EX-99.1 2 d601390dex991.htm EX-99.1

Exhibit 99.1

Investor Meetings

September 23-26, 2013

Cross Winds® Energy Park

Gas Combined Cycle Plant

Consumers Smart Energy Program

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, Rule 175 of the Securities Act of 1933, and relevant legal decisions. The forward-looking statements are subject to risks and uncertainties. All forward-looking statements should be considered in the context of the risk and other factors detailed from time to time in CMS Energy’s and Consumers Energy’s Securities and Exchange Commission filings. Forward-looking statements 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, 2012 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 historical financial results on both a reported (Generally Accepted Accounting Principles) and adjusted (non-GAAP) basis and provides forward-looking guidance on an adjusted 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. These items have the potential to impact, favorably or unfavorably, the company’s reported earnings in future periods. Because the company is not able to estimate the impact of these matters, the company is not providing a reconciliation to the comparable future period reported earnings.

1 |  |

EPS a and Dividend Growth . . . .

EPS

7% CAGR

7%

$1.66 5% $1.55 $1.63 $1.36 $1.45 $1.26

$1.21 $1.08 $0.96 $0.90

$0.84

Int’b l Sale $0.81

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013E Future

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

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

Dividend

7%

6% $1.02 5% 14% 96 84 27%

66¢ 32%

39% 50¢ 36¢ 80%

20¢

0

2006 2007 2008 2009 2010 2011 2012 2013 Future

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

. . . . provide for strong TSR.

2 |  |

CMS Energy MODEL

RESULTS

Consistent Predictable

Self-Imposed Limits

Base Rates < 2% Inflation

O&M Down 2% Next Five Years Investment

Ten Year—$15 Billion

“Needed Not Wanted” Catalysts

Constructive Regulation

Visible Capital Investment

Michigan Economy

Strong Customer Focus

Credit Rating Upgrade

Growth Self-funded

working well.

3 |  |

Model Delivers . . . .

Above Average Return

Future Return

Attractive dividend yield 4%

62% payout ratio

EPS growth rate 5-7

Driven by $7 billion investment in regulated Utility over next five years

Shareowner return 9%-11%

EPSa Growth vs Peers

7% 5%-7%

6%

5%

4% 4%

CMS Peers CMS Peers

Ten-Year Growth Future

a Adjusted EPS (non-GAAP) Source: Bloomberg

good, future return opportunity.

4 |  |

Consumers Energy . . . .

Territory

Overview

Fourth largest combination utility in the United States

1.8 million electric and 1.7 million gas customers

8,600 MW of owned and purchased generation capacity

312 TBtu of gas storage capacity

Premium regulatory environment

. . . . one of largest investors and employers in Michigan.

5 |  |

Near-Term Catalysts . . . .

Catalysts

1. Constructive regulation

2. Capital investment

3. Michigan economy

4. Strong customer focus

5. Credit rating upgrade

6. Growth self-funded

Progress

Governor supportive of 2008 Energy Law

Ten-year visibility — $15 billion investment plan

Michigan GDP up 11% 2010 through 2012 (5th best state)

Leader in cost control; base rate increases < 2%

Parent upgraded to investment grade; Utility upgraded as well

NOLs and tax credits avoid need for block equity

progress made, more opportunities ahead.

6 |  |

CATALYST #1 – Constructive Regulation

Commission

John Quackenbush (R), Chairman Term Ends: July 2, 2017

Sally Talberg (I) Term Ends: July 2, 2019

Greg White (I) Term Ends: July 2, 2015

“Appendix A” Timeline

2013

Seven public forums,

Jan-Apr Company submitted

answers

May-Jun Analyze data

Sep-Nov Draft reports, public

feedback

Nov Final reports

Future Governor makes policy

recommendations

strong law on the books supported by a quality commission.

7 |  |

CATALYST #2 – Capital Investment Plan . . . .

Major Projects

Karn/Weadock Generating Complex,

Environmental Compliance, Increased capacity

Ludington Pumped Storage Plant,

Reliability & Capacity

Cross Winds® Energy Park

Thetford Natural Gas-Fired Plant

Campbell Generating Plant, Environmental Compliance

Gas Transmission

& Storage

Reliability & Automation

Capital Investment

Amount

(bils)

$8.0

$7.3

New Gas

Plant

Average 2013-2017 2018-2022

Base Rate

Increases <2% <2%

. . . . drives EPS and cash flow growth.

8 |  |

CATALYST #3 – Michigan Economic Performance. . . .

Gross Domestic Product – 2010 through 2012

WA 5th MT

8.1 Best 6.7 ME

SD 11%

WI 2.7 ID 4.7 VT NH

2.1 WY 5.9

NY 8.2 IA 6.1

(3.5) NE 6.6 MA 6.6

7.4 7.9 IL PA

NV RI 5.9 OH CT

CO 5.9 NJ 2.9 KS 2.4

7.3 1.0 6.2 MO MD 3.1 7.3 4.3 VA DE 6.1 7.5 CA 1.4 OK TN

5.0 NC DC 4.7 AR 5.7 AZ NM 5.6 4.6 4.2 SC 0.7 MS

GA 7.6 AL 3.2

LA 5.0 5.7 4.6 FL

HI AK 6.9 1.2

U.S. Total = 6.7%

Highest quintile Fourth quintile Third quintile Second quintile Lowest quintile

Source: U.S. Department of Commerce – bea.gov, real GDP 2005 chained dollars, 2012 advance and 2009 – 2011 revised, 6/6/13

among the best in the nation.

9

CATALYST #4 – Strong Customer Focus

Electric Non-fuel O&M Cost

Annual Change 2012 over 2006

Peer Average up 7%

-0.5% Consumers

Source: SNL data service

Examples of Cost Reductions

Three voluntary separation programs

Pension prefunding

Health care sharing

Labor agreements

SAP efficiencies

Productivity up 41%

outstanding cost performance best in class.

10

Trend of O&M Cost Savings

Percent Change

25%

Inflation

-21%

Cost

Reductions

0

Prior Plan

-9%

Accelerated Cost

Reductions -6%

New Plan

-15%

-25%

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Lines smoothed for illustrative purposes

accelerated funding investment and reducing risk.

11

Electric Prices . . . .

7% 2011 Residential Bill as Percent of Disposable Income

National average 3.7%

UT CO CA WY MA WA MN DC RI NH NJ IL ME AK NM VT WI ND IA ID NE MT MD MI SD OR NY VA CT NV KS IN DE OH PA MO AZ KY OK NC AR WV TX GA LA FL TN SC HI AL MS

Source: eia.gov & census.gov, disposable income 70% of household income

competitive nationally and improving.

12

Strong Customer Focus – Cost Control . . . .

Average O&M Annual Change

7%

Avg.

Utilities

Inflation 2%

2%

Avg. -8% -3%

Utilities

Consumers

-2% -1%

-0.5%

Reinvested

-6%

2006-2012 2012 2013E 2013-2017E

Annual Average 2012 Base

Examples of Cost Reductions

Amount

Past (annual average) (mils)

Western coal $250

Workforce restructuring 70

and benefit plans

SAP 40

Productivity 50

Future (est. annual average)

Classic 7 mothballed $20

Productivity 10

Benefit plans 30

Consumers Smart Energy 10

Total Future Savings $70

holds down rates and helps fund better system reliability.

13

Strong Customer Focus – Cost Control

Average O&M Annual Change

7%

Avg.

Utilities

Inflation 2%

2%

Avg. -10% -4%

Utilities

Consumers

-2%

-0.5% -2%

Reinvested

-6%

-8%

2006-2012 2012 2013E 2013-2017E

Annual Average 2012 Base

Examples of Cost Reductions

Annual

Future (mils)

Classic 7 mothballed $20

Productivity 10

Benefit plans 30

Consumers Smart Energy 10

Additional cost controls

Retiree health care $50

Tax benefits (COR) 70

Cross Winds® (PTC) 10

Low cost financing 8

Annual Reductions $208

has been enhanced and accelerated.

14

Structural Benefit Changes

Benefit Costs

2012 over

2009 CAGR

6 |  | Peers 2005

+5%

2006

2007

2008

-4% 2009

-2

2012 2010

-2% 2011

2013

-6% 2012

-8

CMS 2013

Source: SNL, Form 1 Electric O&M Benefits

Benefit Changes

Timeline

– New salaried employees to DC pension

– Union employees, health care cost sharing

– Increased cost sharing

– Healthy living initiated, increased cost sharing

– Preferred and standard health care plans

– New union hires pay full cost retiree health care

– Union employees, health care contributions

– Retiree prescription drug cost sharing

– Retiree health care cost sharing reduces benefit cost additional 2% CAGR

better impact than initially planned.

15

New Cost Savings

Gas Rate Case Avoideda

$49 Benefits

Tax/Other

$0

2013 2014

a Until 2015 test year

Electric Rate Case Avoideda

?$100 Benefits

Tax

Cross Winds®

$0

2014

fund elimination of next gas and electric cases!

16

CATALYST #5– Credit Rating Upgrade

Scale

S&P / Fitch Moody’s S&P Moody’s Fitch

A A2

A- A3 Consumers

BBB+ Baa1 Secured

BBB Baa2

BBB- Baa3

BB+ Ba1

BBB- Baa3 CMS

BB+ Ba1 Unsecured

BB Ba2

Present

BB- Ba3

Prior

B+ B1

2002

B B2

B- B3

Outlook Stable Stable Positive

Impact New Cost Savings

2013

Total Company Savings

(mils)

Financing $ 1

Revolvers 1

Total 2013 $ 2

Annual Savings

Future by 2017 $ 8

adds to cost savings.

17

Operating Cash Flow Growth

Amount

(bils)

$ 2.5

Gross operating cash flowa

up $0.1 billion per year $2.0 $2.1 $2.2

2.0 $1.9

$1.8

$1.6 $1.7

1.5 Interest $1.4 $1.5 king capital

$1.3 taxes

1.0

Base Investment

0.5 Investment choices

0

Cash flow before dividend

(0.5)

2011 2012 2013E 2014E 2015E 2016E 2017E

NOLs & Credits $0.8 $0.7 $0.7 $0.4 $0.4 $0.2 $0.1

a Non-GAAP

18

CATALYST #6 – EPS Growth . . . .

Net NOLs and Tax Credits

$0.8

$0.7 $0.7

$0.4 $0.4

$0.2

$0.1

2011 2012 2013E 2014E 2015E 2016E 2017E

Gross NOLs (bils) $1.5 $1.2 $1.1 $0.3 $0.2 $0 $0

“Block” Equity a 0 0 0 0 0 0 0

a Maintain existing DRIP and continuous equity program

self-funded.

19

Five Key Takeaways

EPS a Growth

$1.70 7%

+7% 5%

+7%

+8%

+12%

+4%

+12%

+7% Target 5%—7%

+11% Actual = 7%

Target 6%—8%

Actual = 8%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

Growth

5%-7% real growth

Dividend growth in line with earnings

Gross operating cash flow up $0.1 billion per year

Transparent

Ten-year investment plan

Constructive regulatory climate

Predictable

On track for 11th consecutive year of consistent, attractive financial performance

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

distinguish CMS from our peers.

20

APPENDIX

2013 Sensitivities

Annual Impact

Status Sensitivity EPS OCF

(mils)

Sales a

• |  | Electric (36,343 Gwh) + 1% + $0.05 + $20

• |  | Gas (291.3 Bcf) + 5 + 0.07 + 30

Gas prices (NYMEX) + $1.00 –+ 0.01 –+ 60

ROE (authorized)

• |  | Electric (10.3%) + 25 bps + 0.03 + 12

• |  | Gas (10.3%) + 25 + 0.01 + 5

a Reflect 2013 sales forecast; weather adjusted

reflect strong risk mitigation.

22

Capital Investment

2013 – 2017 Plan

< $7.0 Billion

Faster Consumers Smart Energy

Pipe replacements

Pole replacements

More gas generation

Opportunity Level

$10 Billion

Customer base rates <2% >4%

at sustainable customer “base rate” increases.

23

Capacity

Installed Capacity Excl Classic 7 New Gas Plant Classic 7

Peak Demand with Reserve Margin

MW

10,500

9,500

8,500 Market

Purchases

7,500

6,500

5,500

4,500

2013 2014 2015 2016 2017 2018

.to meet reserve requirements.

24

New Gas Plant CON Filed

CON filed July 12th

Expected decision within nine months

Reliability to be maintained for customers

Capacity needed to support future energy needs

Investment in Michigan to provide jobs and economic benefits

2012 2013 2014 2015 2016 2017

Air Permit

Submitted Approved

July 25

Certificate

of

Necessity Filed 7/12 Approval

Project

Award Major Full Notice Commercial

Contracts to Proceed Operation

Investment (mils) $6 $106 $345 $253 $40

progress continues as spending ramps-up post approvals.

25

Consumers Energy

Financial & Operating Statistics

Years Ended December 31 2012 2011 2010 2009 2008 2007

ELECTRIC REVENUE AND POWER COSTS ($ Millions)

Residential $1,785 $1,678 $1,614 $1,387 $1,414 $1,326

Commercial 1,228 1,197 1,166 1,099 1,129 1,111

Industrial 781 784 749 677 810 775

Other 38 39 40 36 32 30

Total revenue from customers $3,832 $3,698 $3,569 $3,199 $3,385 $3,242

Wholesale 23 21 20 19 22 23

Retail open access/direct access 53 43 54 31 15 15

Intersystem 64 91 99 94 113 92

Miscellaneous 59 60 60 64 59 71

Total electric utility revenue $4,031 $3,913 $3,802 $3,407 $3,594 $3,443

Fuel for electric generation $517 $559 $520 $460 $483 $385

Purchased and interchange power 1,425 1,348 1,308 1,232 1,388 1,449

DEPRECIATION AND AMORTIZATION $459 $412 $450 $441 $438 $397

OPERATING INCOME $743 $712 $672 $488 $576 $413

NET INCOME $325 $333 $303 $194 $271 $196

DELIVERIES (Million kWhs)

System sales

Residential 12,901 12,931 12,968 12,386 12,854 13,206

Commercial 10,950 10,903 11,026 11,211 11,969 12,384

Industrial 9,685 9,544 9,061 9,290 10,563 11,153

Other 220 224 235 230 225 231

Total sales to ultimate customers 33,756 33,602 33,290 33,117 35,611 36,974

Wholesale 347 332 325 328 333 496

Retail open access/direct access 3,981 3,901 4,079 2,326 1,541 1,364

Intersystem 1,711 1,349 1,394 1,277 1,176 1,329

Total electric system deliveries 39,795 39,184 39,088 37,048 38,661 40,163

AVERAGE ELECTRIC REVENUE (¢ per kWh)

Residential 13.84 12.98 12.45 11.20 11.00 10.04

Commerical 11.21 10.98 10.58 9.80 9.43 8.98

Industrial 8.06 8.21 8.27 7.29 7.67 6.95

Other 17.27 17.41 17.02 15.65 14.22 12.99

Total 11.35 11.01 10.72 9.66 9.51 8.77

ELECTRIC CUSTOMERS BILLED (At December 31)

Residential 1,571,873 1,571,319 1,569,183 1,566,980 1,584,752 1,575,386

Commercial 206,627 207,490 210,380 210,223 208,931 211,365

Indu trial 8,706 8,691 8,881 8,770 8,505 8,619

Retail Open Access/Direct Access 1,065 1,078 1,095 861 642 642

Other 1,320 1,300 1,287 1,282 2,045 2,025

Total 1,789,591 1,789,878 1,790,826 1,788,116 1,804,875 1,798,037

AUTHORIZED RETURN ON EQUITY 10.30% 10.70% 10.70% 10.70% 10.70% 11.15%

EARNED RETURN ON EQUITY-FINANCIAL 10.20% 11.00% 10.60% 6.40%1 9.40% 7.50%

RATE BASE ($ Millions) $7,741 $7,442 $6,815 $6,459 $6,175 $5,407

COOLING DEGREE DAYS 2

Normal degree days in calendar year 607 584 571 578 579 545

Actual degree days 942 767 884 379 542 773

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

Increase (decrease) from normal in:

Electric deliveries (millions of kWh) 502 513 855 (461) 146 736

HEADCOUNT (total utility) 7,205 7,435 7,522 7,755 7,697 7,614

1 |  | 9.1% excluding Big Rock Decommissioning refund

| 2 |  | CDD base 65 degrees, Lansing weather 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

26

Consumers Energy

Financial & Operating Statistics

Years Ended December 31 2012 2011 2010 2009 2008 2007

FUEL COST ($ per MMBtu)

Coal 2.98 2.94 2.51 2.37 2.01 2.04

Oil 19.08 18.55 10.98 9.59 11.54 8.21

Gas 3.16 4.95 5.57 6.57 10.94 10.29

Nuclear 0.00 0.00 0.00 0.00 0.00 0.42

Weighted average for all fuels 3.05 3.18 2.71 2.56 2.47 2.07

FUEL COST FOR GENERATION (%)

Oil 1.5 2.1 3.3 2.5 4.1 9.1

Gas 13.6 14.3 8.4 6.8 14.6 0.9

Nuclear 0.0 0.0 0.0 0.0 0.0 2.2

Nox allow ances 0.0 0.1 0.1 0.1 0.3 (10.1)

POWER GENERATED (Millions of kWhs)

Coal 14,027 15,468 17,879 17,255 17,701 17,903

Oil 6 7 21 14 41 112

Gas 3,003 1,912 1,043 565 804 129

Nuclear 0 0 0 0 0 1,781

Renew able energy (hydro, w ind ‘12) 433 425 365 466 454 416

Net pumped storage 1 (295) (365) (366) (303) (382) (478)

Total net generation 17,174 17,447 18,942 17,997 18,618 19,863

Purchased and interchange:

Non-utility generation 14,539 12,674 12,003 11,538 13,643 12,502

Net interchange power 4,151 6,825 6,045 6,925 6,653 8,009

Total net purchased and interchange power 18,690 19,499 18,048 18,463 20,296 20,511

Total net power supply 35,864 36,946 36,990 36,460 38,914 40,374

POWER GENERATED (%)

Total net generation 47.9 47.2 51.2 49.4 47.8 49.2

Non-utility generation 40.5 34.3 32.5 31.6 35.1 31.0

Net interchange power 11.6 18.5 16.3 19.0 17.1 19.8

Total net purchased and interchange power 52.1 52.8 48.8 50.6 52.2 50.8

Total net power supply 100.0 100.0 100.0 100.0 100.0 100.0

NET DEMONSTRATED CAPABILITY AT PEAK (MW)

Coal 2,846 2,823 2,828 2,850 2,850 2,841

Oil and gas 1,795 1,810 1,814 1,814 1,997 1,459

Combustion turbine 348 465 517 661 661 345

Nuclear 0 0 0 0 0 0

Renew able energy (hydro, w ind ‘12) 176 77 74 74 73 73

Pumped storage 954 955 955 955 955 955

Total owned generation 6,119 6,130 6,188 6,354 6,536 5,673

P&I power capability 2,488 2,458 3,058 2,600 3,050 3,627

Total owned and P&I 8,607 8,588 9,246 8,954 9,586 9,300

NET DEMONSTRATED CAPABILITY AT PEAK (%)

Total owned generation 71.1 71.4 66.9 71.0 68.2 61.0

P&I power capability 28.9 28.6 33.1 29.0 31.8 39.0

Total owned and P&I 100.0 100.0 100.0 100.0 100.0 100.0

Peak load (MW) 2 9,006 8,930 8,190 7,756 7,705 8,391

Reserve capacity (%) 4 4 11 17 22 12

Net demonstrated capacity, summer (MW) 6,119 6,091 6,151 6,353 6,353 5,673

Load factor (%) 3 48.7 50.8 55.3 55.9 59.2 56.3

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

27

Consumers Energy

Financial & Operating Statistics

Years Ended December 31 2012 2011 2010 2009 2008 2007

GAS REVENUE AND COST OF GAS ($ Millions)

Residential $1,415 $1,655 $1,677 $1,808 $1,971 $1,823

Commercial 351 438 449 511 598 552

Industrial 65 89 88 101 124 113

Other 2 3 3 3 5 6

Total sales revenue $1,833 $2,185 $2,217 $2,423 $2,698 $2,494

Transportation fees 58 60 53 48 45 44

Miscellaneous 91 95 84 85 84 83

Total gas utility revenue $1,982 $2,340 $2,354 $2,556 $2,827 $2,621

Cost of gas sold 1,110 1,438 1,516 1,778 2,079 1,918

Gas utility revenue net of cost of gas $872 $902 $838 $778 $748 $703

DEPRECIATION, DEPLETION AND AMORTIZATION $133 $130 $122 $118 $136 $127

OPERATING INCOME $240 $272 $252 $201 $190 $170

NET INCOME $110 $130 $127 $96 $89 $87

SALES AND DELIVERIES (Bcf)

Residential 139 157 152 163 171 167

Commercial 44 50 47 52 57 55

Industrial 9 11 10 11 12 12

Other

Total gas sales 1 192 218 209 226 240 234

Gas transportation deliveries 137 119 108 93 98 107

Total gas sales and transportatio deliveries 329 337 317 319 338 341

GAS CUSTOMERS BILLED (at Dece mber 31)

Residential 1,582,123 1,579,835 1,576,520 1,574,246 1,577,863 1,580,586

Commercial 118,781 118,215 117,860 118,199 118,870 119,703

Industrial 6,437 6,721 6,938 7,073 6,961 7,014

Transportation 3,347 3,179 3,005 2,725 2,507 2,495

Total customers 1,710,688 1,707,950 1,704,323 1,702,243 1,706,201 1,709,798

AVERAGE GAS REVENUE ($ per Mcf)

Residential $10.18 $10.54 $11.03 $11.09 $11.53 $10.93

Commercial 7.98 8.76 9.59 9.83 10.49 10.09

Industrial 7.22 8.09 9.17 9.18 10.33 9.62

Transportation 2 0.87 0.82 0.82 0.82 0.70 0.68

GAS SUPPLY (MMcf)

Gas Cost Recovery 133,741 188,177 170,575 206,866 208,296 216,843

Gas Customer Choice 55,547 48,224 38,806 31,498 24,177 19,520

Total 189,288 236,401 209,381 238,364 232,473 236,363

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

AVERAGE COST OF GAS SOLD ($ per Mcf) 3

Gas Cost Recovery $5.40 $6.02 $6.73 $7.66 $8.36 $7.91

Gas Customer Choice 5.08 6.30 7.27 7.98 9.99 9.79

AUTHORIZED RETURN ON EQUITY 10.30% 10.50% 10.55% 10.55% 10.55% 10.75%

EARNED RETURN ON EQUITY-FINANCIAL 8.60% 10.50% 10.90% 9.90% 9.20% 9.20%

RATE BASE ($ Millions) $3,138 $3,110 $2,867 $2,778 $2,638 $2,444

HEATING DEGREE DAYS 4

Normal degree days in calendar year 6,626 6,678 6,731 6,732 6,741 6,767

Actual degree days 5,714 6,606 6,305 6,913 6,965 6,548

Colder (warmer) than normal (%) (13.8) (1.1) (6.3) 2.7 3.3 (3.2)

Increase (decrease) from normal in:

Gas deliveries (Bcf) (22.9) (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 weather 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

28

As of December 31, 2012

Independent Power Production

Capacity

Primary 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 39 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 47 MI

Total MW 1,035 (net owned) 1,135

Michigan Power

(Livingston) Grayling

Filer City Genesee

EnerBank HQ

DIG

Michigan Power

(Kalamazoo River)

Craven

Renewables Other

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

GAAP Reconciliation

CMS ENERGY CORPORATION

Earnings Per Share By Year GAAP Reconciliation

(Unaudited)

|  | 2003 |  |  | 2004 |  |  | 2005 |  |  | 2006 |  |  | 2007 |  |  | 2008 |  |  | 2009 |  |  | 2010 |  |  | 2011 |  |  | 2012 |
Reported earnings (loss) per share - GAAP |  | ($ | 0.30 | ) |  | $ | 0.64 |  |  | ($ | 0.44 | ) |  | ($ | 0.41 | ) |  | ($ | 1.02 | ) |  | $ | 1.20 |  |  | $ | 0.91 |  |  | $ | 1.28 |  |  | $ | 1.58 |  |  | $ | 1.42 |
After-tax items: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Electric and gas utility |  |  | 0.21 |  |  |  | (0.39 | ) |  |  | — |  |  |  | — |  |  |  | (0.07 | ) |  |  | 0.05 |  |  |  | 0.33 |  |  |  | 0.03 |  |  |  | 0.00 |  |  |  | 0.17 |
Enterprises |  |  | 0.74 |  |  |  | 0.62 |  |  |  | 0.04 |  |  |  | (0.02 | ) |  |  | 1.25 |  |  |  | (0.02 | ) |  |  | 0.09 |  |  |  | (0.03 | ) |  |  | (0.11 | ) |  |  | (0.01 | )
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 | ) |  |  | (0.03 | )
Asset impairment charges, net |  |  | — |  |  |  | — |  |  |  | 1.82 |  |  |  | 0.76 |  |  |  | 0.60 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Cumulative accounting changes |  |  | 0.16 |  |  |  | 0.01 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | — |
Adjusted earnings per share, including MTM - non-GAA |  | $ | 0.81 |  |  | $ | 0.87 |  |  | $ | 1.39 |  |  | $ | 0.57 |  |  | $ | 0.84 |  |  | $ | 1.21 | (a) |  | $ | 1.26 |  |  | $ | 1.36 |  |  | $ | 1.45 |  |  | $ | 1.55 |
Mark-to-market impacts |  |  |  |  |  |  | 0.03 |  |  |  | (0.43 | ) |  |  | 0.51 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Adjusted earnings per share, excluding MTM - non-GAA |  |  | NA |  |  | $ | 0.90 |  |  | $ | 0.96 |  |  | $ | 1.08 |  |  |  | NA |  |  |  | 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.

CMS Energy

Reconciliation of Gross Operating Cash Flow to GAAP Operating Activities

(unaudited)

(mils)

|  | 2011 |  |  | 2012 |  |  | 2013 |  |  | 2014 |  |  | 2015 |  |  | 2016 |  |  | 2017 |
Consumers Operating Income + Depreciation & Amortization |  | $ | 1,527 |  |  | $ | 1,635 |  |  | $ | 1,735 |  |  | $ | 1,821 |  |  | $ | 1,948 |  |  | $ | 2,011 |  |  | $ | 2,113 |
Enterprises Project Cash Flows |  |  | 24 |  |  |  | 17 |  |  |  | 20 |  |  |  | 29 |  |  |  | 37 |  |  |  | 44 |  |  |  | 56 |
Gross Operating Cash Flow |  | $ | 1,551 |  |  | $ | 1,652 |  |  | $ | 1,755 |  |  | $ | 1,850 |  |  | $ | 1,985 |  |  | $ | 2,055 |  |  | $ | 2,169 |
Other operating activities including taxes, interest payments and working capital |  |  | (382 | ) |  |  | (411 | ) |  |  | (405 | ) |  |  | (400 | ) |  |  | (435 | ) |  |  | (805 | ) |  |  | (819 | )
Net cash provided by operating activities |  | $ | 1,169 |  |  | $ | 1,241 |  |  | $ | 1,350 |  |  | $ | 1,450 |  |  | $ | 1,550 |  |  | $ | 1,250 |  |  | $ | 1,350 |