Exhibit 99.1

EX-99.1 2 d367178dex991.htm EXHIBIT 99.1 Exhibit 99.1

Exhibit 99.1

LOGO

Exhibit 99.1

Investor Meetings

June 14, 2012

Foote Hydro 1918

Zeeland 2007

Lake Winds 2012

This presentation is made as of the date hereof and 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. CMS Energy and Consumers Energy undertake no obligation to update any of the information presented herein to reflect facts, events or circumstances after the date hereof.

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 provides financial results on both a reported (Generally Accepted Accounting Principles) and adjusted (non-GAAP) basis. Management views adjusted earnings as a key measure of the company’s present operating financial performance, unaffected by discontinued operations, asset sales, impairments, regulatory items from prior years, or other items. Certain of these items have the potential to impact, favorably or unfavorably, the company’s reported earnings in 2012. The company is not able to estimate the impact of these matters and is not providing reported earnings guidance.

Business Model Strong (5% to 7% growth) . . .

Financial

Business

Use NOLs to Eliminate Need for “Block” Equity

– Grow Operating Cash Flow and EPS 5%—7%

– Invest in Utility

• Create Jobs

• Enhance Customer Value

• Improve Environment

• Reduce O&M

– Base Rate

Increases Inflation

Consistent financial performance

Fair and timely regulation

Utility investment

Customer value

Safe, excellent operations

. . . . and sustainable with moderate rate increases inflation.

Capital Investment . . . .

Rate Base Utility Investment

Bils 15

5%-7%

Reliability/Deliverability Renewables

Smart Grid Environmental

Base capital

Depreciation 5

Average Rate Base (bils)

2011 2012 2013 2014 2015 2016 $10.9 $11.5 $12.3 $13.2 $14.0

Base capital

Investment Choices Reliability/deliverability Renewables Smart Grid Environmental Total Choices

Total Capital 2012-16

2012-16

(bils)

$3.1

$1.2 0.5 0.3 1.5 $3.5

$6.6

. . . . growsrows rate base.

$1.5 Billion Environmental Investment . . . .

Expenditures Clean Air Standards

2012 – 2016 (bils)

Air

• NOx

• SO2

• Mercury Water Solid Waste

$0.1 0.7 0.4 0.1 0.2

Total $1.5

Cross-State Air Pollution Rule mandates SO2 and NOx reductions by January 2012 – stayed

Already achieving compliance

Mercury and Air Toxics Standard (MATS)

Largest five coal units planned to be controlled – around 2,000 MW

Retirement or mothballing of smaller coal plants – 950 MW

. . . . to comply with state and federal laws and regulations.p

Renewable Energy Investment Plans . . . .

Michigan energy law requires:

10% renewables by 2015

Purchase 50% and build 50%

20-year levelized surcharge

Renewable energy surcharge reduced by $57 million annually

Plan to invest about $0.5 billion over next five years

$235 million, Lake Winds Energy Park under construction

. . . . at lower customer costs while maintaining investment.

Balanced Generation – Capacity Fuel Mix

Present 2016

Renewables

Pumped Storage 11%

Oil 8%

Nuclear 9%

Coal

35%

Gas 33%

Pumped Storage 11% Purchases 12% Oil 7% Coal 23% Gas 30%

Nuclear 8% Renewables 9%

Capital Investment “Self Limited” . . . .

2012 – 2016 Plan Opportunity Level

$66 Billion

Faster smart grid

Pipe replacements

Pole replacements

New gas generation

$10 Billion

Customer rates

<2%

>4%

. . . . holdsolds down customer base rate increases.

Michigan Energy Law . . . .

2008 Law Regulation

Growth

•

Renewable energy plan

•

Energy optimization

Speed

•

File and implement

ratemaking

•

Forward test year

Risk Mitigation

•

Retail open access cap

•

Decoupling

John Quackenbush, Chairman Appointed: 9/15/11 Term Ends: 7/2/17 Republican

Orjiakor Isiogu, Commissioner Appointed: 9/9/07 Term Ends: 7/2/13 Democrat

Greg White, Commissioner Appointed: 12/4/09 Term Ends: 7/2/15 Independent

. . . . enables timely rate recovery and mitigates risks.

Rate Case Timeline

2008 2009 2010 2011 2012

ELECTRIC

GAS

$Filed 214 M Increase

$Filed 178 M Increase

implement Self- $179 M

$Filed 114 M Increase

Order Final $139 M

implement Self- $150 M

Order Final $146 M

$Filed 195 M Increase

implement Self- $118 M

Order Final $118 M

implement Self-

$89 M

$ Filed 49 M Increase

$ Filed 55 M Increase

Order Final

$66 M

Order Final

$31 M

implement Self-

$23 M

Order Final

$16 M

2008 2009 2010 2011 2012

Frequent and streamlined rate case strategy continues.

Electric Rate Case Final Order U-16794

Amount

(mils)

Self implemented – December 8

$118 a

10.3% vs 10.7% return on equity

(20)

Lower environmental & other

(6)

Clean coal plant recovery

Higher depreciation

Final Order – June 7

$118

Rate base (bils)

$7.4

Equity ratio – financial

51.38%

– regulatory

42.07

a Limited to 60% of $195 mil request

Major Provisions

New depreciation rates effective June 8

Clean coal plant costs recovered over three earsy

Approved capital expenditures based on historical spending

Regulatory asset for major maintenance O&M in excess of amount authorized

Approved Smart Grid Phase 2

Adopted uncollectible accounts proposed by Consumers

Gas Rate Case Final Order U-16855

Major Provisions

Amount

(mils)

Self implemented – March 1

$23

10.3% vs 10.5% return on equity

(4)

Other “black box” settlement

(3)

Final Order – June 7

$16

Implied rate base (bils)

$3.1

Consumers will invest $56 million annually in main replacement program

Revenue decoupling mechanism through April 30, 2012, may be reinstituted with future case

Approved Consumers projected sales level – 285.6 Bcf

Next gas rate case filed no earlier than December 1, 2012

Ongoing Regulatory Strategy . . . .

Michigan investment

Base rate increases inflation

Rate “offsets”

Communication and alignment

. . . . balances customer interests and investor certainty.

O&M Cost Control . . . .

O&M Cost Change

7.5%

3.3%

-4%

-1%

Average Customer Ratesp2002-2006p2007-2011p2012p2012-2016

Electricppppp

Base ap1%p3%p1%p1%

Fuel & Purchased Powerp2p4p2pp3

Gasppppp

Base ap2%p2%p2%p2%

Commodity p14p(4)p(5)pp(3)

a Includes surchargesppppp

. . . . holds down rates with strong customer focus.

Sales Recovery . . . .

Electric Salesa

GWh

40,000

35,000

30,000

25,000

20,000

15,000 0

1975 1979 1983 1987 1991 1995 1999 2003 2007 2012 2011

7% decline 1979 to 1982

Up 9% 1983 & 1984

6% decline 2007 to 2009

2010 Up to 5% 2012

Electric Salesa vs Prior Years

Before EO

+2.1%

-0.7%

-2.0%

-3.0%

+1.7%

2.4%

+1.3%

+3%

+2%

+5%

-6%

2006 2007 2008 2009 2010 2011 2012

a Weather adjusted

. . . . adds rate “headroom”.

Risk Mitigation . . . .

Risk

Mitigation

Economy

Sluggish recovery or

• Customer focus

downturn

• Back-up liquidity

Capital Investments

Regulatory recovery

• Priority projects

• Regulatory alignment

Regulatory / Political

ROA and customer

• ROA “cap”

rate pressure

• Base rate increases

“inflation”

Commodities (prices)

Regulatory

• Follow MPSC-approved plan

alignment

to ensure recovery

Capital Structure

Interest rates

• Maintain flexibility

• Thick liquidity

• Prefund obligations

Shareowner Return

Sustainable returns;

• Risk management

interest rates

• Consistent EPS performance

• Attractive dividend

. . . customerustomer focus key.

Liquidity (as of 3/31/12) . . . .

Availability

$1.8 Billion

CMS Energy

5-year revolver—2016

Consumers Energy

5-year revolver—2016

5-year revolver—2017

A/R Facility—2012

Cash

$547 mils

499

150

250

358

32% Market Cap

Parent Debt Strategy

Thick liquidity – 2x peers

Pre-funding

Robust backup plan

. . . . strongtrong and conservative.

Operating Cash Flow Growth . . . .

Amount (bils) $2.5

2.0

1.5

1.0

0.5 0.0 (0.5)

$1.5

$1.6

$1.7

$1.8

$1.9

$2.0

$2.1

Gross operating cash flowa up $0.1 billion per year

Working capital and taxes

Base Investment

Investment choices

Cash flow before dividend

2010 2011 2012 2013 2014 2015 2016

NOLs & Credits $0.8 $0.8 $0.7 $0.5 $0.3 $0.2 $0.1

a Non-GAAP

EPS a and Dividend Growth . . . .

EPS

$1.55 $1.52

$0.81

$0.90

$0.96

$1.08

$1.21 b

$1.26

$1.36

$1.45

$0.84

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Future

Adjusted EPS (non-GAAP) excluding MTM in 2004-2006

$1.25 excluding discontinued Exeter operations and accounting changes related to convertible debt and restricted stock

Dividend

14%

27%

32%

39%

80%

20¢

36¢

50¢

66¢

96¢

2006 2007 2008 2009 2010 2011 2012

Payout 0% 25% 30% 40% 49% 58% 62%

. . . . providerovide strong TSR.

Total Shareowner Return . . . .

Investment Considerations

Predictable and visible earnings growth

Affordable, sustainable rates

Customer focus

Needed investment

Regulatory support

Strong risk mitigation

TSR up 9% to 11%

Dividend Yield

EPS GroWth

. . . . upp 9% to 11%.

APPENDIX

Despite Adverse Weather . . . .

First Quarter Weather

+20¢ +15 +10 +5 0 -5 -10 -15 -20

+5¢

-13¢

2012

2011

Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec

Recovery Actions

Amount

Complete

• Lower cost financing 2¢

• Lower pension cost 2

• Lower uncollectibles 1

• Lower property tax 1

• Less “lost” gas 1

• Lower injuries & damages 1

Subtotal Complete 8¢

Underway

• Efficiencies 2

• Economy 2

• Regulatory 1

Subtotal Underway 5¢

Total 13¢

. . . . adjusteddjusted EPS (non-GAAP) guidance unchanged.

Michigan’s Economy Recovering . . . .

Unemployment Improvements

16% 14 12 10 8 6 4 2 0

Michigan

U.S.

14%

10%

2006 2007 2008 2009 2010 2011 2012

Source: Bureau of Labor Statistics

U.S. Auto Sales

In Millions

17.4

14.3

13.0

11.8

10.6

2005 2009 2010 2011 2012F

Source: Wardsauto; J.D. Power and LMC Automotive

. . . . quicker than anticipated.

Capital Expenditures

Plan 2012-2016

2012 2013 2014 2015 2016 Total

(mils) (mils) (mils) (mils) (mils) (mils)

Electric

Distribution $ 198 $ 188 $ 196 $ 191 $ 193 $ 966

Generation 101 79 136 78 130 524

New customers 31 31 35 40 39 176

Other 93 84 70 73 75 $ 395

Base capital $ 423 $ 382 $ 437 $ 382 $ 437 $ 2,061

Gas

Distribution $ 130 $ 144 $ 145 $ 145 $ 145 $ 709

New customers $ 29 $ 18 $ 20 $ 21 $ 22 $ 110

Other 56 52 47 39 40 234

Base capital $ 215 $ 214 $ 212 $ 205 $ 207 $ 1,053

Total base capital $ 638 $ 596 $ 649 $ 587 $ 644 $ 3,114

Investment choices:

Environmental $ 268 $ 349 $ 320 $ 356 $ 260 $ 1,553

Reliability 250 236 249 209 212 1,156

Renewables 186 24 112 228 8 558

Smart Grid 61 51 53 54 47 266

Total choices $ 765 $ 660 $ 734 $ 847 $ 527 $ 3,533

Total Utility $ 1,403 $ 1,256 $ 1,383 $ 1,434 $ 1,171 $ 6,647

Federal Tax Benefits

Net NOLs and Credits

$0.8

$0.7

$0.5

$0.3

$0.2

$0.1

2011 2012 2013 2014 2015 2016

Gross NOLs (bils) $1.3 $1.2 $0.5 $0 $0 $0

“Block” Equity 0 0 0 0 0 0

No need for equity (dilution) through 2016.

2012 Sensitivities . . . .

Annual Impact Sensitivity EPS OCF

(mils)

Sales (weather adjusted) a

Electric (38,116 Gwh) + 1% $0.05 + $20

Gas (287 Bcf) + 1 + 0.01 + 5 Gas prices (NYMEX) + 1.00 * –+ 25 Uncollectible accounts (mils) + 5 –+ 0.01 * ROE (authorized)

Electric (10.7%) + 20 bps + 0.02 + 10

Gas (10.5%) + 20 + 0.01 + 4 Stock price (dilution) $1 share < 0.01 0

* Less than 0.5¢ or $500,000 a Reflect 2012 sales forecast

Credit Ratings . . . .

S&P/Fitch Scale Moody’s S&P Fitch Moody’s

Consumers

A- A3 Secured

BBB+ Baa1 Target

BBB Baa2

BBB- Baa3

BB+ Ba1

CMS

BB+ Ba1 Unsecured

BB Ba2 Target

BB- Ba3

B+ B1

B B2

B- B3

Outlook Positive Stable Positive

Present

2002

. . . . reflect March upgrade by Fitch and positive outlook by S&P and Moody’s.

MATURITY SCHEDULE OF CMS AND CECO LONG-TERM DEBT & PREFERRED SECURITIES AS OF 05/31/12

Reflects call of $150MM Floating Sr Notes (CMS) for 07/16/12 redemption & issuance of $375MM 2.85% FMBs

Maturity Amount

F/V S/U or Call Date (000’s) DEBT/ CO

SHORT-TERM DEBT:

F U SHORT-TERM $ 172,500 5.5% Convertible Sr Notes (Next Put Date 06/15/14) (CMS)

V U 07/16/12 150,000 Floating Rate Sr Notes (CMS) Early Redempt Dt

F S 04/15/13 375,000 5.375% Series B FMBs (CECo)

$ 697,500

LONG-TERM DEBT:

F S 02/15/14 $ 200,000 6% FMBs (CECo)

F U 05/15/14 250,000 2.75% Sr Notes (CMS)

$ 450,000

F S 03/15/15 $ 225,000 5% FMBs Series N (CECo)

F U 09/30/15 250,000 4.25% Sr Notes (CMS)

F S 10/15/15 50,000 2.60% FMBs (CECo)

F U 12/15/15 125,000 6.875% Sr Notes (CMS)

$ 650,000

F S 08/15/16 $ 350,000 5.5% Series M FMBs (CECo)

V U 12/15/16 30,000 $180MM Term Loan (CMS)

$ 380,000

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 10/15/17 100,000 3.21% FMBs (CECo)

F U 02/15/18 250,000 5.05% 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 02/01/20 300,000 6.25% Sr Notes (CMS)

F S 04/15/20 300,000 5.65% FMBs (CECo)

F S 10/15/20 100,000 3.77% FMBs (CECo)

F U 03/15/22 300,000 5.05% Sr Notes (CMS)

F S 05/15/22 375,000 2.85% FMBs (CECo)

F S 09/01/22 250,000 5.30% FMBs (CECo)

V S 04/01/35 35,000 PCRBs (CECo)

F S 09/15/35 175,000 5.80% FMBs (CECo)

F S 09/01/40 50,000 6.17% FMBs (CECO)

F S 10/15/40 50,000 4.97% FMBs (CECo)

$ 4,432,700

$ 6,610,200 TOTAL

Various Maturity Dates/No Maturity Date Available:

$ 152,322 CECo Securitization Bonds after 04/20/12 payment

185,371 CECo Capital lease rental commitments as of 03/31/12

476,432 EnerBank Discount Brokered CDs as of 03/31/12 (CMS)

(16,169) CMS Net unamortized discount as of 03/31/12

(3,221) CECo Net unamortized discount as of 03/31/12

$ 7,404,935 GRAND TOTAL

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

Consumers Electric Utility

Financial & Operating Statistics

Years Ended December 31 2011 2010 2009 2008 2007

ELECTRIC REVENUE AND POWER COSTS ($ Millions)

Residential $1,678 $1,614 $1,387 $1,414 $1,326

Commercial 1,197 1,166 1,099 1,129 1,111

Industrial 784 749 677 810 775

Other 39 40 36 32 30

Total revenue from customers $3,698 $3,569 $3,199 $3,385 $3,242

Wholesale 21 20 19 22 23

Intersystem 43 99 94 113 92

Retail open access/direct access 91 54 31 15 15

Miscellaneous 60 60 64 59 71

Total electric utility revenue $3,913 $3,802 $3,407 $3,594 $3,443

Fuel for electric generation $559 $520 $460 $483 $385

Purchased and interchange pow er 1,348 1,308 1,232 1,388 1,449

DEPRECIATION AND AMORTIZATION $412 $450 $441 $438 $397

OPERATING INCOME $712 $672 $488 $576 $413

NET INCOME $333 $303 $194 $271 $196

DELIVERIES (Million kWhs)

System sales

Residential 12,931 12,968 12,386 12,854 13,206

Commercial 10,903 11,026 11,211 11,969 12,384

Industrial 9,544 9,061 9,290 10,563 11,153

Other 224 235 230 225 231

Total sales to ultimate customers 33,602 33,290 33,117 35,611 36,974

Wholesale 332 325 328 333 496

Retail open access/direct access 3,901 4,079 2,326 1,541 1,364

Intersystem 1,349 1,394 1,277 1,176 1,329

Total electric system deliveries 39,184 39,088 37,048 38,661 40,163

AVERAGE ELECTRIC REVENUE (¢ per kWh)

Residential 12.98 12.45 11.20 11.00 10.04

Commerical 10.98 10.58 9.80 9.43 8.98

Industrial 8.21 8.27 7.29 7.67 6.95

Other 17.41 17.02 15.65 14.22 12.99

Total 11.01 10.72 9.66 9.51 8.77

ELECTRIC CUSTOMERS BILLED (At December 31)

Residential 1,571,319 1,569,183 1,566,980 1,584,752 1,575,386

Commercial 207,490 210,380 210,223 208,931 211,365

Industrial 8,691 8,881 8,770 8,505 8,619

Retail Open Access/Direct Access 1,078 1,095 861 642 642

Other 1,300 1,287 1,282 2,045 2,025

Total 1,789,878 1,790,826 1,788,116 1,804,875 1,798,037

AUTHORIZED RETURN ON EQUITY 10.70% 10.70% 10.70% 10.70% 11.15%

EARNED RETURN ON EQUITY-FINANCIAL 11.00% 10.60% 6.40%1 9.40% 7.50%

RATE BASE ($ Millions) $7,442 $6,815 $6,459 $6,175 $5,407

COOLING DEGREE DAYS 2

Normal degree days in calendar year 584 571 578 579 545

Actual degree days 767 884 379 542 773

Warmer (colder) than normal (%) 31 55 (34) (6) 42

Increase (decrease) from normal in:

Electric deliveries (millions of kWh) 513 855 (461) 146 736

1	9.1% excluding Big Rock Decommissioning refund

2	CDD base 65 degrees, Lansing w eather station, normal equals average of preceding 15 year time period

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

Consumers Electric Utility

Financial & Operating Statistics

Years Ended December 31 2011 2010 2009 2008 2007

FUEL COST ($ per MMBtu)

Coal 2.94 2.51 2.37 2.01 2.04

Oil 18.55 10.98 9.59 11.54 8.21

Gas 4.95 5.57 6.57 10.94 10.29

Nuclear 0.00 0.00 0.00 0.00 0.42

Weighted average for all fuels 3.18 2.71 2.56 2.47 2.07

FUEL COST FOR GENERATION (%)

Coal 83.5 88.2 90.6 81.0 97.9

Oil 2.1 3.3 2.5 4.1 9.1

Gas 14.3 8.4 6.8 14.6 0.9

Nuclear 0.0 0.0 0.0 0.0 2.2

Nox allow ances 0.1 0.1 0.1 0.3 (10.1)

POWER GENERATED (Millions of kWhs)

Coal 15,468 17,879 17,255 17,701 17,903

Oil 7 21 14 41 112

Gas 1,912 1,043 565 804 129

Nuclear 0 0 0 0 1,781

Renew able energy (hydro) 425 365 466 454 416

Net pumped storage 1 (365) (366) (303) (382) (478)

Total net generation 17,447 18,942 17,997 18,618 19,863

Purchased and interchange:

Non-utility generation 12,674 12,003 11,538 13,643 12,502

Net interchange pow er 6,825 6,045 6,925 6,653 8,009

Total net purchased and interchange pow er 19,499 18,048 18,463 20,296 20,511

Total net pow er supply 36,946 36,990 36,460 38,914 40,374

POWER GENERATED (%)

Total net generation 47.2 51.2 49.4 47.8 49.2

Non-utility generation 34.3 32.4 31.6 35.1 31.0

Net interchange pow er 18.5 16.3 19.0 17.1 19.8

Total net purchased and interchange pow er 52.8 48.8 50.6 52.2 50.8

Total net pow er supply 100.0 100.0 100.0 100.0 100.0

NET DEMONSTRATED CAPABILITY AT PEAK (M W)

Coal 2,823 2,828 2,850 2,850 2,841

Oil and gas 1,810 1,814 1,814 1,997 1,459

Combustion turbine 465 517 661 661 345

Nuclear 0 0 0 0 0

Renew able energy (hydro) 77 74 74 73 73

Pumped storage 955 955 955 955 955

Total ow ned generation 6,130 6,188 6,354 6,536 5,673

P&I pow er capability 2,458 3,058 2,600 3,050 3,627

Total ow ned and P&I 8,588 9,246 8,954 9,586 9,300

NET DEMONSTRATED CAPABILITY AT PEAK (%)

Total ow ned generation 71.4 66.9 71.0 68.2 61.0

P&I pow er capability 28.6 33.1 29.0 31.8 39.0

Total ow ned and P&I 100.0 100.0 100.0 100.0 100.0

Peak load (MW) 2 8,930 8,190 7,756 7,705 8,391

Reserve capacity (%) 4 11 17 22 12

Nameplate generating capacity (MW) at peak 6,784 6,784 6,784 6,784 6,784

Load factor (%) 3 50.8 55.3 55.9 59.2 56.3

Heat rate-average Btu of fuel per net kWh generated 10,214 10,132 10,072 10,201 10,198

1	Consumers’ portion of the Ludington pumped storage facility

2	Includes Retail Open Access customers

3	Includes bundled service customers

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

Consumers Gas Utility

Financial & Operating Statistics

Years Ended December 31 2011 2010 2009 2008 2007

GAS REVENUE AND COST OF GAS ($ Millions)

Residential $1,655 $1,677 $1,808 $1,971 $1,823

Commercial 438 449 511 598 552

Industrial 89 88 101 124 113

Other 3 3 3 5 6

Total sales revenue $2,185 $2,217 $2,423 $2,698 $2,494

Transportation fees 60 53 48 45 44

Miscellaneous 95 84 85 84 83

Total gas utility revenue $2,340 $2,354 $2,556 $2,827 $2,621

Cost of gas sold 1,438 1,516 1,778 2,079 1,918

Gas utility revenue net of cost of gas $902 $838 $778 $748 $703

DEPRECIATION, DEPLETION AND AMORTIZATION $130 $122 $118 $136 $127

OPERATING INCOME $272 $252 $201 $190 $170

NET INCOME $130 $127 $96 $89 $87

SALES AND DELIVERIES (Bcf)

Residential 157 152 163 171 167

Commercial 50 47 52 57 55

Industrial 11 10 11 12 12

Other ———— -

Total gas sales 1 218 209 226 240 234

Gas transportation deliveries 119 108 93 98 107

Total gas sales and transportation deliveries 337 317 319 338 341

GAS CUSTOMERS BILLED (at December 31)

Residential 1,579,835 1,576,520 1,574,246 1,577,863 1,580,586

Commercial 118,215 117,860 118,199 118,870 119,703

Industrial 6,721 6,938 7,073 6,961 7,014

Transportation 3,179 3,005 2,725 2,507 2,495

Total customers 1,707,950 1,704,323 1,702,243 1,706,201 1,709,798

AVERAGE GAS REVENUE ($ per Mcf)

Residential $10.54 $11.03 $11.09 $11.53 $10.93

Commercial 8.76 9.59 9.83 10.49 10.09

Industrial 8.09 9.17 9.18 10.33 9.62

Transportation 2 0.82 0.82 0.82 0.70 0.68

GAS SUPPLY (MMcf)

Gas Cost Recovery 188,177 170,575 206,866 208,296 216,843

Gas Customer Choice 48,224 38,806 31,498 24,177 19,520

Total 236,401 209,381 238,364 232,473 236,363

WORKING GAS STORAGE CAPACITY (Bcf) 142 142 142 142 143

AVERAGE COST OF GAS SOLD ($ per Mcf) 3

Gas Cost Recovery $6.02 $6.73 $7.66 $8.36 $7.91

Gas Customer Choice 6.30 7.27 7.98 9.99 9.79

AUTHORIZED RETURN ON EQUITY 10.50% 10.55% 10.55% 10.55% 10.75%

EARNED RETURN ON EQUITY-FINANCIAL 10.50% 10.90% 9.90% 9.20% 9.20%

RATE BASE ($ Millions) $3,110 $2,867 $2,778 $2,638 $2,444

HEATING DEGREE DAYS 4

Normal degree days in calendar year 6,678 6,731 6,732 6,741 6,767

Actual degree days 6,606 6,305 6,913 6,965 6,548

Colder (w armer) than normal (%) (1.1) (6.3) 2.7 3.3 (3.2)

Increase (decrease) from normal in:

Gas deliveries (Bcf) (0.4) (6.4) 4.8 4.1 (6.3)

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	HDD base 65 degrees, seven w eather station average, normal equals average of preceding 15 year time period

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

Enterprises & EnerBank

Independent Power Production

Capacity

Ownership Gross In-Service Under LT

Plant Fuel Interest Capacity Year Contract State

Craven Wood 50% 50 1990 100% NC

DIG Natural Gas 100 710 2001 20 MI

Filer City Coal 50 73 1990 100 MI

Genesee Wood 50 40 1996 100 MI

Grayling Wood 50 38 1992 100 MI

MI Power Natural Gas 100 224 1999 59 MI

Net MW Owned by CMS 1,035

EnerBank HQ

Renewables Other

Michigan Power (Livingston)

Filer City

Michigan Power (Kalamazoo River)

Grayling

Genesee

DIG

Craven

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

GAAP RECONCILIATION

Earnings Per Share By Year GAAP Reconciliation

(Unaudited)


	2003			2004			2005			2006			2007			2008			2009			2010			2011
Reported earnings (loss) per share - GAAP	($	0.30	)	$	0.64		($	0.44	)	($	0.41	)	($	1.02	)	$	1.20		$	0.91		$	1.28		$	1.58

After-tax items:
Electric and gas utility		0.21			(0.39	)		—			—			(0.07	)		0.05			0.33			0.03			0.00
Enterprises		0.74			0.62			0.04			(0.02	)		1.25			(0.02	)		0.09			(0.03	)		(0.11	)
Corporate interest and other		0.16			(0.03	)		0.04			0.27			(0.32	)		(0.02	)		0.01			*			(0.01	)
Discontinued operations (income) loss		(0.16	)		0.02			(0.07	)		(0.03	)		0.40			(*)			(0.08	)		0.08			(0.01	)
Asset impairment charges, net		—			—			1.82			0.76			0.60			—			—			—			—
Cumulative accounting changes		0.16			0.01			—			—			—			—			—			—			—

Adjusted earnings per share, including MTM - non-GAAP	$	0.81		$	0.87		$	1.39		$	0.57		$	0.84		$	1.21	(a)	$	1.26		$	1.36		$	1.45
Mark-to-market impacts					0.03			(0.43	)		0.51

Adjusted earnings per share, excluding MTM - non-GAAP		NA		$	0.90		$	0.96		$	1.08			NA			NA			NA			NA			NA

*	Less than $500 thousand or $0.01 per share.

(a)	$1.25 excluding discontinued Exeter operations and accounting changes related to convertible debt and restricted stock.

2003-11 EPS

CMS Energy

Reconciliation of Gross Operating Cash Flow to GAAP Operating Activities

(unaudited)

(mils)


	2009			2010			2011			2012			2013			2014			2015			2016
Consumers Operating Income + Depreciation & Amortization	$	1,248		$	1,498		$	1,527		$	1,651		$	1,735		$	1,860		$	1,977		$	2,051
Enterprises Project Cash Flows		16			39			24			25			27			33			35			35

Gross Operating Cash Flow	$	1,264		$	1,537		$	1,551		$	1,676		$	1,762		$	1,893		$	2,012		$	2,086
Other operating activities including taxes, interest payments and working capital		(416	)		(578	)		(382	)		(426	)		(412	)		(443	)		(757	)		(776	)

Net cash provided by operating activities	$	848		$	959		$	1,169		$	1,250		$	1,350		$	1,450		$	1,255		$	1,310

2009-16 OCF