Investor Meetings
July 31, 2012
Zeeland 2007
Foote Hydro 1918
Lake Winds 2012
Foote Hydro 1918 Lake Winds 2012
This presentation is made as of the date hereof and contains “forward-looking statements” as defined in Rule 3b-6 of the Securities Exchange Act of 1934, as amended, Rule 175 of the Securities Act of 1933, as amended, and relevant legal decisions. The forward-looking statements are subject to risks and uncertainties. They should be read in conjunction with “FORWARD-LOOKING STATEMENTS AND INFORMATION” and “RISK FACTORS” sections of CMS Energy’s and Consumers Energy’s Form 10-K for the year ended December 31 and as updated in subsequent
10-Qs. CMS Energy’s and Consumers Energy’s “FORWARD-LOOKING STATEMENTS AND INFORMATION” and “RISK
FACTORS” sections are incorporated herein by reference and discuss important factors that could cause CMS Energy’s and Consumers Energy’s results to differ materially from those anticipated in such statements. CMS Energy and Consumers Energy undertake no obligation to update any of the information presented herein to reflect facts, events or circumstances after the date hereof.
The presentation also includes non-GAAP measures when describing CMS Energy’s results of operations and financial performance. A reconciliation of each of these measures to the most directly comparable GAAP measure is included in the appendix and posted on our website at www.cmsenergy.com.
CMS Energy provides financial results on both a reported (Generally Accepted Accounting Principles) and adjusted (non-GAAP) basis. Management views adjusted earnings as a key measure of the company’s present operating financial performance, unaffected by discontinued operations, asset sales, impairments, regulatory items from prior years, or other items. Certain of these items have the potential to impact, favorably or unfavorably, the company’s reported earnings in 2012. The company is not able to estimate the impact of these matters and is not providing reported earnings guidance.
Business Model Strong (5% to 7% growth) . . . .
Financial
– Use NOLs to Eliminate Need for “Block” Equity
– Grow Operating Cash Flow and EPS 5% - 7%
Consistent financial performance
Fair and timely regulation
Utility Customer investment value
Safe, excellent operations
Business
– Invest in Utility
• Create Jobs
• Enhance Customer Value
• Improve Environment
• Reduce O&M
– Base Rate
Increases Inflation
. . . . and sustainable with moderate rate increases inflation.
EPS a and Dividend Growth . . . .
EPS
$1.55
$1.52 7%
5%
$1.45
$1.36
$1.26
$1.21 b
$1.08
$0.96
$0.90
$0.84
$0.81
2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 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
14% 96¢
84¢
27%
32% 66¢
39% 50¢
36¢
80%
20¢
0
2006 2007 2008 2009 2010 2011 2012
Payout 0% 25% 30% 40% 49% 58% 62%
. . . . provide strong TSR.
Operating Cash Flow Growth
Amount
(bils)
$ 2.5
Gross operating cash flowa
up $0.1 billion per year $2.1
$2.0
2.0 $1.9
$1.8
$1.7
$1.5 $1.6
1.5 Interest
Working capital and taxes
1.0
Base Investment
0.5
Investment choices
0
Cash flow before dividend
(0.5)
2010 2011 2012 2013 2014 2015 2016
NOLs & Credits $0.8 $0.8 $0.7 $0.5 $0.3 $0.2 $0.1
–––––
a Non-GAAP
Total Shareowner Return . . . .
Investment Considerations
• Predictable and visible earnings growth
• Affordable, sustainable rates
– Customer focus
– Needed investment
– Regulatory support
• Strong risk mitigation
TSR up 9% to 11%
Dividend Yield
EPS Growth
. . . . up 9% to 11%.
Capital Investment . . . .
Rate Base
Bils
$ 15
14
13
12 5%-7%
11
10
9
8 | Reliability/Deliverability |
Renewables
Environmental
Depreciation
2011 2012 2013 2014 2015 2016
Average
Rate
Base (bils) $10.9 $11.5 $12.3 $13.2 $14.0
Utility Investment
2012-16
(bils)
Base capital $3.1
Investment Choices
Reliability/deliverability $1.2
Renewables 0.5
Smart Grid 0.3
Environmental 1.5
Total Choices $3.5
Total Capital 2012-16 $6.6
....grows rate base.
$1.5 Billion Environmental Investment . . . .
Expenditures
2012 – 2016
(bils)
Air
• NOx $0.1
• SO2 0.7
• Mercury 0.4
Water 0.1
Solid Waste 0.2
Total $1.5
Clean Air Standards
• Cross-State Air Pollution Rule mandates SO2 and NOx reductions by January 2012 – stayed
– Already achieving compliance
• Mercury and Air Toxics Standard (MATS)
– Largest five coal units planned to be controlled – around 2,000 MW
– Retirement or mothballing of smaller coal plants – 950 MW
. . . . to comply with state and federal laws and regulations.
Renewable Energy Investment Plans . . . .
• Michigan energy law requires:
– 10% renewables by 2015
– Purchase 50% and build 50%
– 20-year levelized surcharge
• Renewable energy surcharge reduced by $57 million annually
• Plan to invest about $0.5 billion over next five years
• $235 million, Lake Winds Energy Park under construction
. . . . at lower customer costs while maintaining investment.
9
Balanced Generation – Capacity Fuel Mix
Present
Renewables
4%
Pumped Storage
11%
Coal
Oil 35%
8%
Nuclear
9% Zeeland
(10%)
Gas
33%
2016
Renewables
9%
Coal
Pumped Storage 23%
11%
Purchases
12%
Zeeland
Oil (9%) Gas
7% Nuclear 30%
8%
10
Capacity Position
MW 9,500
8,500 7,500 6,500 5,500 0
Installed Capacity Excl Classic 7 Classic 7
Peak Demand with 11% Reserve Margin Peak Demand with 18% Reserve Margin
Up to 1,500 MW Shortfall
2012 2013 2014 2015 2016 2017
11
Capital Investment “Self Limited” . . . .
2012 – 2016 Plan
Opportunity Level
$6.6 Billion
• Faster smart grid
• Pipe replacements
• Pole replacements
• New gas generation
$10 Billion
Customer rates <2%
>4%
. . . . holdsolds down customer base rate increases.
12
Customer Rate Competitiveness . . . .
Rate Competiveness
Electric Gas
3%
Inflation
1% <1%
Base & Surcharges (2)%
Fuel
2013-2017 2013-2017
Rate Reduction Actions
• Renewable surcharge down 85%
• Headcount – down 7%
• Health care sharing at 70/30
• Labor agreements
• Productivity up 35%
• Western coal at 97%
• O&M cost down 4% in
2012
. . . . important to the Company.
13
Michigan Energy Law . . . .
2008 Law
Growth
• Renewable energy plan
• Energy optimization
Speed
• File and implement ratemaking
• Forward test year
Risk Mitigation
• Retail open access cap
• Decoupling
Regulation
John Quackenbush, Chairman Appointed: 9/15/11 Term Ends: 7/2/17 Republican
Orjiakor Isiogu, Commissioner Appointed: 9/9/07 Term Ends: 7/2/13 Democrat
Greg White, Commissioner Appointed: 12/4/09 Term Ends: 7/2/15 Independent
. . . . enables timely rate recovery and mitigates risks.
14
Rate Case Timeline
2008 2009 2010 2011 2012
ELECTRIC
Filed Filed Filed
$214 M $178 M $195 M
Increase Increase Increase
Self- Final Self- Final Self- Final
implement Order implement Order implement Order
$179 M $139 M $150 M $146 M $118 M $118 M
New
Energy 78% 97% 100%
Law
GAS Filed Filed Filed
$114 M 74% $55 M $49 M 70%
Increase Increase Increase
Final
implement Self- Order Final Order Self- Final
$89 M $66 M Settled implement Order
$31 M $23 M Settled
$16 M
2008 2009 2010 2011 2012
Frequent and streamlined rate case strategy continues.
15
Electric Rate Case Final Order U-16794 . . . .
Amount
(mils)
Self implemented – December 8 $118 a
10.3% vs 10.7% ROE (20)
Lower environmental & other (6)
Clean coal plant recovery (2/3) 6
Higher depreciation 20
Final Order – June 7 $118
Rate base (bils) $7.4
Equity ratio – financial 51.38%
– regulatory 42.07
a Limited to 60% of $195 mil request
Highlights
• Approved Smart Grid deployment
• Lowered O&M $38 million
• Capital investment 111% of increase
• Adopted Company’s sales forecast –reset ROA sales at 10%
. . . . keepseeps Plan on track.
16
Michigan Legislative Proposals . . . .
Seven Ballot Proposals
• Require a 25% renewable portfolio standard by 2025
• Repeal state emergency financial manager
• Allow construction of eight new casinos
• Enshrine collective bargaining in constitution
• Allow home health care workers to unionize
• Stop the new international bridge
• Require a two-thirds vote to raise taxes
Retail Open Access Cap
• House Bill 5503, by Rep. Mike Shirkey: Estimated 38% cap by 2016
• House Bill 5733, by Rep. Ken Horn: Returns to full regulation
The bills will “sit side by side on a shelf.”
Representative Ken Horn, Chairman of the House Energy & Technology Committee
. . . . are costly to customers.
17
Second Quarter Summary
• Second Quarter adjusted EPS (non-GAAP) 40¢; up 14¢ from 2011
• Reaffirm full year adjusted EPS (non-GAAP) guidance of $1.52—$1.55
• MPSC approved electric and gas rate cases
• Operations – systems performed well in heat
• June daily peak load record of 8,672 MW
– All-time peak load record of 9,110 MW, July 17; up 2% from previous record
• Michigan economy
18
2012 Second Quarter EPS
Results By Business Segment
2012 2011
Adjusted
Reported - - (GAAP) 37¢ 38 ¢ (non-GAAP)
EPS
Less:
Restructuring 3¢-¢ Utility 47¢
Discontinued ops & other-(12) Enterprises -
Subtotal 3¢ (12)¢ Interest & other (7)
Adjusted (non-GAAP) 40¢ 26 ¢ Company 40¢
14¢
Weather adjusted 37¢
First Call Estimate 38¢
Year-to-date 77¢ 77¢
. . . . benefited from strong performance and warm weather.
19
Second Quarter EPS (non-GAAP) . . . .
Utility Enterprises + Parent
14¢ 0¢
26¢
Sales
2011 Weather & Sales Cost & Other Rate Changes & Cost & Other 2012
Decoupling
. . . . performance solid.
20
CMS Manages its Work
Adjusted EPS +13¢
• Increased tree trimming 2¢
• Generating plant maintenance 3
• System hardening 3+
Total reinvestment 8¢+
Customer
Hot Reinvestment
Summer
$1.52- $1.52-
$1.55 Warm $1.55
Recovery
Winter
• Lower financing & benefit costs 4¢
• Lower overhead 4
• Efficiencies & other 5
Total recovery 13¢
-13¢
March 31 July 23
. . . . to maximize results for customers and investors.
21
Response to Weather Extremes
2012 EPS Weather Impact First Quarter
13¢ • Recovery actions EPS
Normal 10¢ –Lower financing & benefit costs 4¢
Weather –Lower overhead 4
3¢ | –Efficiencies & other 5¢ |
Total recovery 13¢
Rest of Year
• System improvements EPS
–Tree trimming 2¢
-13¢ –Generating plant maintenance 3
First Second July 1-23 –System hardening 3+
Quarter Quarter Total reinvestment 8¢+
focus on delivering for customers and owners.
22
2012 Adjusted EPS (non-GAAP)
First Half Second Half
0¢ 10¢
$1.55
to
19¢ $1.52
$1.45 Sales 13¢
Weather 1¢
YTD YTD
July 2012 weather 10¢
$0.77 Sales growth 5
2011 weather & other 4
Total 19¢ 0.77
2011 Weather & Sales Cost & Other Rate Changes & Weather & Sales Reliability & Rates & Cost 2012
Decoupling Reinvestment
strong with reinvestment opportunities.
23
Michigan’s Economy Recovering . . . .
Unemployment Improvements
16%
Michigan 14%
14
U.S.
12
10%
10
8%
0
2006 2007 2008 2009 2010 2011 2012
Source: Bureau of Labor Statistics
U.S. Auto Sales
In Millions
17.4
14.2
13.0
11.8
10.6
2005 2009 2010 2011 2012F
Source: Wardsauto; J.D. Power and LMC Automotive
. . . . quicker than anticipated.
24
Sales Recovery . . . .
Electric Sales a
GWh Up 5%
40,000 2010 to 2012
6% decline
35,000 2007 to 2009
30,000
25,000 Up 9%
1983 & 1984
7% decline
20,000 1979 to 1982
15,0000
1975 1979 1983 1987 1991 1995 1999 2003 2007 2012
a Weather adjusted
Electric Salesa vs Prior Years
+8%
Before EO
+3%
+2.1% 2.4% 2.4%
+2%
+1.7%
+1.3%
+5%
-0.7% First
Half
2012
-2.0% Resid +0.6%
Comm +1.1
-3.0% Indust +7.5
Total +3.0
-6%
2006 2007 2008 2009 2010 2011 2012
. . . . adds rate “headroom”.
25
Liquidity (as of 6/30/12) . . . .
Availability
$1.6 Billion
CMS Energy
5-year revolver - 2016 $523 mils
32%
Market Cap a
Consumers Energy
5-year revolver - 2016 497
5-year revolver - 2017 150
A/R Facility - 2012 250
Cash 187
a As of 3/31/12, comparing 18% for peers
Parent Debt Strategy
Thicker liquidity than peers Pre-funding Robust backup plan
. . . . strong and conservative.
26
2012 Cash Flow Forecast (non-GAAP)
CMS Energy Parent
Amount
(mils)
Cash at year end 2011 $ 56
Sources
Consumers Energy dividend and tax sharing $ 445
Enterprises 15
Sources $ 460
Uses
Interest and preferred dividend $ (125)
Overhead and Federal tax payments (15)
Equity infusion (150)
Pension contribution 0
Uses a $ (340)
Cash flow $ 120
Financing and Dividend
New issues (complete) $ 480
Retirements (404)
Equity programs (DRP, continuous equity) 30
Net short-term financing & other (2)
Common dividend (250)
Financing $ (146)
Cash at year end 2012 $ 30
Bank Facility ($550) available $ 547
a Includes other
Consumers Energy
Amount
(mils)
Cash at year end 2011 $ 85
Sources
Operating (depreciation & amortization $595) $ 1,640
Other working capital (55)
Sources $ 1,585
Uses
Interest and preferred dividend $ (225)
Capital expenditures b (1,425)
Dividend and tax sharing $(45) from CMS (445)
Pension contribution 0
Uses $ (2,095)
Cash flow $ (510)
Financing
Equity $ 150
New issues 1,075
Retirements (1,025)
Net short-term financing & other 250
Financing $ 450
Cash at year end 2012 $ 25
Bank Facility ($650) available $ 629
AR Facility ($250) available $ -
b Includes cost of removal and capital leases 27
2012 Sensitivities
Annual Impact
Sensitivity EPS OCF
(mils)
Sales a
•Electric (38,154 Gwh) + 1% + $0.05 + $20
•Gas (283 Bcf) + 1 + 0.01 + 5
Gas prices (NYMEX) + 1.00 * –+15
Uncollectible accounts (mils) + 5 –+ 0.01 *
ROE (authorized)
•Electric (10.3%) + 20 bps + 0.02 + 10
•Gas (10.3%) + 20 + 0.01 + 4
onn strong performance.
* | Less than 0.5¢ or $500,000 |
a Reflect 2012 sales forecast; weather adjusted
28
2012 Financial Targets
2012
Target
Adjusted EPS a $1.52 - $1.55
Gross operating cash flow (bils) a 1.7
Capital structure (year-end)
– FFO/Average debt 18%
– Parent debt b (bils) 2.3
– Utility equity ratio c 50%
a Non-GAAP
b Net of cash
c Financial, excluding securitization and Palisades financing obligation
Status
. . . . on Plan; tenth year of track record.
29
APPENDIX
Days Per Year with Temperatures at 90 or Warmer
At NWS Grand Rapids Weather Station
40
Annual Count 37 2012 Dates
May 20: 90 July 5: 101
Rolling 30 Year Average May 28: 91 July 6: 104
35 June 10: 91 July 7: 99
June 15: 90 July 12: 90
June 16: 92 July 13: 94
June 18: 92 July 14: 94
30 June 19: 93 July 15: 91
June 20: 93 July 16: 97
June 27: 90 July 17: 99 26
June 28: 97 July 18: 91
25 July 1: 91 July 22: 91
July 2: 96 July 23: 94
Days 21 July 3: 96 21
of 20 19 19 July 4: 99
t
17
Coun 15 15
15 14 14 10.1 14
12 12 Avg
11 11 11
10 9 9
0
1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012
31
Peak Load Comparison
• New All-Time Peak
– 9,110 MW on July 17, 2012 (unofficial)
– 8,930 MW on July 21, 2011
– 8,883 MW on August 1, 2006
System Peak Load, 20 Year History
10,000
9,500
9,000
8,500
8,000
7,500
7,000
6,500
6,000
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
6,226
6,502
7,167
7,285
7,398
7,643
7,705
8,190
7,158
7,315
7,549
8,347
8,171
8,474
8,883
8,391
7,741
8,930
7,984
9,110
200 MW increase over average of 2006/2011 peaks.
32
System Performance Comparison
System Peak Load and Customer Interruptions
Customer Interrupted Non-Storm
Customer Interrupted
Peak Load (MW)
Peak Load (MW)
9,500 9,400 9,300 9,200 9,100 9,000 8,900 8,800 8,700 8,600 8,500 8,400 8,300
25,000
8,883
8,930
12,000
9,110
9,300
30,000 25,000 20,000 15,000 10,000 5,000 0
2006 2011 2012
Year
Higher load, fewer customers out. Reaping the benefits of system investment.
33
Company Workforce
Headcount
8,039 7%
7,822
7,727
7,500
2009 2010 2011 2012E
reducededuced 3% in 2012; 7% since 2009.
34
Capital Expenditures
Plan 2012-2016
2012 2013 2014 2015 2016 Total
(mils) (mils) (mils) (mils) (mils) (mils)
Electric
Distribution $ 198 $ 188 $ 196 $ 191 $ 193 $ 966
Generation 101 79 136 78 130 524
New customers 31 31 35 40 39 176
Other 93 84 70 73 75 $ 395
Base capital $ 423 $ 382 $ 437 $ 382 $ 437 $ 2,061
Gas
Distribution $ 130 $ 144 $ 145 $ 145 $ 145 $ 709
New customers $ 29 $ 18 $ 20 $ 21 $ 22 $ 110
Other 56 52 47 39 40 234
Base capital $ 215 $ 214 $ 212 $ 205 $ 207 $ 1,053
Total base capital $ 638 $ 596 $ 649 $ 587 $ 644 $ 3,114
Investment choices:
Environmental $ 268 $ 349 $ 320 $ 356 $ 260 $ 1,553
Reliability 250 236 249 209 212 1,156
Renewables 186 24 112 228 8 558
Smart Grid 61 51 53 54 47 266
Total choices $ 765 $ 660 $ 734 $ 847 $ 527 $ 3,533
Total Utility $ 1,403 $ 1,256 $ 1,383 $ 1,434 $ 1,171 $ 6,647
35
Federal Tax Benefits
Net NOLs and Credits
$0.8
$0.7
$0.5
$0.3
$0.2
$0.1
2011 2012 2013 2014 2015 2016
Gross NOLs (bils) $1.3 $1.2 $0.5 $0 $0 $0
“Block” Equity 0 0 0 0 0 0
No need for equity (dilution) through 2016.
36
Credit Ratings
S&P/Fitch Scale Moody’s S&P Fitch Moody’s
Consumers
A- A3 Secured
BBB+ Baa1 Target
BBB Baa2
BBB- Baa3
BB+ Ba1
CMS
BB+ Ba1 Unsecured
BB Ba2 Target
BB- Ba3
B+ B1
B B2
B- B3
Outlook Positive Stable Positive
Present
2002
reflect growing confidence in Company’s performance and plans.
37
MATURITY SCHEDULE OF CMS AND CECO LONG-TERM DEBT & PREFERRED SECURITIES
AS OF 06/30/12
Reflects early redemption 06/08/12 of $375MM FMBs maturing 04/15/13 & additional borrowing ($10MM) against Barclay Revolver (CMS)
Maturity Amount
F/V S/U or Call Date (000’s) DEBT/ CO
SHORT-TERM DEBT:
F U SHORT-TERM $ 172,500 5.5% Convertible Sr Notes (Next Put Date 06/15/14) (CMS)
V U 07/16/12 150,000 Floating Rate Sr Notes (CMS) Early Redempt Dt
$ 322,500
LONG-TERM DEBT:
F S 02/15/14 $ 200,000 6% FMBs (CECo)
F U 05/15/14 250,000 2.75% Sr Notes (CMS)
$ 450,000
F S 03/15/15 $ 225,000 5% FMBs Series N (CECo)
F U 09/30/15 250,000 4.25% Sr Notes (CMS)
F S 10/15/15 50,000 2.60% FMBs (CECo)
F U 12/15/15 125,000 6.875% Sr Notes (CMS)
$ 650,000
V S 03/31/16 $ 25,000 Barclay Revolver (CMS)
F S 08/15/16 350,000 5.5% Series M FMBs (CECo)
V U 12/15/16 30,000 $180MM Term Loan (CMS)
$ 405,000
F S 02/15/17 $ 250,000 5.15% FMBs (CECo)
F U 07/17/17 250,000 6.55% Sr Notes (CMS)
F S 10/15/17 100,000 3.21% FMBs (CECo)
F U 02/15/18 250,000 5.05% Sr Notes (CMS)
F S 03/01/18 180,000 6.875% Sr Notes (CECo)
V S 04/15/18 67,700 VRDBs to replace PCRBs (CECo)
F S 09/15/18 250,000 5.65% FMBs (CECo)
F S 03/15/19 350,000 6.125% FMBs (CECo)
F U 06/15/19 300,000 8.75% Sr Notes (CMS)
F S 09/15/19 500,000 6.70% FMBs (CECo)
F U 02/01/20 300,000 6.25% Sr Notes (CMS)
F S 04/15/20 300,000 5.65% FMBs (CECo)
F S 10/15/20 100,000 3.77% FMBs (CECo)
F U 03/15/22 300,000 5.05% Sr Notes (CMS)
F S 05/15/22 375,000 2.85% FMBs (CECo)
F S 09/01/22 250,000 5.30% FMBs (CECo)
V S 04/01/35 35,000 PCRBs (CECo)
F S 09/15/35 175,000 5.80% FMBs (CECo)
F S 09/01/40 50,000 6.17% FMBs (CECO)
F S 10/15/40 50,000 4.97% FMBs (CECo)
$ 4,432,700
$ 6,260,200 SUBTOTAL
Various Maturity Dates/No Maturity Date Available:
$ 152,322 CECo Securitization Bonds after 04/20/12 payment
178,731 CECo Capital lease rental commitments as of 06/30/12
458,218 EnerBank Discount Brokered CDs as of 06/30/12 (CMS)
(15,034) CMS Net unamortized discount as of 06/30/12
(2,931) CECo Net unamortized discount as of 06/30/12
$ 7,031,507 TOTAL
Status Codes: F-Fixed rate; V-Variable rate; S-Secured; U-Unsecured
38
Consumers Electric Utility
Financial & Operating Statistics
Years Ended December 31 2011 2010 2009 2008 2007
ELECTRIC REVENUE AND POWER COSTS ($ Millions)
Residential $1,678 $1,614 $1,387 $1,414 $1,326
Commercial 1,197 1,166 1,099 1,129 1,111
Industrial 784 749 677 810 775
Other 39 40 36 32 30
Total revenue from customers $3,698 $3,569 $3,199 $3,385 $3,242
Wholesale 21 20 19 22 23
Intersystem 43 99 94 113 92
Retail open access/direct access 91 54 31 15 15
Miscellaneous 60 60 64 59 71
Total electric utility revenue $3,913 $3,802 $3,407 $3,594 $3,443
Fuel for electric generation $559 $520 $460 $483 $385
Purchased and interchange pow er 1,348 1,308 1,232 1,388 1,449
DEPRECIATION AND AMORTIZATION $412 $450 $441 $438 $397
OPERATING INCOME $712 $672 $488 $576 $413
NET INCOME $333 $303 $194 $271 $196
DELIVERIES (Million kWhs)
System sales
Residential 12,931 12,968 12,386 12,854 13,206
Commercial 10,903 11,026 11,211 11,969 12,384
Industrial 9,544 9,061 9,290 10,563 11,153
Other 224 235 230 225 231
Total sales to ultimate customers 33,602 33,290 33,117 35,611 36,974
Wholesale 332 325 328 333 496
Retail open access/direct access 3,901 4,079 2,326 1,541 1,364
Intersystem 1,349 1,394 1,277 1,176 1,329
Total electric system deliveries 39,184 39,088 37,048 38,661 40,163
AVERAGE ELECTRIC REVENUE (¢ per kWh)
Residential 12.98 12.45 11.20 11.00 10.04
Commerical 10.98 10.58 9.80 9.43 8.98
Industrial 8.21 8.27 7.29 7.67 6.95
Other 17.41 17.02 15.65 14.22 12.99
Total 11.01 10.72 9.66 9.51 8.77
ELECTRIC CUSTOMERS BILLED (At December 31)
Residential 1,571,319 1,569,183 1,566,980 1,584,752 1,575,386
Commercial 207,490 210,380 210,223 208,931 211,365
Industrial 8,691 8,881 8,770 8,505 8,619
Retail Open Access/Direct Access 1,078 1,095 861 642 642
Other 1,300 1,287 1,282 2,045 2,025
Total 1,789,878 1,790,826 1,788,116 1,804,875 1,798,037
AUTHORIZED RETURN ON EQUITY 10.70% 10.70% 10.70% 10.70% 11.15%
EARNED RETURN ON EQUITY-FINANCIAL 11.00% 10.60% 6.40%1 9.40% 7.50%
RATE BASE ($ Millions) $7,442 $6,815 $6,459 $6,175 $5,407
COOLING DEGREE DAYS 2
Normal degree days in calendar year 584 571 578 579 545
Actual degree days 767 884 379 542 773
Warmer (colder) than normal (%) 31 55 (34) (6) 42
Increase (decrease) from normal in:
Electric deliveries (millions of kWh) 513 855 (461) 146 736
1 | 9.1% excluding Big Rock Decommissioning refund |
2 | CDD base 65 degrees, Lansing w eather station, normal equals average of preceding 15 year time period |
CMS Energy Investor Relations One Energy Plaza Jackson, MI 49201 517-788-2590 www.cmsenergy.com
39
Consumers Electric Utility
Financial & Operating Statistics
Years Ended December 31 2011 2010 2009 2008 2007
FUEL COST ($ per MMBtu)
Coal 2.94 2.51 2.37 2.01 2.04
Oil 18.55 10.98 9.59 11.54 8.21
Gas 4.95 5.57 6.57 10.94 10.29
Nuclear 0.00 0.00 0.00 0.00 0.42
Weighted average for all fuels 3.18 2.71 2.56 2.47 2.07
FUEL COST FOR GENERATION (%)
Coal 83.5 88.2 90.6 81.0 97.9
Oil 2.1 3.3 2.5 4.1 9.1
Gas 14.3 8.4 6.8 14.6 0.9
Nuclear 0.0 0.0 0.0 0.0 2.2
Nox allow ances 0.1 0.1 0.1 0.3 (10.1)
POWER GENERATED (Millions of kWhs)
Coal 15,468 17,879 17,255 17,701 17,903
Oil 7 21 14 41 112
Gas 1,912 1,043 565 804 129
Nuclear 0 0 0 0 1,781
Renew able energy (hydro) 425 365 466 454 416
Net pumped storage 1 (365) (366) (303) (382) (478)
Total net generation 17,447 18,942 17,997 18,618 19,863
Purchased and interchange:
Non-utility generation 12,674 12,003 11,538 13,643 12,502
Net interchange pow er 6,825 6,045 6,925 6,653 8,009
Total net purchased and interchange pow er 19,499 18,048 18,463 20,296 20,511
Total net pow er supply 36,946 36,990 36,460 38,914 40,374
POWER GENERATED (%)
Total net generation 47.2 51.2 49.4 47.8 49.2
Non-utility generation 34.3 32.4 31.6 35.1 31.0
Net interchange pow er 18.5 16.3 19.0 17.1 19.8
Total net purchased and interchange pow er 52.8 48.8 50.6 52.2 50.8
Total net pow er supply 100.0 100.0 100.0 100.0 100.0
NET DEMONSTRATED CAPABILITY AT PEAK (M W)
Coal 2,823 2,828 2,850 2,850 2,841
Oil and gas 1,810 1,814 1,814 1,997 1,459
Combustion turbine 465 517 661 661 345
Nuclear 0 0 0 0 0
Renew able energy (hydro) 77 74 74 73 73
Pumped storage 955 955 955 955 955
Total ow ned generation 6,130 6,188 6,354 6,536 5,673
P&I pow er capability 2,458 3,058 2,600 3,050 3,627
Total ow ned and P&I 8,588 9,246 8,954 9,586 9,300
NET DEMONSTRATED CAPABILITY AT PEAK (%)
Total ow ned generation 71.4 66.9 71.0 68.2 61.0
P&I pow er capability 28.6 33.1 29.0 31.8 39.0
Total ow ned and P&I 100.0 100.0 100.0 100.0 100.0
Peak load (MW) 2 8,930 8,190 7,756 7,705 8,391
Reserve capacity (%) 4 11 17 22 12
Nameplate generating capacity (MW) at peak 6,784 6,784 6,784 6,784 6,784
Load factor (%) 3 50.8 55.3 55.9 59.2 56.3
Heat rate-average Btu of fuel per net kWh generated 10,214 10,132 10,072 10,201 10,198
1 | Consumers’ portion of the Ludington pumped storage facility |
2 | Includes Retail Open Access customers |
3 | Includes bundled service customers |
CMS Energy Investor Relations One Energy Plaza Jackson, MI 49201 517-788-2590 www.cmsenergy.com
40
Consumers Gas Utility
Financial & Operating Statistics
Years Ended December 31 2011 2010 2009 2008 2007
GAS REVENUE AND COST OF GAS ($ Millions)
Residential $1,655 $1,677 $1,808 $1,971 $1,823
Commercial 438 449 511 598 552
Industrial 89 88 101 124 113
Other 3 3 3 5 6
Total sales revenue $2,185 $2,217 $2,423 $2,698 $2,494
Transportation fees 60 53 48 45 44
Miscellaneous 95 84 85 84 83
Total gas utility revenue $2,340 $2,354 $2,556 $2,827 $2,621
Cost of gas sold 1,438 1,516 1,778 2,079 1,918
Gas utility revenue net of cost of gas $902 $838 $778 $748 $703
DEPRECIATION, DEPLETION AND AMORTIZATION $130 $122 $118 $136 $127
OPERATING INCOME $272 $252 $201 $190 $170
NET INCOME $130 $127 $96 $89 $87
SALES AND DELIVERIES (Bcf)
Residential 157 152 163 171 167
Commercial 50 47 52 57 55
Industrial 11 10 11 12 12
Other ———-
Total gas sales 1 218 209 226 240 234
Gas transportation deliveries 119 108 93 98 107
Total gas sales and transportation deliveries 337 317 319 338 341
GAS CUSTOMERS BILLED (at December 31)
Residential 1,579,835 1,576,520 1,574,246 1,577,863 1,580,586
Commercial 118,215 117,860 118,199 118,870 119,703
Industrial 6,721 6,938 7,073 6,961 7,014
Transportation 3,179 3,005 2,725 2,507 2,495
Total customers 1,707,950 1,704,323 1,702,243 1,706,201 1,709,798
AVERAGE GAS REVENUE ($ per Mcf)
Residential $10.54 $11.03 $11.09 $11.53 $10.93
Commercial 8.76 9.59 9.83 10.49 10.09
Industrial 8.09 9.17 9.18 10.33 9.62
Transportation 2 0.82 0.82 0.82 0.70 0.68
GAS SUPPLY (MMcf)
Gas Cost Recovery 188,177 170,575 206,866 208,296 216,843
Gas Customer Choice 48,224 38,806 31,498 24,177 19,520
Total 236,401 209,381 238,364 232,473 236,363
WORKING GAS STORAGE CAPACITY (Bcf) 142 142 142 142 143
AVERAGE COST OF GAS SOLD ($ per Mcf) 3
Gas Cost Recovery $6.02 $6.73 $7.66 $8.36 $7.91
Gas Customer Choice 6.30 7.27 7.98 9.99 9.79
AUTHORIZED RETURN ON EQUITY 10.50% 10.55% 10.55% 10.55% 10.75%
EARNED RETURN ON EQUITY-FINANCIAL 10.50% 10.90% 9.90% 9.20% 9.20%
RATE BASE ($ Millions) $3,110 $2,867 $2,778 $2,638 $2,444
HEATING DEGREE DAYS 4
Normal degree days in calendar year 6,678 6,731 6,732 6,741 6,767
Actual degree days 6,606 6,305 6,913 6,965 6,548
Colder (w armer) than normal (%) (1.1) (6.3) 2.7 3.3 (3.2)
Increase (decrease) from normal in:
Gas deliveries (Bcf) (0.4) (6.4) 4.8 4.1 (6.3)
1 | Includes Gas Customer Choice sales |
2 | Average gas revenue for transportation excludes amounts related to MCV and off-system transportation |
3 | Includes pipeline transportation charges |
4 | HDD base 65 degrees, seven w eather station average, normal equals average of preceding 15 year time period |
CMS Energy Investor Relations One Energy Plaza Jackson, MI 49201 517-788-2590 www.cmsenergy.com
41
Enterprises & EnerBank
Independent Power Production
Capacity
Ownership Gross In-Service Under LT
Plant Fuel Interest Capacity Year Contract State
Craven Wood 50% 50 1990 100% NC
DIG Natural Gas 100 710 2001 20 MI
Filer City Coal 50 73 1990 100 MI
Genesee Wood 50 40 1996 100 MI
Grayling Wood 50 38 1992 100 MI
MI Power Natural Gas 100 224 1999 59 MI
Net MW Owned by CMS 1,035
Michigan Power
(Livingston) Grayling
Filer City Genesee
EnerBank HQ
Michigan Power DIG
Renewables (Kalamazoo
River)
Other
Craven
CMS Energy Investor Relations One Energy Plaza Jackson, MI 49201 517-788-2590 www.cmsenergy.com
42
GAAP RECONCILIATION
CMS ENERGY CORPORATION
Earnings Per Share By Year GAAP Reconciliation
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2003 | | | 2004 | | | 2005 | | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | |
Reported earnings (loss) per share - GAAP | | | ($0.30 | ) | | $ | 0.64 | | | | ($0.44 | ) | | | ($0.41 | ) | | | ($1.02 | ) | | $ | 1.20 | | | $ | 0.91 | | | $ | 1.28 | | | $ | 1.58 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
After-tax items: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Electric and gas utility | | | 0.21 | | | | (0.39 | ) | | | — | | | | — | | | | (0.07 | ) | | | 0.05 | | | | 0.33 | | | | 0.03 | | | | 0.00 | |
Enterprises | | | 0.74 | | | | 0.62 | | | | 0.04 | | | | (0.02 | ) | | | 1.25 | | | | (0.02 | ) | | | 0.09 | | | | (0.03 | ) | | | (0.11 | ) |
Corporate interest and other | | | 0.16 | | | | (0.03 | ) | | | 0.04 | | | | 0.27 | | | | (0.32 | ) | | | (0.02 | ) | | | 0.01 | | | | * | | | | (0.01 | ) |
Discontinued operations (income) loss | | | (0.16 | ) | | | 0.02 | | | | (0.07 | ) | | | (0.03 | ) | | | 0.40 | | | | (*) | | | | (0.08 | ) | | | 0.08 | | | | (0.01 | ) |
Asset impairment charges, net | | | — | | | | — | | | | 1.82 | | | | 0.76 | | | | 0.60 | | | | — | | | | — | | | | — | | | | — | |
Cumulative accounting changes | | | 0.16 | | | | 0.01 | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Adjusted earnings per share, including MTM - non-GAAP | | $ | 0.81 | | | $ | 0.87 | | | $ | 1.39 | | | $ | 0.57 | | | $ | 0.84 | | | $ | 1.21 | (a) | | $ | 1.26 | | | $ | 1.36 | | | $ | 1.45 | |
Mark-to-market impacts | | | | | | | 0.03 | | | | (0.43 | ) | | | 0.51 | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Adjusted earnings per share, excluding MTM - non-GAAP | | | NA | | | $ | 0.90 | | | $ | 0.96 | | | $ | 1.08 | | | | NA | | | | NA | | | | NA | | | | NA | | | | NA | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| * | Less than $500 thousand or $0.01 per share. |
| (a) | $1.25 excluding discontinued Exeter operations and accounting changes related to convertible debt and restricted stock. |
2003-11 EPS
CMS ENERGY CORPORATION
Earnings By Quarter and Year GAAP Reconciliation
(Unaudited)
| | | | | | | | | | | | | | | | | | | | |
(In millions, except per share amounts) | | 2011 | |
| | | 1Q | | | 2Q | | | 3Q | | | 4Q | | | YTD Dec | |
Reported net income - GAAP | | $ | 135 | | | $ | 100 | | | $ | 139 | | | $ | 41 | | | $ | 415 | |
| | | | | | | | | | | | | | | | | | | | |
After-tax items: | | | | | | | | | | | | | | | | | | | | |
Electric and gas utility | | | — | | | | — | | | | — | | | | — | | | | — | |
Enterprises | | | * | | | | (28 | ) | | | * | | | | 1 | | | | (27 | ) |
Corporate interest and other | | | — | | | | (4 | ) | | | — | | | | * | | | | (4 | ) |
Discontinued operations income | | | (2 | ) | | | * | | | | * | | | | * | | | | (2 | ) |
| | | | | | | | | | | | | | | | | | | | |
Adjusted income - non-GAAP | | $ | 133 | | | $ | 68 | | | $ | 139 | | | $ | 42 | | | $ | 382 | |
| | | | | | | | | | | | | | | | | | | | |
Average shares outstanding, basic | | | 250.0 | | | | 250.3 | | | | 251.3 | | | | 251.7 | | | | 250.8 | |
Average shares outstanding, diluted | | | 261.7 | | | | 261.9 | | | | 263.9 | | | | 265.5 | | | | 263.4 | |
| | | | | | | | | | | | | | | | | | | | |
Reported earnings per share - GAAP | | $ | 0.52 | | | $ | 0.38 | | | $ | 0.53 | | | $ | 0.15 | | | $ | 1.58 | |
| | | | | | | | | | | | | | | | | | | | |
After-tax items: | | | | | | | | | | | | | | | | | | | | |
Electric and gas utility | | | — | | | | — | | | | — | | | | — | | | | — | |
Enterprises | | | * | | | | (0.11 | ) | | | * | | | | * | | | | (0.11 | ) |
Corporate interest and other | | | — | | | | (0.01 | ) | | | — | | | | * | | | | (0.01 | ) |
Discontinued operations income | | | (0.01 | ) | | | * | | | | * | | | | * | | | | (0.01 | ) |
| | | | | | | | | | | | | | | | | | | | |
Adjusted earnings per share - non-GAAP | | $ | 0.51 | | | $ | 0.26 | | | $ | 0.53 | | | $ | 0.15 | | | $ | 1.45 | |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | | |
(In millions, except per share amounts) | | 2012 | |
| | | 1Q | �� | | 2Q | |
Reported net income - GAAP | | $ | 67 | | | $ | 100 | |
| | | | | | | | |
After-tax items: | | | | | | | | |
Electric and gas utility | | | 36 | | | | 7 | |
Enterprises | | | 1 | | | | 1 | |
Corporate interest and other | | | — | | | | — | |
Discontinued operations income | | | (7 | ) | | | * | |
| | | | | | | | |
Adjusted income - non-GAAP | | $ | 97 | | | $ | 108 | |
| | | | | | | | |
Average shares outstanding, basic | | | 255.6 | | | | 261.2 | |
Average shares outstanding, diluted | | | 266.9 | | | | 268.2 | |
| | | | | | | | |
Reported earnings per share - GAAP | | $ | 0.25 | | | $ | 0.37 | |
| | | | | | | | |
After-tax items: | | | | | | | | |
Electric and gas utility | | | 0.14 | | | | 0.03 | |
Enterprises | | | 0.01 | | | | * | |
Corporate interest and other | | | — | | | | — | |
Discontinued operations income | | | (0.03 | ) | | | * | |
| | | | | | | | |
Adjusted earnings per share - non-GAAP | | $ | 0.37 | | | $ | 0.40 | |
| | | | | | | | |
Note: Year-to-date (YTD) EPS may not equal sum of quarters due to share count differences.
| * | Less than $500 thousand or $0.01 per share. |
2012 A-1
CMS Energy Corporation
Earnings Segment Results GAAP Reconciliation
(Unaudited)
| | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
June 30 | | 2012 | | | 2011 | | | 2012 | | | 2011 | |
Electric Utility | | | | | | | | | | | | | | | | |
Reported | | $ | 0.41 | | | $ | 0.32 | | | $ | 0.49 | | | $ | 0.57 | |
Electric Decoupling Court Order | | | — | | | | — | | | | 0.14 | | | | — | |
Downsizing Program | | | 0.02 | | | | — | | | | 0.02 | | | | — | |
| | | | | | | | | | | | | | | | |
Adjusted | | $ | 0.43 | | | $ | 0.32 | | | $ | 0.65 | | | $ | 0.57 | |
| | | | | | | | | | | | | | | | |
Gas Utility | | | | | | | | | | | | | | | | |
Reported | | $ | 0.03 | | | $ | 0.02 | | | $ | 0.24 | | | $ | 0.36 | |
Downsizing Program | | | 0.01 | | | | — | | | | 0.01 | | | | — | |
| | | | | | | | | | | | | | | | |
Adjusted | | $ | 0.04 | | | $ | 0.02 | | | $ | 0.25 | | | $ | 0.36 | |
| | | | | | | | | | | | | | | | |
Enterprises | | | | | | | | | | | | | | | | |
Reported | | $ | — | | | $ | 0.11 | | | $ | 0.01 | | | $ | 0.12 | |
Downsizing Program | | | * | | | | — | | | | * | | | | — | |
Restructuring Costs | | | * | | | | — | | | | 0.01 | | | | — | |
Tax Changes | | | — | | | | (0.11 | ) | | | — | | | | (0.11 | ) |
Asset Sales Gains and Other | | | — | | | | * | | | | — | | | | * | |
| | | | | | | | | | | | | | | | |
Adjusted | | $ | — | | | $ | * | | | $ | 0.02 | | | $ | 0.01 | |
| | | | | | | | | | | | | | | | |
Corporate Interest and Other | | | | | | | | | | | | | | | | |
Reported | | $ | (0.07 | ) | | $ | (0.07 | ) | | $ | (0.15 | ) | | $ | (0.16 | ) |
Tax Changes | | | — | | | | (0.01 | ) | | | — | | | | (0.01 | ) |
| | | | | | | | | | | | | | | | |
Adjusted | | $ | (0.07 | ) | | $ | (0.08 | ) | | $ | (0.15 | ) | | $ | (0.17 | ) |
| | | | | | | | | | | | | | | | |
Discontinued Operations | | | | | | | | | | | | | | | | |
Reported | | $ | * | | | $ | * | | | $ | 0.03 | | | $ | 0.01 | |
Discontinued Operations Income | | | * | | | | * | | | | (0.03 | ) | | | (0.01 | ) |
| | | | | | | | | | | | | | | | |
Adjusted | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
Totals | | | | | | | | | | | | | | | | |
Reported | | $ | 0.37 | | | $ | 0.38 | | | $ | 0.62 | | | $ | 0.90 | |
Discontinued Operations Income | | | * | | | | * | | | | (0.03 | ) | | | (0.01 | ) |
Electric Decoupling Court Order | | | — | | | | — | | | | 0.14 | | | | — | |
Downsizing Program | | | 0.03 | | | | — | | | | 0.03 | | | | — | |
Restructuring Costs | | | * | | | | — | | | | 0.01 | | | | — | |
Tax Changes | | | — | | | | (0.12 | ) | | | — | | | | (0.12 | ) |
Asset Sales Gains and Other | | | — | | | | * | | | | — | | | | * | |
| | | | | | | | | | | | | | | | |
Adjusted | | $ | 0.40 | | | $ | 0.26 | | | $ | 0.77 | | | $ | 0.77 | |
| | | | | | | | | | | | | | | | |
Average Common Shares Outstanding - Diluted (in millions) | | | 268.2 | | | | 261.9 | | | | 267.7 | | | | 261.5 | |
| | | | | | | | | | | | | | | | |
| * | Less than $0.01 per share. |
2012 A-2
Consumers Energy
2012 Forecasted Cash Flow GAAP Reconciliation (in millions) (unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Reclassifications From Sources and Uses to Statement of Cash Flows | | | | | | |
Presentation Sources and Uses | | | Tax
Sharing
Operating | | | Interest
Payments
as Operating | | | Premium on Early
Debt Retirement
As Operating | | | Other Working
Capital
as Investing | | | Capital
Lease Pymts
as Financing | | | Securitization
Debt Pymts
as Financing | | | Preferred
Dividends
as Financing | | | Common
Dividends
as Financing | | | Consolidated Statements of Cash Flows |
Description | | non-GAAP
Amount | | | | | | | | | | | GAAP
Amount | | | Description |
Cash at year end 2011 | | $ | 85 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 85 | | | Cash at year end 2011 |
Sources | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating | | $ | 1,640 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Other working capital | | | (55 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by
operating activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Sources | | $ | 1,585 | | | $ | (45 | ) | | $ | (223 | ) | | $ | (15 | ) | | $ | 9 | | | $ | 30 | | | $ | 39 | | | $ | — | | | $ | — | | | $ | 1,380 | | | |
Uses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest and preferred dividends | | $ | (225 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Capital expenditures | | | (1,425 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Dividends/tax sharing to CMS | | | (445 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by
investing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Uses | | $ | (2,095 | ) | | $ | 45 | | | $ | 223 | | | $ | — | | | $ | (9 | ) | | $ | — | | | $ | — | | | $ | 2 | | | $ | 400 | | | $ | (1,434 | ) | | Cash flow from
operating and
investing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash flow | | $ | (510 | ) | | $ | — | | | $ | — | | | $ | (15 | ) | | $ | — | | | $ | 30 | | | $ | 39 | | | $ | 2 | | | $ | 400 | | | $ | (54 | ) | | |
Financing | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity | | $ | 150 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
New Issues | | | 1,075 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Retirements | | | (1,025 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net short-term financing & other | | | 250 | | | | | | | | | | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by
financing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Financing | | $ | 450 | | | $ | — | | | $ | — | | | $ | 15 | | | $ | — | | | $ | (30 | ) | | $ | (39 | ) | | $ | (2 | ) | | $ | (400 | ) | | $ | (6 | ) | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net change in cash | | $ | (60 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | (60 | ) | | Net change in cash |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash at year end 2012 | | $ | 25 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 25 | | | Cash at year end 2012 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2012 B-1
CMS Energy Parent
2012 Forecasted Cash Flow GAAP Reconciliation (in millions) (unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Reclassifications From Sources and Uses to Statement of Cash Flows | | | |
Presentation Sources and Uses | | | Interest
Payments
as Operating | | | Overheads &
Tax Payments
as Operating | | | Other
Uses (a)
as Operating | | | Financing
as Operating | | | Cash From
Consolidated
Companies | | | Consolidated Statements of Cash Flows |
| Description | | non-GAAP
Amount | | | | | | | | GAAP
Amount | | | Description |
Cash at year end 2011 | | $ | 56 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 20 | | | $ | 76 | | | Cash at year end 2011 |
Sources | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Consumers Energy dividends/tax sharing | | $ | 445 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Enterprises | | | 15 | | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by
operating activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Sources | | $ | 460 | | | $ | (125 | ) | | $ | (15 | ) | | $ | (41 | ) | | $ | (35 | ) | | $ | 8 | | | $ | 252 | | | |
Uses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Interest and preferred dividends | | $ | (125 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Overhead and Federal tax payments | | | (15 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity infusions | | | (150 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by
investing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Uses (a) | | $ | (340 | ) | | $ | 125 | | | $ | 15 | | | $ | 41 | | | $ | — | | | $ | (141 | ) | | $ | (300 | ) | | Cash flow from
operating and
investing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash flow | | $ | 120 | | | $ | — | | | $ | — | | | $ | — | | | $ | (35 | ) | | $ | (133 | ) | | $ | (48 | ) | | |
Financing and dividends | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
New Issues | | $ | 480 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Retirements | | | (404 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity programs (DRP, continuous equity) | | | 30 | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net short-term financing & other | | | (2 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Common dividend | | | (250 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | Net cash provided by
financing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Financing | | $ | (146 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | 35 | | | $ | 155 | | | $ | 44 | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net change in cash | | $ | (26 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 22 | | | $ | (4 | ) | | Net change in cash |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash at year end 2012 | | $ | 30 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | 42 | | | $ | 72 | | | Cash at year end 2012 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | Includes other and roundings |
2012-B-2
Consolidated CMS Energy
2012 Forecasted Consolidation of Consumers Energy and CMS Energy Parent Statements of Cash Flow (in millions) (unaudited)
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Eliminations/Reclassifications to Arrive at the
Consolidated Statement of Cash Flows | | | |
Statements of Cash Flows | | | Consumers
Common Dividend
as Financing | | | Consumers
Preferred Dividend
as Operating | | | Equity
Infusions to
Consumers | | | Consolidated Statements of Cash Flows |
| Description | | Consumers
Amount | | | CMS Parent
Amount | | | | | | Amount | | | Description |
Cash at year end 2011 | | $ | 85 | | | $ | 76 | | | $ | — | | | $ | — | | | $ | — | | | $ | 161 | | | Cash at year end 2011 |
Net cash provided by operating activities | | $ | 1,380 | | | $ | 252 | | | $ | (400 | ) | | $ | (2 | ) | | $ | — | | | $ | 1,230 | | | Net cash provided by
operating activities |
Net cash provided by investing activities | | | (1,434 | ) | | | (300 | ) | | | — | | | | — | | | | 150 | | | | (1,584 | ) | | Net cash provided by
investing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash flow from operating and investing activities | | $ | (54 | ) | | $ | (48 | ) | | $ | (400 | ) | | $ | (2 | ) | | $ | 150 | | | $ | (354 | ) | | Cash flow from
operating and
investing activities |
Net cash provided by financing activities | | $ | (6 | ) | | $ | 44 | | | $ | 400 | | | $ | 2 | | | $ | (150 | ) | | $ | 290 | | | Net cash provided by
financing activities |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Net change in cash | | $ | (60 | ) | | $ | (4 | ) | | $ | — | | | $ | — | | | $ | — | | | $ | (64 | ) | | Net change in cash |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash at year end 2012 | | $ | 25 | | | $ | 72 | | | $ | — | | | $ | — | | | $ | — | | | $ | 97 | | | Cash at year end 2012 |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
2012 B-3
CMS Energy
2012 Reconciliation of Gross Operating Cash Flow to GAAP Operating Activities
(unaudited)
(mils)
| | | | |
| | | 2012 | |
Consumers Operating Income + Depreciation & Amortization | | $ | 1,640 | (a) |
Enterprises Project Cash Flows | | | 15 | |
| | | | |
Gross Operating Cash Flow | | $ | 1,655 | |
Other operating activities including taxes, interest payments and working capital | | | (425 | ) |
| | | | |
Net cash provided by operating activities | | $ | 1,230 | |
| | | | |
| (a) | Excludes impact of $59 million electric decoupling write off |
2012 B-4
CMS Energy
Reconciliation of Gross Operating Cash Flow to GAAP Operating Activities
(unaudited)
(mils)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | 2013 | | | 2014 | | | 2015 | | | 2016 | |
Consumers Operating Income + Depreciation & Amortization | | $ | 1,248 | | | $ | 1,498 | | | $ | 1,527 | | | $ | 1,640 | (a) | | $ | 1,735 | | | $ | 1,860 | | | $ | 1,977 | | | $ | 2,051 | |
Enterprises Project Cash Flows | | | 16 | | | | 39 | | | | 24 | | | | 15 | | | | 27 | | | | 33 | | | | 35 | | | | 35 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Gross Operating Cash Flow | | $ | 1,264 | | | $ | 1,537 | | | $ | 1,551 | | | $ | 1,655 | | | $ | 1,762 | | | $ | 1,893 | | | $ | 2,012 | | | $ | 2,086 | |
Other operating activities including taxes, interest payments and working capital | | | (416 | ) | | | (578 | ) | | | (382 | ) | | | (425 | ) | | | (412 | ) | | | (443 | ) | | | (757 | ) | | | (776 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net cash provided by operating activities | | $ | 848 | | | $ | 959 | | | $ | 1,169 | | | $ | 1,230 | | | $ | 1,350 | | | $ | 1,450 | | | $ | 1,255 | | | $ | 1,310 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) | Excludes impact of $59 million electric decoupling write off |
2009-16 OCF
