 558 558 558 558 558 Actual degree days 542 773 613 916 431 Percent warmer (colder) than normal (2.9) 38.5 9.9 64.2 (22.8) Increase (decrease) from normal in: Electric deliveries (millions of kWh) 146 736 118 1,359 (365) EPS $ 0.02 $ 0.09 $ 0.01 $ 0.14 ($0.05)

Years Ended December 31 2008 2007 2006 2005 2004 —— —— —— —— —— — FUEL COST ($/MMBtu) Coal 2.01 2.04 2.09 1.78 1.43 Oil 11.54 8.21 8.68 5.98 4.68 Gas 10.94 10.29 8.92 9.76 10.07 Nuclear 0.00 0.42 0.24 0.34 0.33 Weighted average for all fuels 2.47 2.07 1.72 1.64 1.26 FUEL COST FOR GENERATION (%) Coal 81.0 97.9 88.2 76.6 86.0 Oil and gas 4.1 9.1 6.7 14.4 6.2 Nuclear 0.0 2.2 3.7 5.4 6.2 Combustion turbine 14.6 0.9 0.8 1.8 0.4 NoX allowances 0.3 (10.2) 0.6 1.8 1.2 POWER GENERATED (Millions of kWhs) Coal 17,701 17,903 17,744 19,711 18,810 Nuclear 0 1,781 5,904 6,636 5,346 Oil 41 112 48 225 193 Gas 804 129 161 356 38 Hydro 454 416 485 387 445 Net pumped storage^(a) (382) (478) (426) (516) (538) Total net generation 18,618 19,863 23,916 26,799 24,294 Purchased and interchange: MCV partnership 0 0 4,779 5,792 10,144 Other affiliates 949 949 992 941 1,017 Non-affiliates and interchange 19,347 20,889 10,882 7,662 3,291 Total purchased and interchange 20,296 21,838 16,653 14,395 14,452 Total generation and purchased 38,914 41,701 40,569 41,194 38,746 NET DEMONSTRATED CAPABILITY (MW) AT PEAK Coal 2,850 2,841 2,841 2,837 2,837 Oil and gas 1,997 1,459 1,459 1,459 1,459 Nuclear 0 0 778 778 767 Combustion turbine 661 345 345 332 345 Hydro 73 73 74 74 73 Pumped storage 955 955 955 955 955 Total owned generation 6,536 5,673 6,452 6,435 6,436 Plus P&I power capability 3,050 3,627 2,756 2,516 2,479 Total owned and P&I 9,586 9,300 9,208 8,951 8,915 Peak load (megawatts)^(b) 7,488 8,183 8,657 7,845 6,956 Nameplate generating capacity (MW) at peak 6,784 6,784 6,784 6,784 6,784 Heat rate-average Btu of fuel per net kWh generated (steam) 10,201 10,198 10,123 10,088 10,099 Load factor ^(b) 59.2 56.3 52.4 54.7 59.3 Reserve capacity (%) 22.0 12.0 6.0 12.4 22.0 —— —— —— —— —— — ^(a)Consumers’ portion of the Ludington pumped storage facility.
^(b)Excluding Retail Open Access loads.

2008 2007 2006 2005 2004 GAS REVENUE AND COST OF GAS ($ Millions) Residential $ 1,971 $ 1,823 $ 1,646 $ 1,742 $ 1,466 Commercial 598 552 498 510 420 Industrial 124 113 111 116 94 Other 5 6 4 9 2 Total sales revenue $ 2,698 $ 2,494 $ 2,259 $ 2,377 $ 1,982 Transportation fees 45 44 40 43 41 Miscellaneous 84 83 75 63 58 Total gas utility revenue $ 2,827 $ 2,621 $ 2,374 $ 2,483 $ 2,081 Cost of gas sold 2,079 1,918 1,770 1,844 1,468 Gas utility revenue net of cost of gas $ 748 $ 703 $ 604 $ 639 $ 613 DEPRECIATION, DEPLETION AND AMORTIZATION $ 136 $ 127 $ 122 $ 117 $ 112 OPERATING INCOME $ 190 $ 170 $ 113 $ 151 $ 178 —— —— —— —— —— — NET INCOME $ 89 $ 87 $ 37 $ 48 $ 71 —— —— —— —— —— — SALES AND DELIVERIES (Bcf) Residential 171 167 154 176 177 Commercial 57 55 50 57 56 Industrial 12 12 12 13 13 Other - - — 1 - Total gas sales (1) 240 234 216 247 246 Gas transportation deliveries 98 107 92 103 139 Total gas sales and transportation deliveries 338 341 308 350 385 —— —— —— —— —— — GAS CUSTOMERS BILLED (at December 31) Residential 1,577,863 1,580,586 1,584,666 1,577,358 1,562,462 Commercial 118,870 119,703 119,936 121,314 118,461 Industrial 6,961 7,014 6,982 7,081 7,145 Transportation 2,507 2,495 2,483 2,567 2,721 Total customers 1,706,201 1,709,798 1,714,067 1,708,320 1,690,789 —— —— —— —— —— — AVERAGE GAS REVENUE ($ per Mcf) Residential $ 11.53 $ 10.93 $ 10.70 $ 9.89 $ 8.31 Commercial 10.49 10.09 9.87 8.96 7.44 Industrial 10.33 9.62 9.45 8.68 6.10 Transportation (2) 0.70 0.68 0.61 0.61 0.57 GAS SUPPLY (MMcf) Gas Cost Recovery 208,296 216,843 207,223 236,978 232,722 Gas Customer Choice 24,177 19,520 15,915 13,989 17,873 Total 232,473 236,363 223,138 250,967 250,595 —— —— —— —— —— — AVERAGE COST OF GAS SOLD ($ per Mcf) (3) Gas Cost Recovery $ 8.36 $ 7.91 $ 8.03 $ 7.47 $ 5.95 Gas Customer Choice 9.99 9.79 8.94 6.75 5.89 AUTHORIZED RETURN ON EQUITY 10.75% 10.75% 11.0% 11.4% 11.4% —— —— —— —— —— — RATE BASE (at December 31) ($ Millions) $ 2,638 $ 2,444 $ 2,446 $ 2,226 $ 2,136 —— —— —— —— —— — EARNED RETURN ON EQUITY-RATEMAKING 8.2% 8.4% 5.1% 6.6% 10.5% —— —— —— —— —— — HEATING DEGREE DAYS Normal degree days in calendar year 7,098 7,098 7,098 7,098 7,098 Actual degree days 6,917 6,561 6,119 6,557 6,763 Percent colder (warmer) than normal (2.6) (7.6) (13.8) (7.6) (4.7) Increase (decrease) from normal in: Gas deliveries (Bcf) 4.1 (6.3) (30.2) (7.4) (10.7) EPS $ 0.02 ($0.03) ($0.12) ($0.03) ($0.05) (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.

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 70 35 Coal/Wood Waste Michigan 1990 100 * 5 Genesee 40 20 Biomass Michigan 1996 100 * 6 Grayling 38 19 Biomass Michigan 1992 100 * 7 Honey Lake 36 14 Biomass California 1989 100 * 8 Michigan Power 224 224 Natural Gas Michigan 1999 0 —— —— —— —— —— —— —— — Projects in Operation 1,199 1,078 —— —— — * Operated by CMS Energy As of April 2009

ELECTRIC RATE CASE U-15645* On November 14, 2008, Consumers Energy filed an application with the Michigan Public Service Commission seeking an increase in its electric generation and distribution rates based on a 2009 test year. On April 27, 2009 the MPSC staff filed their position on Consumers Energy’s request for $214 million rate relief. The staff is recommending a rate increase of $75 million with an 11% ROE and a tracker for uncollectibles. The staff did not support a full decoupling, but did support a tracker that would allow the company to recover revenue lost due to energy optimization programs. On May 14, the company self-implemented $179 million revenue increase using the rate design filed in November. Item Company MPSC Staff MPSC Staff Remarks (Mils) (Mils) B/(W) (Mils) 1. O&M $50 ($25) ($75) Distribution O&M: ($34) includes Forestry ($19) Production O&M: ($19) – Based on historical trends Uncollectibles: ($8) – Based on 3-year average Non-officer EICP: ($7) Executive compensation: ($2) Other: ($5), includes AMI ($3) 2. Rate of Return 17 5 (12) Debt cost rates: ($9) – Lower debt cost Other capitalization/costs: ($3) – Equity timing 3. Rate Base 75 44 (31) Net Plant: ($25) – Lower capex spending Depreciation Reserve: ($5) – Based on historical trends Working Capital: ($1) 4. Book 16 12 (4) Lower net plant Depreciation 5. Property Taxes 9 5 (4) Lower net plant 6. Gross Margin 43 32 (11) Sales: 36.2 mwh vs 36.8 mwh – Based on adjusted sales through Nov. 2008 7. Other 4 2 (2) Taxes and AFUDC —— —— — 8. Total $214 $75 $(139) ======= Ratemaking Existing Consumers MPSC Capital Structure % (U-15245) Filing Staff Filing —— —— —— — Long Term Debt 41.55% 44.51% 44.80% Short Term Debt 0.81 0.77 0.78 Preferred Stock 0.50 0.47 0.48 Common Equity 41.75 40.88⁽¹⁾ 40.51⁽²⁾ Deferred FIT 14.65 12.73 12.80 JDITC/Other 0.74 0.64 0.63 —— —— — 100.00% 100.00% 100.00% =========== ================== ================== Rate Base and Return Existing Consumers MPSC Staff Percentage (U-15245) Filing —— —— —— — Rate Base $ 5.53 $6.27 billion $5.97 billion billion Return on Rate Base 6.93% 7.22% 7.03% Return on Equity 10.70% 11.00% 11.00% ⁽¹⁾Equivalent to 47.61% on a financial basis
⁽²⁾Equivalent to 47.22% on a financial basis ELECTRIC RATE CASE SCHEDULE Rebuttal Testimony May 18, 2009 Motions to Strike Testimony May 29, 2009 Replies to Motions to Strike June 4, 2009 Cross of all Witnesses June 8-19, 2009 Initial Briefs July 9, 2009 Reply Briefs July 23, 2009 Proposal for Decision September 2, 2009 (target) Decision By November 14, 2009 *Electric Rate Case U-15645 can be accessed at the Michigan Public Service Commission’s website. http://efile.mpsc.cis.state.mi.us/efile/electric.html

MATURITY SCHEDULE OF CMS AND CECO LONG-TERM DEBT & PREFERRED SECURITIES AS OF 04/30/2009 Maturity Amount F/V S/U or Call Date (000’s) DEBT/ CO —— —— —— —— — SHORT-TERM DEBT: F S 08/15/09 $ 150,000 4.4% Series K FMBs (CECo) — $ 150,000 LONG-TERM DEBT: F S 05/15/10 $ 250,000 4% $250MM FMBs (CECo) 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 08/01/10 300,000 7.75% Sr Unsec Notes (CMS) — $ 607,900 F U 04/15/11 $ 300,375 8.5% Sr Notes (CMS) F U 12/01/11 287,500 2.875% Convertible Sr Notes Put Date (CMS)* — $ 587,875 F U 02/01/12 $ 150,000 6.3% Senior Notes (CMS) F S 02/15/12 300,000 5% Series L FMBs (CECo) 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) F U 07/15/13 140,000 3.375% Convertible Sr Notes Put Date (CMS)* F S 02/15/14 200,000 6% FMBs (CECo) 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 S 09/15/19 500,000 6.70% FMBs (CECo) F S 04/15/20 300,000 5.65% FMBs (CECo) F U 07/15/27 177,835 QUIPS 7.75%(CMS) Pref Sec ** V S 04/01/35 35,000 PCRBs (CECo) F S 04/15/35 140,309 5.65% FMBs IQ Notes (CECo) F S 09/15/35 175,000 5.80% FMBs (CECo) — $4,690,844 — $6,036,619 GRAND TOTAL — $ 5,858,784 GRAND TOTAL EXCLUDING PREFERRED SECURITIES — Various Maturity Dates/No Maturity Date Available: $ 260,514 CECo Securitization Bonds (Long-Term & Short-Term) after 04/20/09 payment 224,564 CECo Capital lease rental commitments (Long-Term & Short-Term) as of 03/31/09 CMS Enterprises (Genesee) Capital lease rental commitmts (Long-Term & 727 Short-Term) as of 03/31/09 162,625 CECo DOE Liability as of 04/30/09 171,748 EnerBank (Long-Term & Short-Term) Discount Brokered CDs as of 03/31/09 (CMS) (23,978) CMS Net unamortized discount as of 03/31/09 (5,647) CECo Net unamortized discount as of 03/31/09 71,564 CMS Enterprises Debt as of 03/31/09 — $6,898,736 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 **—Includes subordinated notes amounts associated with preferred securities. Issue amount: $172.5MM QUIPS. Status Codes: F-Fixed rate; V-Variable rate; S-Secured; U-Unsecured

Projected Consumers Capital Expenditures Appendix-7

2009 - 2013 Capital Expenditures Category Amount Value Add (bils) Maintenance $2.1 Maintain existing generating and distribution system Environmental 1.0 Reduce emissions and comply with regulations Customer growth 0.9 Meet customer requirements Clean coal plant 0.5 Meet customer demand AMI 0.6 Enable customer and company cost efficiencies Renewables 0.3 Minimize carbon footprint Reliability and other 0.9 Improve customer satisfaction Total $6.3 Investment driven by customer needs, regulation and cost efficiencies. Appendix-8

Capital Spending 2008 Budget Outlook Contingency Maintenance including customer growth 706 600 674 611.3 Environmental 45 69 197 197.1 Choices 75 181 264 125.1 120 186 Capital spending dialed back with some choices delayed temporarily. Average depreciation $410 million Equity contributions to Utility $0 $100 $250 2009 2010 Plan _ _ _ _ _ a 2007 10K Millions $ Appendix-9

Renewable Energy Today 2008 Energy Generation Mix 40,100 Mwh Wind Hydro Biomass Solid waste Anaerobic digester Landfill gas Nuclear (PPA) Renewables Coal MISO Purchase Natural Gas 17 5 45 19 14 382 MW of renewable resources provide 5% of total energy. a _ _ _ _ _ a Based on generation needed to serve total customer requirements Appendix-10

Wind Growth - (2008-2018) 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 71 71 71 71 71 271 271 571 571 971 971 Projected 200 MW 300 MW 400 MW Appendix-11

Tax Benefits New American Recovery and Reinvestment Act of 2009 bonus depreciation extends life of NOLs. Appendix-12 Year-End Actual Estimate 2008 2009 2010 (bils) (bils) (bils) Gross NOL carry forwards $ 1.3 $ 1.1 $ .5 Net NOL cash benefit at 35% .4 .4 $ .2 Credit carry forwards .3 .3 .3 Remaining cash benefit $ .7 $ .7 $ .5 Previous amount $ .7 $ .6 $ .4

2009 Sensitivities Annual Impact Sensitivity EPS FCF (mils) Sales Electric (34,416 GWh) a + 1% + $.04 + $18 Gas (290 bcf) + 1 + .02 + 7 Uncollectible accounts ($58 million) + $5 million + .02 + 5 Auto-sector-wide bankruptcy (15) - (30) (.04) - (.08) (15) - (30) Gas prices ($4.40/mcf) + .50 + .01 + 60 ROE Electric + 50 bps + .06 + 25 Gas + 50 + .02 + 10 Principal sensitivities include the economy (sales and UAs), gas prices, and accomplishing rate recovery. _ _ _ _ a Excluding HSC Appendix-13

Liquidity Components At 04-30-09 Facility Available Renewal Date (mils) (mils) A/R program $ 250 $ 250 February 2010 Bank of Nova Scotia LOC 192 0 November 2009 Consumers revolvers UBOC 150 150 September 2009 JPMorgan 500 328 March 2012 Energy Parent revolver 550 487 April 2012 Subtotal $1,642 $1,215 Cash balance NA 898 NA $1,642 $2,113 Adequate liquidity at Parent and Utility. Appendix-14