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.
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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.
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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.
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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.
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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.
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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.
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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.
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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 expendituresa | (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