EX-99.1 2 d505063dex991.htm EX-99.1

Exhibit 99.1

Investor Meeting

March 18, 2013

Cross Winds® Energy Park Consumers Smart Energy Program

Gas Combined Cycle Plant

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 2013. The company is not able to estimate the impact of these matters and is not providing reported earnings guidance.

2 |  |

Six Key Takeaways . . . .

EPS a Growth

• Consistent strong financial performance

• Visible investment-driven EPS growth

• Constructive regulation

• 6th Best GDP growth in nation

• Operational excellence

• Strong customer focus

$1.70 7% +7% $1.66 $1.63 +7% 5% +8%

+12% +4% +12%

Target 5%—7%

+7%

+11% Actual = 7%

Target 6%—8% Actual = 8%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

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

. . . . distinguish CMS from our peers.

3 |  |

EPSa and Dividend Growth . . . .

EPS Dividend in Place

$1.66 $1.63 7% 5%

$1.55

$1.45

$1.36

$1.26

b

$1.21

$1.08

$0.96

$0.90

$0.84 $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

6% 1.02

14% 96¢

84¢

27%

32% 66¢ 39% 50¢ 80% 36¢

20¢

0

2006 2007 2008 2009 2010 2011 2012 2013

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

. . . . provides for strong TSR.

4 |  |

Capital Investment Plan . . . .

Major Projects Capital Investment

Included in Plan:

• 700 MW Gas plant

• Ludington Pumped Storage upgrade

• Consumers Smart Energy

• Gas transmission and storage upgrades Cost reduced or delayed:

• Environmental compliance

• 150 MW Cross Winds®Energy Park

Amount

(bils)

$8.0

$7.3

$7.0

New Gas Plant

$6.5

2013-2017 2018-2022 Base Rate Increases <2% <2%

. . . . drives EPS and cash flow growth.

5 |  |

Propane to Gas Switching . . . .

• 70,000 connection ahead

• Saves customers ~$2,000 per year

• 2.5 year payback

• Every 2,000 switched = $1 million margin

Customer Switching Pace Picking Up

5,000

3,000

1,345 125

Past / yr. 2012 2013 Future Target

. . . . a better energy value.

6 |  |

Long-term Capital Investment a . . . .

Amount (bils) $1.6 New Gas Plant

1.4 $1.5

1.2

Peer 1.0 Average

Amount

0.8

(bils) 0.6 First five years $ 7 Next five years 8 0.4 CMS Ten years $15 0.2 Average ? $1.5

0.0

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022

a Source: 10K; actual amounts through 2011 smoothed for illustration

. . . . drives earnings and cash flow growth.

7 |  |

Rate Case Filings . . . .

2008 2009 2010 2011 2012 2013 2014

ELECTRIC 85%

$Filed 145 M

62% 70% 94% (Need?)

Implement Self- Final Order Order Order (Mar 19) Order $139 M $146 M $118 M

(Sept 18)

New Energy Law

GAS $ Filed 49 M

Order Order (Need?) Order Settled Settled

$66 M

$31 M $16 M 120%

41% 94% 188% Self-

Implement (Aug 1)

2008 2009 2010 2011 2012 2013 2014

% of capex

. . . . continue to be routine, streamlined and primarily investment recovery.

8 |  |

Rate Cases . . . .

Electric Gas as

Amount Amount

(mils) (mils) Self-implement 3/19 (ROE @ 10.3%) $110 Request $49 ROE @ 10.1% $(11) Capital Investment Investment (10) (w/o working capital) 120% O&M (11) Misc. revenuesevenues ( 4) Memo: Customer gas prices down $(150)3 Staff filing $ 74 2015 Capex Adjustment djustment Mechanism (18 months) $70 2014 Capex Adjustment djustment $ 82 (36) Staff testimony July 2

Environment & Consumers Smart Energy only

Staff $ 46 Self-implementation entation filing July 12 Self-implementation ntation date August 1 Proposal for Decision July 9 Proposal for decision November 18 Final orderrder by September 18 Final order by January 31

. . . . focusedocused on capital investment.

9

Sales Recovery a . . . .

Industrial Total

Actual

4%

Excluding Economic Development Tariff (E1 Tariff) Excluding E1 Tariff & Energy Optimization

3%

2%

1% 1% 1% 1%

2012 2013E 2012 2013E

a Weather adjusted

. . . . reeflects strength of underlying economy in Michigan.

10

Sales Recovery a (weather adjusted) . . . .

Industrial Total

10%

Consumers U.S. Utilities

6%

4% 4%a

3%a

2% 2% 2%

1% 1%a 1%a 0%

-1%

Consumers 2010 2011 2012 2013E 2010 2011 2012 2013E vs Peers

a Excluding E1 Tariff Source: EEI

. . . . steady, stronger than other service territories.

11

Michigan Economy in 2011 . . . .

Gross Domestic Product Growth: 2011 vs 2010

WA 6th 2.0 MT ND

7.6

0.0 MN Best 1.2

SD 2.3 ME OR WI -0.4 4.7 ID 0.8 VT

1.1

0.6 WY 0.5 NH MI

-1.2 IA NY 1.5 2.3 MA

NE 1.9 1.1

0.1 IL 2.2 PA RI

1.3 IN OH CT NV UT 1.2 0.8 CO 1.1 1.1 2.0 1.2 2.0 KS MO NJ

1.9 WV MD

0.5 0.0 -0.5 KY 4.5 VA 0.9 DE

CA 0.5 0.3

1.6 2.0 TN DC

OK NC

1.0 AR 1.9 1.9 1.8 NM 0.3 SC

AZ 0.2

MS 1.2 1.5 TX -0.8 AL GA

3.3 LA -0.8 1.7 0.5

FL Highest quintile

HI 0.5

AK Fourth quintile -0.2 2.5 Third quintile

U.S. Total = 0.9% Second quintile

Lowest quintile

. . . . outperformed the Midwest and most of U.S.

12

Michigan Economy in 2012 . . . .

Estimated Gross Domestic Product Growth: 2012 vs 2011

WA th 3.1 MT ND 6 6.8 1.9 . MN Best 2.6

SD 3.3 ME OR WI 1.7 4.8 ID 2.3 VT

2.6

2.2 WY 2.2 NH MI

1.2 IA NY 2.8 3.3 MA

NE 3.0 2.5

2.0 IL 3.2 PA RI

2.7 IN OH CT NV UT 2.6 2.3 CO 2.6 2.5 3.1 2.6 3.1 KS MO NJ

3.0 WV MD

2.2 1.9 1.6 KY 4.7 VA 2.4 DE

CA 2.2 2.0

2.8 3.1 TN DC

OK NC

2.5 AR 3.0 3.1 3.0 2 21 .1 NM SC

AZ 2.0 2.6 MS AL

2.8 TX GA 1.4 1.4 3.9 LA 2.9 2.2

FL

HI 2.2 Highest quintile

AK

1.7 3.4 Fourth quintile Third quintile

U.S. Total (est) = 2.4% Second quintile

Source: U.S. Department of Commerce Lowest quintile

. . . . continued strong performance .

13

O&M Cost Control . . . .

7% Average Annual Increase

Peers

Consumers

Flat% -2% -1% -2%

Reinvested

-6% -6%

2006-2011 Average 2012 2013E 2013-2017E Consumers Energy Headcount 8,026 (2006) 7,205

. . . . holds down customer rates and creates headroom for investment.

14

Utility O&M Cost Control . . . .

Future O&M Cost

Inflation Inflation

2% 2%

-1% -6%

2013E 2013-2017E

Examples of Cost Reductions

Amount Past (annual average) (mils)

• Western coal $250

• Workforce restructuring 70 and benefit plans

• SAP 40

• Productivity 50

Future (2013-2017E)

• Small coal plants mothballed $60

• Productivity 50

• Benefit plans 40

• Consumers Smart Energy 60

. . . . holds down rates and allows better system reliability.

15

Operational Performance . . . .

Results

• Growing business

• Engaged employees

• Long term EPS 5%-7%

• Customer base rates <2%

Aggressive Management

• O&M costs down

• Headcount down 10%

• Enhanced productivity 41%

Operations

• Improved EFOR a 44%

• Improved SAIDI b 24%

Safety

• 75% Improvement

a Equivalent Forced Outage Rate b System Average Interruption Duration Index

. . . . drivesrives results.

16

Operating Cash Flow Growth

Amount (bils) $2.5

Gross operating cash flowa $2.2 up $0.1 billion per year 2.0 $1.8 $1.7 $1.6 1.5 Interest $1.5 king capital $1.4 $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 $0.8 $0.8 $0.4 $0.4 $0.2 $0.1

a Non-GAAP

17

EPSa Growth . . . .

EPS

$1.66 $1.63 7% 5%

$1.55

$1.45

$1.36

$1.26

b

$1.21

$1.08

$0.96

$0.90

$0.84 $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

vs Peers

7%

5%-7% 6% 5%

4% 4%

CMS Peers CMS Peers Ten-Year Growth Future

. . . . predictable and among the best.

18

Six Key Takeaways . . . .

EPS a Growth

$1.70 7% +7% $1.66 $1.63 +7% 5% +8%

+12% +4% +12%

Target 5%—7%

+7%

+11% Actual = 7%

Target 6%—8% Actual = 8%

2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

• Consistent strong financial performance

• Visible investment-driven EPS growth

• Constructive regulation

• 6th Best GDP growth in nation

• Operational excellence

• Strong customer focus

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

. . . . distinguish CMS from our peers.

19

Appendix

20

Capital Expenditures 2013-2017 Plan

2012 2013 2014 2015 2016 2017 Total

(mils) (mils) (mils) (mils) (mils) (mils) (mils) Electric Distribution $ 214 $ 198 $ 196 $ 195 $ 205 $ 181 $ 975 Generation 99 54 86 122 135 104 501 New Customers 36 36 55 46 48 45 230 Other 86 99 88 78 75 85 425 Base Capital $ 435 $ 387 $ 425 $ 441 $ 463 $ 415 $ 2,131

Gas Distribution $ 129 $ 153 $ 143 $ 125 $ 122 $ 139 $ 682 New Customers 50 37 36 36 36 37 182 Other 60 58 56 38 41 44 237 Base Capital $ 239 $ 248 $ 235 $ 199 $ 199 $ 220 $ 1,101 Total base capital $ 674 $ 635 $ 660 $ 640 $ 662 $ 635 $ 3,232

Investment Choices

Environmental $ 170 $ 331 $ 314 $ 247 $ 154 $ 97 $ 1,143 Reliability 135 163 134 106 100 159 662 Gas Infrastructure 110 142 154 133 116 118 663 Thetford Gas Plant - 6 112 346 237 49 750 Renewables 183 31 77 153 5 1 267 Consumers Smart Energy 49 66 61 45 53 98 323 Total Choices $ 647 $ 739 $ 852 $ 1,030 $ 665 $ 522 $ 3,808

Total Utility $ 1,321 $ 1,374 $ 1,512 $ 1,670 $ 1,327 $ 1,157 $ 7,040

21

CMS Manages its Work . . . .

Reinvestment

Adjusted EPS • Customer reinvestment 8¢ (non-GAAP) • Low income and Foundation 2 +13¢ • “25x25” Lobby & other 3 Total reinvestment 13?

Hot Summer

Customer Reinvestment $1.55—$1.55 $1.52 Warm Winter

Recovery

• Lower financing & benefit costs 4¢

• Lower overhead 4

• Efficiencies & other 5 Total recovery 13¢

-13¢

March 31 July 23

. . . . delivering the high side of performance for customers and owners.

22

Parent Investment Grade . . . .

Scale

S&P / Fitch Moody’s S&P Moody’s Fitch A A2

Consumers A- A3 Secured BBB+ Baa1 BBB Baa2 BBB- Baa3 BB+ Ba1

BBB- Baa3

CMS BB+ Ba1 Unsecured BB Ba2 BB- Ba3 B+ B1 B B2 B- B3 Outlook Positive Stable Positive Present

2002

. . . . first time in history of the Company.

23

2013 Cash Flow Forecast (non-GAAP)

CMS Energy Parent

Amount

(mils)

Cash at year end 2012 $ 53 Sources Consumers Energy dividend and tax sharing $ 540 Enterprises 20 Sources $ 560 Uses Interest and preferred dividend $ (135) Overhead and Federal tax payments (15) Equity infusion (150) Pension contribution (1) Uses a $ (315) Cash flow $ 245 Financing and Dividend New issues $ 250 Retirements 0 DRP, continuous equity 30 Net short-term financing & other (5) Common dividend (270) Financing $ 5 Cash at year end 2013 $ 303

Bank Facility ($550) available $ 549

Consumers Energy

Amount

(mils)

Cash at year end 2012 $ 5 Sources Operating (depreciation & amortization $620) $ 1,735 Other working capital (10) Sources $ 1,725 Uses Interest and preferred dividend $ (230) Capital expenditures b (1,375) Dividend and tax sharing $(125) to CMS (540) Pension contribution (49) Uses $ (2,194) Cash flow $ (469) Financing Equity $ 150 New issues 325 Retirements 0 Net short-term financing & other 15 Financing $ 490 Cash at year end 2013 $ 26

Bank Facility ($650) available $ 648 AR Facility ($250) available $ 125

a Includes other b Includes cost of removal and capital leases

24

2013 Sensitivities . . . .

Annual Impact

Sensitivity EPS OCF

(mils)

Sales a

• Electric (37,578 Gwh) + 1% + $0.05 + $20

• Gas (287.9 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

. . . . on strong performance.

a Reflect 2013 sales forecast; weather adjusted

25

ELECTRIC RATE CASE U-17087*

On September 19, 2012, Consumers Energy filed an application with the Michigan Public Service Commission seeking an

increase in its electric generation and distribution rates based on a 2013 test year. The filing also seeks approval of several rate

adjustment mechanisms, including an investment recovery mechanism that would allow recovery in 2014 of an additional $82

million for incremental 2014 investment, subject to reconciliation. On February 21, 2013, the MPSC Staff filed their position,

recommending a rate increase of $74 million with an ROE of 10.1%. The variance between Consumers filed position and the

MPSC Staff’s position is detailed below. On February 27, the Company filed testimony that it intends to self-implement a $110

million rate increase on and after March 19, 2013 under the provisions of 2008 PA 286.

MPSC Staff

Company MPSC Staff B/(W)

Item (Mils) (Mils) (Mils) Explanation of Variance

1. Rate Base $ 80 $ 70 $ (10) Working Capital: $(9)

Lower investments: $(1)

2. Depreciation/ 43 43 -

Property Taxes

3. Gross Margin (9) (13) (4) Higher miscellaneous revenue: $(4)

4. O&M 46 13 (33) Compensation: $(13)

Reduced distribution, forestry, other: $(20)

5. Cost of Capital (15) (39) (24) ROE at 10.1% vs 10.5%: $(22)

Reduced debt cost: $(2)

6. Total $145 $74 $(71)

7. Investment $82 $46 $(36) Staff’s proposal limits 2014 recovery to

Recovery environmental and smart grid-related

Mechanism investments

Ratemaking Existing Consumers MPSC

Capital Structure % (U-16794) Filing Staff Filing

Long Term Debt 39.39% 38.52% 38.52%

Short Term Debt 1.75 1.80 1.80

Preferred Stock 0.42 0.38 0.38

Common Equity 42.07(1) 41.19(2) 41.19(2)

Deferred FIT 15.89 17.70 17.70

JDITC/Other 0.48 0.41 0.41

100.00% 100.00% 100.00%

Rate Base and Return Existing Consumers MPSC

Percentage (U-16794) Filing Staff Filing

Rate Base (billion) $7.40 $8.20 $8.08

Return on Rate Base 6.70% 6.51% 6.32%

Return on Equity 10.30% 10.50% 10.1%

(1)Equivalent to 51.38% on a financial basis.

(2)Equivalent to 51.43% on a financial basis.

ELECTRIC RATE CASE SCHEDULE

Self-implementation Hearing March 1, 2013

Rebuttal Testimony March 13, 2013

Self-implementation Date March 19, 2013

Cross of all Witnesses March 25 – April 5, 2013

Initial Briefs May 3, 2013

Reply Briefs May 24, 2013

Proposal for Decision July 9, 2013

Commission Order By September 18, 2013

*Electric Rate Case U-17087 can be accessed at the Michigan Public Service Commission’s website.

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

26

GAS RATE CASE U-17197

On February 1, 2013, Consumers Energy filed an application with the Michigan Public Service Commission seeking an increase in its gas

delivery and transportation rates based on a 12 months ending June 2014 test year. The request seeks authority to recover new investment in

system reliability, regulatory compliance and technology enhancements. Anticipated lower gas commodity prices during the test year period

will reduce customer bills by approximately $150 million, more than offsetting the requested increase for all customers that purchase their

gas from Consumers Energy. The filing also seeks approval of several rate adjustment mechanisms, including an investment recovery

mechanism that would allow recovery in 2015 of an additional $70 million for incremental 2014 and 2015 investments, subject to

reconciliation. If approved, the $49 million revenue deficiency would add about 3.4% to the typical residential customer’s average monthly

bill. Because the rates approved in Case No. U-16855 were the result of a settlement agreement, specific cost of service items were not

identified in that rate order. Therefore, the items identified on Lines 1-5 below are comparisons to amounts which the Company assumed

were reflected in the U-16855 final order.

Item $ Millions Remarks

1. Rate Base $59 New investment gas infrastructure: $37

Depreciation: $12

Property taxes: $3

Income taxes, AFUDC and other: $7

2. Working Capital (27) Lower gas inventory cost

3. Cost of Capital (3) Reduced debt cost and capital structure change: ($7)

ROE at 10.5% versus authorized 10.3%: $4

4. O&M 12 Distribution & Cust Ops; Corporate: $15

Compensation and benefits: $9

Technology: $5

Uncollectibles: ($4)

LAUF and company use: ($13)

5. Gross Margin 8 Sales and transportation revenue: $9

Miscellaneous revenues: ($1)

6. Total $49

Ratemaking Existing As Filed After-Tax

Capital Structure (U-16855)* Percent of Total Annual Cost Weighted Costs

Long Term Debt 39.37% 38.38% 5.39% 2.07%

Short Term Debt 1.71 1.77 2.56 0.05

Preferred Stock 0.40 0.37 4.46 0.02

Common Equity 41.34(1) 40.99(2) 10.50 4.30

Deferred FIT 16.24 17.60 0.00 0.00

JDITC/Other .94 .89 0.05

100.00% 100.00% 6.49%(3)

Rate Base and Return Existing

Percentage (U-16855)* As Filed

Rate Base (billion) $3.14 $3.24

Return on Rate Base 6.59% 6.49%

Return on Equity 10.30% 10.50%

(1)Equivalent to 50.96% on financial basis.

(2)Equivalent to 51.40% on financial basis.

(3)Equivalent to 9.26% pre-tax basis.

GAS RATE CASE SCHEDULE

Staff and interveners file testimony July 2, 2013

Consumers files self-implementation rates July 12, 2013

Self-implementation hearing July 16, 2013

Rebuttal testimony July 24, 2013

Self-implementation date August 1, 2013

Cross of all witnesses August 5-14, 2013

Initial Briefs September 13, 2013

Reply Briefs October 4, 2013

Proposal for Decision target date November 18, 2013

Commission Order January 31, 2014

*Assumed. Final order was a result of a settlement agreement which did not identify these items specifically.

27

Consumers Energy Electric Utility

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 $2,901 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 9,795 39,184 39,088 37,048 38,661 40,163

AVERAGE ELECTRIC REVENUE (¢ per kWh)

Residential 113.84 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

Industrial 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

28

Consumers Energy Electric Utility

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 8.55 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 (%)

Coal 84.9 83.5 88.2 90.6 81.0 97.9

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 allowances 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 3,0031,912 1,043 565 804 129

Nuclear 0 0 0 0 0 1,781

Renew able energy (hydro, wind '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 4,1516,825 6,045 6,925 6,653 8,009

Total net purchased and interchange pow er 18,690 1 ,499 18,048 18,463 20,296 20,511

Total net pow er supply 35,864 3 ,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 pow er 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 pow er supply 100.0 100.0 100.0 100.0 100.0 100.0

NET DEMONSTRATED CAPABILITY AT PEAK (MW)

Coal 2,846 1,823 2,828 2,850 2,850 2,841

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

Combustion turbine 348 465 517 661 661 345

Nuclear 0 0 0 0 0 0

Renewable energy (hydro, wind '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

29

Consumers Energy Gas Utility

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 transportation deliveries 329 337 317 319 338 341

GAS CUSTOMERS BILLED (at December 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 (w armer) 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 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

30

Enterprises & EnerBank

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

Net MW Owned by CMS 1,035

Michigan Power

(Livingston) Grayling

Filer City Genesee

EnerBank HQ

Michigan Power DIG

Renewables (Kalamazoo

Other River)

Craven

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

31

GAAP Reconciliation

32

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-GAAP |  | $ | 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-GAAP |  |  | 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.

2003-12 EPS

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 |

2011-17 OCF

CMS Energy

2012 Reconciliation of Gross Operating Cash Flow to GAAP Operating Activities

(unaudited)

(mils)

|  | 2012 |
Consumers Operating Income + Depreciation & Amortization |  | $ | 1,635 | (a)
Enterprises Project Cash Flows |  |  | 17 |
Gross Operating Cash Flow |  | $ | 1,652 |
Other operating activities including taxes, interest payments and working capital |  |  | (411 | )
Net cash provided by operating activities |  | $ | 1,241 |

(a) |  | Excludes impact of $59 million electric decoupling write off

2012 OCF

Consumers Energy

2013 Forecasted Cash Flow GAAP Reconciliation (in millions) (unaudited)

|  |  | Reclassifications From Sources and Uses to Statement of Cash Flows |  |  |  |  |  |
Presentation Sources and Uses |  |  | Tax |  |  | Interest |  |  | Other Working |  |  | Capital |  |  | Securitization |  |  | Preferred |  |  | Common |  |  | Consolidated Statements of Cash Flows
Description |  | non-GAAP Amount |  |  | Sharing Operating |  |  | Payments as Operating |  |  | Capital as Investing |  |  | Lease Pymts as Financing |  |  | Debt Pymts as Financing |  |  | Dividends as Financing |  |  | Dividends as Financing |  |  | GAAP Amount |  |  | Description
Cash at year end 2012 |  | $ | 5 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 5 |  |  | Cash at year end 2012
Sources |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating (dep & amort $620) |  | $ | 1,735 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Other working capital |  |  | (10 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sources |  | $ | 1,725 |  |  | $ | (125 | ) |  | $ | (228 | ) |  | $ | (101 | ) |  | $ | 28 |  |  | $ | 41 |  |  | $ | — |  |  | $ | — |  |  | $ | 1,340 |  |  | Net cash provided by operating activities
Uses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest and preferred dividends |  | $ | (230 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pension Contribution |  |  | (49 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Capital expenditures a |  |  | (1,375 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Dividends/tax sharing to CMS |  |  | (540 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Uses |  | $ | (2,194 | ) |  | $ | 125 |  |  | $ | 228 |  |  | $ | 101 |  |  | $ | — |  |  | $ | — |  |  | $ | 2 |  |  | $ | 415 |  |  | $ | (1,323 | ) |  | Net cash provided by investing activities
Cash flow |  | $ | (469 | ) |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 28 |  |  | $ | 41 |  |  | $ | 2 |  |  | $ | 415 |  |  | $ | 17 |  |  | Cash flow from operating and investing activities
Financing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity |  | $ | 150 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
New Issues |  |  | 325 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Retirements |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net short-term financing & other |  |  | 15 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financing |  | $ | 490 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (28 | ) |  | $ | (41 | ) |  | $ | (2 | ) |  | $ | (415 | ) |  | $ | 4 |  |  | Net cash provided by financing activities
Net change in cash |  | $ | 21 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 21 |  |  | Net change in cash
Cash at year end 2013 |  | $ | 26 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 26 |  |  | Cash at year end 2013

a Includes cost of removal and capital leases

2013 B-1

CMS Energy Parent

2013 Forecasted Cash Flow GAAP Reconciliation (in millions) (unaudited)

|  | Reclassifications From Sources and Uses to Statement of Cash Flows |  |  |  |  |  |
Presentation Sources and Uses |  |  | Interest |  |  | Overheads & |  |  | Other |  |  | Cash From |  |  | Consolidated Statements of Cash Flows
Description |  | non-GAAP Amount |  |  | Payments as Operating |  |  | Tax Payments as Operating |  |  | Uses (a) as Operating |  |  | Consolidated Companies |  |  | GAAP Amount |  |  | Description
Cash at year end 2012 |  | $ | 53 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 35 |  |  | $ | 88 |  |  | Cash at year end 2012
Sources |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Consumers Energy dividends/tax sharing |  | $ | 540 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Enterprises |  |  | 20 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Sources |  | $ | 560 |  |  | $ | (135 | ) |  | $ | (15 | ) |  | $ |  | (6) |  | $ | 23 |  |  | $ | 427 |  |  | Net cash provided by operating activities
Uses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Interest and preferred dividends |  | $ | (135 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Overhead and Federal tax payments |  |  | (15 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity infusions |  |  | (150 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Pension Contribution |  |  | (1 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Uses (a) |  | $ | (315 | ) |  | $ | 135 |  |  | $ | 15 |  |  | $ | 6 |  |  | $ | (86 | ) |  | $ | (245 | ) |  | Net cash provided by investing activities
Cash flow |  | $ | 245 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (63 | ) |  | $ | 182 |  |  | Cash flow from operating and investing activities
Financing and dividends |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
New Issues |  | $ | 250 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Retirements |  |  | — |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Equity programs (DRP, continuous equity) |  |  | 30 |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net short-term financing & other |  |  | (5 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Common dividend |  |  | (270 | ) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Financing |  | $ | 5 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 72 |  |  | $ | 77 |  |  | Net cash provided by financing activities
Net change in cash |  | $ | 250 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 9 |  |  | $ | 259 |  |  | Net change in cash
Cash at year end 2013 |  | $ | 303 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 44 |  |  | $ | 347 |  |  | Cash at year end 2013

(a) |  | Includes other

2013 B-2

Consolidated CMS Energy

2013 Forecasted Consolidation of Consumers Energy and CMS Energy Parent Statements of Cash Flow (in millions) (unaudited)

Statements of Cash Flows |  |  | Eliminations/Reclassifications to Arrive at the Consolidated Statement of Cash Flows |  |  | Consolidated Statements of Cash Flows
| Consumers Common Dividend as Financing |  |  | Consumers Preferred Dividend as Operating |  |  | Equity Infusions to Consumers |  |
|  | Consumers Amount |  |  | CMS Parent Amount |  |  |  |  |
Description |  |  |  |  |  |  | Amount |  |  | Description
Cash at year end 2012 |  | $ | 5 |  |  | $ | 88 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 93 |  |  | Cash at year end 2012
Net cash provided by operating activities |  | $ | 1,340 |  |  | $ | 427 |  |  | $ | (415 | ) |  | $ | (2 | ) |  | $ | — |  |  | $ | 1,350 |  |  | Net cash provided by operating activities
Net cash provided by investing activities |  |  | (1,323 | ) |  |  | (245 | ) |  |  | — |  |  |  | — |  |  |  | 150 |  |  |  | (1,418 | ) |  | Net cash provided by investing activities
Cash flow from operating and investing activities |  | $ | 17 |  |  | $ | 182 |  |  | $ | (415 | ) |  | $ | (2 | ) |  | $ | 150 |  |  | $ | (68 | ) |  | Cash flow from operating and investing activities
Net cash provided by financing activities |  | $ | 4 |  |  | $ | 77 |  |  | $ | 415 |  |  | $ | 2 |  |  | $ | (150 | ) |  | $ | 348 |  |  | Net cash provided by financing activities
Net change in cash |  | $ | 21 |  |  | $ | 259 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 280 |  |  | Net change in cash
Cash at year end 2013 |  | $ | 26 |  |  | $ | 347 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 373 |  |  | Cash at year end 2013

2013 B-3