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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2006MARCH 31, 2007
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from _______________ to _______________
Commission Registrant; State of Incorporation; IRS Employer
File Number Address; and Telephone Number Identification No.
- ----------- ----------------------------------------- ------------------
1-9513 CMS ENERGY CORPORATION 38-2726431
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550
1-5611 CONSUMERS ENERGY COMPANY 38-0442310
(A Michigan Corporation)
One Energy Plaza, Jackson, Michigan 49201
(517) 788-0550
Indicate by check mark whether the Registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
Registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark whether the Registrant is a large accelerated filer, an
accelerated filer, or a non-accelerated filer. See definition of "accelerated
filer and large accelerated filer" in Rule 12b-2 of the Exchange Act.
CMS ENERGY CORPORATION: Large accelerated filer [X] Accelerated filer [ ]
Non-Accelerated filer [ ]
CONSUMERS ENERGY COMPANY: Large accelerated filer [ ] Accelerated filer [ ]
Non-Accelerated filer [X]
Indicate by check mark whether the Registrant is a shell company (as defined in
Rule 12b-2 of the Exchange Act).
CMS ENERGY CORPORATION: Yes [ ] No [X] CONSUMERS ENERGY COMPANY: Yes [ ] No [X]
Indicate the number of shares outstanding of each of the issuer's classes of
common stock at OctoberApril 30, 2006:2007:
CMS ENERGY CORPORATION:
CMS Energy Common Stock, $.01 par value 222,434,688224,497,687
CONSUMERS ENERGY COMPANY, $10 par value,
privately held by CMS Energy Corporation 84,108,789
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CMS ENERGY CORPORATION
AND
CONSUMERS ENERGY COMPANY
QUARTERLY REPORTS ON FORM 10-Q TO THE
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
FOR THE QUARTER ENDED SEPTEMBER 30, 2006MARCH 31, 2007
This combined Form 10-Q is separately filed by CMS Energy Corporation and
Consumers Energy Company. Information contained herein relating to each
individual registrant is filed by such registrant on its own behalf.
Accordingly, except for its subsidiaries, Consumers Energy Company makes no
representation as to information relating to any other companies affiliated with
CMS Energy Corporation.
TABLE OF CONTENTS
Page
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Glossary.............................................................Glossary ............................................................ 3
PART I:I - FINANCIAL INFORMATION
Item 1. Financial Statements
CMS Energy Corporation
Consolidated Statements of Income (Loss) ...................... CMS - 29
Consolidated Statements of Cash Flows ......................... CMS - 31
Consolidated Balance Sheets ................................... CMS - 32
Consolidated Statements of Common Stockholders' Equity ........ CMS - 34
Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies ............... CMS - 37
2. Asset Sales, Discontinued Operations and Impairment
Charges ................................................ CMS - 39
3. Contingencies ............................................. CMS - 43
4. Financings and Capitalization ............................. CMS - 58
5. Earnings Per Share ........................................ CMS - 60
6. Financial and Derivative Instruments ...................... CMS - 61
7. Retirement Benefits ....................................... CMS - 65
8. Income Taxes .............................................. CMS - 66
9. Asset Retirement Obligations .............................. CMS - 68
10. Equity Method Investments ................................. CMS - 70
11. Reportable Segments ....................................... CMS - 71
Consumers Energy Company
Consolidated Statements of Income ............................. CE - 22
Consolidated Statements of Cash Flows ......................... CE - 23
Consolidated Balance Sheets ................................... CE - 24
Consolidated Statements of Common Stockholder's Equity ........ CE - 26
Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies ............... CE - 29
2. Contingencies ............................................. CE - 30
3. Financings and Capitalization ............................. CE - 41
4. Financial and Derivative Instruments ...................... CE - 43
5. Retirement Benefits ....................................... CE - 45
6. Asset Retirement Obligations .............................. CE - 46
7. Income Taxes .............................................. CE - 48
8. Reportable Segments ....................................... CE - 50
1
TABLE OF CONTENTS
(CONTINUED)
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
CMS Energy Corporation
Executive Overview............................................. CMS - 1
Forward-Looking Statements and Information..................... CMS - 32
Results of Operations.......................................... CMS - 5
Critical Accounting Policies................................... CMS - 1611
Capital Resources and Liquidity................................ CMS - 2115
Outlook........................................................ CMS - 2317
Implementation of New Accounting Standards..................... CMS - 3426
New Accounting Standards Not Yet Effective..................... CMS - 34
Consolidated Financial Statements
Consolidated Statements of Income (Loss)....................... CMS - 36
Consolidated Statements of Cash Flows.......................... CMS - 39
Consolidated Balance Sheets.................................... CMS - 40
Consolidated Statements of Common Stockholders' Equity......... CMS - 42
Condensed Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies................ CMS - 43
2. Asset Impairment Charges and Sales......................... CMS - 46
3. Contingencies.............................................. CMS - 48
4. Financings and Capitalization.............................. CMS - 66
5. Earnings Per Share......................................... CMS - 68
6. Financial and Derivative Instruments....................... CMS - 69
7. Retirement Benefits........................................ CMS - 76
8. Asset Retirement Obligations............................... CMS - 78
9. Executive Incentive Compensation........................... CMS - 80
10. Equity Method Investments.................................. CMS - 83
11. Reportable Segments ....................................... CMS - 84
1
TABLE OF CONTENTS
(CONTINUED)
Page
--------
27
Consumers Energy Company
Management's Discussion and Analysis
Executive Overview............................................. CE - 1
Forward-Looking Statements and Information..................... CE - 2
Results of Operations.......................................... CE - 5
Critical Accounting Policies................................... CE - 128
Capital Resources and Liquidity................................ CE - 1611
Outlook........................................................ CE - 1813
Implementation of New Accounting Standards..................... CE - 2720
New Accounting Standards Not Yet Effective..................... CE - 27
Consolidated Financial Statements
Consolidated Statements of Income (Loss)....................... CE - 30
Consolidated Statements of Cash Flows.......................... CE - 31
Consolidated Balance Sheets.................................... CE - 32
Consolidated Statements of Common Stockholder's Equity......... CE - 34
Condensed Notes to Consolidated Financial Statements (Unaudited):
1. Corporate Structure and Accounting Policies................. CE - 37
2. Contingencies............................................... CE - 3921
Item 3. Financings and Capitalization............................... CE - 53
4. Financial and Derivative Instruments........................ CE - 55
5. Retirement Benefits......................................... CE - 60
6. Asset Retirement Obligations................................ CE - 62
7. Executive Incentive Compensation............................ CE - 64
8. Reportable Segments......................................... CE - 67 Quantitative and Qualitative Disclosures about Market
Risk...........Risk........................................................... CO - 1
Item 4. Controls and Procedures..............................................Procedures................................... CO - 1
PART II:II - OTHER INFORMATION
Item 1. Legal Proceedings........................................ CO - 21
Item 1A. Risk Factors............................................. CO - 56
Item 2. Unregistered Sales of Equity Securities and Use of
Proceeds..............................................Proceeds....................................................... CO - 78
Item 3. Defaults Upon Senior Securities.......................... CO - 8
Item 4. Submission of Matters to a Vote of Security Holders...... CO - 8
Item 5. Other Information........................................ CO - 8
Item 6. Exhibits................................................. CO - 89
Signatures........................................................ CO - 910
2
GLOSSARY
Certain terms used in the text and financial statements are defined below
AFUDC............................AFUDC.............................. Allowance for Funds Used During
Construction
ALJ..............................ALJ................................ Administrative Law Judge
APB..............................AOC................................ Administrative Order on Consent
AOCL............................... Accumulated Other Comprehensive Loss
APB................................ Accounting Principles Board
APB Opinion No. 18...............18................. APB Opinion No. 18, "The Equity Method of
Accounting for Investments in Common
Stock"
ARO..............................ARO................................ Asset retirement obligation
Bay Harbor....................... aHarbor......................... A residential/commercial real estate area
located near Petoskey, Michigan. In 2002,
CMS Energy sold its interest in Bay
Harbor.
bcf..............................bcf................................ One billion cubic feet of gas
Big Rock.........................Rock........................... Big Rock Point nuclear power plant
owned by
Consumers
Board of Directors............... Board of Directors of CMS Energy
CEO..............................CEO................................ Chief Executive Officer
CFO..............................CFO................................ Chief Financial Officer
CFTC.............................CFTC............................... Commodity Futures Trading Commission
CKD................................ Cement Kiln Dust
Clean Air Act....................Act...................... Federal Clean Air Act, as amended
CMS Energy.......................Energy......................... CMS Energy Corporation, the parent of
Consumers and Enterprises
CMS Energy Common Stock or common
stock..................stock........................... Common stock of CMS Energy, par value $.01
per share
CMS ERM..........................ERM............................ CMS Energy Resource Management Company,
formerly CMS MST, a subsidiary of
Enterprises
CMS Field Services...............Services................. CMS Field Services, Inc., formerly a
wholly owned subsidiary of CMS Gas
Transmission. The sale of this subsidiary
closed in July 2003.
CMS Gas Transmission.............Transmission............... CMS Gas Transmission Company, a wholly
owned subsidiary of Enterprises
CMS Midland......................Generation..................... CMS Midland Inc.Generation Co., a wholly owned
subsidiary of Enterprises
CMS International Ventures......... CMS International Ventures LLC, a
subsidiary of Consumers
that has a 49 percent ownership interest in
the MCV PartnershipEnterprises
CMS Midland Holdings Company..... CMS Midland Holdings Company, a subsidiary
of Consumers that has a 46 percent ownership
interest in First Midland Limited
Partnership and a 35 percent lessor interest
in the MCV Facility
CMS MST..........................MST............................ CMS Marketing, Services and Trading
Company, a wholly owned subsidiary of
Enterprises, whose name was changed to CMS
ERM effective January 2004
CMS Oil and Gas.................. CMS Oil and Gas Company, formerly a
subsidiary of Enterprises
Consumers........................Consumers.......................... Consumers Energy Company, a subsidiary of
CMS Energy
CPEE............................. Companhia Paulista de Energia Eletrica, a
subsidiary of Enterprises
3
Customer Choice Act..............Act................ Customer Choice and Electricity
Reliability Act, a Michigan statute
enacted in June 2000
DCCP.............................DCCP............................... Defined Company Contribution Plan
Detroit Edison...................Edison..................... The Detroit Edison Company, a
non-affiliated company
DIG..............................DFD................................ Duke/Fluor Daniel, a non-affiliated
company
3
DIG................................ Dearborn Industrial Generation, LLC, an
indirect wholly owned subsidiary of CMS
Energy
DOE..............................DOE................................ U.S. Department of Energy
DOJ..............................DOJ................................ U.S. Department of Justice
Dow..............................Dow................................ The Dow Chemical Company, a non-affiliated
company
DTE Energy....................... DTE Energy Company, a non-affiliated company
EISP.............................EISP............................... Executive Incentive Separation Plan
EITF.............................EITF............................... Emerging Issues Task Force
EITF Issue No. 02-03.............02-03............... Issues Involved in Accounting for
Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy
Trading and Risk Management Activities
Entergy..........................El Chocon.......................... The 1,200 MW hydro power plant located in
Argentina, in which CMS Generation held a
17.2 percent ownership interest
Entergy............................ Entergy Corporation, a non-affiliated
company
Enterprises......................Enterprises........................ CMS Enterprises Company, a subsidiary of
CMS Energy
EPA.............................. U. S.EPA................................ U.S. Environmental Protection Agency
EPS..............................EPS................................ Earnings per share
ERISA............................ Employee Retirement Income Security Act
Exchange Act.....................Act....................... Securities Exchange Act of 1934, as
amended
FASB.............................FASB............................... Financial Accounting Standards Board
FERC............................... Federal Energy Regulatory Commission
FIN 14............................. FASB Interpretation No. 14, Reasonable
Estimation of the Amount of a Loss
FIN 46(R).............................. Revised FASB Interpretation No. 46,
Consolidation of Variable Interest
Entities
FERC............................. Federal Energy Regulatory Commission
FIN 47...........................47............................. FASB Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations
FIN 48...........................48............................. FASB Interpretation No. 48, Uncertainty in
Income Taxes
FMB.............................. First Mortgage Bonds
FMLP.............................FMLP............................... First Midland Limited Partnership, a
partnership that holds a lessor interest
in the MCV Facility
and an indirect subsidiary
of Consumers
FTR.............................. Financial transmission right
GAAP.............................GAAP............................... Generally Accepted Accounting Principles
GasAtacama.......................GasAtacama......................... GasAtacama Holding Limited, a limited
liability partnership that manages
GasAtacama S.A., which includes an
integrated natural gas pipeline and
electric generating plant located in
Argentina and Chile and Atacama Finance
Company.
GCR..............................Company
GCR................................ Gas cost recovery
GVK.............................. GVK Facility, a 250 MW gas fired power plant
located in South Central India, in which CMS
Generation formerly held a 33 percent
interest
ISFSI............................IRS................................ Internal Revenue Service
ISFSI.............................. Independent Spent Fuel Storage Installation
IRS.............................. Internal Revenue Service
4
ITC.............................. ITC Holdings Corporation
Jorf Lasfar......................Lasfar........................ The 1,356 MW coal-fueled power plant in
Morocco
jointly owned by CMS Generation and
ABB Energy Ventures, Inc.
Jubail...........................Jubail............................. A 240 MW natural gas cogeneration power
plant located in Saudi Arabia, in which
CMS Generation ownsowned a 25 percent interest
kWh..............................kWh................................ Kilowatt-hour (a unit of powerenergy equal to
one thousand watt hours)
Ludington........................Lucid Energy....................... Lucid Energy LLC, a non-affiliated company
4
Ludington.......................... Ludington pumped storage plant, jointly
owned by Consumers and Detroit Edison
mcf..............................mcf................................ One thousand cubic feet of gas
MCV Facility.....................Facility....................... A natural gas-fueled, combined-cycle
cogeneration facility operated by the MCV
Partnership
MCV Partnership..................Partnership.................... Midland Cogeneration Venture Limited
Partnership
in which Consumers has a 49
percent interest through CMS Midland
MCV PPA..........................PPA............................ The Power Purchase Agreement between
Consumers and the MCV Partnership with a
35-year term commencing in March 1990, as
amended, and as interpreted by the
Settlement Agreement dated as of January
1, 1999 between the MCV Partnership and
Consumers.Consumers
MD&A.............................&A............................... Management's Discussion and Analysis
MDEQ.............................MDEQ............................... Michigan Department of Environmental
Quality
METC.............................MDL................................ Multidistrict Litigation
METC............................... Michigan Electric Transmission Company,
LLC, Midwest Energy Market............ An energy market developed by the MISO to
provide day-ahead and real-time market
information and centralized dispatch for
market participants
MISO.............................a non-affiliated company
MISO............................... Midwest Independent Transmission System
Operator, Inc.
MMBtu............................MMBtu.............................. Million British Thermal Units
Moody's..........................Moody's............................ Moody's Investors Service, Inc.
MPSC.............................MPSC............................... Michigan Public Service Commission
MRV.............................. Market-Related Value of Plan assets
MSBT.............................MSBT............................... Michigan Single Business Tax
MW...............................MW................................. Megawatt (a unit of power equal to one
million watts)
NEIL.............................MWh................................ Megawatt hour (a unit of energy equal to
one million watt hours)
NEIL............................... Nuclear Electric Insurance Limited, an
industry mutual insurance company owned by
member utility companies
Neyveli..........................Neyveli............................ CMS Generation Neyveli Ltd, a 250 MW
lignite-fired power station located in
Neyveli, Tamil Nadu, India, in which CMS
International Ventures holdsheld a 50 percent
interest
NMC..............................NMC................................ Nuclear Management Company LLC, formed in
1999 by Northern States Power Company (now
Xcel Energy Inc.), Alliant Energy,
Wisconsin Electric Power Company, and
Wisconsin Public Service Company to
operate and manage nuclear generating
facilities owned by the four utilities
NOL.............................. Net Operating Loss
NRC.............................. Nuclear Regulatory Commission
5
NYMEX............................NRC................................ Nuclear Regulatory Commission
NYMEX.............................. New York Mercantile Exchange
OPEB.............................OPEB............................... Postretirement benefit plans other than
pensions for retired employees
Palisades........................Palisades.......................... Palisades nuclear power plant
which is
owned by Consumers
Panhandle........................Panhandle.......................... Panhandle Eastern Pipe Line Company,
including its subsidiaries Trunkline, Pan
Gas Storage, Panhandle Storage, and
Panhandle Holdings. Panhandle was a wholly
owned subsidiary of CMS Gas Transmission.
The sale of this subsidiary closed in June
2003.
PCB..............................PCB................................ Polychlorinated biphenyl
5
Peabody Energy...................Energy..................... Peabody Energy Corporation, a
non-affiliated company
Pension Plan.....................Plan....................... The trusteed, non-contributory, defined
benefit pension plan of Panhandle,
Consumers and CMS Energy
PJM RTO.......................... Pennsylvania-Jersey-Maryland Regional
Transmission OrganizationPowerSmith......................... A 124 MW natural gas power plant located
in Oklahoma City, Oklahoma, in which CMS
Generation holds a 6.25% limited partner
ownership interest
Price-Anderson Act...............Act................. Price Anderson Act, enacted in 1957 as an
amendment to the Atomic Energy Act of
1954, as revised and extended over the
years. This act stipulates between nuclear
licensees and the U.S. government the
insurance, financial responsibility, and
legal liability for nuclear accidents.
PSCR.............................PSCR............................... Power supply cost recovery
PURPA............................PURPA.............................. Public Utility Regulatory Policies Act of
1978
RCP..............................Quicksilver........................ Quicksilver Resources, Inc., a
non-affiliated company
RCP................................ Resource Conservation Plan
ROA..............................ROA................................ Retail Open Access
SAB No. 107...................... Staff Accounting Bulletin No. 107,
Share-Based Payment
SEC..............................S&P................................ Standard & Poor's Ratings Group, a
division of The McGraw-Hill Companies,
Inc.
SEC................................ U.S. Securities and Exchange Commission
Section 10d(4) Regulatory Asset..Asset.... Regulatory asset as described in Section
10d(4) of the Customer Choice Act, as
amended
Securitization...................Securitization..................... A financing method authorized by statute
and approved by the MPSC which allows a
utility to sell its right to receive a
portion of the rate payments received from
its customers for the repayment of
Securitization bonds issued by a special
purpose entity affiliated with such
utility
SENECA...........................SENECA............................. Sistema Electrico del Estado Nueva Esparta
C.S.C.A., a former subsidiary of Enterprises
SERP.............................SERP............................... Supplemental Executive Retirement Plan
SFAS.............................SFAS............................... Statement of Financial Accounting
Standards
SFAS No. 5.......................5......................... SFAS No. 5, "Accounting for Contingencies"
SFAS No. 71...................... SFAS No. 71, "Accounting for the Effects of
Certain Types of Regulation"
SFAS No. 87......................87........................ SFAS No. 87, "Employers' Accounting for
Pensions"
SFAS No. 88......................88........................ SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination
Benefits"
SFAS No. 98......................98........................ SFAS No. 98, "Accounting for Leases"
SFAS No. 98, "Accounting for Leases"
6
SFAS No. 106.....................106....................... SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than
Pensions"
SFAS No. 115.....................109....................... SFAS No. 109, "Accounting for Income
Taxes"
SFAS No. 115....................... SFAS No. 115, "Accounting for Certain
Investments in Debt and Equity Securities"
SFAS No. 123(R).................. SFAS No. 123 (revised 2004), "Share-Based
Payment"
SFAS No. 132(R)...................................... SFAS No. 132 (revised 2003), "Employers'
Disclosures about Pensions and Other
Postretirement Benefits"
SFAS No. 133.....................133....................... SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities, as
amended and interpreted"
SFAS No. 143.....................143....................... SFAS No. 143, "Accounting for Asset
Retirement Obligations"
6
SFAS No. 143,144....................... SFAS No. 144, "Accounting for Asset
Retirement Obligations"the
Impairment or Disposal of Long-Lived
Assets"
SFAS No. 157.....................157....................... SFAS No. 157, "Fair Value Measurement"
SFAS No. 158.....................158....................... SFAS No. 158, "Employers' Accounting for
Defined Benefit Pension and Other
Postretirement Plans - an amendment of
FASB Statements No. 87, 88, 106, and
132(R)"
Shuweihat........................SFAS No. 159....................... SFAS No. 159, "The Fair Value Option for
Financial Assets and Financial
Liabilities, Including an amendment to
FASB Statement No. 115"
Shuweihat.......................... A power and desalination plant of Emirates
CMS Power Company, in which
CMS Generation holdsheld a 20 percent interest
SLAP............................. Scudder Latin American Power Fund
Special Committee................ A special committee of independent
directors, established by CMS Energy's Board
of Directors, to investigate matters
surrounding round-trip trading
Stranded Costs...................Costs..................... Costs incurred by utilities in order to
serve their customers in a regulated
monopoly environment, which may not be
recoverable in a competitive environment
because of customers leaving their systems
and ceasing to pay for their costs. These
costs could include owned and purchased
generation and regulatory assets.
Superfund........................Superfund.......................... Comprehensive Environmental Response,
Compensation and Liability Act
Takoradi.........................Takoradi........................... A 200 MW open-cycle combustion turbine
crude oil power plant located in Ghana, in
which CMS Generation ownsowned a 90 percent
interest
Taweelah.........................TAQA............................... Abu Dhabi National Energy Company, a
subsidiary of Abu Dhabi Water and
Electricity Authority
Taweelah........................... Al Taweelah A2, a power and desalination
plant of Emirates CMS Power Company, in
which CMS Generation holdsheld a 40 percent
interest
TGM................................ A natural gas transportation and pipeline
business located in Argentina, in which
CMS International Ventures owned a 20
percent interest
TGN................................ A natural gas transportation and pipeline
business located in Argentina, in which
CMS Gas Transmission owns a 23.54 percent
interest
Trunkline.......................... CMS Trunkline Gas Company, LLC, formerly a
subsidiary of CMS Panhandle Holdings, LLC
7
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8
CMS Energy Corporation
CMS ENERGY CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS
This MD&A is a consolidated report of CMS Energy and Consumers. The terms "we"
and "our" as used in this report refer to CMS Energy and its subsidiaries as a
consolidated entity, except where it is clear that such term means only CMS
Energy. This MD&A has been prepared in accordance with the instructions to Form
10-Q and Item 303 of Regulation S-K. This MD&A should be read in conjunction
with the MD&A contained in CMS Energy's Form 10-K/A Amendment No. 110-K for the year ended December
31, 2005.2006.
EXECUTIVE OVERVIEW
CMS Energy is an energy company operating primarily in Michigan. We are the
parent holding company of Consumers and Enterprises. Consumers is a combination
electric and gas utility company serving Michigan's Lower Peninsula.
Enterprises, through various subsidiaries and equity investments, is engaged in
domestic and international diversified energy businesses including independent power
production, electric distribution, and natural gas transmission, storage, and
processing. We manage our businesses by the nature of services each provides and
operate principally in three business segments: electric utility, gas utility,
and enterprises.
We earn our revenue and generate cash from operations by providing electric and
natural gas utility services, electric power generation, and gas distribution,
transmission, storage, and processing. Our businesses are affected primarily by:
- weather, especially during the normal heating and cooling seasons,
- economic conditions, primarily in Michigan,
- regulation and regulatory issues that affect our electric and gas
utility operations,
- energy commodity prices,
- interest rates, and
- our debt credit rating.
During the past several years, our business strategy has involved improving our
consolidated balance sheet and maintaining focus on our core strength: utility
operations and service.
Our primary focus with respect to our non-utility businesses has been
to optimize cash flow and further reduce our business risk and leverage through
the sale of selected assets, and to improve earnings and cash flow from the
businessesIn April 2007, we retain.
In July 2006, we reached an agreement to sell thesold Palisades nuclear plant to Entergy for $380 million. The final purchase
price was subject to various closing adjustments resulting in us receiving $361
million. We also signedpaid Entergy $30 million to assume ownership and responsibility
for the Big Rock Independent Spent Fuel Storage Installation (ISFSI). We entered
into a 15-year power purchase agreement with Entergy for 100 percent of the
plant's current electric output. We are targeting to close
theThe sale by May 1, 2007. When completed, the sale will resultresulted in an immediate improvement
in our cash flow, a reduction in our nuclear operating and decommissioning risk,
and an improvement in our financial flexibility to support other utility
investments. We expectThe MPSC order approving the transaction requires that a significant portion$255 million
be credited to our retail customers through refunds applied over the remainder
of 2007 and 2008.
CMS-1
CMS Energy Corporation
In 2007, we intend to complete the proceeds
will benefitsale of our customers.non-North American Enterprises
assets. We plan to use the cash thatproceeds from these sales to retire debt and to
invest in our utility business.
In March 2007, we retain fromcompleted the sale to reduce utility debt.
We are working to reduce parent debt. In 2006, we retired $76 million of CMS
Energy 9.875 percent senior notes. We also invested $200 milliona portfolio of our businesses in
Consumers,Argentina and Consumers extinguished, through a legal defeasance, $129 million of 9
percent related party notes.
CMS-1
CMS Energy Corporation
Working capital and cash flow continue to be a challenge for us asour northern Michigan non-utility natural gas prices continueassets to be volatile. Although our natural gas purchases are
recoverable from our utility customers, higher priced natural gas stored as
inventory requires additional liquidity due to the lag in cost recovery.Lucid
Energy for $130 million. In addition to causing working capital issues for us, historically high natural
gas prices caused the MCV Partnership to reevaluate the economics of operating
the MCV Facility and to record an impairment charge in 2005. If gas prices
increase from their current levels, it could result in a further impairment ofMarch 2007, we also sold our interest in El Chocon,
an Argentine hydroelectric generating business, to Endesa, S.A. for $50 million.
We used the MCV Partnership.
Duecash proceeds to the impairment of the MCV Facilityinvest in our utility business and operating losses from
mark-to-market adjustments on derivative instruments, the equity held by a
Consumers' subsidiary and the other minority interest owners in the MCV
Partnership has decreased significantly and is now negative. As the MCV
Partnership recognizes future losses,reduce debt.
In April 2007, we will assume an additional seven percent
of the MCV Partnership's negative equity, which is a portion of the limited
partners' negative equity, in addition to our proportionate share.
In July 2006, we reachedentered into an agreement to sell our interests in the MCV
Partnership and the FMLP.CMS Energy Brasil S.A. for
$211 million to CPFL Energia S.A., a Brazilian utility. The sale is subjectexpected to
various regulatory approvals
including the MPSC. If the sale closesclose by the end of 2006, as expected, it will
have a $56 million positive impact onthe second quarter of 2007, subject to approval by the
Brazilian national electric utility regulatory agency.
In April 2007, we completed the sale of our 2006 cash flow. Theownership interest in SENECA and
certain associated generating equipment to Petroleos de Venezuela, S.A. for
$106 million.
In May 2007, we completed the sale will reduceof our exposureownership interest in businesses in
the Middle East, Africa, and India to sustained high natural gas prices.TAQA for $900 million. We willplan to use the
proceeds to invest in our utility business and reduce utility debt.
IfIn addition, during 2007, we plan to conduct an auction to sell our GasAtacama
combined gas pipeline and power generation businesses in Argentina and Chile,
and our electric generating plant in Jamaica. For additional details on our
planned asset sales, see the sale"Enterprises Outlook" section within this MD&A.
In January 2007, we took an important step in our business plan by reinstating a
dividend on our common stock after a four-year suspension at $0.05 per share. We
paid $11 million in common stock dividends in February 2007. We also took steps
toward resolving a long-outstanding litigation issue. In January 2007, we
reached a preliminary agreement to settle two class action lawsuits related to
round-trip trading by CMS MST. We believe that eliminating this business
uncertainty is not completed,in the viabilitybest interests of our shareholders.
In the MCV
Facility is still in question.
Going forward,future, we will focus our strategy will continue to focus on:
- managing cash flow issues,continued investment in our utility business,
- successful completion of announced asset sales,
- reducing parent company debt, and
- growing earnings - reducing risk, and
- positioning us to make investments that complement our strengths.
We continue to pursue opportunities and options for our Enterprises business,
both opportunities for beneficial asset sales and development opportunities that
enhance value. In October 2006, we signed agreements with Peabody Energy to
co-develop, construct, operate, and indirectly own 15 percent of the Prairie
State Energy Campus, a 1,600 MW power plant and coal mine in southern Illinois.
This project complements our expertise in power plant construction and operation
and will enhance future earnings with acceptable financial risk.while controlling operating costs.
As we execute our strategy, we will need to overcome a sluggish Michigan economy
that has been hampered by negative developments in Michigan's automotive
industry and limited growth in the non-automotive sectors of the state's
economy. TheseThe return of ROA customer load has offset some of these negative
effects will be offset somewhat by the reduction we are
experiencing in ROA load in our service territory.effects. At September 30, 2006,March 31, 2007, alternative electric suppliers were providing 308283 MW
of generation service to ROA customers. This is four3 percent of our total
distribution load and represents a decrease of 6019 percent of ROA load compared
to the end of September
2005. It is, however, difficult to predict future ROA customer trends.
CMS-2
CMS Energy CorporationMarch 31, 2006.
FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-Q and other written and oral statements that we make contain
forward-looking statements as defined in Rule 3b-6 under the Securities Exchange
Act of 1934, as amended, Rule 175 under the Securities Act of 1933, as amended,
and relevant legal decisions. Our intention with the use of such words as "may,"
"could," "anticipates," "believes," "estimates," "expects," "intends," "plans,"
and other similar words is to identify forward-looking statements that involve
risk and uncertainty. We designed this
CMS-2
CMS Energy Corporation
discussion of potential risks and uncertainties to highlight important factors
that may impact our business and financial outlook. We have no obligation to
update or revise forward-looking statements regardless of whether new
information, future events, or any other factors affect the information
contained in the statements. These forward-looking statements are subject to
various factors that could cause our actual results to differ materially from
the results anticipated in these statements. Such factors include our inability
to predict and (or) control:
- the price of CMS Energy Common Stock, capital and financial market
conditions, and the effect of such market conditions on the Pension
Plan, interest rates, and access to the capital markets, including
availability of financing to CMS Energy, Consumers, or any of their
affiliates, and the energy industry,
- market perception of the energy industry, CMS Energy, Consumers, or
any of their affiliates,
- credit ratings of CMS Energy, Consumers, or any of their affiliates,
- currency fluctuations, transfer restrictions, and exchange controls,
- factors affecting utility and diversified energy operations, such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs, environmental
incidents, or electric transmission or gas pipeline system
constraints,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including those related to
environmental laws and regulations, and potential environmental
remediation costs associated with such decisions, including but not
limited to Bay Harbor,
- potentially adverse regulatory treatment and (or) regulatory lag
concerning a number of significant questions presently before the MPSC
including:
- recovery of Clean Air Act capital and operating costs and other
environmental and safety-related expenditures,
- power supply and natural gas supply costs when fuel prices are
increasing and (or) fluctuating,
- timely recognition in rates of additional equity investments in
Consumers,
- adequate and timely recovery of additional electric and gas
rate-based investments,
- adequate and timely recovery of higher MISO energy and
transmission costs,
- recovery of Stranded Costs incurred due to customers choosing
alternative energy suppliers,
- recovery of Palisades plant sale-related costs, and
- sales of the Palisades plant and our interest in the MCV
Partnership,
CMS-3
CMS Energy Corporation
- the impact of adverse naturalpossible regulation or legislation regarding carbon
dioxide and other greenhouse gas prices on the MCV Partnership and
the FMLP investments, regulatory decisions that limit recovery of
capacity and fixed energy payments, and our ability to complete the
sale of our interests in the MCV Partnership and the FMLP,
- the negative impact on the MCV Partnership's financial performance, if
Consumers is successful in exercising the regulatory out provision of
the MCV PPA, and if the sale of our interests in the MCV Partnership
and the FMLP is not completed,emissions,
- the effects on our ability to purchase capacity to serve our customers
and fully recover the cost of these purchases, if Consumers exercises
its regulatory out rights and the owners of the MCV Partnership exercises itsFacility exercise
their right to terminate the MCV PPA,
- federal regulation of electric sales and transmission of electricity,
including periodic re-examination
CMS-3
CMS Energy Corporation
by federal regulators of the market-based sales authorizations in
wholesale power markets without price restrictions,
- energy markets, including availability of capacity and the timing and
extent of changes in commodity prices for oil, coal, natural gas,
natural gas liquids, electricity and certain related products due to
lower or higher demand, shortages, transportation costs problems, or
other developments,
- our ability to collect accounts receivable from our customers,
- potential for the Midwest Energy Market to develop into an active
energy market in the stateearnings volatility as a result of Michigan, which may require us to
account for certain electric energy contracts as derivatives,
- the GAAP requirement that we
utilize mark-to-market accounting on certain energy commodity
contracts and interest rate swaps, which may have, in any given
period, a significant positive or negative effect on earnings, which
could change dramatically or be eliminated in subsequent periods, and could add to earnings volatility,
- the effect on our electric utility of the direct and indirect impacts
of the continued economic downturn experienced by our automotive and
automotive parts manufacturing customers,
- potential disruption, expropriation or interruption of facilities or
operations due to accidents, war, terrorism, or changing political
conditions, and the ability to obtain or maintain insurance coverage
for such events,
- changes in available gas supplies or Argentine government regulations
that could further restrict natural gas exports to our GasAtacama
electric generating plant and the operating and financial effects of
the restrictions, including further impairment of our investment in
GasAtacama,
- nuclear power plant performance, operation, decommissioning, policies,
procedures, incidents, and regulation, including the availabilityoutcome of pending litigation regarding the DOE liability for
spent nuclear fuel storage during former ownership and operation of
nuclear power plants,
- technological developments in energy production, delivery, and usage,
- achievement of capital expenditure and operating expense goals,
- changes in financial or regulatory accounting principles or policies,
CMS-4
CMS Energy Corporation
- changes in domestic or foreign tax laws, or new IRS or foreign
governmental interpretations of existing or past tax laws,
- outcome, cost, and other effects of legal and administrative
proceedings, settlements, investigations and claims, including
particularly claims, damages, and fines resulting from round-trip
trading and inaccurate commodity price reporting, including the
outcome of shareholder actions and investigations by the DOJ regarding round-trip trading and
price reporting,
- limitations on our ability to control the development or operation of
projects in which our subsidiaries have a minority interest,
- disruptions in the normal commercial insurance and surety bond markets
that may increase costs or reduce traditional insurance coverage,
particularly terrorism and sabotage insurance and performance bonds,
CMS-4
CMS Energy Corporation
- the ability to efficiently sell assets when deemed appropriate or
necessary, including the sale of non-strategic or under-performing
domestic or international assets and discontinuation of certain
operations,
- other business or investment considerations that may be disclosed from
time to time in CMS Energy's or Consumers' SEC filings, or in other
publicly issued written documents,
- the successful close of the proposed sale of CMS Energy Brasil S.A.,
- the outcome of the planned sales of other generation and distribution
assets in Latin America, and
- other uncertainties that are difficult to predict, many of which are
beyond our control.
For additional information regarding these and other uncertainties, see the
"Outlook" section included in this MD&A, Note 3, Contingencies, and Part II,
Item 1A. Risk Factors.
RESULTS OF OPERATIONS
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for
per share amounts)
------------------------
Three months ended September 30March 31 2007 2006 2005 Change
- ------------------------------- ------ --------------------------------- ---- ---- ------
Net Loss Available to Common Stockholders $ (103)(215) $ (265)(27) $ 162(188)
Basic EarningsLoss Per Share $(0.47) $(1.21) $0.74$(0.97) $(0.12) $(0.85)
Diluted EarningsLoss Per Share $(0.47) $(1.21) $0.74$(0.97) $(0.12) $(0.85)
------ ------ -----------
Electric Utility $ 9351 $ 6229 $ 3122
Gas Utility (20) (16) (4)57 37 20
Enterprises (Includes the MCV Partnership and
the FMLP interests) (132) (260) 128(187) (58) (129)
Corporate Interest and Other (45) (51) 644 (43) 87
Discontinued Operations 1 - 1(180) 8 (188)
------ ------ -----------
Net Loss Available to Common Stockholders $ (103)(215) $ (265)(27) $ 162(188)
====== ====== ===========
For the three months ended September 30, 2006,March 31, 2007, our net loss available to common
stockholders was $103$215 million, compared to a net loss of $265$188
million for 2005.
The decreased net loss primarily reflects a lower asset impairment charge in
2006 versus 2005. Inworse than 2006. Compared with the thirdfirst quarter of 2006, we recordednet income
from our electric and gas utility segments increased a combined $42 million,
reflecting benefits from a recent MPSC gas rate case order and favorable weather
impacts, offset slightly by higher depreciation expense associated with
increased plant investment and planned operating expenses. The positive utility
results were more than offset by results at our other operating segments, as
losses on asset sales and impairment charges more than offset the net assetimpact of
mark-to-market activities and the impact of various tax issues.
CMS-5
CMS Energy Corporation
impairment charge of $169 million on our investment in GasAtacama compared to a
net impairment charge of $385 million associated with the MCV Partnership
recorded in 2005. Also contributing to the improvement was the positive impact
at our electric utility due to increased revenue from an electric rate order,
the return to full service-rates of customers previously using alternative
energy suppliers, and the expiration of rate caps in December 2005. These
improvements were offset partially by mark-to-market losses on long-term gas
contracts and associated hedges at the MCV Partnership, which partially reduced
gains reported in 2005, an increased loss at our gas utility primarily due to a
reduction in deliveries resulting from customer conservation, and mark-to-market
losses recorded in 2006 at CMS ERM and Taweelah versus gains recorded in 2005.
Specific changes to the net loss available to common stockholders for the three
months ended September 30,March 31, 2007 versus 2006 versus 2005 were:are:
In Millions
-----------
- - reductionimpact of activities associated with discontinued operations
as the loss on the disposal of our Argentine businesses and
non-utility Michigan gas assets in March 2007 and lower
earnings from discontinued businesses expected to be sold
during the remainder of 2007 replaced earnings recorded for
these businesses in 2006, $(188)
- - asset impairment charges as we recorded a $169
million impairment onprimarily related to our GasAtacama investmentinvestments
in 2006 versus
a $385 million impairment charge associated with the MCV
Partnership in 2005, $216TGN, Powersmith and Jamaica, (157)
- - increasetax provision on the cumulative undistributed earnings of
foreign subsidiaries at Enterprises that are expected to be
sold in net income from our electric utility primarily due
to an increase in revenue from an electric rate order, the
return to full service-rates of customers previously using
alternative energy suppliers, the expiration of rate caps in
December 2005 offset partially by higher operating expense and
lower deliveries due to milder weather, 31
- - decrease in corporate interest due to reduced interest expense
on lower debts levels in 2006, and the absence of premiums paid
for the repurchase of a portion of our CMS 9.875 percent senior
notes in 2005, offset partially by an increase in legal fees, 62007, (43)
- - decrease in earnings from other activities at the MCV
Partnership as mark-to-market losses on long-term gas contracts
and associated hedges, which partially reduced gains recorded
in 2005, more than offset the recognition of a property tax
refund, (39)
- - mark-to-market losses at CMS ERM in 2006 versus gains in 2005, (17)
- - decrease in net income from equity earningsmethod investees at
Enterprises primarily due to mark-to-market lossesreduced earnings at Jorf Lasfar,
Taweelah in 2006
versus gains in 2005, (17)and GasAtacama, (11)
- - absencereversal of incomecorporate deferred tax benefits recordedvaluation allowances
associated with capital loss carryforwards and foreign basis
differences related to international operations that are
expected to be sold in 2005 at Enterprises
resulting from the American Jobs Creation Act of 2004, (10)
- - additional decrease in net income from Enterprises primarily
due to a loss on the termination of prepaid gas contracts and
higher maintenance expense, and (4)2007, 81
- - decrease in net incomelosses from our ownership interest in the MCV
Partnership primarily due to the absence, in 2007, of
mark-to-market losses on certain long-term gas contracts and
financial hedges, 57
- - increase in earnings at our Electric utility primarily due to
a reductionweather driven increase in deliveries, resulting from increased customer
conservation efforts and the effect of the annual unbilled gas
volume analysis, which resulted in a decrease of accrued gas
revenues in 2006 compared to increase in accrued gas revenues
in 2005. (4)
----
Total Change $162
====
CMS-6
CMS Energy Corporation
In Millions (except for
per share amounts)
------------------------
Nine months ended September 30 2006 2005 Change
- ------------------------------ ------ ------ ------
Net Loss Available to Common Stockholders $ (58) $ (88) $ 30
Basic Earnings Per Share $(0.26) $(0.42) $0.16
Diluted Earnings Per Share $(0.26) $(0.42) $0.16
------ ------ -----
Electric Utility $ 159 $ 141 $ 18
Gas Utility 14 39 (25)
Enterprises (Includes the MCV Partnership and
the FMLP interests) (177) (126) (51)
Corporate Interest and Other (58) (142) 84
Discontinued Operations 4 - 4
------ ------ -----
Net Loss Available to Common Stockholders $ (58) $ (88) $ 30
====== ====== =====
For the nine months ended September 30, 2006, net loss available to common
stockholders was $58 million compared to a net loss of $88 million for 2005. The
decreased net loss primarily reflects a lower asset impairment charge in 2006
versus 2005. In the third quarter of 2006, we recorded a net impairment charge
of $169 million on our investment in GasAtacama compared to a net impairment
charge of $385 million associated with the MCV Partnership in 2005. Also
contributing to the improvement were the positive impacts at our electric
utility of increased revenue from an electric rate order, the return to full
service-rates of customers previously using alternative energy suppliers, and
the expiration of rate caps in December 2005. Further contributing to the
improvement was a $62 million impact from the resolution of an IRS income tax
audit in 2006. The audit resolution resulted in an increase to net income of $46
million at our corporate interest and other segment, $8 million at Enterprises,
$4 million at the electric utility, $3 million at the gas utility, and $1
million in discontinued operations.
These improvements were offset partially by mark-to-market losses on long-term
gas contracts and associated hedges at the MCV Partnership, which partially
reduced gains reported in 2005. The improvements were also offset partially by
the absence of income tax benefits recorded in 2005 at Enterprises resulting
from the American Jobs Creation Act of 2004, and an increased loss at our gas
utility due to a reduction in deliveries resulting from customer conservation
and warmer weather in 2006.
CMS-7
CMS Energy Corporation
Specific changes to the net loss available to common stockholders for the nine
months ended September 30, 2006 versus 2005 were:
In Millions
-----------
- - reduction in asset impairment charges as we recorded a $169
million impairment on our GasAtacama investment in 2006 versus
a $385 million impairment charge associated with the MCV
Partnership in 2005, $216
- - effects of the resolution of an IRS income tax audit on
corporate and Enterprises income taxes, primarily for the
restoration and the utilization of income tax credits, 5422
- - increase in net income fromearnings at our electricGas utility primarily due to the
positive effects of a recent MPSC gas rate case and an
increase in revenue from an electric rate order, the
return to full service-rates of customers previously using
alternative energy suppliers, the expiration of rate caps in
December 2005 offset partially by higher operating expense and
lower deliveries due to milderthe weather, 1820
- - additional reduction in corporate interest and other expenses
primarily due to lower debt retirement charges, a decrease in
general taxes, and an insurance reimbursement received in June
2006 for previously incurred legal expenses, 38
- - decreaseincrease in earnings from other activities at the MCV
Partnership as mark-to-market losses on long-term gas contracts
and associated hedges, which partially reduced gains recorded
in 2005, more than offset the recognition of a property tax
refund in 2006, (161)
- - mark-to-market losses at CMS ERM in 2006 versus gains in 2005, (57)
- - absence of income tax benefits recorded in 2005 at Enterprises
resulting from the American Jobs Creation Act of 2004, (33)
- - decrease in net income from our gas utility primarily due to a
reduction in deliveries resulting from increased customer
conservation efforts and warmer weather in 2006, and (25)
- - decrease in net income from equity earnings at Enterprises primarily due to the
establishmentrecording of a tax reserve related to
some of our foreign investmentsmark-to-market gains in 2007 versus losses
recorded in 2006, 16
- - net gain on additional Argentine and lower earningsMichigan businesses sold
in March 2007, and 8
- - other miscellaneous benefits at GasAtacama. (20)
----corporate and Enterprises. 7
-----
Total Change $ 30
====$(188)
=====
CMS-8
CMS Energy Corporation
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30March 31 2007 2006 2005 Change
- -------------------- ---- ---- ------
ThreeNet Income for the three months ended $ 93 $ 62 $31
Nine months ended $159 $141 $18
==== ====$51 $29 $22
=== === ===
Three Months Ended Nine Months Ended
September 30, September 30,
Reasons for the change:
2006 vs. 2005 2006 vs. 2005
- -----------------------
------------------ -----------------
Electric deliveries $ 59 $ 178
Power supply costs and related revenue 46 58$24
Other operating expenses,
other income and non-commodity revenue (44) (174)
Regulatory return on capital expenditures (9) (30)9
General taxes (2) (3)(4)
Interest charges (1) (3)1
Income taxes (18) (8)
---- --------
Total change $ 31 $ 18
==== =====$22
===
CMS-6
CMS Energy Corporation
ELECTRIC DELIVERIES: ForIn the three months ended September 30, 2006, electric
deliveries, excluding intersystem sales, decreased 0.3 billion kWh or 2.3
percent versus 2005. For the nine months ended September 30, 2006, electric
deliveries, excluding intersystem sales, decreased 0.6 billion kWh or 2.0
percent versus 2005. The decrease in electric deliveries for both periods is
primarily due to weather. Despite lower electric deliveries, electric delivery
revenue increased primarily due to an electric rate order, increased surcharge
revenue, and the return to full-service ratesfirst quarter of customers previously using
alternative energy suppliers (ROA customer deliveries). These three issues, and
their relative impact on electric delivery revenue, are discussed in the
following paragraphs.
Electric Rate Order: In December 2005, the MPSC issued an order authorizing an
annual rate increase of $86 million for service rendered on and after January
11, 2006. As a result of this order,2007, electric delivery revenues
increased by $24 million forover 2006 as deliveries to end-use customers were 9.5
billion kWh, an increase of 0.2 billion kWh or 2 percent versus 2006. The
increase in electric deliveries was primarily due to colder weather in the three months ended September 30,first
quarter of 2007 versus 2006 and $67 million forresulted in an increase in electric delivery
revenue of $17 million. Average temperatures in the nine months ended September 30, 2006 versusfirst quarter of 2007 were
3.8 degrees colder than the same periods in 2005.
Surcharge Revenue: Effective January 1,period last year.
In the first quarter of 2006, we started collecting a surcharge that the MPSC
authorized under Section 10d(4) of the Customer Choice Act. ThisDue to timing
considerations, this surcharge increased electric delivery revenue by $15$5 million
forin the three
months ended September 30, 2006 and $38 million for the nine months ended
September 30, 2006first quarter of 2007 versus the same periods in 2005. In addition, on January 1,
2006, we began recovering customer choice transition costs from our residential
customers, thereby increasing electric delivery revenue by another $4 million
for the three months ended September 30, 2006 and $9 million for the nine months
ended September 30, 2006 versus the same periods in 2005.
CMS-9
CMS Energy Corporation
ROA Customer Deliveries:2006.
The Customer Choice Act allows all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. At September 30, 2006,March
31, 2007, alternative electric suppliers were providing 308283 MW of generation
service to ROA customers. This amount represents a decrease of 6019 percent of ROA load
compared to the end of September 2005.March 31, 2006. The return of former ROA customers to full-service
rates increased electric revenues
$12delivery revenue $2 million forin the three months ended September 30, 2006 and $40 million for
the nine months ended September 30, 2006first quarter of
2007 versus the same periods in 2005.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2005, power supply costs exceeded
power supply revenue due to rate caps for our residential customers. Rate caps
for our residential customers expired on December 31, 2005. In 2006, the absence
of rate caps allows us to record power supply revenue to offset fully our power
supply costs. Our ability to recover these power supply costs resulted in a $46
million increase to electric revenue for the three months ended September 30,
2006 and $58 million for the nine months ended September 30, 2006 versus the
same periods in 2005.2006.
OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: ForIn the three
months ended September 30, 2006,first
quarter of 2007, other operating expenses decreased $1 million, other income
increased $48$6 million, and non-commodity revenue increased $4$2 million versus
2005. For the nine months
ended September 30, 2006, other operating expenses increased $183 million, other
income increased $8 million, and non-commodity revenue increased $1 million
versus 2005.2006.
The increasedecrease in other operating expenses reflects higher operating and
maintenance, customer service, depreciation and amortization, and pension and
benefit expenses.
For the three months ended September 30, 2006,was primarily due to lower operating
and maintenance expense, increasedincluding reductions to certain workers' compensation
and injuries and damages expense. These decreases were offset partially by
higher depreciation, amortization, and overhead expense. Operating and
maintenance expense decreased primarily due to higher storm restoration costs. For the nine months
ended September 30,absence, in 2007, of costs
incurred in 2006 operating and maintenance expense increased primarily
due to costs related to a planned refueling outage at our Palisades nuclear
plant, higher tree trimming,and lower overhead line maintenance and storm restoration costs.
Higher customer service expense reflects contributions, beginning in January
2006 pursuant to a December 2005 MPSC order, to a fund that provides energy
assistance to low-income customers.
Depreciation and amortization expense increased due to higher plant in service
and greater amortization of certain regulatory assets. Pension and benefitOverhead expense
reflects changes in actuarial
assumptions in 2005, and the latest collective bargaining agreement between the
Utility Workers Union of America and Consumers.
For the three months ended September 30, 2006, the increase in non-commodity
revenue wasincreased primarily due to an increase in capital-related services providedcosts related to METC in 2006 versus 2005.
For the nine months ended September 30, 2006, theour voluntary separation program and
costs associated with our utility reorganization.
The increase in other income was primarily due to higher interest income andassociated with
our Section 10d(4) Regulatory Asset. This increase reflects the absence, in
2006,2007, of expenses
recordedthe impact of the MPSC's final order in 2005 associated with the early retirement of debt.this case. The increase in
non-commodity revenue was primarily due to an increase in miscellaneous service
revenues offset partially by a decrease in capital-related services provided to
METC in 2006 versus 2005.
REGULATORY RETURN ON CAPITAL EXPENDITURES: The $9 million decrease forhigher revenue from customer late
payment fees.
GENERAL TAXES: In the three
months ended September 30, 2006 and $30 million decrease for the nine months
ended September 30, 2006 versus the same periods in 2005, were bothfirst quarter of 2007, general tax expense increased
primarily due to lower
income associated with recording a return on capital expenditures in excess of
our depreciation base as allowed by the Customer Choice Act. In December 2005,
the MPSC issued an order that authorized us to recover $333 million of Section
10d(4) costs. The order authorized recovery of a lower level of costs versus the
level used to record 2005 income.
CMS-10
CMS Energy Corporation
GENERAL TAXES: For the three months ended September 30, 2006, the increase in
general taxes reflects higher MSBT expense and higher property tax expense. For
the nine months ended September 30, 2006, the increase in general taxes reflects
higherand MSBT expense offset partially by lower property tax expense.versus 2006.
INTEREST CHARGES: ForIn the three months ended September 30, 2006,first quarter of 2007, interest charges increaseddecreased due
to higher associated company interest expense, offset
partially by a 3 basis point reduction in the average rate of interest on our
debt and lower average debt levels and lower interest expense associated with
potential customer refunds versus the same period in 2005. For the nine
months ended September 30, 2006, interest charges increased primarily due to an
IRS income tax audit settlement. The settlement recognized that Consumers'
taxable income for prior years was higher than originally filed, resulting in
interest on the tax liability for these prior years.2006.
INCOME TAXES: ForIn the three months ended September 30, 2006,first quarter of 2007, income taxes increased versus 2005 primarily due to higher earnings by the electric utility.
For the nine months ended September 30, 2006, income taxes increased versus 2005 primarily due
to higher earnings by the electric utility offset partially byversus 2006. Partially offsetting
this increase is the resolutionabsence, in 2007, of an IRS incomeadjustments to certain deferred tax
audit, which resulted in a $4 million income
tax benefit caused by the restoration and utilization of income tax credits.balances. For additional details, see Note 8, Income Taxes.
CMS-7
CMS Energy Corporation
GAS UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30March 31 2007 2006 2005 Change
- -------------------- ---- ---- ------
ThreeNet Income for the three months ended $(20) $(16)$57 $37 $ (4)
Nine months ended $ 14 $ 39 $(25)
==== ====20
=== === ====
Three Months Ended Nine Months Ended
September 30, September 30,
Reasons for the change:
2006 vs.2005 2006 vs.2005
- ----------------------- ------------------ -----------------
Gas deliveries $(13) $(49)$ 14
Gas wholesale and retail services, otherrate increase 33
Other gas revenuesrevenue and other income 9 204
Operation and maintenance 3 1
General(13)
Depreciation and general taxes and depreciation - (5)
Interest charges (3) (6)(2)
Income taxes - 14
----(11)
----
Total change $ (4) $(25)
====20
====
GAS DELIVERIES: ForIn the three months ended September 30,first quarter of 2007, gas delivery revenues increased by
$14 million over 2006 gasas deliveries, including miscellaneous transportation to
end-use customers, decreased 1were 137 bcf, an increase of 14 bcf or 5.4 percent. This decrease reflects the impact of the annual unbilled gas volume
analysis on 2006 results. In 2006, this analysis supported a decrease in gas
volumes. In 2005, this annual analysis led to a slight11 percent versus
2006. The increase in gas volumes.
For the nine months ended September 30, 2006, gas deliveries, including
miscellaneous transportation to end-use customers, decreased 29 bcf or 13.3
percent. The decrease in gas deliveries was primarily due to warmercolder weather in the
first quarter of 2007 versus 2006. Average temperatures in the first quarter of
2007 were 3.8 degrees colder than the same period last year.
GAS RATE INCREASE: In November 2006, the MPSC issued an order authorizing an
annual rate increase of $81 million. As a result of this order, gas revenues
increased $33 million for the first quarter of 2007 versus 2005 and increased customer conservation efforts in response to
higher gas prices.
CMS-11
CMS Energy Corporation
GAS WHOLESALE AND RETAIL SERVICES,2006.
OTHER GAS REVENUESREVENUE AND OTHER INCOME: ForIn the three and nine months ended September 30, 2006, the increase primarily reflects
higher pipeline revenuesfirst quarter of 2007, other gas
revenue and other income increased $4 million versus 2006 primarily due to
higher pipeline capacity optimization in 2006 versus
2005.revenue.
OPERATION AND MAINTENANCE: ForIn the three and nine months ended September 30,
2006,first quarter of 2007, operation and
maintenance expenses decreasedincreased versus 20052006 primarily due to lower operating expenses offset partially by higher pension and benefit and customer
service expenses. Pension and benefit expense reflects changes in
actuarial assumptions in 2005 and the latest collective bargaining agreement
between the Utility Workers Union of America and Consumers.overhead expense. Customer service expense increased primarily due
to higher uncollectible accounts expense.expense and contributions, beginning in
November 2006 pursuant to a November 2006 MPSC order, to a fund that provides
energy assistance to low-income customers. Overhead expense increased primarily
due to costs related to our voluntary separation program and costs associated
with our utility reorganization.
DEPRECIATION AND GENERAL TAXES AND DEPRECIATION: ForTAXES: In the nine months ended September 30, 2006,first quarter of 2007, depreciation
expense increased versus 20052006 primarily due to higher plant in service. The increase in general taxes reflectsGeneral
tax expense also increased, primarily due to higher MSBT expense, offset
partially by lower property tax expense.
INTEREST CHARGES: ForIn the three months ended September 30, 2006,first quarter of 2007, interest charges increased due toreflect higher GCR interest expense, offset partially by a 3
basis point reduction in the average rate of
interest on our debt andGCR overrecovery balance, offset partially by lower average debt
levels versus 2006.
INCOME TAXES: In the same period in 2005. For the nine months ended
September 30,first quarter of 2007, income taxes increased versus 2006 interest charges increased
primarily due to an IRS income
tax audit settlement. The settlement recognized that Consumers' taxable income
for prior years was higher than originally filed, resulting in interest on the
tax liability for these prior years.
INCOME TAXES: For the nine months ended September 30, 2006, income taxes
decreased versus 2005 primarily due to lower earnings by the gas utility and the
resolution of an IRS income tax audit, which resulted in a $3 million income tax
benefit caused by the restoration and utilization of income tax credits.
CMS-12utility.
CMS-8
CMS Energy Corporation
ENTERPRISES RESULTS OF OPERATIONS
In Millions
----------------------
September 30---------------------
March 31 2007 2006 2005 Change
- -------------------- ----- --------- ------
ThreeNet Income for the three months ended $(132) $(260) $128
Nine months ended $(177) $(126) $(51)$(187) $(58) $(129)
====== ==== ===== ===== ====
Three Months Ended Nine Months Ended
September 30, September 30,
Reasons for the change:
2006 vs. 2005 2006 vs. 2005
- ----------------------- ------------------ -----------------
Operating revenues $ (2) $ 11926
Cost of gas and purchased power (15) (212)
Fuel costs mark-to-market at the MCV Partnership (225) (593)20
Earnings from equity method investees (21) (30)(17)
Gain on sale of assets - (5)12
Operation and maintenance (10) (27)2
General taxes, depreciation, and other income, net 84 131(3)
Asset impairment charges 945 945(242)
Fixed charges 6 9
Minority interest (520) (353)1
Income taxes (114) (35)
-----15
The MCV Partnership 57
-----
Total change $ 128 $ (51)
=====$(129)
=====
OPERATING REVENUES: For the three months ended September 30, 2006,March 31, 2007, operating
revenues decreasedincreased $26 million versus 20052006 primarily due to lowerhigher revenues at
CMS ERM resulting from mark-to-market lossesgains on power and gas contracts compared
to gainslosses on such items in 2005, and2006, partially offset by lower third-party financial revenues and power sales. These
decreases were offset by increased revenue at our Takoradi plant, which is
contracted to provide power when local hydro-generating plants are unable to
meet demand, and increased customer demand at our South American facilities.
For the nine months ended September 30, 2006, operating revenues increased
versus 2005 due to the impact of increased production at our Takoradi plant.
Also contributing to the increase was increased customer demand at our South
American facilities and increased third-party gas sales at CMS ERM. These
increases were offset partially by lower revenues at CMS ERM due to
mark-to-market losses on power and gas contracts compared to gains on such items
in 2005 and lower third-party financial revenues and power
sales.
COST OF GAS AND PURCHASED POWER: For the three and nine months ended September
30, 2006,March 31, 2007, cost
of gas and purchased power increaseddecreased $20 million versus 2005.2006. The increasedecrease was
primarily due to higher fuel costs related to increased production at
Takoradi. Also contributing to the increase was higher fuel prices and an
increase in fuel and power purchases in order to meet customer demand, primarily
in South America. These increases were offset partially by decreases in the
prices and volumes of gas sold by CMS ERM.
CMS-13
CMS Energy Corporation
FUEL COSTS MARK-TO-MARKET AT THE MCV PARTNERSHIP: For the three months ended
September 30, 2006, the fuel costs mark-to-market adjustments of certain
long-term gas contracts and financial hedges at the MCV Partnership decreased
operating earnings due to decreasedlower natural gas prices compared to smaller losses in
2005.
For the nine months ended September 30, 2006, the fuel costs mark-to-market
adjustments at the MCV Partnership decreased operating earnings due to the
impact of gas prices on the market value of certain long-term gas contracts and
financial hedges. In order to reflect the market value of these contracts and
hedges, mark-to-market losses were recorded in 2006 to reduce partially gains
recorded on these assets in 2005. The 2005 gains were primarily due to the
marking-to-market of certain long-term gas contracts and financial hedges that,
as a result of the implementation of the RCP, no longer qualified as normal
purchases or cash flow hedges.CMS ERM.
EARNINGS FROM EQUITY METHOD INVESTEES: For the three months ended September 30,
2006,March 31,
2007, earnings from equity earningsmethod investees decreased by $21$17 million versus 2005. This2006.
The decrease wasis primarily the result of lower earnings of $9 million at Jorf
Lasfar due to higher income tax expense, a $6 million reduction in
mark-to-market lossesgains on interest rate swaps associated with our investment in
Taweelah, compared to gains recorded on these instrumentsand a $5 million reduction in
the same period of 2005. Also contributing to the decrease were lower earnings
from our investment in Neyveli, due to the absence of a favorable revenue
dispute settlement recorded in 2005, and lower earnings at GasAtacama from
increased spot market power purchases due to higher
cost of fuel used for generation as a result of gas shortages and higher interest
rates.
Equity earnings for the nine months ended September 30, 2006 decreased $30shortages. These decreases
were partially offset by $3 million versus 2005. The decrease was due to the establishment of a tax reserve
related to some of our foreign investments and lowerincreased earnings at GasAtacama.TGN, which was
subsequently impaired.
GAIN ON SALE OF ASSETS: For the ninethree months ended September 30, 2006, thereMarch 31, 2007 the net gain
on asset sales was $12 million. There were no gains or losses on asset sales comparedfor
the three months ended March 31, 2006. The net gain consisted of a $23 million
gain on sale of our equity investment in El Chocon to a $3Endesa S.A. partially
offset by an $11 million gainloss on the sale of GVKour equity investment in TGM and
a $2 million gain on the sale of SLAPour Bay Area Pipeline in 2005.Michigan to Lucid Energy. For additional details, see
Note 2, Asset Sales, Discontinued Operations and Impairment Charges.
CMS-9
CMS Energy Corporation
OPERATION AND MAINTENANCE: For the three months ended September 30, 2006,March 31, 2007, operation
and maintenance expenses increaseddecreased $2 million due to a loss recorded on the terminationabsence of the remaining prepaid gas contractsresearch and
development costs in 2007 at CMS ERM and higher
maintenance expenses.
For the nine months ended September 30, 2006, operation and maintenance expenses
increased due to higher salaries and benefits, primarily at South American
subsidiaries, increased expenditures related to prospecting initiatives, a loss
recorded on the termination of the remaining prepaid gas contracts at CMS ERM,
and higher maintenance expenses.Energy Brasil S.A.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME, NET: For the three months ended
September 30, 2006,March 31, 2007, the net of general tax expense, depreciation, and other income
increaseddecreased operating income compared to 2005. This2006 due to higher general taxes,
primarily at our South American subsidiaries.
ASSET IMPAIRMENT CHARGES: For the three months ended March 31, 2007, asset
impairment charges were $242 million. There were no asset impairment charges for
the three months ended March 31, 2006. The increase was primarily due to the
recognition of a property tax refund of $88 million at the MCV Partnership,
offset partially by related appeal expenses of $16 million. Also contributing to
the increase was lower depreciation expense at the MCV Partnership resulting
from the impairment of property, plant, and equipment and higher interest
income.
For the nine months ended September 30, 2006, the net of general tax expense,
depreciation and other income increased operating income compared to 2005. This
was primarily due to the recognition of a property tax refund of $88 million at
the MCV Partnership, offset partially by related appeal expenses of $16 million.
Also contributing to the increase was lower depreciation expense at the MCV
Partnership resulting from the impairment of property, plant, and equipment and
higher interest income and lower accretion expense related to the termination of
the prepaid gas contracts at CMS ERM.
CMS-14
CMS Energy Corporation
ASSET IMPAIRMENT CHARGES: For the three and nine months ended September 30,
2006, asset impairment charges decreased by $945 million versus the same periodsreduction in 2005. For the three and nine months ended September 30, 2006, a charge of
$239 million was recorded for the impairmentfair value of our equity investment in GasAtacama and related notes receivable. For the three and nine months ended
September 30, 2005, a chargeTGN, including
$197 million of $1.184 billion was recorded for the impairment
of property, plant, and equipment at the MCV Partnership.
FIXED CHARGES: For the three and nine months ended September 30, 2006, fixed
charges decreased due to lower interest expenses at the MCV Partnership as the
result of lower debt levels, offset partially by higher interest expense from an
increase in subsidiary debt and interest rates.
MINORITY INTEREST: The allocation of profits to minority owners decreases our
net income, and the allocation of losses to minority owners increases our net
income. For the three months ended September 30, 2006, minority owners shared in
a portion of the profits at our subsidiaries. For the three months ended
September 30, 2005, minority owners shared in a portion of losses at our
subsidiaries. The profits in 2006 and the losses in 2005 were primarily due to
activities at the MCV Partnership.
For the nine months ended September 30, 2006, minority owners shared in a
portion of the losses at our subsidiaries versus sharing in greater losses of
these subsidiaries in 2005. The losses in 2006 and 2005 were primarily due to
activities at the MCV Partnership.cumulative currency translation loss.
INCOME TAXES: For the three months ended September 30, 2006, theMarch 31, 2007, income tax benefit
was lowerincreased $15 million versus 2005 as the incomesame period in 2006. The increase is primarily
due to the tax benefitsbenefit related to asset impairment charges offset by a provision
on the impairmentcumulative undistributed earnings of foreign subsidiaries expected to be
sold during 2007.
THE MCV PARTNERSHIP: Due to the November 2006 sale of our investmentownership interests in GasAtacama, recorded in 2006, were less than the
income tax benefits related to the impairment of property, plant, and equipment
at
the MCV Partnership, recordedwe have condensed their consolidated results of operations
for the three months ended March 31, 2006 for discussion purposes. The decrease
in 2005. Also contributinglosses from our ownership interest in the MCV Partnership is primarily due to
the decrease was
the absence, in 2007, of income tax benefits related to the American Jobs Creation Act
recorded in 2005.
For the nine months ended September 30, 2006, the income tax benefit was lower
versus 2005. In 2006, the impairment of our investment in GasAtacamamark-to-market losses on certain long-term contracts
and the
resolution of an IRS income tax audit, primarily for the restoration and
utilization of income tax credits, resulted in fewer benefits than the 2005
impairment of property, plant, and equipment at the MCV Partnership. Also
contributing to the decrease was the absence of income tax benefits related to
the American Jobs Creation Act recorded in 2005.financial hedges.
CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS
In Millions
---------------------
September 30--------------------
March 31 2007 2006 2005 Change
- -------------------- ---- --------- ------
ThreeNet Income for the three months ended $(45) $ (51) $ 6
Nine months ended $(58) $(142) $84
====$44 $(43) $87
=== ===== ===
For the three months ended September 30, 2006,March 31, 2007, net income from corporate interest
and other was $44 million versus net expenses were $45of $43 million a decrease of $6 million versus the same period in
2005. The decrease reflects the absence of premiums paid for the repurchase of a
portion of our CMS 9.875 percent senior notes in 2005 and reduced interest
expense due to lower debt levels in 2006. The decrease was offset partially by
increased legal fees.$87
million change is primarily due to an analysis of our tax position at March 31,
2007. Due to sales of our international operations during 2007, we determined
that certain deferred tax valuation allowances associated with capital loss
carryforwards and foreign basis differences were no longer required.
DISCONTINUED OPERATIONS: For the ninethree months ended September 2006, corporate interestMarch 31, 2007, the net loss
from discontinued operations was $180 million compared to net income of $8
million in 2006. The $188 million difference is primarily due to losses related
to the March 2007 sale of Argentine businesses and other net
expenses were $58 million,non-utility natural gas
assets in Michigan. Further contributing to the difference is a decreasereduction in
earnings from subsidiaries expected to be sold during the remainder of $84 million versus the same period in
2005. The decrease reflects the resolution of an IRS income tax audit, which
resulted in a $46 million income tax benefit primarily for the restoration2007. For
additional details, see Note 2, Asset Sales, Discontinued Operations and
CMS-15Impairment Charges.
CMS-10
CMS Energy Corporation
utilization of income tax credits. Also contributing to the reduction in
expenses were lower debt retirement charges and an insurance reimbursement
received in June 2006 for previously incurred legal expenses.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A. For additional accounting policies, see Note 1,
Corporate Structure and Accounting Policies.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, weWe use estimates and assumptions in preparing our consolidated financial
statements that may affect reported amounts and disclosures. We use accounting
estimates for asset valuations, depreciation, amortization, financial and
derivative instruments, employee benefits, and contingencies. For example, we
estimate the rate of return on plan assets and the cost of future health-care
benefits to determine our annual pension and other postretirement benefit costs.
There are risks and
uncertainties thatActual results may cause actual results to differ from estimated results due to factors such as changes
in the regulatory environment, competition, foreign exchange, regulatory
decisions, and lawsuits.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that
arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that a loss is probable and the amount
of loss can be reasonably estimated. The recording of estimated liabilities for
contingencies is guided byWe use the principles in SFAS No. 5.5 when
recording estimated liabilities for contingencies. We consider many factors in
making these assessments, including the history and specifics of each matter.
The amount of income taxes we pay is subject to ongoing audits by federal,
state, and foreign tax authorities, which can result in proposed assessments.
Our estimate for the potential outcome for any uncertain tax issue is highly
judgmental. We believe we have provided adequately for any likely outcome
related to these matters. However, our future results may include favorable or
unfavorable adjustments to our estimated tax liabilities in the period the
assessments are made or resolved or when statutes of limitation on potential
assessments expire. As a result, our effective tax rate may fluctuate
significantly on a quarterly basis. In July 2006, theThe FASB issued a new interpretation on the
recognition and measurement of uncertain tax positions.positions that we adopted on
January 1, 2007. For additional details, see the "New"Implementation of New
Accounting Standards Not Yet Effective"Standards" section included in this MD&A.
DISCONTINUED OPERATIONS: We have determined that certain consolidated
subsidiaries meet the criteria of assets held for sale under SFAS No. 144. At
March 31, 2007, these subsidiaries include Takoradi, SENECA, and certain
associated holding companies. At December 31, 2006, these subsidiaries include
our Argentine businesses sold in March 2007, a majority of our Michigan
non-utility businesses sold in March 2007, Takoradi, SENECA, and certain
associated holding companies. For additional details, see Note 2, Asset Sales,
Discontinued Operations and Impairment Charges.
ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND
MARKET RISK INFORMATION
FINANCIAL INSTRUMENTS: We account for investmentsDebt and equity securities classified as
available-for-sale are reported at fair value determined from quoted market
prices. Debt and equity securities classified as held-to-maturity are reported
at cost.
Unrealized gains or losses resulting from changes in fair value of certain
available-for-sale debt and equity securities using SFAS No. 115. For additional detailsare reported, net of tax, in
equity as part of AOCL. Unrealized gains or losses are excluded from earnings
unless the related changes in fair value are determined to be other than
temporary. Unrealized gains or losses on accounting for financial
instruments, see Note 6, Financial and Derivative Instruments.our nuclear decommissioning investments
are reflected as regulatory liabilities on our
CMS-11
CMS Energy Corporation
Consolidated Balance Sheets. Realized gains or losses would not affect our
consolidated earnings or cash flows.
DERIVATIVE INSTRUMENTS: We account for derivative instruments in accordance with
SFAS No. 133. Except as noted within this section, there have been no material
changes to the accounting for derivative instruments since the year ended December
31, 2005.2006, there have been no significant changes in the amount or types of
derivatives that we hold or to how we account for derivatives. For additional
details on accounting forour derivatives, see Note 6, Financial and Derivative Instruments.
To determine the fair value of our derivatives, we use information from external
sources (i.e., quoted market prices and third-party valuations), if available.
For certain contracts, this information is not available and we use mathematical
valuation models to value our derivatives. These models require CMS-16
CMS Energy Corporation
various inputs
and assumptions, including commodity market prices and volatilities, as well as
interest rates and contract maturity dates. The following table summarizes the
interest rate and volatility rate assumptions we used to value these contracts
at March 31, 2007:
Interest Rates (%) Volatility Rates (%)
------------------ --------------------
Gas-related option contracts 5.00 39 - 49
Electricity-related option contracts 5.00 50 - 87
Changes in forward prices or volatilities could significantly change the
calculated fair value of our derivative contracts. The cash returns we actually
realize on these contracts may vary, either positively or negatively, from the
results that we estimate using these models. As part of valuing our derivatives
at market, we maintain reserves, if necessary, for credit risks arising from the
financial condition of our counterparties.
The following table summarizes theDerivative Contracts Associated with Equity Investments: At March 31, 2007,
certain of our equity method investments, specifically Taweelah, Shuweihat, Jorf
Lasfar, and Jubail, held interest rate and volatility rate assumptions
we used to value these contracts at September 30, 2006:
Interest Rates (%) Volatility Rates (%)
------------------ --------------------
Long-term gas contracts associated with the MCV
Partnership 5.08 - 5.37 32 - 88
Establishment of the Midwest Energy Market: In 2005, the MISO began operating
the Midwest Energy Market. As a result, the MISO now centrally dispatches
electricity and transmission service throughout much of the Midwest and provides
day-ahead and real-time energy market information. At this time, we believe that
the establishment of this market does not represent the development of an active
energy market in Michigan, as defined by SFAS No. 133. As the Midwest Energy
Market matures, we will continue to monitor its activity level and evaluate
whether or not an active energy market may exist in Michigan. If an active
market develops in the future, some of our electric purchase and sale contracts
may qualify as derivatives. However, we believe that we would be able to apply
the normal purchases and sales exception of SFAS No. 133 to the majority of
these contracts (including the MCV PPA) and, therefore, would not be required to
mark these contracts to market.
Derivatives Associated with the MCV Partnership: Certain of the MCV
Partnership's long-term gas contracts, as well as its futures, options, and
swaps, are accounted for as derivatives, with changes in fair value recorded in
earnings each quarter. The changes in fair value recorded to earnings in 2006
were as follows:
In Millions
--------------------------------------
2006
-------------------------------------
First Second Third Year to
Quarter Quarter Quarter Date
------- ------- ------- -------
Long-term gas contracts $(111) $(34) $(16) $(161)
Related futures, options, and swaps (45) (8) (12) (65)
----- ---- ---- -----
Total $(156) $(42) $(28) $(226)
===== ==== ==== =====
These losses, shown before consideration of tax effects and minority interest,
are included in the total Fuel costs mark-to-market at the MCV Partnership on
our Consolidated Statements of Income (Loss). Because of the volatility of the
natural gas market, the MCV Partnership expects future earnings volatility on
both its long-term gas contracts and its futures, options, and swap contracts,
since gains and losses will beforeign exchange contracts.
We recorded each quarter. We will continue to record
these gains and losses in our consolidated financial statements until we close
the sale of our interest in the MCV Partnership.
We have recorded derivative assets totaling $30 million associated with the fair
value of all of these contracts on our Consolidated Balance Sheets at September
30, 2006. The MCV Partnership expects almost all of these assets, which
represent cumulative net mark-to-market gains, to reverse as losses through
earnings during 2007 and 2008 as the gas is purchased and the futures, options,
and swaps settle, with the remainder reversing between 2009 and 2011. Due to the
impairment of the MCV Facility and
CMS-17
CMS Energy Corporation
subsequent losses, the value of the equity held by all of the owners of the MCV
Partnership has decreased significantly and is now negative. Since we are one of
the general partners of the MCV Partnership, we have recognized a portion of the
limited partners' negative equity. As the MCV Partnership recognizes future
losses from the reversal of these derivative assets, we will continue to assume
a portion of the limited partners' share of those losses, in addition to our proportionate share but only until we close the sale of our interest in the MCV
Partnership.
In conjunction with the sale of our interest in the MCV Partnership, all of the long-term gas contracts and the related futures, options, and swaps will be
sold. As a result, we will no longer record thechange in fair value of these
contracts onin AOCL if the contracts qualified for cash flow hedge accounting;
otherwise, we recorded our Consolidated Balance Sheetsshare in Earnings from Equity Method Investees.
In May 2007, we sold our ownership interest in businesses in the Middle East,
Africa, and India including Taweelah, Shuweihat, Jorf Lasfar, and Jubail. As a
result of the sale, we will not be required tono longer recognize gains or losses related to
changes in the fair value of the derivative contracts held by these contracts on our
Consolidated Statementsequity
method investees. At March 31, 2007, we had accumulated a net loss of Income (Loss). Additionally, at September 30, 2006,
we have recorded a cumulative net gain of $25$14
million, net of tax, and minority
interest, in Accumulated other comprehensive lossAOCL representing our proportionate share of
mark-to-market gains and losses from cash flow hedges held by the MCV
Partnership.equity method
investees. At the date we closeclosed the sale, this amount, adjusted for any
additional changes in fair value, will bewas reclassified and recognized in earnings.
Any changes inearnings as
part of the fair value of these contracts recognized before the closing
will not affect the sale price of our interest in the MCV Partnership.sale. For additional details on the sale of our interest in the MCV Partnership,these
equity method investees, see the
"Other Electric Utility Business Uncertainties - MCV Underrecoveries" section in
this MD&ANote 2, Asset Sales, Discontinued Operations and
Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies - The Midland Cogeneration Venture."Impairment Charges.
CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts as a part of
activities considered to be an integral part ofthat support
CMS Energy's ongoing operations.
There have been no material changes to the accounting for CMS ERM's contracts
since the year ended December 31, 2005. We include the fair value of the derivative
contracts held by CMS ERM in either Price risk management assets or Price risk
management liabilities on our Consolidated Balance Sheets. The following tables
provide a summary of these contracts at September 30, 2006:March 31, 2007:
CMS-12
CMS Energy Corporation
In Millions
------------------------------------------------------------
Non-Trading Trading Total
----------- ------- -----
Fair value of contracts outstanding
at December 31, 2005 $(63) $ 100 $ 372006 $31 $(68) $(37)
Fair value of new contracts when
entered into during the period (a) --- (1) (1)
Contracts realized or otherwise
settled during the period 121(b) (124)(c) (3) 7 4
Other changes in fair value (d) (24) (40) (64)(b) 6 (6) --
--- ---- ----- -----
Fair value of contracts outstanding
at September 30, 2006 $ 34 $ (65) $ (31)March 31, 2007 $34 $(68) $(34)
=== ==== ===== =====
(a) Reflects only the initial premium payments (receipts) for new contracts. No
unrealized gains or losses were recognized at the inception of any new
contracts.
(b) During the third quarter of 2006, CMS ERM terminated certain non-trading
gas contracts. CMS ERM had recorded derivative liabilities, representing
cumulative unrealized mark-to-market losses, associated with these
contracts. As the contracts are now settled, the related derivative
liabilities are no longer included in the balance of CMS ERM's non-trading
derivative contracts at September 30, 2006 and, as a result, that balance
has changed significantly from December 31, 2005 and is now an asset.
(c) During the third quarter of 2006, CMS ERM terminated certain trading gas
contracts. CMS ERM had
CMS-18
CMS Energy Corporation
recorded derivative assets, representing cumulative unrealized
mark-to-market gains, associated with these contracts. As the contracts are
now settled, the related derivative assets are no longer included in the
balance of CMS ERM's trading derivative contracts at September 30, 2006
and, as a result, that balance has changed significantly from December 31,
2005 and is now a liability.
(d) Reflects changes in price and net increase (decrease)the fair value of forward positionscontracts over the period, as well as
changesincreases or decreases to present value and credit reserves.
Fair Value of Non-Trading Contracts at September 30, 2006March 31, 2007 In Millions
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Maturity (in years)
----------------------------------
Total
----------------------------------------------Fair Less Greater
Source of Fair Value Fair Value Less than 1 1 to 3 4 to 5 Greater than 5
- -------------------- ---------- ---------------- ------ ------ -------------------- -------
Prices actively quoted $ - $ - $ - $ - $ -$-- $-- $-- $-- $--
Prices obtained from external
sources or based on models and
other valuation methods 34 12 22 - -18 16 -- --
--- --- --- --- ---
Total $34 $12 $22 $ - $ -$18 $16 $-- $--
=== === === === ===
Fair Value of Trading Contracts at September 30, 2006March 31, 2007 In Millions
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Maturity (in years)
----------------------------------
Total
----------------------------------------------Fair Less Greater
Source of Fair Value Fair Value Less than 1 1 to 3 4 to 5 Greater than 5
- -------------------- ---------- ---------------- ------ ------ -------------------- -------
Prices actively quoted $(44) $(14) $(29) $(1) $ -$(40) $(20) $(20) $-- $--
Prices obtained from external
sources or based on models and
other valuation methods (21) (12) (9) - -
----(28) (25) (3) -- --
---- ---- ---- --- ---
Total $(65) $(26) $(38) $(1) $ -$(68) $(45) $(23) $-- $--
==== ==== ==== === ===
MARKET RISK INFORMATION: The following is an update of our risk sensitivities
since December 31, 2005.2006. These sensitivities indicate the potential loss in fair
value, cash flows, or future earnings from our financial instruments, including
our derivative contracts, assuming a hypothetical adverse change in market rates
or prices of 10 percent. Changes in excess of the amounts shown in the
sensitivity analyses could occur if changes in market rates or prices exceed the
10 percent shift used for the analyses.
Interest Rate Risk Sensitivity Analysis (assuming an increase in market interest
rates of 10 percent):
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Variable-rate financing - before-tax annual
earnings exposure $ 42 $ 4
Fixed-rate financing - potential REDUCTION
in fair value (a) 203 223181 193
(a) Fair value reduction could only be realized if we repurchased all of our
fixed-rate financing.
Certain equity method investees have entered into interest rate swaps. These
instruments are not required to be included in the sensitivity analysis, but can
have an impact on financial results.
CMS-19CMS-13
CMS Energy Corporation
Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market
prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Potential REDUCTION in fair value:
Non-trading contracts
Gas supply optionFixed fuel price contracts $ -(a) $-- $ 1
CMS ERM gas forward contracts 4 3 -
Derivative contracts associated with the MCV Partnership:
Long-term gas contracts 13 39
Gas futures, options, and swaps 27 48
Trading contracts
Electricity-related option contracts - 25 3
Electricity-related swaps 10 131 --
Gas-related option contracts -1 1
Gas-related swaps and futures 2 1 4
(a) In 2006, we entered into two contracts that fix the prices we pay for
gasoline and diesel fuel used in our fleet vehicles and equipment through
September 2007. These contracts are derivatives with an immaterial fair
value at March 31, 2007.
Investment Securities Price Risk Sensitivity Analysis (assuming an adverse
change in market prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Potential REDUCTION in fair value of
available-for-sale equity securities
(primarily SERP investments): $5 $5$6 $6
Consumers maintainsmaintained trust funds, as required by the NRC, for the purpose of
funding certain costs of nuclear plant decommissioning. At September 30, 2006
and December 31, 2005, thesedecommissioning through April 2007, the
date of the sale of Palisades. These funds were invested primarily in equity
securities, fixed-rate, fixed-income debt securities, and cash and cash
equivalents, and arehave been recorded at fair value on our Consolidated Balance
Sheets. These investments arewere exposed to price fluctuations in equity markets
and changes in interest rates. Because the accounting for nuclear plant
decommissioning recognizesrecognized that costs arewere recovered through Consumers' electric
rates, fluctuations in equity prices or interest rates dodid not affect our
consolidated earnings or cash flows.
For additional details on market risk and derivative activities, see Note 6,
Financial and Derivative Instruments. For additional details on nuclear plant
decommissioning at Big Rock and Palisades, see the "Other Electric Utility
Business Uncertainties - Nuclear Matters" section included in this MD&A.
CMS-20
CMS Energy Corporation
OTHER
Other accounting policies important to an understanding of our results of
operations and financial condition include:
- accounting for long-lived assets and equity method investments,
- accounting for the effects of industry regulation,
- accounting for pension and OPEB,
- accounting for asset retirement obligations, and
- accounting for nuclear decommissioning costs.
CMS-14
CMS Energy Corporation
These accounting policies were disclosed in our 20052006 Form 10-K/A10-K and there have
been no subsequent material changes.
CAPITAL RESOURCES AND LIQUIDITY
Factors affecting our liquidity and capital requirements are:
- results of operations,
- capital expenditures,
- energy commodity and transportation costs,
- contractual obligations,
- regulatory decisions,
- debt maturities,
- credit ratings,
- working capital needs, and
- collateral requirements.
During the summer months, we purchase natural gas and store it for resale
primarily during the winter heating season. Although our prudent natural gas
purchasescosts are recoverable from our customers, the amount paid for natural gas stored
as inventory requires additional liquidity due to the timing of thelag in cost recoveries.recovery. We
have credit agreements with our commodity suppliers and those
agreements containcontaining terms that have resultedcan
result in margin calls. AdditionalWhile we currently have no outstanding margin calls
or other credit supportassociated with our natural gas purchases, they may be required if agency
ratings are lowered or if market conditions become unfavorable relative to our
obligations to those parties.
Our current financial plan includes controlling operating expenses and capital
expenditures, executing on asset sales and evaluating market conditions for
financing opportunities. Due
to the adverse impact of the MCV Partnership asset impairment charge recorded in
2005 and the MCV Partnership fuel cost mark-to-market charges during 2006,
Consumers' ability to issue FMB as primary obligations or as collateral for
financing is expected to be limited to $298 million through December 31, 2006.
After December 31, 2006, Consumers' ability to issue FMB in excess of $298
million is based on achieving a two-times FMB interest coverage ratio.opportunities, if needed.
We believe the following items will be sufficient to meet our liquidity needs:
- our current level of cash and revolving credit facilities,
- our anticipated cash flows from operating and investing activities,
including asset sales, and
- our ability to access junior secured and unsecured borrowing capacity in the
capital markets, if necessary.
In the first quarter of 2007, Moody's and - our anticipated cash flowsS&P affirmed CMS Energy's and
Consumers' credit ratings and revised the rating outlook to positive from
operating and investing activities.
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CMS Energy Corporation
In June 2006,stable. Moody's also affirmed our liquidity rating and revised therating. Additionally, Fitch Ratings
upgraded credit rating outlook for Consumers to stable from negative. In August and September
2006, Moody's upgraded Consumers' and CMS Energy's credit ratings.
We have not made a specific determination concerning the reinstatementratings on certain of common
stock dividends. The Board of Directors may reconsider or revise its dividend
policy based upon certain conditions, including our results of operations,
financial condition, capital requirements, and contingent liabilities as well as
other relevant factors.securities.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2006, $529March 31, 2007, we had $642 million consolidated cash, was on hand, which includes $70$65
million of restricted cash and $83$4 million from entities consolidated pursuant to
FASB Interpretation No.FIN 46(R).
Our primary ongoing source of cash is dividends and other distributions from our
subsidiaries. For the ninethree months ended September 30, 2006,March 31, 2007, Consumers paid $71$94
million in common stock dividends to CMS Energy.
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CMS Energy Corporation
SUMMARY OF CONSOLIDATED STATEMENTS OF CASH FLOWSFLOWS:
In Millions
-------------
Nine------------
Three months ended September 30March 31 2007 2006
2005
- ------------------------------ -------------------------------- ---- -----
Net cash provided by (used in):
Operating activities $315 $ 436 $ 567171
Investing activities (436) (362)
-----6 (36)
---- -----
Net cash provided by operating and investing activities - 205321 135
Financing activities (389) (82)(57) (225)
Effect of exchange rates on cash 1 1
--------- -----
Net Increase (Decrease) in Cash and Cash Equivalents $(388)$265 $ 124
=====(89)
==== =====
OPERATING ACTIVITIES: For the ninethree months ended September 30, 2006,March 31, 2007, net cash
provided by operating activities was $436$315 million, a decreasean increase of $131$144 million
versus 2005. This2006. In addition to an increase in earnings at our electric and gas
utility segments, the increase in operating cash flow was mainly due to the
resulttiming of decreasesaccounts payable, increased usage of gas inventory in storage, and the
absence of the MCV Partnership gas supplier funds on deposit, andpartially offset
by the timing of accounts payable. These changes were offset
partially by a decrease in accounts receivable, reduced inventory purchases,
cash proceeds from the sale of excess sulfur dioxide allowances, and a return of
funds formerly held as collateral under certain gas hedging arrangements. The
decreasereceivable. We experienced colder weather in the MCV Partnership gas supplier funds on deposit was the resultfirst
quarter of refunds to suppliers from decreased exposure due to declining gas prices in2007 versus 2006. The decreasetiming of payments for increased natural gas
purchases to meet customer demand in accounts payable was mainly due tothe first quarter of 2007, coupled with the
absence of payments for higher priced gas thatmade during the first quarter of 2006,
increased our operating cash flow. A mild winter in 2006 allowed us to
accumulate more gas in our underground storage facilities. The increased usage
of gas already in storage during the first quarter of 2007 also increased our
operating cash flow. These increases were accrued at December 31, 2005. The decreasereduced partially by the timing of our
collection of increased billings in accounts
receivable was primarilythe first quarter of 2007 due to the increased sales of accounts receivable in
2006, the collection of receivables in 2006 reflecting higher gas prices billed
during the latter part of 2005,recent
regulatory actions and the expiration of emergency rules initiated
by the MPSC, which delayed customer payments during the heating season.weather-driven demand.
INVESTING ACTIVITIES: For the ninethree months ended September 30, 2006,March 31, 2007, net cash
used inprovided by investing activities was $436$6 million, an increase of $74$42 million
versus 2005.2006. This was primarily due to the absence of short-term investment proceeds,
the absence ofa net increase in proceeds from asset
sales of $134 million and the result of a $75 million deposit from TAQA. These
increases were offset by a decrease in restricted cash released in 2007 versus
2006 of $109 million and an increase of $91 million in capital expenditures
primarily at our electric and an increase in notes receivable. This activity was offset by the release of
restricted cash in February 2006, which we used to extinguish long-term
debt-related parties.
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CMS Energy Corporationgas utility segments.
FINANCING ACTIVITIES: For the ninethree months ended September 30, 2006,March 31, 2007, net cash used
in financing activities was $389$57 million, an increasea decrease of $307$168 million versus 2005.2006.
This was primarily due to a decrease in proceeds from common stock
issuancesfewer debt retirements of $271$196 million. For additional
details on long-term debt activity, see Note 4, Financings and Capitalization.
Our cash flow statements include amounts related to discontinued operations
through the date of disposal. For additional details on discontinued operations,
see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.
OBLIGATIONS AND COMMITMENTS
REVOLVING CREDIT FACILITIES: For details on our revolving credit facilities, see
Note 4, Financings and Capitalization.
DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4,
Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: CMS Energy and certain of its subsidiaries enter
into various arrangements in the normal course of business to facilitate
commercial transactions with third-parties.third parties. These arrangements include
indemnifications, letters of credit, surety bonds, and financial and performance
guarantees.
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CMS Energy Corporation
We enter into agreements containing indemnifications standard in the industry
and indemnifications specific to a transaction, such as the sale of a
subsidiary. Indemnifications are usually agreements to reimburse other companies
if those companies incur losses due to third-party claims or breach of contract
terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a
third-party. Letters of credit substitute the bank's credit for ours and reduce
credit risk for the third-party beneficiary. We monitor these obligations and
believe it is unlikely that we would be required to perform or otherwise incur
any material losses associated with these guarantees.
In May 2007, we sold our ownership interests in businesses in the Middle East,
Africa, and India to TAQA. TAQA has assumed all obligations related to our
project-financing security agreements. For more details on the sale of our
ownership interests to TAQA, see Note 2, Asset Sales, Discontinued Operations
and Impairment Charges.
For additional details on these and other guarantee arrangements, see Note 3,
Contingencies, "Other Contingencies - FASB Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others."
REVOLVING CREDIT FACILITIES: For details on revolving credit facilities, see
Note 4, Financings and Capitalization.
SALE OF ACCOUNTS RECEIVABLE: For details on the sale ofUnder a revolving accounts receivable sales
program, Consumers may sell up to $325 million of certain accounts receivable.
The highly liquid and efficient market for securitized financial assets provides
a lower cost source of funding compared to unsecured debt. For additional
details, see Note 4, Financings and Capitalization.
OUTLOOK
CORPORATE OUTLOOK
Over the next few years, ourOur business strategy will focus on managingthe successful completion of announced asset
sales, continued investment in our utility business, reducing parent debt, and
growing earnings while controlling operating costs.
Our primary focus with respect to our non-utility businesses is to optimize cash
flow issues, reducingand further reduce our business risk and leverage through the sale of
non-strategic assets. In 2007, we intend to exit the international marketplace.
We have sold, reached agreements to sell, or announced plans to sell our
ownership interests in businesses in the Middle East, Africa, India, and Latin
America. We plan to use the proceeds from the pending asset sales to invest in
our utility business and reduce parent company debt, growing earnings, reducing risk,debt.
As a result of the reorganization at our utility business that we announced in
2006 and positioning usour planned exit from the international marketplace, we incurred
charges in the first quarter of 2007. Completion of our planned asset sales may
result in additional charges in 2007. We are unable to make new investments that complementestimate the timing or
extent of these charges.
In January 2007, we reinstated a dividend on our strengths.common stock after a four-year
suspension at $0.05 per share. We paid $11 million in common stock dividends in
February 2007. On April 24, 2007, we declared a dividend of $0.05 per share on
our common stock payable May 31, 2007 to shareholders of record on May 10, 2007.
CMS-17
CMS Energy Corporation
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Summer 2006 temperatures were higher than historical averages, leading
to increasedIn 2007, we expect electric deliveries to electric customers. The summer 2006 also posted
record peak demand surpassing the record peak demand set in 2005 by five
percent. In 2006, we project annual electric deliveries will declinegrow about one-half of one
percent from 2005compared to 2006 levels. This short-termThe outlook for 2007 assumes a stabilizing economysmall decline in
industrial economic activity and normal weather conditions forthroughout the
fourth quarterremainder of 2006.the year.
Over the next five years, we expect electric deliveries to grow at an average
rate of about one and one-half1.5 percent per year. However, such growth is
dependent onThis outlook assumes a modestly growing customer
base and a stabilizing Michigan economy.economy after 2007. This growth rate includes
both full-service sales and delivery service to customers who choose to buy
generation service from an alternative electric supplier, but excludes
transactions with other wholesale market participants and other electric
utilities. This growth rate reflects a long-range expected trend of growth.
Growth from year to year may vary from this trend due to customer response to
the following:
- energy conservation measures,
- fluctuations in weather conditions, and
- changes in economic conditions, including utilization and expansion or
contraction of manufacturing facilities.
ELECTRIC CUSTOMER REVENUE OUTLOOK: Our electric utility customer base includes a
mix of residential, commercial, and diversified industrial customers. In 2006,
Michigan's automotive industry experienced manufacturing facility closures and
restructurings. Our electric utility results are not dependent upon a single
customer, or even a few customers, and customers in the automotive sector
represented five percent of our total 2006 electric revenue. We cannot predict
the impact of current or possible future restructuring plans or possible future
actions by our industrial customers.
ELECTRIC RESERVE MARGIN: We are currently planning for a reserve margin of approximately
11 percent for summer 2007, or supply resources equal to 111 percent of
projected firm summer peak load. Of the
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CMS Energy Corporation 2007 supply resources target of 111
percent, we expect 96 percent to come from our electric generating plants and
long-term power purchase contracts, and 15 percent to come from other
contractual arrangements. Our 15-year power purchase agreement with Entergy for
100 percent of the Palisades facility's current electric output will offset the
reduction in the owned capacity represented by the sale of the Palisades
facility in April 2007. We have purchased capacity and energy contracts covering
partially the estimated reserve margin requirements for 2007 through 2010. As a
result, we recognized an asset of $63$62 million for unexpired seasonal capacity
and energy contracts at September 30, 2006. Upon
the completion of the sale of the Palisades plant, the power purchase agreement
will offset, for the 15-year term of the agreement, the reduction in the owned
capacity represented by the Palisades plant.
The MCV PPA is not affected by our agreement to sell our interest in the MCV
Partnership.March 31, 2007.
After September 15, 2007, we expect to exercise our claim for
relief under the regulatory out provision in
the MCV PPA.PPA, resulting in a reduction in the amount paid to the MCV Partnership
to equal the amount we are allowed to recover in the rate charged to customers.
If we are successful in exercising our claim,this provision, the MCV Partnership hasmay,
under certain circumstances, have the right to terminate the MCV PPA, which
could affect our reserve margin status. The MCV PPA represents 1513 percent of
our 2007 supply resources target.
ELECTRIC UTILITY PLANT OUTAGE: In September 2006, we removed from service unit
three of the J.H. Campbell electric generating plant, representing 765 MW of our
capacity. The scheduled outage was for installation of equipment necessary to
comply with environmental standards. We expected the unit to return to service
in March 2007. However, the outage extended to May 1, 2007 due to unanticipated
delays in construction due to labor shortages, the collapse of an outdoor crane
on unit three and problems with a major generator component that was refurbished
by the original equipment manufacturer. The MPSC allows for the recovery of
reasonable and prudent replacement power costs.
ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission
service to us, increased
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CMS Energy Corporation
substantially the transmission rates it chargescharged us in 2006. The increasedrevenue
collected by METC under those rates areis subject to refund and to reduction based onpending a FERC ruling.
In January 2007, the outcome of hearings atparties filed a settlement agreement with the FERC. This
settlement, if approved by the FERC, scheduled for December 2006. Recoverywill result in a refund of 2006
transmission charges of $18 million and a portioncorresponding reduction of these costs is included in our approved 2006 PSCR plan. The PSCR
process allows recovery of all reasonable and prudent power
supply costs. However, we cannot predict when recovery of the transmission costs associated
with the rate increase will commence. To the extent that we incur and are unable
to collect these increased costs in a timely manner, our cash flows from
electric utility operations will be affected negatively. For additional details on power supply costs, see Note 3,
Contingencies, "Consumers' Electric Utility Rate Matters - Power Supply Costs."
In May 2006, ITC, a company that operates electric transmission facilities
through a wholly owned subsidiary, including the transmission system within
Detroit Edison's territory, filed an application with the FERC to acquire METC.
The FERC subsequently delayed hearings concerning the METC transmission rates.
In October 2006, ITC's acquisition of METC was completed. We are unable to
predict the nature and timing of any action by the FERC on transmission rates
but we will continue to participate in the FERC proceeding concerning the METC
transmission rates.
INDUSTRIAL REVENUE OUTLOOK: Our electric utility customer base includes a mix of
residential, commercial, and diversified industrial customers. In March 2006,
Delphi Corporation, a large industrial customer of Consumers with six facilities
in our service territory, announced plans to sell or close all but one of their
manufacturing operations in Michigan as part of their bankruptcy restructuring.
Our electric utility operations are not dependent upon a single customer, or
even a few customers, and customers in the automotive sector constitute four
percent of our total electric revenue. In addition, returning former ROA
industrial customers will benefit our electric utility revenue. However, we
cannot predict the impact of these restructuring plans or possible future
actions by other industrial customers.
THE21ST CENTURY ELECTRIC CAPACITY NEED FORUM:ENERGY PLAN: In January 2006,2007, the chairman of the MPSC
Staff issued a
report on future electric capacity inproposed three major policy initiatives to the stategovernor of Michigan. The
reportinitiatives involve the use of more renewable energy resources by all
load-serving entities such as Consumers, the creation of an energy efficiency
program, and a procedure for reviewing proposals to construct new generation
facilities. The January proposal indicated that existing generation resources are adequate in the short term, but
could be insufficient to maintain reliability standardsMichigan needs new base-load
capacity by 2009. The report also
indicated that new coal-fired baseload generation may be needed by 2011. The
MPSC Staff recommended an approval2015 and bid process for new power plants. To
address revenue stability risks, the MPSC Staff also proposed a special
reliability charge that a utility would assess on all electric distribution
customers. In April 2006, the governor of Michigan issued an executive directive
calling for the development of a comprehensive energy plan for the state of
Michigan. The directive calls for the Chairman of the MPSC, working in
cooperation with representatives from the public and private sectors,recommends measures to make recommendations on Michigan's energy policy by the end of 2006.it easier to predict customer
demand and revenues. The proposed initiatives will require changes to current
legislation. We will continue to participate as the MPSC, addresses
CMS-24
CMS Energy Corporationlegislature, and other
stakeholders address future electric capacityresource needs.
BURIAL OF OVERHEAD POWER LINES:BALANCED ENERGY INITIATIVE: In May 2007, we filed a "Balanced Energy Initiative"
with the MPSC providing a comprehensive energy resource plan to meet our
projected short-term and long-term electric power requirements. The Cityplan is
responsive to the 21st Century Electric Energy Plan and assumes that Michigan
will implement a state-wide energy efficiency program and a renewable energy
portfolio standard. The filing requests the MPSC to rule that the Balanced
Energy Initiative represents a reasonable and prudent plan for the acquisition
of Taylor, a municipality locatednecessary electric utility resources.
As acknowledged in Wayne County, Michigan, passed an ordinance that required Detroit Edison to bury
a sectionthe 21st Century Electric Energy Plan, implementation of overhead power lines at Detroit Edison's expense. In September
2004,the
Balanced Energy Initiative will require legislative repeal or significant reform
of the Michigan Courtcustomer choice law. In addition, we endorse the 21st Century
Electric Energy Plan recommendation to adopt a new, up-front certification
policy for major power plant investments. Our filing requests the MPSC to find
that the addition of Appeals upheld a lower court decision affirming500 MW of gas-fired combined cycle generating capacity is
reasonable and prudent. This addition could be in the legalityform of the ordinance over Detroit Edison's objections. Other municipalitiesconstruction
of a new gas-fired generating plant to begin service in our service territory adopted,2011, or proposedin the adoptionform of
similar
ordinances. Detroit Edison appealeda purchase of an existing gas-fired facility. The filing also recommends
construction of a new 750 MW clean coal generating facility on an existing
Consumers site to begin operation in 2015. Ownership of 250 MW of the total
capacity is assumed to be allocated to municipal entities or other interested
parties, resulting in 500 MW dedicated to us.
PROPOSED RENEWABLE ENERGY LEGISLATION: There are various bills introduced into
in the U.S. Congress and the Michigan Courtlegislature relating to mandatory
renewable energy standards. If enacted, these bills generally would require
electric utilities to acquire a certain percentage of Appeals ruling totheir power from renewable
sources or otherwise pay fees or purchase allowances in lieu of having the
Michigan Supreme Court. In May 2006, the Michigan Supreme Court ruledresources. We cannot predict whether any such bill will be enacted or in favor
of Detroit Edison. The Court found that the MPSC has primary jurisdiction over
this issue and accordingly, the Taylor ordinance is subject to any applicable
rules and regulations of the MPSC, including issues concerning who should bear
the expense of underground facilities. If incurred, we would seek recovery of
such costs from the municipality, or from our customers located in the
municipality, subject to MPSC approval.what
form.
ELECTRIC UTILITY BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
condition and future results and condition.of operations. These trends or uncertainties have,
or we reasonably expect could have, a material impact on revenues or income from
continuing electric operations.
ELECTRIC ENVIRONMENTAL ESTIMATES:Electric Environmental Estimates: Our operations are subject to environmental
laws and regulations. Costs to operate our facilities in compliance with these
laws and regulations generally have been recovered in customer rates.
Clean Air Act: Compliance with the federal Clean Air Act and resulting
regulations has been, and will continuecontinues to be a significant focus for us. The Nitrogen Oxide State
Implementation Plan requires significant reductions in nitrogen oxide emissions.
To comply with the regulations, we expect to incur capital expenditures totaling
$835 million. AsThese expenditures include installing selective catalytic
reduction control technology on
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CMS Energy Corporation
four of September 2006,our coal-fired electric generating units. The key assumptions in the
capital expenditure estimate include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- an AFUDC capitalization rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 7.8 percent. From 1998 to present, we have
incurred $660$760 million in capital expenditures to comply with the federal Clean
Air Act and resulting regulations and anticipate that the remaining $175$75 million
of capital expenditures will be made in 20062007 through 2011.
In addition to modifying coal-fired electric generating plants, our compliance
plan includes the use of nitrogen oxide emission allowances until all of the
control equipment is operational in 2011. The nitrogen oxide emission allowance
annual expense is projected to be $4$3 million per year, which we expect to
recover from our customers through the PSCR process. The projected annual
expense is based on market price forecasts and forecasts of regulatory
provisions, known as progressive flow control, that restrict the usage in any
given year of allowances banked from previous years. The allowances and their
cost are accounted for as inventory. The allowance inventory is expensed at the
rolling average cost as the electric generating plants emit nitrogen
oxide.
Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air
Interstate Rule that requires additional coal-fired electric generating plant
emission controls for nitrogen oxides and sulfur dioxide. We plan to meet the
nitrogen oxide requirements of this rule by year roundyear-round operation of our
selective catalytic reduction control technology units, installation of low
nitrogen oxide burners, and purchasing emission allowances. We plan to meet the
sulfur dioxide requirements of this rule using sorbent injection, installation
of flue gas desulfurization scrubbers atand purchasing emission allowances. Our
total cost for equipment installation is expected to reach approximately $700
million by 2015. Additional purchases of sulfur dioxide emission allowances in
2012 and 2013 will be needed for an estimated total cost of $960$12 million per year,
which we expect to be incurred by 2014.recover from our customers through the PSCR process.
Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury
Rule, which requires initial reductions of mercury emissions from coal-fired
electric generating plants by 2010 and further reductions by 2018. Based on
current technology, we anticipate our capital costs for mercury emissions
reductions required by Phase I of the Clean Air Mercury Rule to be less than $50
million and these reductions implemented by 2010. Phase II requirements of the
Clean Air Mercury Rule are not yet known and a cost estimate has not been
determined.
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CMS Energy Corporation
In April
2006, Michigan's governor announced a plan that would result in mercury
emissions reductions of 90 percent by 2015. We are currently working with the
MDEQ on the details of these rules. We will developthis rule; however, we have developed preliminary cost
estimates and a cost estimate whenmercury emissions reduction plan based on our best knowledge of
control technology options and anticipated requirements. Our plan includes
expenditures of approximately $550 million for mercury control equipment and
continuous emissions monitoring systems through 2014.
The following table compares the details of
these rules are determined.federal Clean Air Mercury Rule to the proposed
state mercury rule:
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CMS Energy Corporation
2010 2015 2018
-------------------- -------------------- --------------------
Clean Air 30% reduction by 70% reduction by
Mercury Rule 2010 with interstate 2018 with interstate
trading of trading of
allowances allowances
$4 million in $136 million in
capital capital plus $30
million annually in
allowance purchases
Proposed State 30% reduction by 90% reduction by
Mercury Rule 2010 without 2015 without
interstate trading interstate trading
of allowances of allowances
$4 million in $546 million in
capital capital
Greenhouse gases: Several legislative proposals have been introduced in the
United States Congress that would require reductions in emissions of greenhouse
gases, including potentially carbon dioxide. We cannot predict whether any
federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any of these rules and their effect on
our operations and financial results. Also,On April 2, 2007, the U.S. Supreme Court has agreed to
hear a case claimingruled
that the EPA is required by the Clean Air Act to consider
regulating carbon dioxide emissions from automobiles. Thegives the EPA asserts that it
lacksthe authority to regulate emissions of
carbon dioxide emissions. Ifand other greenhouse gases from automobiles. In its decision, the
Supreme Court finds
thatcourt ordered the EPA to revisit its contention that it has authoritythe discretion not
to regulate carbon dioxidegreenhouse gas emissions in this case, it
could result in new federal carbon dioxide regulations for other industries,
including the utility industry.from automobiles.
To the extent that greenhouse gas emission reduction rules come into effect, the
mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sector. We cannot estimate the potential
effect of
federal or state level greenhouse gas policy on our future consolidated results of
operations, cash flows, or financial position due to the uncertain nature of the
policies at this time. However, we stay abreast ofwill continue to monitor greenhouse gas
policy developments and will continue to assess and respond to their potential implications on
our business operations.
Water: In March 2004, the EPA issued rules that govern electric generating plant
cooling water intake systems. The rules require significant reduction in fish
killed by operating equipment. Fish kill reduction studies are required to be
submitted to the EPA in 2007 and 2008. EPA compliance options in the rule are
currently beingwere
challenged in court. In January 2007, the court rejected many of the compliance
options favored by industry and we will finalize our cost estimates in
early 2007, when a decision onremanded the finalbulk of the rule is anticipated. We expectback to
implement the EPA
approved process from 2009for reconsideration. The court's ruling is expected to 2011.increase significantly
the cost of complying with this rule. However, the cost to comply will not be
known until the EPA's reconsideration is complete. At this time, the EPA has not
established a schedule to address the court decision.
For additional details on electric environmental matters, see Note 3,
Contingencies, "Consumers' Electric Utility Contingencies - Electric
Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING:Competition and Regulatory Restructuring: The Customer Choice Act allows all of
our electric customers to buy electric generation service from us or from an
alternative electric supplier. At September 30, 2006,March 31, 2007, alternative electric suppliers
were providing 308283 MW of generation service to ROA customers, which
represents fourcustomers. This is 3 percent
of our total distribution load.load and represents a decrease of 19 percent of ROA
load compared to March 31, 2006. In prior orders, the MPSC approved recovery of
Stranded Costs incurred from 2002 through 2003 through a surcharge applied to
ROA customers. If downward ROA trends continue, it may extend the time it takes
to recover fully our Stranded Costs. It is difficult to predict future ROA
customer trends.
Section 10d(4) Regulatory Assets: In December 2005, the MPSC issued an order
that authorized ustrends, which affect our ability to recover $333 million in Section 10d(4) costs. Instead of
collecting these costs evenly over five years, the order instructed us to
collect 10 percent of the regulatory asset total in the first year, 15 percent
in the second year, and 25 percent in each of the third, fourth, and fifth
years.timely our Stranded Costs.
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CMS Energy Corporation
ELECTRIC RATE CASE: In January 2006, we filed a petition for rehearing with the MPSC that
disputed the aspect of the order dealing with the timing of our collection of
these costs. In April 2006, the MPSC issued an order that denied our petition
for rehearing.
Stranded Costs: Prior MPSC orders adopted a mechanism pursuant to the Customer
Choice Act to provide recovery of Stranded Costs that occur when customers leave
our system to purchase electricity from alternative suppliers. In November 2005,March 2007, we filed an application with the MPSC related toseeking
an 11.25 percent authorized return on equity and an annual increase in revenues
of $157 million. The increase includes a $23 million base rate reduction, the
determinationaddition of 2004
Stranded Costs. Applyinga $13 million surcharge for the Stranded Cost methodology usedreturn on investments in prior MPSC
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CMS Energy Corporation
orders, we concluded that we experienced Stranded Costs in 2004; however, we
also concluded that these costs were offset completely by our net sales of
excess power into the bulk electricity market. In September 2006, the MPSC
issued an order approving our proposalBig Rock,
and the resulting conclusion that our
Stranded Costs for 2004 were fully offset by wholesale saleselimination of $167 million Palisades base rate recovery credit in the
PSCR. If approved as requested, the rate requests would go into effect in
January 2008 and would apply to all retail electric customers. We cannot predict
the bulk
electricity market. Theamount or timing of any MPSC also determined that this order completesdecision on the series of Stranded Cost cases resulting from the Customer Choice Act.
Through and Out Rates: From December 2004 to March 2006, we paid a transitional
charge pursuant to a FERC order eliminating regional "through and out" rates. In
May 2006, the FERC approved an agreement between the PJM RTO transmission owners
and Consumers concerning these transitional charges. The agreement resolves all
issues regarding transitional charges for Consumers and eliminates the potential
for refunds or additional charges to Consumers. In May 2006, Baltimore Gas &
Electric filed a notice of withdrawal from the settlement. Consumers, PJM, and
others filed responses with the FERC on this matter. The FERC has not ruled on
whether the notice of withdrawal is effective, but we do not believe this action
will have any material impact on us.requests.
For additional details and material changes relating to the restructuring of the
electric utility industry and electric rate matters,Consumers' Electric Utility Rate Matters, see Note
3, Contingencies,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric Utility Rate Matters."
OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES
THE MCV UNDERRECOVERIES:PARTNERSHIP: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990.
We hold a 49 percent partnership interest in the MCV
Partnership, and a 35 percent lessor interest in the MCV Facility.
Sale of our Interest in the MCV Partnership and the FMLP: In July 2006, we
reached an agreement to sell 100 percent of the stock of CMS Midland, Inc. and
CMS Midland Holdings Company to an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments for $60.5 million. These Consumers'
subsidiaries hold our interests in the MCV Partnership and the FMLP. The sales
agreement calls for the purchaser, an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments, to pay $85 million, subject to certain
conditions and reimbursement rights, if Dow terminates an agreement under which
it is provided power and steam by the MCV Partnership. The purchaser will secure
their reimbursement obligation with an irrevocable letter of credit of up to $85
million. The MCV PPA and the associated customer rates are not affected by the
sale. We are targeting to close the sale before the end of 2006. The sale is
subject to various regulatory approvals, including the MPSC's approval and the
expiration of the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976. The MPSC has established a contested case proceeding
schedule, which will allow for a decision from the MPSC by the end of 2006. In
October 2006, we reached a settlement agreement with the MPSC Staff and the
parties involved, which recommends that the MPSC grant all authorizations
necessary to complete the sale of our interests in the MCV Partnership and the
FMLP. The MPSC's approval of the settlement agreement is required for it to
become effective. We cannot predict the timing or the outcome of the MPSC's
decision. We further cannot predict with certainty whether or when this
transaction will be completed.
For additional details on the sale of our interests in the MCV Partnership and
the FMLP, see Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies - The Midland Cogeneration Venture".
Financial Condition of the MCV Partnership: Under the MCV PPA, variable energy
payments to the MCV Partnership are based on the cost of coal burned at our coal
plants and our operation and maintenance expenses. However, the MCV
Partnership's costs of producing electricity are tied to the cost
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CMS Energy Corporation
of natural gas. Historically high natural gas prices have caused the MCV
Partnership to reevaluate the economics of operating the MCV Facility and to
record an impairment charge in 2005. If natural gas prices remain at present
levels or increase, the operations of the MCV Facility would be adversely
affected and could result in the MCV Partnership failing to meet its obligations
under the sale and leaseback transactions and other contracts.
Underrecoveries related to the MCV PPA: Further, theThe cost that we incur under the MCV PPA
exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash
underrecoveries of capacity and fixed energy payments of $56
million in 2006 and $39 million in 2007. However, ourwe use the direct savings from
the RCP, after allocating a portion to customers, are used to offset a portion of our
capacity and fixed energy underrecoveries expense. After September 15, 2007, we
expect to claim relief under the regulatory out provision in the MCV PPA,
thereby limiting our capacity and fixed energy payments to the MCV Partnership
to the amounts that we collect from our customers. The effect of any suchThis action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on the MCV Partnership's financial performance, and
- eliminate
our underrecoveries of capacity and fixed energy payments.
In addition, the MPSC's future actions on the capacity and fixed energy payments
recoverable from customers subsequent to September 15, 2007 may also further
affect negatively the financial performance of the MCV Partnership, if such
action resulted in us claiming additional relief under the regulatory out
provision. The MCV Partnership has indicatednotified us that it may taketakes issue with our intended
exercise of the regulatory out provision after September 15, 2007. We believe
that the provision is valid and fully effective, but cannot assure that it will
prevail in the event of a dispute. If we are successful in exercising the
regulatory out provision, the MCV Partnership hasmay, under certain circumstances,
have the right to terminate or reduce the amount of capacity sold under the MCV
PPA. If the MCV Partnership terminates the MCV PPA or reduces the amount of
capacity sold under the MCV PPA, we would seek to replace the lost capacity to
maintain an adequate electric reserve margin. This could involve entering into a
new PPA and (or) entering into electric capacity contracts on the open market.
We cannot predict our ability to enter into such contracts at a reasonable
price. We are also unable to predict regulatory approval of the terms and
conditions of such contracts, or that the MPSC would allow full recovery of our
incurred costs.
To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC,
which asked the MPSC to make a determination regarding whether it wished to
reconsider the amount of the MCV PPA payments that we recover from customers. We
are unable to predict the outcome of this request. For additional details on the
MCV Partnership, see Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies - The Midland Cogeneration Venture.MCV PPA."
NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006,April 2007, we reached an agreement
to sellsold Palisades and the Big Rock Independent Spent Fuel Storage Installation
(ISFSI) to
Entergy for $380 million. Under the agreement, if the transaction
does not close by March 1, 2007, theThe final purchase price will be reduced by
approximately $80,000 per day with additional costs if the deal does not close
by June 1, 2007. Based on the MPSC's published schedulewas subject to various
closing adjustments resulting in us receiving $361 million. We also paid Entergy
$30 million to assume ownership and responsibility for the contested case
proceedings regarding this transaction,Big Rock ISFSI.
Because of the sale is targeted to close by May 1,
2007. This two-month delayof Palisades, we will also pay the NMC, the former operator
of the Palisades plant, $7 million in exit fees and will forfeit our investment
in the originally anticipated March 1, 2007 closing
date would result in a purchase price reductionNMC of approximately $5 million.
We
estimate thatCMS-22
CMS Energy Corporation
The MPSC order approving the Palisades saletransaction allows us to recover the book
value of the Palisades plant. This will result in a $31estimated excess proceeds of
$66 million premium abovebeing credited to our customers through refunds applied over the
Palisades asset values atremainder of 2007 and 2008. Final proceeds in excess of the anticipatedbook value are
subject to closing date after accounting foradjustments and review by the MPSC. The MPSC order deferred
ruling on the recovery of $30 million in estimated sales-related costs. This premium is expectedtransaction costs, including
the NMC exit fees, and the $30 million payment to benefit our
customers.Entergy related to the Big
Rock ISFSI until the next general rate case.
Entergy will assume responsibility for the future decommissioning of the plant
and for storage and disposal of spent nuclear fuel. We will be required to pay
Entergy $30 million for acceptingfuel located at the responsibility for the storagePalisades and
disposal of
the Big Rock ISFSI. AtISFSI sites. We transferred $252 million in trust fund assets to
Entergy. Estimated decommissioning funds of $189 million will be credited to our
retail customers through refunds applied over the anticipated dateremainder of close,
decommissioning trust assets are estimated to be $587 million. We will retain
$205 million2007 and 2008.
Final disposition of these funds atis subject to closing date balances and is
subject to review by the time of close and will be entitled to receive
a return of an additional $130 million, pending either a
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CMS Energy Corporation
favorable federal tax ruling regarding the release of the funds or, if no such
ruling is issued, after decommissioning of the Palisades site is complete. These
estimates increased approximately $20 million compared to second quarter 2006
estimates primarily because of market appreciation during the third quarter of
2006.MPSC. The disposition of the retained and receivable nuclearremaining decommissioning
funds is subject to regulatory approval. We expect that a significant portion ofreview by the proceeds will be used to benefit our customers. We plan to use the cash that
we retain from the sale to reduce utility debt.MPSC.
As part of the transaction, Entergy will sell us 100 percent of the plant's
output up to its current annual average capacity of 798 MW under a 15-year power
purchase agreement. During the termBecause of the power purchase agreement, Entergy is obligated
to supply, and we are obligated to take, all capacity and energy from the
Palisades plant, exclusive of uprates above the plant's presently specified
capacity. When the plant is not operating or is derated, under certain
circumstances, Entergy can elect to provide replacement power from another
source at the rates set in the power purchase agreement. Otherwise, we would
have to obtain replacement power from the market. However, we are only obligated
to pay Entergy for capacity and energy actually delivered by Entergy either from
the plant or from an allowable replacement source chosen by Entergy. If Entergy
schedules a plant outage in June, July or August, Entergy is required to provide
replacement power at power purchase agreement rates. There are significant
penalties incurred by Entergy if the delivered energy fails to achieve a minimum
capacity factor level during July and August. Over the term of the power purchase agreement, the
pricingtransaction is structured such that Consumers' ratepayers
will retain the benefits ofa lease for accounting purposes. Due to our continuing
involvement with the Palisades plant's low-cost nuclear generation.
The sale is subject to various regulatory approvals, includingassets, we will account for the MPSC's
approvalPalisades plant
as a financing for accounting purposes and not a sale. This will result in the
recognition of the power purchase agreement, the FERC's approval for Entergy to
sell power to us under the power purchase agreement and other related matters,
and the NRC's approval of the transfer of the operating license to Entergy and
other related matters. In October 2006, the Federal Trade Commission issued a notice that neither it nor the Department of Justice's Antitrust Division plan
to take enforcement actionfinance obligation.
For additional details on the sale. The final purchase price will be subject
to various closing adjustments such as working capitalsale of Palisades and capital expenditure
adjustments, adjustments for nuclear fuel usage and inventory, and the date of
closing. However, the sale agreement can be terminated if the closing does not
occur within 18 months of the execution of the agreement. The closing can be
extended for up to six months to accommodate delays in receiving regulatory
approval. We cannot predict with certainty whether or when the closing
conditions will be satisfied or whether or when this transaction will be
completed.
Big Rock: Decommissioning of the site is nearing completion. Demolition of the
last remaining plant structure, the containment building, and removal of
remaining underground utilities and temporary office structures was completed in
August 2006. Final radiological surveys are now being completed to ensure that
the site meets all requirements for free, unrestricted release in accordance
with the NRC approved License Termination Plan (LTP) for the project. We
anticipate NRC approval to return approximately 475 acres of the site, including
the area formerly occupied by the nuclear plant, to a natural setting for
unrestricted use by early 2007. An area of approximately 107 acres including the Big Rock ISFSI, where eight casks loaded with spent fuel and other high-level
radioactive material are stored, is part of the sale of nuclear assets as
previously discussed.
Palisades: The amount of spent nuclear fuel at Palisades exceeds the plant's
temporary onsite wet storage pool capacity. We are using dry casks for temporary
onsite dry storage to supplement the wet storage pool capacity. As of September
2006, we have loaded 29 dry casks with spent nuclear fuel.
Palisades' current license from the NRC expires in 2011. In March 2005, the NMC,
which operates the Palisades plant, applied for a 20-year license renewal for
the plant on behalf of Consumers. In October 2006, the NRC issued its final
environmental impact statement on Palisades' license renewal. The NRC found that
there were no environmental impacts that would preclude license renewal for an
additional
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CMS Energy Corporation
20 years of operation. We expect a decision from the NRC on the license renewal
application in 2007.
For additional details on nuclear plant decommissioning at Big Rock and
Palisades, see Note
3, Contingencies, "Other Consumers' Electric Utility Contingencies - The Sale of
Nuclear Plant Decommissioning.Assets and the Palisades Power Purchase Agreement."
GAS UTILITY BUSINESS OUTLOOK
GROWTH: In 2006,2007, we project gas deliveries will decline by four percent,slightly, on a
weather-adjusted basis, from 20052006 levels due to increasedcontinuing conservation and
overall economic conditions in the state of Michigan. Over the next five years,
we expect gas deliveries to be relatively flat.decline by less than one-half of one percent
annually. Actual gas deliveries in future periods may be affected by:
- fluctuations in weather patterns,conditions,
- use by independent power producers,
- competition in sales and delivery,
- changes in gas commodity prices,
- Michigan economic conditions,
- the price of competing energy sources or fuels,
and
- gas consumption per customer.customer,
- improvements in gas appliance efficiency, and
- use of a Revenue Decoupling and Conservation Incentive mechanism.
GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our future financial
results and financial condition. These trends or uncertainties could have a
material impact on future revenues or income from gas operations.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. For additional details, see Note 3, Contingencies, "Consumers' Gas
Utility Contingencies - Gas Environmental Matters."
CMS-23
CMS Energy Corporation
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our
purchased natural gas costs if incurred under reasonable and prudent policies
and practices. The MPSC reviews these costs, policies, and practices for
prudency in annual plan and reconciliation proceedings. For additional details
on gas cost recovery, see Note 3, Contingencies, "Consumers' Gas Utility Rate
Matters - Gas Cost Recovery."
2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued
Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously-ordered $34 million reduction in our
depreciation expense,
- required us to undertake a study to determine why our plant removal
costs are in excess of other regulated Michigan natural gas utilities,
and
- required us to file a study report with the MPSC Staff on or before
December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.DEPRECIATION: We are also required to file our next gas depreciation case with
the MPSC within 90 days after the MPSC issuance of a final order in the pending
case related to ARO accounting. We cannot predict when the MPSC will issue a
final order in the ARO accounting case.
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CMS Energy Corporation
If a final order in our next gas depreciation case is not issued concurrently
with a final order in a general gas rate case, the MPSC may incorporate the
results of the depreciation case order is issued after theinto general gas general rate case order,
we proposed to incorporate its results into the gas general rates usingthrough use of a
surcharge mechanism a process used to incorporate specialty items into customer
rates.
2005(which may be either positive or negative).
2007 GAS RATE CASE: In July 2005,February 2007, we filed an application with the MPSC
seeking a 12an 11.25 percent authorized return on equity along with a $132an $88 million
annual increase in our gas delivery and transportation rates. As partrates, of this filing,
we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony in October
2005. In its testimony, the MPSC Staff recommended granting interim rate relief
of $38 million.
In February 2006, the MPSC Staff recommended granting final rate relief of $62
million. The MPSC Staff proposed thatwhich $17
million of this amountwould be contributed to a low income and energy efficiency fund. We have
proposed the use of a Revenue Decoupling and Conservation Incentive Mechanism
for residential and general service rate classes to help assure a reasonable
opportunity to recover costs regardless of sales levels.
ENTERPRISES OUTLOOK
Our primary focus with respect to our non-utility businesses is to optimize cash
flow and further reduce our business risk and leverage through the sale of
non-strategic assets. In 2007, we intend to complete the sale of several
Enterprises assets, including all of our businesses in Latin America, the Middle
East, North Africa and India.
In February 2007, we entered into an Agreement of Purchase and Sale with TAQA to
sell our ownership interest in businesses in the Middle East, Africa, and India
for $900 million. Businesses included in the sale are Taweelah, Shuweihat, Jorf
Lasfar, Jubail, Neyveli, and Takoradi and are subject to the receipt of all
necessary governmental, lender and partner approvals. We closed on the sale in
May 2007. After considering the effects of taxes, post-closing adjustments, and
closing costs, we anticipate a gain of approximately $50 million. The MPSC Staffestimated
gain is also recommended
reducing our allowed return on common equitysubject to 11.15 percent, from our current
11.4 percent.a number of adjustments that will occur at or shortly
after closing.
In March 2006,2007, we completed the MPSC Staff revised its recommended final rate reliefsale of a portfolio of our businesses in
Argentina and our northern Michigan non-utility natural gas assets to $71Lucid
Energy for $130 million. We also sold our interest in El Chocon, an Argentine
hydroelectric generating business, to Endesa, S.A. for $50 million. Our interest
in El Chocon was originally part of the asset group that Lucid Energy agreed to
purchase; however, Endesa, S.A. had a right of first offer on our interest in El
Chocon that it exercised. We will maintain our interest in the TGN natural gas
business in Argentina, which remains subject to a potential sale to the
government of Argentina or some other disposition. In recognition of our
commitment to sell our 23.5 percent interest in TGN, in the first quarter of
2007 we recorded an after-tax impairment charge of $140 million, which includes $17consisted
of a reduction in the fair value of our TGN ownership interest of $12 million,
net of tax, and recognition of cumulative foreign currency translation losses of
$128 million, net of tax.
In April 2007, we entered into a purchase and sale agreement with Petroleos de
Venezuela, S.A., which is owned by the Bolivarian Republic of Venezuela, to sell
our ownership interest in SENECA and certain associated generating equipment for
$106 million. We closed on the sale in April 2007.
In April 2007, we entered into an agreement to sell CMS Energy Brasil S.A. for
$211 million to be contributedCPFL Energia S.A., a Brazilian utility. We expect to a low income and energy
efficiency fund. In April 2006, we revised our request for final rate relief
downward to $118 million.
In May 2006,close on
the MPSC issued an order granting us interim gas rate reliefsale by the end of $18
million annually, which is under bond andthe second quarter of 2007, subject to refund if final rate relief
is granted in a lesser amount. The order also extendedapproval by the
temporary two-year
surcharge of $58 million granted in October 2004 until the issuance of a final
order in this proceeding. The MPSC has not set a date for issuance of an order
granting final rate relief.
In July 2006, the ALJ issued a Proposal for Decision recommending final rate
relief of $74 million above current rate levels, which include interim and
temporary rate relief. The $74 million includes $17 million to be contributed to
a low income and energy efficiency fund. The Proposal for Decision also
recommended reducing our return on common equity to 11 percent, from our current
11.4 percent.
ENTERPRISES OUTLOOK
We are evaluating new development prospects outside of our current asset base to
determine whether they fit within our business strategy. These and other
investment opportunities for Enterprises will be considered for risk, rate of
return, and consistency with our business strategy. Meanwhile, we plan to
continue restructuring our Enterprises business with the objective of narrowing
the focus of our operations as well as exploring beneficial asset sale
opportunities.
CMS-31Brazilian national regulatory agency.
CMS-24
CMS Energy Corporation
UNCERTAINTIES:We anticipate gross proceeds from the sales of SENECA, CMS Energy Brasil S.A.
and our ownership interest in businesses in the Middle East, Africa, and India
to total approximately $1.217 billion. The book value of these assets at March
31, 2007 is approximately $932 million which includes a cumulative net foreign
currency translation loss of $63 million. The asset book values will vary
between March 31, 2007 and each transaction's closing date. Final book value is
dependent upon the timing of closing, results of operations for certain of the
assets up to closing, and other factors.
We also announced plans to conduct an auction to sell our GasAtacama combined
gas pipeline and power generation businesses in Argentina and Chile, and our
electric generating plant in Jamaica. We expect to complete the financial positionsale of our
diversified energythese
businesses may be affected by a numberthe end of trends2007.
For additional details, see Note 2, Asset Sales, Discontinued Operations and
Impairment Charges.
UNCERTAINTIES: Trends or uncertainties. Thoseuncertainties that could have a material impact on our
consolidated income, cash flows, or balance sheet and credit improvement
include:
- successful close of the sale of CMS Energy Brasil S.A.,
- the outcome of the planned sale of other generation and distribution
assets, including the following uncertainties which could affect the
value of certain of these businesses:
- changes in available gas supplies or Argentine government
regulations that could further restrict natural gas exports
to our ability to sell or to improve the performance of assets and
businesses in accordance with our business plan,GasAtacama electric generating plant,
- changes in exchange rates or in local economic or political
conditions, particularly in Argentina, Venezuela, Brazil, and the
Middle East,
- changes in foreign taxes or laws or in governmental or
regulatory policies that could reduce significantly the
tariffs charged and revenues recognized by certain foreign
subsidiaries, or increase expenses,
- imposition of stamp taxes on South American contracts that could
increase project expenses substantially,
- impact of any future rate cases, FERC actions, or orders on regulated
businesses,indemnity and environmental remediation obligations at Bay
Harbor,
- impact of ratings downgrades on our liquidity, operating costs, and
cost of capital,
- impact of changes in commodity prices and interest rates on certain derivative
contracts that do not qualify for hedge accounting and must be marked
to market through earnings, - changes in available gas supplies or Argentine government regulations
that could further restrict natural gas exports to our GasAtacama
electric generating plant, and
- impact of indemnityrepresentations, warranties, and environmental remediation obligations at Bay
Harbor.
GASATACAMA: On March 24, 2004, the Argentine government authorized the
restriction of exports of natural gas to Chile, giving priority to domestic
demandrelated indemnities in
Argentina. This restriction has had a detrimental effect on
GasAtacama's earnings since GasAtacama's gas-fired electric generating plant is
located in Chile and uses Argentine gas for fuel. From April through December
2004, Bolivia agreed to export 4 million cubic meters of gas per day to
Argentina, which allowed Argentina to minimize its curtailments to Chile.
Argentina and Bolivia extended the term of that agreement through December 31,
2006. With the Bolivian gas supply, Argentina relaxed its export restrictions to
GasAtacama, allowing GasAtacama to receive approximately 50 percent of its
contracted gas quantities at its electric generating plant.
On May 1, 2006, the Bolivian government announced its intention to nationalize
the natural gas industry and raise prices under its existing gas export
contracts. Since May, gas flow from Bolivia has been restricted, as Argentina
and Bolivia have been renegotiating the price for gas. Simultaneously, gas
supply to GasAtacama has been further curtailed. In July 2006, Argentina agreed
to increase the price it pays for gas from Bolivia through the term of the
existing contract, December 31, 2006. Concurrently, Argentina announced that it
would recover all of this price increase by a special tax on its gas exports.
The decision of Argentina to increase the cost of its gas exports, in addition
to maintaining the current curtailment scheme, increased the risk and cost of
GasAtacama's fuel supply.
In August 2006, GasAtacama was notified by one of its major gas suppliers that
it would no longer deliver gas to GasAtacama under the Argentine government's
current policy. This indicated GasAtacama's operations could be adversely
affected by this situation. In conjunctionconnection with the preparationsales of our
consolidated financial statements for the quarter ended September 30, 2006, we
performed an impairment analysis, which concluded that the fair value of our
investment was lower than the carrying amountSENECA, Argentine assets to Lucid Energy,
CMS Energy Brasil S.A., and that this decline was other than temporary. In the third quarter of 2006, we recorded an impairment charge
of $239 million on our Consolidated Statements of Income (Loss). As a result,
our net income was reduced by $169 million after considering tax effectspending sales if completed and
minority interest.closed.
GASATACAMA: At September 30, 2006,March 31, 2007, the carrying value of our investment in
GasAtacama was $122$114 million. This remaining value continues to be exposed to the
threat of a complete gas curtailmentrestriction by Argentina and the inability of
GasAtacama to pass CMS-32
CMS Energy Corporation
through the increased costs associated with such a
curtailmentrestriction to its regulated customers. Therefore, if conditions do not improve,
the result could be a further impairment of our investment in GasAtacama.
In February 2007, we announced plans to conduct an auction to sell GasAtacama.
We expect to complete the sale by the end of 2007. For additional details, see
Note 2, Asset Sales, Discontinued Operations and Impairment Charges and Sales.
SENECA: SENECA operates an electric utility on Margarita Island, Venezuela under
a Concession Agreement with the Venezuelan Ministry ofCharges.
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CMS Energy and Petroleum
(MEP). The Concession Agreement provides for semi-annual customer tariff
adjustments for the effects of inflation and foreign exchange variations. The
last tariff adjustment occurred in December 2003. In 2003, the MEP approved a
fuel subsidy to offset partially the lower tariff revenue. This fuel subsidy
originally expired on December 31, 2004, but has been approved through December
31, 2005. SENECA has informed the MEP that for 2006, SENECA will continue to
apply the fuel subsidy as a credit against a portion of its fuel bills from its
fuel supplier, Deltaven, a governmental body regulated by the MEP. Continued
receipt of the fuel subsidy is part of SENECA's broader discussions with the MEP
for appropriate financial relief. We have been informed that the MEP is
examining other aspects of SENECA's financial relief proposal. The outcome of
these discussions is uncertain and, if not favorable, could impact adversely
SENECA's liquidity and the value of our investment.Corporation
PRAIRIE STATE: In October 2006, we signed agreements with Peabody Energy to
co-develop the Prairie State Energy Campus (Prairie State), a 1,600 MW power
plant and coal mine in southern Illinois. Enterprises and Peabody Energy will
co-develop and each own 15 percent ofIn April 2007, we withdrew from
Prairie State indirectly through a jointly
owned limited liability company. Enterprises will serve as lead developer,
construction manager, and operatorbecause, at this time, it does not meet our investment criteria,
including the level of the mine-mouth power plant. Peabody Energy
will be lead developer of the mine that will fuel the power plant. Financial
close of the project is contingent upon Peabody Energy and Enterprises being
able to secure:
- non-recourse project financing,
- an engineering, procurement, and construction contract for the power
plant, and
- long-term power purchase agreements for a substantial portion of
Enterprises' and Peabody Energy'sour share of the project's output.
Construction of the first 800 MW generating unit is expected to take about four
years to complete and the second 800 MW unit will be completed shortly
afterward. Our expected equity investment of approximately $200 million is
expected to be financed with a bridge loan until the completion of construction.
CMS-33
CMS Energy Corporationoutput from
Prairie State.
OTHER OUTLOOK
VOLUNTARY
RULES REGARDING BILLING PRACTICES: In OctoberDecember 2006, the MPSC announced
a voluntary agreement relatingissued proposed
rule changes to residential customer billing practices with usstandards and other Michigan
natural gas and electric utilities that willpractices. These
changes, if adopted, would provide additional helpprotection to low-income customers
forduring the winter heating period ofseason that will be defined as November 1 2006 through
March 31, 2007. The rules addressextend the time between billing practices such as billing cycles,
fees, deposits, shutoffs,date and collection of unpaid bills for retail customers of
electricdue date from 17 days to 22
days, and gas utilities. These rules will have aneliminate estimated $3 million
negative effect on our earnings formetering readings unless actual readings are not
feasible. We are presently evaluating the periodimpacts of these proposed rules and
an estimated
negative effect on our cash flow of up to $50 million for 2006.
MCV PARTNERSHIP NEGATIVE EQUITY: Dueare working with other Michigan utilities in providing comments to the impairment ofMPSC
regarding the MCV Facility and
operating losses from mark-to-market adjustments on derivative instruments, the
equity held by Consumers and by all of the owners of the MCV Partnership has
decreased significantly and is now negative. Since Consumers is one of the
general partners of the MCV Partnership, we have recognized a portion of the
limited partners' negative equity. As the MCV Partnership recognizes future
losses, we will continue to assume a portion of the limited partners' share of
those losses, in addition to our proportionate share.proposed rule changes.
LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an investigation
by the DOJ regarding round-trip trading transactions by CMS MST. Also, we are
named as a party in various litigation matters including, but not limited to,
securities class action lawsuits and several lawsuits regarding alleged false
natural gas price reporting and price manipulation. Additionally, the SEC is
investigating the actions of former CMS Energy subsidiaries in relation to
Equatorial Guinea. For additional details regarding these and other matters, see
Note 3, Contingencies and Part II, Item 1. Legal Proceedings.
FIXED PRICE CONTRACTS: DIG and CMS ERM are parties to long-term requirements
contracts to provide steam and/or electricity based on a fixed price schedule.
The price of natural gas, the primary fuel used by DIG, is volatile and has
increased substantially in recent years. Because the prices charged under DIG's
contracts do not reflect current natural gas prices, DIG's and CMS ERM's
financial performance has been impacted negatively. However, since not all of
its capacity is committed under these contracts, DIG has been able to sell a
portion of its electric capacity and (or) energy on the market at a profit, or,
through CMS ERM, engage in a hedging strategy to minimize its losses. DIG and
CMS ERM may take various actions such as seeking restructuring of the contracts.
CMS Energy may also take other measures to address the unfavorable returns.
PENSION REFORM: In August 2006, the President signed into law the Pension
Protection Act of 2006. The bill reforms the funding rules for employer-provided
pension plans, effective for plan years beginning after 2007. We are in the
process of determining the impactAs a result of
this legislation.bill, we expect to reduce our contributions to the Pension Plan over the
next 10 years by a present value amount of $56 million.
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 123(R)158, EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT PENSION AND SABOTHER
POSTRETIREMENT PLANS - AN AMENDMENT OF FASB STATEMENTS NO. 107, SHARE-BASED PAYMENT:87, 88, 106, AND
132(R): In September 2006, the FASB issued SFAS No. 123(R)158. Phase one of this
standard required us to recognize the funded status of our defined benefit
postretirement plans on our Consolidated Balance Sheets at December 31, 2006.
Phase one was implemented in December 2006. Phase two of this standard requires
companiesthat we change our plan measurement date from November 30 to use the fair valueDecember 31,
effective December 31, 2008. We do not believe that implementation of employee stock options and similar awards at
the grant date to value the awards. SFAS No. 123(R) was effective for usphase two
of this standard will have a material effect on January 1, 2006.our consolidated financial
statements. We electedexpect to adopt the modified prospective method recognitionmeasurement date provisions of this Statement instead of retrospective restatement. We adopted
the fair value method of accounting for share-based awards effective December
2002. Therefore, SFAS No. 123(R) did not have a significant impact on our
results of operations when it became effective. We applied the additional
guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R). For
additional details, see Note 9, Executive Incentive Compensation.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE158
in 2008.
FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006,We adopted the FASB
issuedprovisions of
FIN 48 effective for uson January 1, 2007. This interpretation provides a two-step approach for
the recognition and measurement of
CMS-26
CMS Energy Corporation
uncertain tax positions taken, or expected to be taken, by a company on its
income tax returns. The first step is to evaluate the tax position to determine
if, based on management's best judgment, it is greater than 50 percent likely
that the taxing
authoritywe will sustain the tax position. The second step is to measure the
appropriate amount of the benefit to recognize. This is done by estimating the
potential outcomes and recognizing the greatest amount that has a cumulative
probability of at least 50 percent. We are presently evaluating the impacts, if
any. Any initial impacts of implementing FIN 48 requires interest and penalties, if
applicable, to be accrued on differences between tax positions recognized in our
consolidated financial statements and the amount claimed, or expected to be
claimed, on the tax return.
As a result of the implementation of FIN 48, we have identified additional
uncertain tax benefits of $11 million as of January 1, 2007. Included in this
amount is an increase in our valuation allowance of $100 million, decreases to
tax reserves of $61 million and a decrease to deferred tax liabilities of $28
million. In addition, our equity method investment, Jorf Lasfar, in which we
held a 50 percent interest, identified $26 million of uncertain tax benefits in
its adoption of FIN 48 for U.S. GAAP purposes. We have reflected our share of
this amount, $13 million, as a reduction to our beginning retained earnings
balance and in our investment in the subsidiary. Thus, our beginning retained
earnings was reduced by $24 million as a result of the adoption of FIN 48.
CMS Energy and its subsidiaries file a consolidated U.S. federal income tax
return as well as unitary and combined income tax returns in several states. CMS
Energy and its subsidiaries also file separate company income tax returns in
several states. The only significant state tax paid by CMS Energy is in
Michigan. However, since the Michigan Single Business Tax is not an income tax,
it is not part of the FIN 48 analysis. For the U.S. federal income tax return,
CMS Energy completed examinations by federal taxing authorities for its taxable
years prior to 2002. The federal income tax returns for the years 2002 through
2005 are open under the statute of limitations.
We have reflected a net interest liability of $3 million related to our
uncertain income tax positions on our Consolidated Balance Sheets as of January
1, 2007. We have not accrued any penalties with respect to uncertain tax
benefits. We recognize accrued interest and penalties, where applicable, related
to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against
certain U.S. and foreign deferred tax assets totaling $216 million and other
uncertain tax positions of $31 million, resulting in total unrecognized benefits
of $247 million. Of this amount, $217 million would result in a cumulativedecrease in our
effective tax rate, if recognized. We released $81 million of our valuation
allowance in the first quarter of 2007, due to the anticipated sales of our
foreign investments, as reflected in our effective tax rate reconciliation in
Note 8, Income Taxes. Therefore, remaining uncertain tax benefits that would
reduce our effective tax rate beyond this quarter are $136 million. As we
continue to market our foreign investments, it is reasonably possible that
additional valuation allowance adjustments could be made. We are not in a
position to estimate any additional adjustment at this date, other than to retained earnings.
CMS-34
CMS Energy Corporationstate
that we have no expectation of reversing any of the $86 million valuation
allowance attributable to the inflation indexing of our Venezuelan investment.
We are not expecting any other material changes to our uncertain tax positions.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 157, FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued SFAS
No. 157, effective for us January 1, 2008. The standard provides a revised
definition of "fair value" and gives guidance on how to measure the fair value
of assets and liabilities. Under the standard, fair value is defined as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly exchange between market participants. The standard does not expand
the use of fair value in any new circumstances. However, additional disclosures
will be required on the impact and reliability of fair value measurements
reflected in
theCMS-27
CMS Energy Corporation
our consolidated financial statements. The standard will also eliminate the
existing prohibition of recognizing "day one" gains or losses on derivative
instruments, and will generally require such gains and losses to be recognized
through earnings. We are presently evaluating the impacts, if any, of
implementing SFAS No. 157. We currently do not hold any derivatives that would
involve day one gains or losses.
SFAS NO. 158, EMPLOYERS' ACCOUNTING159, THE FAIR VALUE OPTION FOR DEFINED BENEFIT PENSIONFINANCIAL ASSETS AND OTHER
POSTRETIREMENT PLANS -FINANCIAL
LIABILITIES, INCLUDING AN AMENDMENT OFTO FASB STATEMENTSSTATEMENT NO. 87, 88, 106, AND
132(R):115: In September 2006,February 2007,
the FASB issued SFAS No. 158.159, effective for us January 1, 2008. This standard
will requiregive us the option to select certain financial instruments and other items,
which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we
would recognize the funded status of our defined benefit postretirement
plans on our balance sheets at December 31, 2006. SFAS No. 158 will require us
to recognizeunrealized gains and losses associated with changes in the funded statusfair
value of our plans in the year initem over time. The statement will also require disclosures for
items for which the changes occur. Upon implementation of this standard,fair value option has been elected. We are presently
evaluating whether we expectwill choose to record an
additional postretirement benefit liability of approximately $653 million and a
regulatory asset of $612 million. We expect a reduction of $26 million toelect the fair value option for any
financial instruments or other comprehensive income, after tax. Regulatory asset treatment is consistent with
past MPSC and FERC guidance. This standard also requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008.
We do not believe that implementation of this provision of the standard would
have a material effect on our financial statements.
STAFF ACCOUNTING BULLETIN NO. 108, CONSIDERING THE EFFECTS OF PRIOR YEAR
MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL
STATEMENTS: In September 2006, the SEC issued SAB No. 108, effective for us
December 31, 2006. This accounting bulletin clarifies how registrants should
assess the materiality of prior period financial statement errors in the current
period. We do not presently believe that adoption of this standard would have a
material effect on our financial position or results of operations.
CMS-35items.
CMS-28
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(UNAUDITED)
In Millions
------------------
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30MARCH 31 2007 2006
2005 2006 2005
- ------------ ------ ------ ------ ------
In Millions--------------------------- ------- --------
OPERATING REVENUE $1,462 $1,307 $4,890 $4,382$ 2,237 $ 1,937
EARNINGS FROM EQUITY METHOD INVESTEES 19 40 63 9236
OPERATING EXPENSES
Fuel for electric generation 300 215 782 57098 182
Fuel costs mark-to-market at the MCV Partnership 28 (197) 226 (367)-- 156
Purchased and interchange power 235 203 567 400332 134
Cost of gas sold 196 242 1,439 1,4151,045 946
Other operating expenses 292 262 818 753264 266
Maintenance 72 62 239 17874
Depreciation depletion and amortization 129 121 418 399161 158
General taxes (9) 59 137 20080 76
Asset impairment charges 239 1,184 239 1,184
------ ------ ------ ------
1,482 2,151 4,865 4,732
------ ------ ------ ------242 --
------- -------
2,284 1,992
------- -------
OPERATING INCOME (LOSS) (1) (804) 88 (258)LOSS (28) (19)
OTHER INCOME (DEDUCTIONS)
Accretion expense - (4) (4) (14)
Gain on asset sales, net - - - 512 --
Interest and dividends 23 14 62 3917 17
Regulatory return on capital expenditures 8 17 18 48
Foreign currency losses, net (1) - - (4)3
Other income 3 7 10 29 28
Other expense (2) (13) (12) (25)
------ ------ ------ ------
35 24 93 77
------ ------ ------ ------(3) (11)
------- -------
37 16
------- -------
FIXED CHARGES
Interest on long-term debt 117 117 356 360101 116
Interest on long-term debt - related parties 3 7 11 234
Other interest 6 7 3 23 13
Capitalized interest (3) (2) (1) (7) (3)
Preferred dividends of subsidiaries 1 1
4 3
------ ------ ------ ------------- -------
108 126
127 387 396
------ ------ ------ ------------- -------
LOSS BEFORE MINORITY INTERESTS (92) (907) (206) (577)(99) (129)
MINORITY INTERESTS (OBLIGATIONS), NET 41 (479) (27) (380)
------ ------ ------ ------2 (69)
------- -------
LOSS BEFORE INCOME TAXES (133) (428) (179) (197)(101) (60)
INCOME TAX BENEFIT (31) (165) (125) (116)
------ ------ ------ ------(70) (28)
------- -------
LOSS FROM CONTINUING OPERATIONS (102) (263) (54) (81)(31) (32)
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $-TAX (TAX
BENEFIT) OF $(68) IN 2007 AND $1 TAX EXPENSE IN 2006 1 - 4 -
------ ------ ------ ------(180) 8
------- -------
NET LOSS (101) (263) (50) (81)(211) (24)
PREFERRED DIVIDENDS 2 2 8 7
------ ------ ------ ------3 3
REDEMPTION PREMIUM ON PREFERRED STOCK 1 --
------- -------
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS $ (103)(215) $ (265) $ (58) $ (88)
====== ====== ====== ======(27)
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-36CMS-29
In Millions, Except
Per Share Amounts
-------------------
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30MARCH 31 2007 2006
2005 2006 2005
- --------------------------------------- ------ ------
------ ------
In Millions
CMS ENERGY
NET LOSS
Net Loss Available to Common Stockholders $ (103)(215) $ (265) $ (58) $ (88)
====== ======(27)
====== ======
BASIC LOSSEARNINGS (LOSS) PER AVERAGE COMMON SHARE
Loss from Continuing Operations $(0.47) $(1.21) $(0.28) $(0.42)
Income$(0.16) $(0.16)
Gain (Loss) from Discontinued Operations - - 0.02 -
------ ------(0.81) 0.04
------ ------
Net Loss Attributable to Common Stock $(0.47) $(1.21) $(0.26) $(0.42)
====== ======$(0.97) $(0.12)
====== ======
DILUTED LOSSEARNINGS (LOSS) PER AVERAGE COMMON SHARE
Loss from Continuing Operations $(0.47) $(1.21) $(0.28) $(0.42)
Income$(0.16) $(0.16)
Gain (Loss) from Discontinued Operations - - 0.02 -
------ ------(0.81) 0.04
------ ------
Net Loss Attributable to Common Stock $(0.47) $(1.21) $(0.26) $(0.42)
------ ------ ------ ------$(0.97) $(0.12)
====== ======
DIVIDENDS DECLARED PER COMMON SHARE $ -0.05 $ - $ - $ -
====== ====== ====== ======--
------ ------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-37
CMS Energy Corporation
(This page intentionally left blank)
CMS-38CMS-30
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NINEIn Millions
-------------
THREE MONTHS ENDED -----------------
SEPTEMBER 30MARCH 31 2007 2006
2005
- --------------------------------------- ----- -------
In Millions-----
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $(211) $ (50) $ (81)(24)
Adjustments to reconcile net loss to net cash
provided by operating activities
Depreciation depletion and amortization (includes
nuclear decommissioning of $4$1 per period) 418 399162 162
Deferred income taxes and investment tax credit (223) (132)(143) (29)
Minority interests (obligations), net (27) (380)(15) (68)
Asset impairment charges 242 --
Fuel costs mark-to-market at the MCV Partnership 226 (367)-- 156
Regulatory return on capital expenditures (18) (48)
Asset impairment charges 239 1,184(8) (3)
Capital lease and other amortization 34 30
Accretion expense 4 14
Gain10 11
Loss on the sale of assets - (5)267 --
Earnings from equity method investees (63) (92)(19) (36)
Cash distributions received from equity method investees 63 7113 21
Changes in other assets and liabilities:
Decrease (increase)Increase in accounts receivable and accrued
revenues 250 (18)
Increase(466) (176)
Decrease (increase) in accrued power supply and gas
revenue 27 (26)
Decrease in inventories (246) (351)517 377
Decrease in deferred property taxes 102 106
Increase (decrease) in accounts payable (116) 184(2) (149)
Decrease in accrued taxes (152) (146)
Increase (decrease)(50) (50)
Decrease in accrued expenses 35 (36)
Increase (decrease)(52) (13)
Decrease in the MCV Partnership gas supplier funds
on deposit (159) 275-- (90)
Decrease in other current and non-current assets 106 765 96
Increase (decrease) in other current and
non-current liabilities 13 (47)(22) 12
----- ------------
Net cash provided by operating activities $ 436 $ 567315 171
----- ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital
lease) $(477) $ (435)(220) (129)
Cost to retire property (41) (20)(5) (19)
Restricted cash and restricted short-term investments 125 (149)18 127
Investments in nuclear decommissioning trust funds (20) (5)(1) (17)
Proceeds from nuclear decommissioning trust funds 20 31
Proceeds from short-term investments - 295
Purchase of short-term investments - (186)2 4
Maturity of the MCV Partnership restricted investment
securities held-to-maturity 119 316-- 28
Purchase of the MCV PartnershipParnership restricted investment
securities held-to-maturity (118) (267)-- (26)
Proceeds from sale of assets - 59180 --
Cash relinquished from sale of assets (46) --
Deposit on pending asset sale 75 --
Other investing (44) (1)3 (4)
----- ------------
Net cash used inprovided by (used in) investing activities $(436) $ (362)6 (36)
----- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds, and other long-term debt $ 72 $ 1,08615 13
Issuance of common stock 18 2897 2
Retirement of bonds and other long-term debt (433) (1,381)(30) (226)
Redemption of preferred stock (32) --
Payment of common stock dividends (11) --
Payment of preferred stock dividends (8) (8)(3) (3)
Payment of capital lease and financial lease obligations (23) (26)(2) (3)
Debt issuance costs, financing fees, and other (15) (42)(1) (8)
----- ------------
Net cash used in financing activities $(389) $ (82)(57) (225)
----- ------------
EFFECT OF EXCHANGE RATES ON CASH 1 1
----- ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $(388) $ 124265 (89)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 351 847
669
----- ------------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 459616 $ 793758
===== ============
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-39CMS-31
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
September 30
2006 DecemberIn Millions
------------------------
MARCH 31
2007 DECEMBER 31
ASSETS (Unaudited) 2005(UNAUDITED) 2006
- ------ ------------ ----------- In Millions-----------
PLANT AND PROPERTY (AT COST)
Electric utility $ 8,4348,583 $ 8,2048,504
Gas utility 3,239 3,1513,283 3,273
Enterprises 1,049 1,068533 552
Other 31 2531
------- -------
12,753 12,44812,430 12,360
Less accumulated depreciation, depletion,
and amortization 5,259 5,1235,286 5,233
------- -------
7,494 7,3257,144 7,127
Construction work-in-progress 587 520759 646
------- -------
8,081 7,8457,903 7,773
------- -------
INVESTMENTS
Enterprises 554 712510 588
Other 11 10 13
------- -------
564 725521 598
------- -------
CURRENT ASSETS
Cash and cash equivalents at cost, which
approximates market 459 847577 263
Restricted cash and restricted short-term investments 70 198at cost, which approximates
market 65 71
Accounts receivable, notes receivable and accrued
revenue, less allowances of $31$22 and $31,$29,
respectively 476 809
Notes receivable 65 15998 575
Accrued power supply and gas revenue 129 156
Accounts receivable, dividends receivable and notes receivable -
related parties 83 5474 63
Inventories at average cost
Gas in underground storage 1,293 1,069619 1,129
Materials and supplies 100 9693 87
Generating plant fuel stock 127 110112 126
Assets held for sale 113 189
Price risk management assets 19 11322 45
Regulatory assets - postretirement benefits 19 19
Derivative instruments 48 242Deferred income taxes 151 155
Deferred property taxes 124 160131 150
Prepayments and other 163 167112 115
------- -------
3,046 3,8993,215 3,143
------- -------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 526 560
Additional minimum pension 399 399502 514
Postretirement benefits 99 1161,111 1,131
Customer Choice Act 197 222179 190
Other 469 484506 497
Nuclear decommissioning trust funds 606 602
Assets held for sale 160 280
Price risk management assets 25 165
Nuclear decommissioning trust funds 582 55517 19
Goodwill 30 2726 26
Notes receivable 138 137
Notes receivable - related parties 131 187
Notes receivable 229 187114 125
Other 600 649279 336
------- -------
3,287 3,5513,638 3,857
------- -------
TOTAL ASSETS $14,978 $16,020$15,277 $15,371
======= =======
CMS-40CMS-32
September 30
2006 DecemberIn Millions
------------------------
MARCH 31
2007 DECEMBER 31
STOCKHOLDERS' INVESTMENT AND LIABILITIES (Unaudited) 2005(UNAUDITED) 2006
- ---------------------------------------- ------------ ----------- In Millions-----------
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 350.0 shares;
outstanding 222.3224.2 shares and
220.5222.8 shares, respectively $ 2 $ 2
Other paid-in capital 4,461 4,4364,468 4,468
Accumulated other comprehensive loss (301) (288)(192) (318)
Retained deficit (1,886) (1,828)
------- -------
2,276 2,322(2,168) (1,918)
-------- --------
2,110 2,234
Preferred stock of subsidiary 44 44
Preferred stock 261250 261
Long-term debt 6,644 6,8006,032 6,202
Long-term debt - related parties 178 178
Non-current portion of capital and finance lease obligations 296 308
------- -------
9,699 9,913
------- -------52 42
-------- --------
8,666 8,961
-------- --------
MINORITY INTERESTS 344 333
------- -------85 77
-------- --------
CURRENT LIABILITIES
Current portion of long-term debt and capital
and finance leases 315 316
Current portion of long-term debt - related parties - 129722 564
Notes payable 1 2
Accounts payable 497 597494 499
Accrued rate refunds 5 37
Accounts payable - related parties 1 2 16
Accrued interest 117 145105 126
Accrued taxes 180 331295 312
Liabilities held for sale 65 101
Price risk management liabilities 34 80
Current portion of gas supply contract obligations - 10
Deferred income taxes 98 55
MCV Partnership gas supplier funds on deposit 34 19349 70
Legal settlement liability 200 200
Other 308 241
------- -------
1,585 2,113
------- -------247 243
-------- --------
2,184 2,156
-------- --------
NON-CURRENT LIABILITIES
Regulatory Liabilities
Regulatory liabilities for cost of removal 1,174 1,1201,200 1,166
Income taxes, net 475 455547 539
Other regulatory liabilities 236 178240 249
Postretirement benefits 431 3821,074 1,066
Deferred income taxes 4 297107 111
Deferred investment tax credit 63 6761 62
Asset retirement obligationsobligation 508 498
496Liabilities held for sale 31 39
Price risk management liabilities 41 161
Gas supply contract obligations - 6124 31
Argentine currency impairment reserve 197 --
Other 428 444
------- -------
3,350 3,661
------- -------353 416
-------- --------
4,342 4,177
-------- --------
COMMITMENTS AND CONTINGENCIES (Notes 3, 4 and 6)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $14,978 $16,020
======= =======$ 15,277 $ 15,371
======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-41CMS-33
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)
In Millions
------------------------
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30MARCH 31 2007 2006
2005 2006 2005
- ------------ ------- ------- ------- -------
In Millions--------------------------- ----------- -----------
COMMON STOCK
At beginning and end of period $ 2 $ 2
$ 2 $ 2
------- ------- ------- -------
OTHER PAID-IN CAPITAL
At beginning of period 4,452 4,4224,468 4,436 4,140
Common stock issued 10 7 25 288
Common stock repurchased (1) (1) (1) (1)13 8
Common stock reissued - -6 1
1
------- -------Redemption of preferred stock (19) --
------- -------
At end of period 4,461 4,428 4,461 4,428
------- -------4,468 4,445
------- -------
ACCUMULATED OTHER COMPREHENSIVE LOSS
Minimum PensionRetirement Benefits Liability
At beginning of period (19) (26) (19) (17)
Minimum pension liability adjustments (a) - - - (9)
------- ------- ------- -------
Atand end of period (23) (19) (26) (19) (26)
------- -------
------- -------
Investments
At beginning of period 10 8 914 9
Unrealized gain on investments (a) -- 2 1 3 -
------- -------
------- -------
At end of period 12 9 12 9
------- -------14 11
------- -------
Derivative Instruments
At beginning of period (12) 35
(3) 35 (9)
Unrealized gain (loss)loss on derivative instruments (a) (22) 31 (22) 43(3) (4)
Reclassification adjustments included in net
loss (a) 1 (1) (1) (1) (7)
------- -------
------- -------
At end of period 12 27 12 27
------- -------(14) 30
------- -------
Foreign Currency Translation
At beginning of period (308) (312)(297) (313)
(319)Sale of Argentine assets (a) 128 --
Other foreign currency translations (a) 2-- 5 7 12
------- -------
------- -------
At end of period (306) (307) (306) (307)(169) (308)
------- -------
------- -------
At end of period (301) (297) (301) (297)
------- -------Total Accumulated Other Comprehensive Loss (192) (286)
------- -------
RETAINED DEFICIT
At beginning of period (1,783) (1,557)(1,918) (1,828)
(1,734)Adjustment to initially apply FIN 48 (24) --
Net loss (a) (101) (263) (50) (81)(211) (24)
Preferred stock dividends declared (2) (2) (8) (7)
------- -------(3) (3)
Common stock dividends declared (11) --
Redemption of preferred stock (a) (1) --
------- -------
At end of period (1,886) (1,822) (1,886) (1,822)
------- -------(2,168) (1,855)
------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 2,2762,110 $ 2,311 $ 2,276 $ 2,3112,306
======= =======
======= =======
(A)(a) DISCLOSURE OF COMPREHENSIVE LOSS:
Minimum Pension Liability
Minimum pension liability adjustments, net of tax
benefit of $-, $-, $- and $(5), respectively $ - $ - $ - $ (9)
Investments
Unrealized gain on investments, net of tax
of $- in 2007 and $1 $-, $1 and $-, respectivelyin 2006 $ -- $ 2 1 3 -
Derivative Instruments
Unrealized gain (loss)loss on derivative
instruments, net of tax (tax benefit)
of $(7), $15, $(14)$3 in 2007 and $28, respectively (22) 31 (22) 43$(5) in 2006 (3) (4)
Reclassification adjustments included in
net loss, net of tax benefit
of $-, in 2007 and $(1), $(2) and
$(7), respectively in 2006 1 (1)
Sale of Argentine assets, net of tax of $68 128 --
Other foreign currency translations -- 5
Redemption of preferred stock, net of tax
benefit of $(1) in 2007 (1) (1) (7)
Foreign currency translation, net 2 5 7 12--
Net loss (101) (263) (50) (81)
------- -------(211) (24)
------- -------
Total Comprehensive Loss $ (120)(86) $ (227) $ (63) $ (42)
======= =======(22)
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-42CMS-34
(PAGE INTENTIONALLY LEFT BLANK)
CMS-35
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CMS-36
CMS Energy Corporation
CMS ENERGY CORPORATION
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
These interim Consolidated Financial Statements have been prepared by CMS Energy
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in consolidated financial statements prepared in
accordance with accounting principles generally accepted in the United States
have been condensed or omitted. Certain prior year amounts have been
reclassified to conform to the presentation in the current year.year, including
certain reclassifications to our Consolidated Financial Statements for
discontinued operations. Therefore, the consolidated financial statements for
the year ended December 31, 2006 have been updated for amounts previously
reported. In management's opinion, the unaudited information contained in this
report reflects all adjustments of a normal recurring nature necessary to assure
the fair presentation of financial position, results of operations and cash
flows for the periods presented. The Condensed Notes to Consolidated Financial Statements
and the related Consolidated Financial Statements should be read in conjunction
with the Consolidated Financial Statements and related Notes contained in CMS
Energy's Form 10-K/A Amendment No. 110-K for the year ended December 31, 2005.2006. Due to the seasonal
nature of CMS Energy's operations, the results as presented for this interim
period are not necessarily indicative of results to be achieved for the fiscal
year.
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: CMS Energy is an energy company operating primarily in
Michigan. We are the parent holding company of Consumers and Enterprises.
Consumers is a combination electric and gas utility company serving Michigan's
Lower Peninsula. Enterprises, through various subsidiaries and equity
investments, is engaged in domestic and international diversified energy
businesses including independent power production, electric distribution, and
natural gas transmission, storage and processing. We manage our businesses by
the nature of services each provides and operate principally in three business
segments: electric utility, gas utility, and enterprises.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include CMS
Energy, Consumers, Enterprises, and all other entities in which we have a
controlling financial interest or are the primary beneficiary, in accordance
with FASB Interpretation No.FIN 46(R). We use the equity method of accounting for investments in
companies and partnerships that are not consolidated, where we have significant
influence over operations and financial policies, but are not the primary
beneficiary. We eliminate intercompany transactions and balances.
USE OF ESTIMATES: We prepare our consolidated financial statements in conformity
with U.S. GAAP. We are required to make estimates using assumptions that may
affect the reported amounts and disclosures. Actual results could differ from
those estimates.
We are required to record estimated liabilities for contingencies in theour consolidated financial
statements when it is probable that a loss will be incurred in the future as a
result of a current event, and when an amount can be reasonably estimated. We
have used this accounting principle to record estimated liabilities as discussed
inFor
additional details, see Note 3, Contingencies.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity
and natural gas,
CMS-37
CMS Energy Corporation
and the transportation, processing, and storage of natural gas when services are
provided. Sales taxes are recorded as liabilitiesWe record sales tax on a net basis and are not
included inexclude it from revenues. RevenuesWe
recognize revenues on sales of marketed electricity, natural gas, and other
energy products are recognized at delivery. Mark-to-marketWe recognize mark-to-market changes in the fair
CMS-43
CMS Energy Corporation
values of energy trading contracts that qualify as derivatives are recognized as revenues in
the periods in which the changes occur.
ACCOUNTING FOR MISO TRANSACTIONS: CMS ERM accounts for MISO transactions on a
net basis for all of the generating units for which CMS ERM markets power. CMS
ERM allocates other fixed costs associated with MISO settlements back to the
generating units and records billing adjustments when invoices are received.
Consumers accounts for MISO transactions on a net basis for all of its
generating units combined. Consumers records billing adjustments when invoices
are received and also records an expense accrual for future adjustments based on
historical experience.
ACCRETION EXPENSE: CMS ERM engaged in prepaid sales arrangements to provide
natural gas to various entities over periods of up to 12 years at predetermined
price levels. CMS ERM established a liability for those outstanding obligations
equal to the discounted present value of the contracts, and hedged its exposures
under those arrangements. The amounts were recorded as liabilities on our
Consolidated Balance Sheets and were guaranteed by Enterprises. As CMS ERM
fulfilled its obligations under the contracts, it recognized revenues upon the
delivery of natural gas, recorded a reduction to the outstanding obligation, and
recognized accretion expense. In August 2006, CMS ERM extinguished its remaining
outstanding obligations for $70 million, which included a $6 million loss on
extinguishment.
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY: Our subsidiaries and affiliates
whose functional currency is not the U.S. dollar translate their assets and
liabilities into U.S. dollars at the exchange rates in effect at the end of the
fiscal period. We translate revenue and expense accounts of such subsidiaries
and affiliates into U.S. dollars at the average exchange rates that prevailed
during the period. TheseWe show these foreign currency translation adjustments are shown in the
stockholders' equity section on our Consolidated Balance Sheets. ExchangeWe include
exchange rate fluctuations on transactions denominated in a currency other than
the functional currency, except those that are hedged, are included in determining net
income.
At September 30, 2006,March 31, 2007, the cumulative Foreign Currency Translation component of
stockholders' equity is $306was $169 million, which primarily represents currency
losses in Argentina and Brazil. The cumulative foreign currency loss due to the
unfavorable exchange rate of the Argentine peso using an exchange rate of 3.1083.102
pesos per U.S. dollar was $264$129 million, net of tax. The cumulative foreign
currency loss due to the unfavorable exchange rate of the Brazilian real using
an exchange rate of 2.1742.04 reais per U.S. dollar was $44$41 million, net of tax.
IMPAIRMENT OF LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessmentWe evaluate
potential impairments of our long-lived assets, other than goodwill, based on
various analyses, including the projection of undiscounted cash flows, whenever
events or changes in circumstances indicate that the carrying amount of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. We periodically perform tests of impairment if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. OfIf the carrying amount of the investment or asset
exceeds its estimated undiscounted future cash flows, we recognize an impairment
loss and write-down the investment or asset to its estimated fair value.
We also assess our total assets, recorded at $14.978
billion at September 30, 2006, 58 percent represent long-lived assets andability to recover the carrying amounts of our equity method
investments whenever events or changes in circumstances indicate that are subjectthe
carrying amount of the investments may not be recoverable. This assessment
requires us to this typedetermine the fair values of analysis.our equity method investments. We
determine fair value using valuation methodologies, including discounted cash
flows and the ability of the investee to sustain an earnings capacity that
justifies the carrying amount of the investment. We record a write down if the
fair value is less than the carrying value and the decline in value is
considered to be other than temporary.
For additional details, see Note 2, Asset Sales, Discontinued Operations and
Impairment Charges and Sales.
DETERMINATION OF PENSION MRV OF PLAN ASSETS:Charges.
RECLASSIFICATIONS: We determine the MRV for pension
plan assets, as defined in SFAS No. 87, as the fair value of plan assets on the
measurement date, adjusted by the gains or losses that will not be admitted into
MRV until future years. We reflect each year's assets gain or loss in MRV in
equal amounts over a five-year period beginning on the date the original amount
was determined. The MRV is used in the calculation of net pension cost.
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CMS Energy Corporation
OTHER INCOME AND OTHER EXPENSE: The following tables show the components of
Other income and Other expense:
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Other income
Interest and dividends - related parties $ 3 $ 2 $ 9 $ 7
Electric restructuring return 1 1 3 5
Return on stranded and security costs 1 1 4 4
Nitrogen oxide allowance sales 1 1 7 2
Refund of surety bond premium - - 1 -
Reduction of contingent liability - - - 3
All other 1 5 5 7
--- --- --- ---
Total other income $ 7 $10 $29 $28
=== === === ===
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Other expense
Investment write-down $ - $ - $ - $ (1)
Loss on SERP investment - - - (1)
Loss on reacquired and extinguished debt - (10) (5) (16)
Civic and political expenditures (1) (1) (2) (2)
Donations - - (1) -
All other (1) (2) (4) (5)
--- ---- ---- ----
Total other expense $(2) $(13) $(12) $(25)
=== ==== ==== ====
RECLASSIFICATIONS: Certainhave reclassified certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income (loss) for the periods presented. The most significant of these
reclassifications is related to certain subsidiaries reclassified as "held for
sale" on our Consolidated Balance Sheets and activities of those subsidiaries as
Income (Loss) From Discontinued Operations in our Consolidated Statements of
Income (Loss). For additional details, see Note 2, Asset Sales, Discontinued
Operations and Impairment Charges, "Discontinued Operations."
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CMS Energy Corporation
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE: SFAS No. 157, Fair Value
Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us
January 1, 2008. The standard provides a revised definition of "fair value" and
gives guidance on how to measure the fair value of assets and liabilities. Under
the standard, fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly exchange between market
participants. The standard does not expand the use of fair value in any new
circumstances. However, additional disclosures will be required on the impact
and reliability of fair value measurements reflected in theour consolidated
financial statements. The standard will also eliminate the existing prohibition
of recognizing "day one" gains or losses on derivative instruments, and will
generally require such gains and losses to be recognized through earnings. We
are presently evaluating the impacts, if any, of implementing SFAS No. 157. We
currently do not hold any derivatives that would involve day one gains or
losses.
CMS-45
CMS Energy Corporation
SFAS No. 158, Employers' Accounting159, The Fair Value Option for Defined Benefit PensionFinancial Assets and Other
Postretirement Plans -Financial
Liabilities, Including an amendment ofto FASB StatementsStatement No. 87, 88, 106, and
132(R): For details on SFAS No. 158, see Note 7, Retirement Benefits.
FIN 48, Accounting for Uncertainty in Income Taxes:115: In June 2006,February 2007,
the FASB issued FIN 48,SFAS No. 159, effective for us January 1, 2007.2008. This interpretation provides a
two-step approach forstandard
will give us the recognitionoption to select certain financial instruments and measurement of uncertain tax positions
taken, or expectedother items,
which otherwise are not required to be taken, by a company on its income tax returns. The
first step ismeasured at fair value, and measure those
items at fair value. If we choose to evaluateelect the tax position to determine if, based on
management's best judgment, it is greater than 50 percent likely thatfair value option for an item, we
would recognize unrealized gains and losses associated with changes in the taxing
authority will sustain the tax position. The second step is to measure the
appropriate amountfair
value of the benefit to recognize. This is done by estimatingitem over time. The statement will also require disclosures for
items for which the potential outcomes and recognizing the greatest amount thatfair value option has a cumulative
probability of at least 50 percent.been elected. We are presently
evaluating the impacts, if
any. Any initial impacts of implementing FIN 48 would result in a cumulative
adjustmentwhether we will choose to retained earnings.
Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year
Misstatements when Quantifying Misstatements in Current Year Financial
Statements: In September 2006, the SEC issued SAB No. 108, effective for us
December 31, 2006. This accounting bulletin clarifies how registrants should
assess the materiality of prior period financial statement errors in the current
period. We do not presently believe that adoption of this standard would have a
material effect on our financial position or results of operations.
2: ASSET IMPAIRMENT CHARGES AND SALES
ASSET IMPAIRMENT CHARGES
We evaluate potential impairments of our investments in long-lived assets, other
than goodwill, based on various analyses, including the projection of
undiscounted cash flows, whenever events or changes in circumstances indicate
that the carrying amount of the assets may not be recoverable. If the carrying
amount of the investment or asset exceeds its estimated undiscounted future cash
flows, an impairment loss is recognized and the investment or asset is written
down to its estimated fair value.
We also assess our ability to recover the carrying amounts of our equity method
investments whenever events or changes in circumstances indicate that the
carrying amount of the investments may not be recoverable. This assessment
requires us to determine the fair values of our equity method investments. The
determination of fair value is based on valuation methodologies, including
discounted cash flows and the ability of the investee to sustain an earnings
capacity that justifies the carrying amount of the investment. Ifelect the fair value is less thanoption for any
financial instruments or other items.
2: ASSET SALES, DISCONTINUED OPERATIONS AND IMPAIRMENT CHARGES
ASSET SALES
In March 2007, we completed the carrying valuesale of a portfolio of our businesses in
Argentina and the decline in value is considered to be
other than temporary, an appropriate write-down is recorded.
GasAtacama: On March 24, 2004, the Argentine government authorized the
restriction of exports ofour northern Michigan non-utility natural gas assets to Chile, giving priority to domestic
demand in Argentina. This restriction has had a detrimental effect on
GasAtacama's earnings since GasAtacama's gas-firedLucid
Energy for gross cash proceeds of $130 million. The Argentine assets sold
include our electric generating plant is
locatedinterests in Chile and uses Argentine gas for fuel. From April through December
2004, Bolivia agreed to export 4 million cubic meters of gas per day to
Argentina, which allowed Argentina to minimize its curtailments to Chile. Argentina and Bolivia extendedour interest in
the termTGM natural gas transportation and pipeline business in Argentina. The
Michigan assets sold include the Antrim natural gas processing plant, 155 miles
of associated gathering lines, and interests in three special purpose gas
transmission pipelines that agreement through December 31,
2006. Withtotal 110 miles.
In connection with the Bolivian gas supply, Argentina relaxedsale of our Argentine and Michigan assets, we entered
into agreements that grant Lucid Energy:
- - an option to buy CMS Gas Transmission's ownership interest in TGN, subject
to the rights of other third parties,
- - the right to a portion of damages that may be awarded and received by CMS
Gas Transmission in connection with certain legal proceedings, and
- - the right to all of the proceeds that Enterprises will receive if it sells
its export restrictionsstock interest in CMS Generation San Nicolas Company.
Under these agreements, we have essentially sold our rights to GasAtacama, allowing GasAtacamacertain awards or
proceeds that we may receive in the future. A portion of the consideration
received in the sale has been allocated to receive approximately 50 percent of its
contracted gas quantities at its electricthese agreements. We have recorded
$32 million as a deferred credit in Other Non-current Liabilities on our
Consolidated Balance Sheets.
In March 2007, we also sold our interest in El Chocon, an Argentine
hydroelectric generating plant.
CMS-46business,
CMS-39
CMS Energy Corporation
On May 1, 2006, the Bolivian government announced its intention to nationalize
the natural gas industry and raise prices under its existing gas export
contracts. Since May, gas flow from Bolivia has been restricted, as Argentina
and Bolivia have been renegotiating the priceEndesa, S.A. for gas. Simultaneously, gas
supply to GasAtacama has been further curtailed. In July 2006, Argentina agreed
to increase the price it pays for gas from Bolivia through the termgross cash proceeds of the
existing contract, December 31, 2006. Concurrently, Argentina announced that it
would recover all of this price increase by a special tax on its gas exports.$50 million.
The decision of Argentina to increase the cost of its gas exports, in addition
to maintaining the current curtailment scheme, increased the risk and cost of
GasAtacama's fuel supply.
In August 2006, GasAtacama was notified by one of its major gas suppliers that
it would no longer deliver gas to GasAtacama under the Argentine government's
current policy. This indicated GasAtacama's operations could be adversely
affected by this situation. In conjunction with the preparationimpacts of our consolidated financial statements for the quarter ended September 30, 2006, we
performed an impairment analysis to determine the fair value of our investmentasset sales are included in GasAtacama. We determined the fair value by discounting a set of
probability-weighted streams of future operating cash flows. We concluded that
the fair value of our investment, which includes notes receivable-related partyGain on asset sales, net and
Income (Loss) from GasAtacama, was lower than the carrying amount and that this decline was
other than temporary. In the third quarter of 2006, we recorded an impairment
charge of $239 million onDiscontinued Operations in our Consolidated Statements of
Income (Loss). As a
result, our net income was reduced by $169 million after considering tax effects
and minority interest.
Our remaining investment in GasAtacama consists of $122 million of notes
receivable, reported under the Enterprises business segment. These notes are
classified as Notes receivable-related parties on our Consolidated Balance
Sheets. A $53 million valuation allowance was recognized against the notes
receivable as a result of the impairment. Future earnings or losses at
GasAtacama will be first applied to the notes receivable valuation allowance. We
will recognize any future interest income on the notes receivable when payments
are received.
MCV: In the third quarter of 2005, we recorded impairment charges of $1.184
billion on our Consolidated Statements of Income (Loss). These impairment
charges included $1.159 billion to recognize the reduction in fair value of the
MCV Facility's fixed assets and $25 million that represented interest
capitalized during the construction of the MCV Facility. As a result, our net
income was reduced by $385 million after considering tax effects and minority
interest.
ASSET SALES
In August 2006, we auctioned off 36 parcels of land near Ludington, Michigan.
Consumers held a majority share of the land, which Consumers co-owned with DTE
Energy. We closed on all 36 parcels in October 2006. Our portion of the gross
proceeds is approximately $6 million.
Gross cash proceeds received from the sale of assets totaled $59 millionThere were no asset sales for the ninethree months ended September 30, 2005. The impacts of these sales are included in
Gain on assets sales, net on our Consolidated Statements of Income (Loss).
CMS-47
CMS Energy CorporationMarch 31,
2006.
For the ninethree months ended September 30, 2005,March 31, 2007, we sold the following assets:assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:
In Millions
- --------------------------------------------------------------------------------
Pretax After-tax
Gain Gain
Date sold Business/Project Gain Gain(Loss) (Loss)
- --------- ---------------- ------ ---------
February GVKMarch El Chocon $ 3 $ 2
April Scudder Latin American Power Fund 2 1
April Gas turbine23 $15
March TGM and auxiliary equipment - -
---Bay Area Pipeline (a) (11) (7)
---- ---
Total gain on asset sales $ 512 $ 3
===8
==== ===
(a) Included in the $130 million sale to Lucid Energy.
SUBSEQUENT ASSET SALES: In February 2007, we entered into an Agreement of
Purchase and Sale with TAQA to sell our ownership interest in businesses in the
Middle East, Africa, and India for $900 million. Businesses included in the sale
are Taweelah, Shuweihat, Jorf Lasfar, Jubail, Neyveli, and Takoradi. We closed
on the sale in May 2007. The book value of these assets at March 31, 2007 was
approximately $682 million. After considering the effects of taxes, post-closing
adjustments, and closing costs, we anticipate a gain of approximately $50
million. The estimated gain is also subject to a number of adjustments that will
occur at or shortly after closing.
In April 2007, we sold Palisades to Entergy for $380 million. The final purchase
price was subject to various closing adjustments resulting in us receiving $361
million. We also paid Entergy $30 million to assume ownership and responsibility
for the Big Rock ISFSI. We entered into a 15-year power purchase agreement with
Entergy for 100 percent of the plant's current electric output. For additional
details on sale of Palisades and the Big Rock ISFSI, see Note 3, Contingencies,
"Other Consumers' Electric Utility Contingencies - The Sale of Nuclear Assets
and the Palisades Power Purchase Agreement."
In April 2007, we entered into a purchase and sale agreement with Petroleos de
Venezuela, S.A., which is owned by the Bolivarian Republic of Venezuela, to sell
our ownership interest in SENECA and certain associated generating equipment for
$106 million. We closed on the sale in April 2007. The book value of these
assets at March 31, 2007 was approximately $55 million.
PENDING ASSET SALES: In April 2007, we entered into an agreement to sell CMS
Energy Brasil S.A. for $211 million to CPFL Energia S.A., a Brazilian utility.
We expect to close on the sale by the end of the second quarter of 2007, subject
to approval by the Brazilian national regulatory agency. The book value of these
assets at March 31, 2007 was approximately $195 million, which includes a
cumulative net foreign currency translation loss of $63 million.
We also announced plans to conduct an auction to sell our GasAtacama combined
gas pipeline and power generation businesses in Argentina and Chile, and our
electric generating plant in Jamaica. We expect to complete the sale of these
businesses by the end of 2007.
Our pending asset sales are subject to the receipt of all necessary
governmental, lender and partner approvals. We plan to use the proceeds from the
pending asset sales to invest in our utility business and reduce parent company
debt.
CMS-40
CMS Energy Corporation
The asset book values will vary between March 31, 2007 and each transaction's
closing date. Final book value is dependent upon the timing of closing, results
of operations for certain of the assets up to closing, and other factors.
DISCONTINUED OPERATIONS
Items classified as "held for sale" on our Consolidated Balance Sheets are
comprised of consolidated subsidiaries that meet the criteria of held for sale
under SFAS No. 144. At March 31, 2007, these subsidiaries include Takoradi,
SENECA, and certain associated holding companies. At December 31, 2006, these
subsidiaries include our Argentine businesses sold in March 2007, a majority of
our Michigan non-utility businesses sold in March 2007, Takoradi, SENECA, and
certain associated holding companies.
The major classes of assets and liabilities "held for sale" on our Consolidated
Balance Sheets are as follows:
In Millions
----------------------------------
March 31, 2007 December 31, 2006
-------------- -----------------
Assets
Cash $ 39 $ 88
Accounts receivable, net 60 80
Notes receivable 106 110
Property, plant and equipment, net 54 168
Other 14 23
---- ----
Total assets $273 $469
==== ====
Liabilities
Accounts payable $ 42 $ 66
Minority interest 12 14
Other 42 60
---- ----
Total liabilities $ 96 $140
==== ====
CMS Energy Brasil S.A., is a consolidated subsidiary that meets the criteria of
held for sale under SFAS No. 144 subsequent to March 31, 2007. As a result, the
major classes of assets and liabilities of CMS Energy Brasil S.A. will be
classified as "held for sale" on our Consolidated Balance Sheets in the second
quarter of 2007.
CMS-41
CMS Energy Corporation
The major classes of assets and liabilities of CMS Energy Brasil S.A. at March
31, 2007 and at December 31, 2006 are as follows:
In Millions
----------------------------------
March 31, 2007 December 31, 2006
-------------- -----------------
Assets
Cash $ 21 $ 14
Accounts receivable, net 29 25
Goodwill 26 25
Investments 35 33
Property, plant and equipment, net 68 65
Other 30 19
---- ----
Total assets $209 $181
==== ====
Liabilities
Accounts payable $ 17 $ 16
Accrued taxes 13 10
Minority interest 27 25
Other 20 12
---- ----
Total liabilities $ 77 $ 63
==== ====
Our discontinued operations contain the activities of the subsidiaries
classified as "held for sale" as well as those disposed of during the quarter
and are a component of our Enterprises business segment. We reflect the
following amounts in the Income (Loss) From Discontinued Operations line in our
Consolidated Statements of Income (Loss):
In Millions
---------------
Three months ended March 31 2007 2006
- --------------------------- ----- ----
Revenues $ 75 $507
===== ====
Discontinued operations:
Pretax income (loss) from discontinued operations $(248) $ 9
Income tax expense (benefit) (68) 1
----- ----
Income (Loss) From Discontinued Operations $(180)(a) $ 8
===== ====
(a) Includes a loss on disposal of our Argentine and northern Michigan
non-utility assets of $278 million ($171 million after-tax and minority
interest).
Income (Loss) From Discontinued Operations includes a provision for anticipated
closing costs and a portion of CMS Energy's parent company interest expense.
Interest expense of $3 million for the three months ended March 31, 2007 and $3
million for the three months ended March 31, 2006 has been allocated based on
the net book value of the asset to be sold divided by CMS Energy's total
capitalization of each discontinued operation multiplied by CMS Energy's
interest expense.
IMPAIRMENT CHARGES
We record an asset impairment when we determine that the expected future cash
flows from an asset would be insufficient to provide for recovery of the asset's
carrying value. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by
CMS-42
CMS Energy Corporation
which the carrying amount exceeds the fair value. We estimate the fair market
value of the asset utilizing the best information available. This information
includes quoted market prices, market prices of similar assets, and discounted
future cash flow analyses. The assets written down include certain equity method
and other investments.
There were no asset impairments recorded for the three months ended March 31,
2006. The table below summarizes our asset impairments for the three months
ended March 31, 2007:
In Millions
------------------
Three months ended March 31, 2007 Pretax After-tax
- --------------------------------- ------ ---------
Asset impairments:
Enterprises:
TGN (a) $215 $140
Jamaica (b) 22 14
PowerSmith (c) 5 3
---- ----
Total asset impairments $242 $157
==== ====
(a) In the first quarter of 2007, we recorded an impairment charge to recognize
the reduction in fair value of our investment in TGN, a natural gas
business in Argentina. The impairment included a cumulative net foreign
currency translation loss of approximately $197 million. We will maintain
our interest in TGN, which remains subject to a potential sale to the
government of Argentina or some other disposition.
(b) In the first quarter of 2007, we recorded an impairment charge to reflect
the fair market value of our investment in an electric generating plant in
Jamaica.
(c) In March 2007, we recorded an impairment charge to reflect the fair value
of our investment in PowerSmith.
3: CONTINGENCIES
SEC AND OTHERDOJ INVESTIGATIONS: During the period of May 2000 through January 2002,
CMS MST engaged in simultaneous, prearranged commodity trading transactions in
which energy commodities were sold and repurchased at the same price. These so
called round-trip trades had no impact on previously reported consolidated net
income, earnings per share or cash flows, but had the effect of increasing
operating revenues and operating expenses by equal amounts.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip
trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict
the outcome of this matter and what effect, if any, this investigation will have
on its business. In March 2004, the SEC approved a cease-and-desist order
settling an administrative action against CMS Energy related to round-trip
trading. The order did not assess a fine and CMS Energy neither admitted to nor
denied the order's findings. The settlement resolved the SEC investigation
involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action
against three former employees related to round-trip trading at CMS MST. One of
the individuals has settled with the SEC. CMS Energy is currently advancing
legal defense costs for the remaining two individuals in accordance with
existing indemnification policies. Those two individuals filed a motion to
dismiss the SEC action, which was denied.
SECURITIES CLASS ACTION LAWSUITS: Beginning onin May 17, 2002, a number of complaints
were filed against
CMS-43
CMS Energy Corporation
CMS Energy, Consumers and certain officers and directors of CMS Energy and its
affiliates.affiliates in the United States District Court for the Eastern District of
Michigan. The cases were consolidated into a single lawsuit (the "Shareholder
Action"), which generally seeks unspecified damages based on allegations that
the defendants violated United States securities laws and regulations by making
allegedly false and misleading statements about CMS Energy's business and
financial condition, particularly with respect to revenues and expenses recorded
in connection with round-trip trading by CMS MST. In January 2005, the court
granted a motion to dismiss Consumers and three of the individual defendants,
but denied the motions to dismiss CMS Energy and the 13 remaining individual
defendants. The court issued an opinion and order datedIn March 24, 2006, granting
in part and denying in part plaintiffs' amended motion for class certification.
Thethe court conditionally certified a class consisting
of "[a]ll"all persons who purchased CMS Common Stock during the period of October 25,
2000 through and including May 17, 2002 and who were damaged thereby." The court
excluded purchasers of CMS Energy's 8.75 percent Adjustable Convertible Trust
Securities ("ACTS") from the class. Trial has been scheduled for March 2007. Inclass and, in response, to
the court's opinion and order excluding purchasers of ACTS from the shareholder
class, a new class action lawsuit
was filed on behalf of ACTS purchasers. The
new lawsuit namespurchasers (the "ACTS Action") against the same
defendants asnamed in the shareholder actionShareholder Action. The settlement described in the
following paragraph, if approved, will resolve both the Shareholder and contains
essentially the same allegations and class period.ACTS
Actions.
On January 3, 2007, CMS Energy and the individual
defendants will defend themselves vigorously in this litigation but cannot
predict its outcome.
ERISA LAWSUITS: CMS Energy wasother parties entered into a named defendant, along with Consumers, CMS MST,
and
CMS-48
CMS Energy Corporation
certain named and unnamed officers and directors, in two lawsuits, filed in July
2002 in United States District Court for the Eastern DistrictMemorandum of
Michigan,
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings PlanUnderstanding (the Plan). Plaintiffs alleged breaches of
fiduciary duties under ERISA and sought restitution on behalf of the Plan with
respect to a decline in value of the shares of CMS Energy Common Stock held in
the Plan, as well as other equitable relief and legal fees. On March 1, 2006,
CMS Energy and Consumers reached an agreement,"MOU"), subject to court and independent
fiduciary approval, to settleregarding settlement of
the two class action lawsuits. The settlement agreement requiredwas approved by a $28special
committee of independent directors and by the full board of directors of CMS
Energy. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. The MOU is expected to lead to a detailed
stipulation of settlement that will be presented to the assigned federal judge
and the affected class in the second quarter of 2007. Under the terms of the
MOU, the litigation will be settled for a total of $200 million, cash payment by CMS Energy's primary insurer to be used to pay Plan
participantsincluding the
cost of administering the settlement and beneficiaries for alleged losses, as well as any legalattorney fees and
expenses. In addition,the court awards. CMS
Energy agreedwill make a payment of approximately $123 million plus an amount
equivalent to certain other steps regarding
administrationinterest on the outstanding unpaid settlement balance beginning on
the date of the Plan. The hearing on finalpreliminary approval of the court and running until the balance of
the settlement was
heldfunds is paid into a settlement account. Out of the total
settlement, CMS Energy's insurers will pay approximately $77 million directly to
the settlement account. CMS Energy took an approximate $123 million net pre-tax
charge to 2006 earnings in the fourth quarter of 2006. In entering into the MOU,
CMS Energy makes no admission of liability under the Shareholder Action and the
ACTS Action. At March 31, 2007, we have a receivable of $77 million and a legal
settlement liability of $200 million recorded on June 15, 2006. On June 27, 2006, the judge entered the Order and Final
Judgment, approving the proposed settlement with minor modifications.our Consolidated Balance
Sheets.
GAS INDEX PRICE REPORTING INVESTIGATION: CMS Energy has notified appropriate
regulatory and governmental agencies that some employees at CMS MST and CMS
Field Services appeared to have provided inaccurate information regarding
natural gas trades to various energy industry publications, which compile and
report index prices. CMS Energy is cooperating with an ongoing investigation by the DOJ
regarding this matter. CMS Energy is unable to predict the outcome of the DOJ
investigation and what effect, if any, the investigation will have on its
business. The CFTC filed a civil injunctive action against two former CMS Field
Services employees in Oklahoma federal district court on February 1, 2005. The
action alleges the two engaged in reporting false natural gas trade information,
and seeks to enjoin suchthese acts, compel compliance with the Commodities Exchange
Act, and impose monetary penalties. Trial dates have been held in abeyance
pending settlement discussions. CMS Energy is currently advancing legal defense
costs to the two individuals in accordance with existing indemnification
policies.
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CMS Energy Corporation
BAY HARBOR: As part of the development of Bay Harbor by certain subsidiaries of
CMS Energy, which went forward under an agreement with the MDEQ, third parties
constructed a golf course and a park over several abandoned cement kiln dust
(CKD)CKD piles, left over
from the former cement plant operation on the Bay Harbor site. Pursuant to the
agreement with the MDEQ, a water collection system was constructed to recover
seep water from one of the CKD piles and CMS Energy built a treatment plant to
treat the seep water. In 2002, CMS Energy sold its interest in Bay Harbor, but
retained its obligations under previous environmental indemnifications entered
into at the inception of the project.
In September 2004, following an eight month shutdown of the treatment plant, the MDEQ issued a notice of noncompliance after finding
high-pH seep water in Lake Michigan adjacent to the property. The MDEQ also
found higher than acceptable levels of heavy metals, including mercury, in the
seep water.
In February 2005, the EPA executed an Administrative Order on Consent (AOC)AOC to address problems at Bay Harbor,
upon the consent of CMS Land Company (CMS Land) and CMS Capital, LLC, both
subsidiaries of CMS Energy. Pursuant to the AOC, the EPA approved a Removal
Action Work Plan in July 2005. Among other things, this plan calls for the
installation of collection trenches to intercept high pHhigh-pH CKD leachate flow to
the lake. It is anticipated that by November 15, 2006,All collection trenches will be installedsystems contemplated in all areas identified in the plan.this work plan have been
installed. Shoreline effectiveness monitoring is ongoing, and CMS Land is
obligated to address any observed exceedances in pH. This may potentially
include the augmentation of the collection system. In May 2006, the EPA approved
a pilot carbon dioxide augmentation plan to augment the leachate recovery system
by improving pH results in the Pine Court area of the collection system. The
augmentation system was installed in June 2006.
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CMS Energy Corporation
In February 2006, CMS Land submitted to the EPA a proposed Remedial
Investigation and Feasibility Study for the East Park CKD pile. The EPA approved
a schedule for near-term activities, which includes consolidating certain CKD
materials and installing collection trenches in the East Park leachate release
area. In June 2006, the EPA approved an East Park CKD Removal Action Work Plan
and Final Engineering Design for Consolidation. The work plan calls for completion of the
collection trenches in East Park by November 15, 2006.
The owner of one parcel of land at Bay Harbor has filed a lawsuit in Emmet
County Circuit Court against CMS Energy and severalthe MDEQ have
initiated negotiations of its subsidiaries, as well
as Bay Harbor Golf Club Inc., Bay Harbor Company LLC, David C. Johnson,an AOC and David V. Johnson, one of the developersto define a long-term remedy at Bay Harbor. Several of these
defendants have demanded indemnification from CMS Energy and affiliates for the
claims made against them in the lawsuit. After a hearing in March 2006 on
motions filed by CMS Energy and other defendants, the judge dismissed various
counts of the complaint. CMS Energy will defend vigorously the existing case and
any other property damage and personal injury claims or lawsuits.East Park.
CMS Land has entered into various access, purchase and settlement agreements
with several of the affected landowners at Bay Harbor.Harbor, and entered into a
confidential settlement with one landowner to resolve a lawsuit filed by that
landowner. CMS Land completed the purchase of fourhas purchased five unimproved lots and a lottwo lots with a house. It has an agreement to purchase one
additional unimproved lot and a lot with a house.houses.
At this time, CMS Land believes it has all necessary access arrangements to
complete the remediation work required under the AOC.
CMS Energy recorded charges related to this matter in 2004, 2005, 2006 totaling
$93 million. At March 31, 2007, CMS Energy has recorded a chargeliability of $85$48 million for
its remaining obligations. We based the liability on 2006 discounted costs,
using a discount rate of 4.7 percent and an inflation rate of 1 percent on
annual operating and maintenance costs. We used the interest rate for 30-year
U.S. Treasury securities for the discount rate. The undiscounted amount of the
remaining obligation is $62 million. We expect to pay $18 million in 2007, $17
million in 2008, $3 million in 2009, and the remaining expenditures as part of
long-term operating and maintenance costs. Any significant change in
assumptions, such as an increase in the number of sites, different remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could impact our estimate of remedial action costs and the timing
of the expenditures. An adverse outcome of this matter could, depending on the
size of any indemnification obligation or liability under environmental laws,
have a potentially significant adverse effect on CMS Energy's financial
condition and liquidity and could negatively impact CMS Energy's financial
results. CMS Energy cannot predict the ultimate cost or outcome of this matter.
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CMS Energy Corporation
CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws
and regulations. Costs to operate our facilities in compliance with these laws
and regulations generally have been recovered in customer rates.
Clean Air Act: Compliance with the federal Clean Air Act and resulting
regulations has been, and will continue to be, a significant focus for us. The
Nitrogen Oxide State Implementation Plan requires significant reductions in
nitrogen oxide emissions. To comply with the regulations, we expect to incur
capital expenditures totaling $835 million through 2011. The key assumptions in
the capital expenditure estimate include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- an AFUDC capitalization rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 7.8 percent. As of September 2006, we have
incurred $660 million in capital expenditures to comply with the federal Clean
Air Act and resulting regulations and anticipate that the remaining $175 million
of capital expenditures will be made in 2006 through 2011. These expenditures
include installing selective catalytic reduction control technology at four of
our coal-fired electric generating plants.
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CMS Energy Corporation
In addition to modifying coal-fired electric generating plants, our compliance
plan includes the use of nitrogen oxide emission allowances until all of the
control equipment is operational in 2011. The nitrogen oxide emission allowance
annual expense is projected to be $4 million per year, which we expect to
recover from our customers through the PSCR process. The projected annual
expense is based on market price forecasts and forecasts of regulatory
provisions, known as progressive flow control, that restrict the usage in any
given year of allowances banked from previous years. The allowances and their
cost are accounted for as inventory. The allowance inventory is expensed at the
rolling average cost as the coal-fired electric generating plants emit nitrogen
oxide.
Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air
Interstate Rule that requires additional coal-fired electric generating plant
emission controls for nitrogen oxides and sulfur dioxide. The rule involves a
two-phase program to reduce emissions of nitrogen oxides by more than 60 percent
and sulfur dioxide by more than 70 percent from 2003 levels by 2015. The final
rule will require that we run our selective catalytic reduction control
technology units year round beginning in 2009 and may require that we purchase
additional nitrogen oxide allowances beginning in 2009.
In addition to the selective catalytic reduction control technology installed to
meet the nitrogen oxide standards, our current plan includes installation of
flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to
meet the Phase I reduction requirements of the Clean Air Interstate Rule, at an
estimated total cost of $960 million. Our capital cost estimates include an
escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.4 percent.
We currently have a surplus of sulfur dioxide allowances, which were granted by
the EPA and are accounted for as inventory. In January 2006, we sold some of our
excess sulfur dioxide allowances for $61 million and recognized the proceeds as
a regulatory liability.
Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury
Rule, which requires initial reductions of mercury emissions from coal-fired
electric generating plants by 2010 and further reductions by 2018. The Clean Air
Mercury Rule establishes a cap-and-trade system for mercury emissions that is
similar to the system used in the Clean Air Interstate Rule. The industry has
not reached a consensus on the technical methods for curtailing mercury
emissions. However, based on current technology, we anticipate our capital costs
for mercury emissions reductions required by Phase I of the Clean Air Mercury
Rule to be less than $50 million and these reductions implemented by 2010. Phase
II requirements of the Clean Air Mercury Rule are not yet known and a cost
estimate has not been determined.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to
certain aspects of EPA's Clean Air Mercury Rule, asserting that the rule is
inadequate. We cannot predict the outcome of this proceeding.
In April 2006, Michigan's governor announced a plan that would result in mercury
emissions reductions of 90 percent by 2015. This plan would adopt the Clean Air
Mercury Rule through its first phase. Beginning in year 2015, the mercury
emissions reduction standards outlined in the governor's plan would become more
stringent than those included in the Clean Air Mercury Rule. We are working with
the MDEQ on the details of these rules. We will develop a cost estimate when the
details of these rules are determined.Routine Maintenance Classification: The EPA has alleged that some utilities have
incorrectly classified plant modifications as "routine maintenance" rather than
seeking permits to modify the plant from the EPA. We have received and responded
to information requests from the EPA on this subject. We believe that we have
properly interpreted the requirements of "routine maintenance." If our
interpretation is found to be incorrect, we
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CMS Energy Corporation may be required to install
additional pollution controls at some or all of our coal-fired electric
generating plants and potentially pay fines. Additionally, the viability of
certain plants remaining in operation could be called into question.
Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental
Protection Act, we expect that we will ultimately incur investigation and
remedial action costs at a number of sites. We believe that these costs will be
recoverable in rates under current ratemaking policies.
We are a potentially responsible party at several contaminated sites
administered under the Superfund. Superfund liability is joint and several,
meaning that many other creditworthy parties with substantial assets are
potentially responsible with respect to the individual sites. Based on our
experience, we estimate that our share of the total liability for the known
Superfund sites will be between $1 million and $10 million. At September 30, 2006,March 31, 2007,
we have recorded a liability for the minimum amount of our estimated probable
Superfund liability.liability in accordance with FIN 14. The timing of payments related to
the remediation of our Superfund sites is uncertain. Any significant change in
assumptions, such as different remediation techniques, nature and extent of
contamination, and legal and regulatory requirements, could affect our estimate
of remedial action costs and the timing of our remediation payments.
Ludington PCB: In October 1998, during routine maintenance activities, we
identified PCB as a component in certain paint, grout, and sealant materials at
Ludington. We removed and replaced part of the PCB material. We have proposedSince proposing a
plan to deal with the remaining materials, andwe have had several conversations
with the EPA. The EPA has proposed a rule which would authorize continued use of
such material in place, subject to certain restrictions. We are awaitingnot able to
predict when a responsefinal rule will be issued.
Electric Utility Plant Air Permit Issues: In April 2007, we received a Notice of
Violation/Finding of Violation from the EPA.
MCV Environmental Issue: In July 2004,EPA alleging that fourteen of our
utility boilers exceeded visible emission limits in their associated air
permits. The utility boilers are located at the MDEQ, Air Control Division, issuedD.E. Karn/J.C. Weadock
Generating Complex, the MCV Partnership a Letter of Violation asserting thatJ.H. Campbell Plant, the MCV Facility
violated its Air Use Permit to Install (PTI) by exceeding the carbon monoxide
emission limit on the Unit 14 duct burner and failing to maintain certain
records in the required format. The MCV Partnership thereafter declared five of
the six duct burners in the MCV Facility as unavailable for operational use
(which reduced the generation capability of the MCV Facility by approximately
100 MW) and took other corrective action to address the MDEQ's assertions.
Following voluntary settlement discussions, the MDEQ issued the MCV Partnership
a new PTI, which established higher carbon monoxide emissions limits on the five
duct burners that had been declared unavailable. The MCV Partnership has
returned those duct burners to service. The MDEQBC Cobb Electric Generating
Station and the MCV Partnership have
agreed to a settlementJR Whiting Plant. We are preparing for discussions with the EPA
regarding these allegations, but cannot predict the financial impact or outcome
of the emission violation, which will also satisfy state
and federal requirements and remove the MCV Partnership from the EPA's High
Priority Violators List. The settlement involves a fine of $45,000. The
settlement is subject to public notice and comment. The MCV Partnership believes
it has resolved all issues associated with this Letter of Violation and does not
expect further MDEQ action on this matter.issue.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities (the
plaintiffs), which sell power to us, filed a lawsuit in Ingham County Circuit
Court. The lawsuit alleged that we incorrectly calculated the energy charge
payments made pursuant to power purchase agreements with qualifying facilities.
In February 2004, the Ingham County Circuit CourtThe judge deferred to the primary jurisdiction of the MPSC, dismissing the
circuit court case without prejudice.
The Michigan Court of Appeals upheld this order on the primary jurisdiction
question, but remanded the case back on another issue. In February 2005, the MPSC issued an order
in the 2004 PSCR plan case concluding that we have been correctly administering
the energy charge calculation methodology. The plaintiffs have appealed the MPSC
order to the Michigan Court of Appeals. The plaintiffs also filed suit in the
United
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CMS Energy Corporation
States Court for the Western District of Michigan, which the judge subsequently
dismissed.dismissed on the basis that the pending state court litigation would fully
resolve any federal issue before the courts. The plaintiffs havethen appealed the
dismissal to the United States Court of Appeals.Appeals, which held that the district
court matter should be stayed rather than dismissed, pending the outcome of the
state appeal. We cannot predict the outcome of these appeals.
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CMS Energy Corporation
CONSUMERS' ELECTRIC UTILITY RESTRUCTURINGRATE MATTERS
ELECTRIC ROA: The Customer Choice Act allows allIn prior orders, the MPSC approved recovery of Stranded Costs
incurred from 2002 through 2003 plus the cost of money through the period of
collection. At March 31, 2007, we had a regulatory asset for Stranded Costs of
$66 million on our electric customers to
buy electric generation service from us or from an alternative electric
supplier.Consolidated Balance Sheets. We collect Stranded Costs
through a surcharge on ROA customers. At September 30, 2006,March 31, 2007, alternative electric
suppliers were providing 308283 MW of generation service to ROA customers, which
represents four percent of
our total distribution load. This representsrepresent a decrease of one19 percent of ROA load compared to June 30, 2006 and a decrease of 60 percent ofMarch 31, 2006. This
downward trend has affected negatively our ability to recover timely our
Stranded Costs. If downward ROA load comparedtrends continue, it may require legislative or
regulatory assistance to recover fully our Stranded Costs. However, the end of September 2005.Customer
Choice Act allows electric utilities to recover their net Stranded Costs. It is
difficult to predict future ROA customer trends.
STRANDED COSTS: Prior MPSC orders adopted a mechanism pursuant totrends and their effect on the Customer
Choice Act to providetimely
recovery of Stranded Costs that occur when customers leave
our system to purchase electricity from alternative suppliers. In November 2005,
we filed an application with the MPSC related to the determination of 2004
Stranded Costs. Applying the Stranded Cost methodology used in prior MPSC
orders, we concluded that we experienced Stranded Costs in 2004; however, we
also concluded that these costs were offset completely by our net sales of
excess power into the bulk electricity market. In September 2006, the MPSC
issued an order approving our proposal and the resulting conclusion that our
Stranded Costs for 2004 were fully offset by wholesale sales into the bulk
electricity market. The MPSC also determined that this order completes the
series of Stranded Cost cases resulting from the Customer Choice Act.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
POWER SUPPLY COSTS: To reduce the risk of high electric pricespower supply costs during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasingpurchase electric
capacity and energy contracts for the physical delivery of electricity primarily
in the summer months and to a lesser degree in the winter months. We have
purchased capacity and energy contracts covering partially the estimated reserve
margin requirements for 2007 through 2010. As a result, we have recognized an asset of $63$62
million for unexpired seasonal capacity and energy contracts at September 30, 2006. At September 2006,March 31, 2007.
As of March 31, 2007, we expect the total capacity cost ofcosts for these primarily seasonal
electric capacity and energy contracts for 2006 to be $17 million.$14 million for 2007.
PSCR: The PSCR process allows recovery of reasonable and prudent power supply
costs. Revenues from the PSCR charges are subject to reconciliation after review
of actualThe MPSC reviews these costs for reasonableness and prudence.prudency in annual
plan proceedings and in plan reconciliation proceedings. The following table
summarizes our PSCR reconciliation filings with the MPSC:
Power Supply Cost Recovery Reconciliation
PSCR Cost
Net Under- of Power Description of Net
PSCR Year Date Filed Order Date recovery Sold Underrecovery
- --------- ---------- ---------- ------------ -------------- ------------------------
2005 March 2006 Pending $39 million $1.086 billion Underrecovery relates to
Reconciliation our commercial and
industrial customers and
includes the cost of
money.
2006 March 2007 Pending $115 million $1.492 billion Underrecovery relates to
Reconciliation our increased METC costs
and coal supply costs,
increased bundled sales,
and other cost increases
beyond those included in
the 2006 PSCR plan
filings.
2007 PSCR Plan: In September 2006, we filed our 2007 PSCR plan with the MPSC.
The plan sought
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CMS Energy Corporation
authorization to incorporate our 2005 we submitted
ourand 2006 PSCR plan filing to the MPSC.underrecoveries into our
2007 PSCR monthly factor. In November 2005, we submitted an amended
2006 PSCR plan to the MPSC to include higher estimates for METC and coal supply
costs. In December 2005, the MPSC issued an order that temporarily excluded
these increased costs from our PSCR charge and further reduced the charge by one
mill per kWh. We implemented the temporary order in January 2006.
In August 2006, the MPSC issued ana temporary order
approvingallowing us to implement our amended 20062007 PSCR plan,
which resultsmonthly factor on January 1, 2007, as
filed. The order also allowed us to continue to roll in an increasedprior year
underrecoveries and overrecoveries in future PSCR factor for the remainder of 2006. We expect
PSCR underrecoveries for 2006 of $116 million. These underrecoveries are due to
the MPSC delaying recovery of our increased METC and coalplans.
Underrecoveries in power supply costs increased bundled sales, and other cost increases beyond thoseare included in the
September 2005Accrued power supply and
November 2005 filings.gas revenue on our Consolidated Balance Sheets. We expect to recover fully all
of our
2006 PSCR costs. When we are unable to collect these costs as they are
incurred, there is a negative impact on our cash flows from electric utility
operations. In March 2006, we submitted our 2005 PSCR reconciliation filing to the MPSC. We
estimate an underrecovery of $39 million for commercial and industrial
customers, which we expect to recover fully. We cannot predict the outcome of these PSCR proceedings.
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CMS Energy CorporationELECTRIC RATE CASE: In September 2006,March 2007, we submitted our 2007 PSCR plan filingfiled an application with the MPSC seeking
an 11.25 percent authorized return on equity and an annual increase in revenues
of $157 million as shown in the following table:
In Millions
-----------
Components of the increase in revenue
Reduction in base rates (a) $(23)
Surcharge for return on nuclear investments (b) 13
Elimination of Palisades base rate recovery credit (c) 167
----
Total increase in revenues $157
====
(a) The reduction in base rates is due to the removal of Palisades related
costs offset by Clean Air Act related and other utility expenditures,
changes in the capital structure, and increased distribution system
operation and maintenance costs including employee pension and health care
costs.
(b) The nuclear surcharge is a proposal to earn a return on funds spent on Big
Rock spent nuclear fuel storage, decommissioning, and site restoration
expenditures until pending DOE litigation and future MPSC which
includesproceedings
regarding this issue are concluded.
(c) Palisades power purchase agreement costs are currently offset through
feedback in the underrecoveries incurred in 2005 and 2006. We expectPSCR related to self-implementPalisades base rate revenues via a base
rate recovery credit. The Palisades base rate recovery credit will be
discontinued once Palisades' costs are removed from base rates.
If approved as requested, the proposed 2007 PSCR chargerate requests would go into effect in January 2007, absent action by
the MPSC by the end of 2006.2008
and would apply to all retail electric customers. We cannot predict the outcomeamount
or timing of this proceeding.any MPSC decision on the requests.
OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
THE MIDLAND COGENERATION VENTURE:MCV PPA: The MCV Partnership, which leases and operates the MCV Facility,
contracted to sell 1,240 MW of electricity to Consumers forunder a 35-year periodpower
purchase agreement beginning in 1990. We hold a 49 percent partnership interest inestimate that capacity and energy
payments under the MCV Partnership, and a 35 percent lessor interest in the MCV Facility. In 2004, we
consolidated the MCV Partnership and the FMLP into our consolidated financial
statements in accordance with FASB Interpretation No. 46(R).
Sale of our Interest in the MCV Partnership and the FMLP: In July 2006, we
reached an agreement to sell 100 percent of the stock of CMS Midland, Inc. and
CMS Midland Holdings Company to an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments for $60.5 million. These Consumers'
subsidiaries hold our interest in the MCV Partnership and the FMLP.PPA will be $620 million per year. The sale
does not affect the MCV PPA and the
associated customer rates. Werates are targeting
to close on the saleunaffected by the end of 2006. The sale is subject to various
regulatory approvals, including the MPSC's approval and the expiration of the
waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
In JulyNovember 2006 the MPSC issued an order establishing a contested case proceeding
and provided a schedule, which will allow for a decision from the MPSC by the
end of 2006. In October 2006, we reached a settlement agreement with the MPSC
Staff and the parties involved, which recommends that the MPSC grant all
authorizations necessary to complete the sale of our
interestsinterest in the MCV Partnership and the FMLP. The MPSC's approval of the settlement agreement is
required for it to become effective. If approved by the MPSC, the settlement
agreement requires us to file reports subsequent to the closing providing
details of the amount of net proceeds available for debt reduction and what type
of debt was reduced, and to file an amended 2007 through 2011 PSCR plan to
address potential changes related to the MCV PPA and the RCP. We cannot predict
the timing or the outcome of the MPSC's decision nor can we predict with
certainty whether or when this transaction will be completed.
Because of the power purchase agreement in place between Consumers and the MCV
Partnership, the transaction is effectively a sale and leaseback for accounting
purposes. SFAS No. 98 specifies the accounting required for a seller's sale and
simultaneous leaseback transaction involving real estate, including real estate
with equipment. In accordance with SFAS No. 98, the transaction will be required
to be accounted for as a financing and not a sale. This is due to forms of
continuing involvement we will have with the MCV Partnership. At closing, we
will remove from our Consolidated Balance Sheets all of the assets, liabilities,
and minority interest associated with both the MCV Partnership and the FMLP
except for the real estate assets and equipment of the MCV Partnership. Those
assets will remain at their carrying value. If the fair value is determined to
be less than the present carrying value, an impairment charge would result.
Further, as disclosed in Note 6, Financial and Derivative Instruments,
"Derivative Contracts Associated with the MCV Partnership," we will reflect in
earnings certain cumulative amounts of the MCV Partnership-related derivative
fair value changes that are accounted for in other comprehensive income. We will
also reflect in earnings income related to certain of the MCV Partnership gas
contracts, which are being sold. The transaction will not result in the MCV
Partnership or the FMLP assets being classified as held for sale on our
Consolidated Balance Sheets.
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CMS Energy Corporation
Financial Condition of the MCV Partnership: Under the MCV PPA, variable energy
payments to the MCV Partnership are based on the cost of coal burned at our coal
plants and our operation and maintenance expenses. However, the MCV
Partnership's costs of producing electricity are tied to the cost of natural
gas. Historically high natural gas prices have caused the MCV Partnership to
reevaluate the economics of operating the MCV Facility and to record an
impairment charge in 2005. If natural gas prices remain at present levels or
increase, the operations of the MCV Facility would be adversely affected and
could result in the MCV Partnership failing to meet its obligations under the
sale and leaseback transactions and other contracts. Due to the impairment of
the MCV Facility and subsequent losses, the value of the equity held by all of
the owners of the MCV Partnership has decreased significantly and is now
negative. Since we are one of the general partners of the MCV Partnership, we
have recognized a portion of the limited partners' negative equity. At September
30, 2006, the negative minority interest for the other general partners' share,
including their portion of the limited partners' negative equity, is $101
million and is included in Other Non-current Assets on our Consolidated Balance
Sheets.
Underrecoveries related to the MCV PPA: Further, theThe cost that we incur under the MCV PPA
exceeds the recovery amount allowed by the MPSC. We expense allestimate cash
underrecoveries directly to income. We estimate underrecoveries of $56 million
in 2006our capacity and fixed energy payments of $39 million in 2007. Of the 2006 estimate,2007
of which we have expensed $42$13 million during the ninethree months ended September 30, 2006.March 31,
2007. However, our directwe use savings from the RCP, after allocating a portion to
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CMS Energy Corporation
customers, are used to offset a portion of our capacity and fixed energy underrecoveries
expense.
RCP: In January 2005, we implemented the MPSC-approved RCP with modifications.
The RCP allows us to recover the same amount of capacity and fixed energy
charges from customers as approved in prior MPSC orders. However, we are able to
dispatch the MCV Facility based on natural gas market prices. This results in
fuel cost savings for the MCV Facility, which the MCV Partnership shares with
us. The RCP also requires us to contribute $5 million annually to a renewable
resources program. As of March 2007, we have contributed $12 million to the
renewable resources program. The underlying RCP agreement between Consumers and
the MCV Partnership extends through the term of the MCV PPA. However, either
party may terminate that agreement under certain conditions. In January 2007,
the Michigan Attorney General filed an appeal with the Michigan Supreme Court
regarding the MPSC's order approving the RCP. We cannot predict the outcome of
this matter.
Regulatory Out Provision in the MCV PPA: After September 15, 2007, we expect to
claim relief under the regulatory out provision in the MCV PPA, thereby limiting
our capacity and fixed energy payments to the MCV Partnership to the amounts
that we collect from our customers. The MCV Partnership has indicatednotified us that it
may taketakes issue with our intended exercise of the regulatory out provision after September 15, 2007.provision. We
believe that the provision is valid and fully effective, but cannot assure that
it will prevail in the event of a dispute. If we are successful in exercising
the regulatory out provision, the MCV Partnership hasmay, under certain
circumstances, have the right to terminate or reduce the amount of capacity sold
under the MCV PPA from 1,240 MW to 806 MW, which could affect our reserve
margin. In addition, the MPSC's future actions on the capacity and fixed
energy payments after September 15, 2007 may further affect negatively the
financial performance of the MCV Partnership, if such action resulted in us
claiming additional relief under the regulatory out provision. We anticipate that the MPSC will review our exercise of the regulatory
out provision and the likely consequences of such action will be reviewed by the MPSC in 2007. Some parties have suggestedIt is possible
that in the event that the MCV Partnership ceases performance under the MCV PPA,
prior orders could limit recovery of replacement power costs to the amounts that
the MSPCMPSC authorized for recovery under the MCV PPA. We cannot predict the
outcome of any future disputes concerning these issues.
RCP: In January 2005, the MPSC issued an order approving the RCP, with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV FacilityDepending on the basiscost of
natural gas market
prices, which reducesreplacement power, this could result in our costs exceeding the MCV Facility's annual production of electricity and,
as a result, reduces the MCV Facility's consumption of natural gas by an
estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced
natural gas consumedrecovery amount
allowed by the MCV Facility benefits our interest in the MCV
Partnership. The RCP also calls for us to contribute $5 million annually to a
renewable resources program. As of September 2006, we have contributed $9
million to the renewable resources program.
In January 2005, we implemented the RCP. The underlying agreement for the RCP
between Consumers and the MCV Partnership extends through the term of the MCV
PPA. However, either party may terminate that agreement under certain
conditions. In February 2005, a group of intervenors in the RCP case filed for
rehearing of the MPSC order approving the RCP, which the MPSC denied in
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CMS Energy Corporation
October 2006. The Attorney General also filed an appeal with the Michigan Court
of Appeals.MPSC. We cannot predict the outcome of these matters.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004,To comply with a prior MPSC order, we made a filing in May 2007 with the Michigan Tax Tribunal
issued its decision inMPSC,
which asked the MPSC to make a determination regarding whether it wished to
reconsider the amount of the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The City of Midland appealed the
decision to the Michigan Court of Appeals, and the MCV Partnership filed a
cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a
pending case with the Michigan Tax Tribunal for tax years 2001 through 2006. The
MCV Partnership estimates that the 1997 through 2005 tax year cases will result
in a refund to the MCV Partnership of $88 million, inclusive of interest, if the
decision of the Michigan Tax Tribunal is upheld. In February 2006, the Michigan
Court of Appeals largely affirmed the Michigan Tax Tribunal decision, but
remanded the case back to the Michigan Tax Tribunal to clarify certain aspects
of the Tax Tribunal decision. In April 2006, the City of Midland filed an
application for Leave to Appeal with the Michigan Supreme Court. The remanded
proceedings may result in the determination of a greater refund to the MCV
Partnership. In July 2006, the Michigan Supreme Court denied the City of
Midland's application, which resulted in the MCV Partnership recognizing the $88
million refund as a reduction in property tax expense.
NUCLEAR PLANT DECOMMISSIONING: The MPSC and the FERC regulate the recovery of
costs to decommission, or remove from service, our Big Rock and Palisades
nuclear plants. Decommissioning funding practices approved by the MPSC require
us to file a report on the adequacy of funds for decommissioning at three-year
intervals. We prepared and filed updated cost estimates for Big Rock and
Palisades in March 2004. Excluding additional costs for spent nuclear fuel
storage due to the DOE's failure to accept this spent nuclear fuel on schedule,
these reports show a decommissioning cost of $361 million for Big Rock and $868
million for Palisades. Since Big Rock is currently in the process of
decommissioning, this estimated cost includes historical expenditures in nominal
dollars and future costs in 2003 dollars, with all Palisades costs given in 2003
dollars. Updated cost projections for Big Rock indicate an anticipated
decommissioning cost of $393 million as of June 2006.
Big Rock: In December 2000, funding of the Big Rock trust fund stopped because
the MPSC-authorized decommissioning surcharge collection period expired. In our
March 2004 report to the MPSC, we indicatedPPA payments that we would manage the
decommissioning trust fundrecover from customers. We
are unable to meet annual NRC financial assurance requirements
by withdrawing NRC radiological decommissioning costs from the fund and
initially funding non-NRC, greenfield costs out of corporate funds. In March
2006, we contributed $16 million to the trust fund from our corporate funds to
support NRC radiological decommissioning costs. Excluding the additional nuclear
fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we
are projecting that the level of funds provided by the trust will fall short of
the amount needed to complete the decommissioning by $39 million, which is the
amount projected for non-NRC, greenfield costs. We plan initially to fund the
$39 million out of corporate funds. Therefore, at this time, we plan to provide
a total of $55 million from corporate funds for costs associated with NRC
radiological and non-NRC greenfield decommissioning work. We plan to seek
recovery of such expenditures. We cannot predict the outcome of these efforts.
Palisades: Excluding additionalthis request.
THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT: Sale of
Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million.
The final purchase price was subject to various closing adjustments such as
working capital and capital expenditure adjustments and nuclear fuel storage costs dueusage and
inventory adjustments resulting in us receiving $361 million. We also paid
Entergy $30 million to the DOE's
failure to accept spent fuel on schedule, we concluded, based on the cost
estimates filed in March 2004, that the existing Palisades' surcharge of $6
million needed to be increased to $25 million annually, beginning January 2006.
A settlement agreement was approved by the MPSC, providingassume ownership and responsibility for the continuationBig Rock
ISFSI. Because of the existing $6 million annual decommissioning surcharge through 2011, our
current license expiration date, and for the next periodic review to be filed in
March 2007. Amounts collected from electric retail customers and deposited in
trusts, including trust earnings, are credited to a regulatory liability.
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CMS Energy Corporation
In March 2005,sale of Palisades, we will also pay the NMC, which operatesthe former
operator of the Palisades plant, applied for a
20-year license renewal$7 million in exit fees and will forfeit our
investment in the NMC of $5 million.
Entergy will assume responsibility for the future decommissioning of the
Palisades plant on behalfand for storage and disposal of Consumers. We expect a
decision from the NRC on the license renewal application in 2007. At this time,
we cannot determine what impact this will have on decommissioning costs or the
adequacy of funding. Initial estimates of decommissioning costs, assuming a
plant retirement date of 2031, show decommissioning costs of either $818 million
or $1.049 billion for Palisades, depending on the decommissioning methodology
assumed. These costs, which exclude additional costs for spent nuclear fuel storage due tolocated at
the DOE's failure to accept spent nuclear fuel on schedule, are
given in 2003 dollars.
In July 2006, we reached an agreement to sell Palisades and the Big Rock ISFSI sites. At closing, we transferred $252
million in decommissioning trust fund balances to Entergy.
As partThe MPSC order approving the Palisades transaction allows us to recover the
estimated $314 million book value of the Palisades plant. As a result, we
estimate that we will credit excess proceeds of $66 million to our retail
customers through refunds applied over the remainder of 2007 and 2008. The MPSC
order deferred ruling on the recovery of $30 million in estimated transaction
costs, including the NMC exit fees, and the $30 million payment to Entergy
related to the Big Rock ISFSI until the next general rate case. We will defer
these costs as a regulatory asset on our Consolidated Balance Sheets as recovery
is probable.
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CMS Energy Corporation
In April 2007, the NRC, through its staff, issued an order approving the
transfer of the Palisades operating license. Subsequently, in April 2007, the
NRC issued an order requiring that certain intervenors be given, under a
protective order, information related to the buyer's financial capability. If,
after the review of the information, the intervenors wished to seek additional
proceedings on the license transfer, the NRC would consider the request. The NRC
did not alter or stay the prior order approving the license transfer. We believe
that it is unlikely that the NRC will conduct further proceedings, but we cannot
predict the outcome of the matter. These events did not hold up the closing of
the sale of Palisades.
The following table summarizes the estimated impacts of the Palisades and the
Big Rock ISFSI transactions:
In Millions
- -----------------------------------------------------------------------------------
Customer Benefits (a) Deferred costs
- --------------------- --------------
Purchase price $380 NMC exit fee $ 7
Less: Estimated book value of
Palisades plant 314 Forfeiture of the NMC investment 5
----
Excess proceeds to be refunded to
customers 66 (b) Estimated selling expenses 18
Big Rock ISFSI operation and
maintenance fee to
Excess decommissioning trust
funds to be refunded to
customers 189 (c) Entergy 30
---- ---
Total estimated customer
refunds $255 Total regulatory asset $60
==== ===
(a) In the FERC's February 2007 order regarding the Palisades transaction, the
FERC granted our request to apply $11 million in FERC decommissioning trust
fund balances for the Palisades plant toward the Big Rock decommissioning
shortfall, as described in "Big Rock Nuclear Plant Decommissioning" within
this section. The order was contingent upon the NRC approving the transfer
of operating licenses, which the NRC approved in April 2007. This
determination is the subject of a clarification request filed by a
wholesale customer with the FERC.
(b) Final proceeds in excess of the book value are subject to closing
adjustments and review by the MPSC.
(c) In the MPSC's March 2007 order approving the Palisades transaction, the
MPSC indicated that $189 million of MPSC jurisdictional decommissioning
funds must be credited to our retail customers through refunds applied over
the remainder of 2007 and 2008. Final disposition of these funds is subject
to closing date balances and is subject to review by the MPSC. The
remaining estimated $116 million of the MPSC jurisdictional decommissioning
funds, which is subject to closing date reconciliation will be used to
benefit our retail customers and is expected to be addressed in a separate
filing made with the MPSC.
Palisades Power Purchase Agreement: Entergy contracted to sell us 100 percent of
the plant's output up to its current annual average capacity of 798 MW under a
15-year power purchase agreement.agreement beginning in April 2007. We provided $30
million in security to Entergy for our power purchase agreement obligation in
the form of a letter of credit. We estimate that capacity and energy payments
under the Palisades power purchase agreement will be $300 million per year.
Because of the Palisades power purchase agreement, that will be in
place between Consumers and Entergy, the transaction is effectively a sale and
leaseback for accounting purposes. SFAS No. 98 specifies the accounting required
for a seller's sale and simultaneous leaseback transaction involving real estate, includingestate. We will
have continuing involvement with the Palisades plant through security provided
to Entergy for our power purchase agreement obligation, our DOE liability, and
other forms of involvement. As a result, we will account for the Palisades
plant, which is
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CMS Energy Corporation
the real estate with equipment. In accordance with SFAS No. 98,asset subject to the transaction will be accounted forleaseback, as a financing for accounting
purposes and not a sale. This is due
to forms of continuing involvement.We will account for the remaining non-real estate
assets and liabilities associated with the transaction as a sale.
As such, we have not classifieda financing, the assets
as held for salePalisades plant will remain on our Consolidated Balance
Sheets.Sheets and the related proceeds will be recorded as a financing obligation. The
sale is subject to various regulatory approvals, including the MPSC's
approvalvalue of the power purchase agreement,finance obligation is based on an allocation of the FERC's approval for Entergytransaction
proceeds to sell power to usthe fair values of the net assets sold and fair value of the
Palisades plant assets under the power purchase agreement and other related matters,financing.
BIG ROCK NUCLEAR PLANT DECOMMISSIONING: The MPSC and the NRC's approvalFERC regulate the
recovery of costs to decommission the Big Rock nuclear plant. In December 2000,
funding of the transferBig Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. In a March 2007 report to
the MPSC, we indicated that we have managed the decommissioning trust fund to
meet the annual NRC financial assurance requirements by withdrawing NRC
radiological decommissioning costs from the trust fund and initially funding
non-NRC greenfield costs out of corporate funds. In March 2006, we contributed
corporate funds of $16 million to the trust fund to support the NRC radiological
decommissioning costs. Excluding the additional nuclear fuel storage costs due
to the DOE's failure to accept spent nuclear fuel on schedule, we are projecting
the level of funds provided by the trust will fall short of the operating licenseamount needed to
Entergycomplete decommissioning by an additional $36 million. This total of $52
million, which are costs associated with NRC radiological and other related matters. In October 2006, the Federal Trade Commission issued a
notice that neither it nor the Departmentnon-NRC greenfield
decommissioning work, are being funded out of Justice's Antitrust Divisioncorporate funds. We plan to take enforcement actionseek
recovery of expenditures that we have funded in future filings with the MPSC and
have a $36 million regulatory asset recorded on our Consolidated Balance Sheets
as of March 31, 2007.
Cost projections for Big Rock indicate a decommissioning cost of $389 million as
of March 2007, of which we have incurred $387 million. These amounts exclude the
sale. The final purchase price will be subject
to various closing adjustments such as working capital and capital expenditure
adjustments, adjustmentsadditional costs for spent nuclear fuel usage and inventory, andstorage due to the dateDOE's failure to
accept this spent nuclear fuel on schedule. They also exclude post September 11
increased security costs that we are recovering through the security cost
recovery provisions of closing. Under the agreement, if the transaction does not close by March 1,
2007, the purchase pricePublic Act 609 of 2002. These activities had no material
impact on consolidated net income. Any remaining Big Rock decommissioning costs
will initially be reduced by $80,000 per day with additional
costs if the sale does not close by June 1, 2007. We cannot predict with
certainty whether or when the closing conditions will be satisfied or whether or
when this transaction will be completed.funded out of corporate funds.
NUCLEAR MATTERS: Nuclear Fuel Cost: We amortizeamortized nuclear fuel cost to fuel
expense based on the quantity of heat produced for electric generation. For
nuclear fuel used after April 6, 1983, we chargecharged certain disposal costs to
nuclear fuel expense, recoverrecovered these costs through electric rates, and remitremitted
them to the DOE quarterly. We elected to defer payment for disposal of spent
nuclear fuel burned before April 7, 1983. At September 30, 2006, ourOur DOE liability is $150 million.$154 million at
March 31, 2007. This amount includes interest, which is payable upon the first
delivery of spent nuclear fuel to the DOE. TheWe have recovered, through electric
rates, the amount of this liability, excluding a portion of interest, was recovered through electric rates.interest. In
conjunction with the sale of Palisades and the Big Rock ISFSI, we will retainretained this
obligation and provideprovided $155 million in security to Entergy for this obligation
in the form of either cash, a letter of credit, or other acceptable means.credit.
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE
was to begin accepting deliveries of spent nuclear fuel for disposal by January
1998. Subsequent U.S. Court of Appeals litigation, in which we and other
utilities participated, has not been successful in producing more specific
relief for the DOE's failure to accept the spent nuclear fuel.
There are two court decisions that support the right of utilities to pursue
damage claims in the United States Court of Claims against the DOE for failure
to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims. We filed our complaint in
December 2002. If our litigation against the DOE is successful, we plan to use
any recoveries to pay
CMS-57
CMS Energy Corporationas reimbursement for the costincurred costs of spent nuclear fuel
storage until the DOE takes possession as
required by law.during our ownership of Palisades
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CMS Energy Corporation
and Big Rock. We can make no assurance that the litigation against the DOE will
be successful. The sale of Palisades and the Big Rock ISFSI did not transfer the
right to any recoveries from the DOE related to costs of spent nuclear fuel
storage incurred during our ownership of Palisades and Big Rock.
In 2002, the site at Yucca Mountain, Nevada was designated for the development
of a repository for the disposal of high-level radioactive waste and spent
nuclear fuel. We expect that the DOE, in due course, will submit a final license
application to the NRC for the repository. The application and review process is
estimated to take several years.
Insurance: We maintainmaintained nuclear insurance coverage on our nuclear plants.plants until
Palisades and the Big Rock ISFSI were sold in April 2007. At Palisades, we
maintainmaintained nuclear property insurance from NEIL totaling $2.750 billion and
insurance that would partially cover the cost of replacement power during
certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $30 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.
At Palisades, we maintainmaintained nuclear liability insurance for third-party bodily
injury and off-site property damage resulting from a nuclear energy hazard for
up to approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. Part of the Price-Anderson Act's
financial protection is a mandatory industry-wide program under which owners of
nuclear generating facilities could be assessed if a nuclear incident occurs at
any nuclear generating facility. The maximum assessment against us could be $101
million per occurrence, limited to maximum annual installment payments of $15
million.
We also maintainmaintained insurance under a program that covers tort claims for bodily
injury to nuclear workers caused by nuclear hazards. The policy contains a $300
million nuclear industry aggregate limit. Under a previous insurance program
providing coverage for claims brought by nuclear workers, we remain responsible
for a maximum assessment of up to $6 million. This requirement will end December
31, 2007.
Big Rock remainswas insured for nuclear liability up to $544 million through nuclear
insurance and the NRC indemnity, and maintainswe maintained a nuclear property insurance
policy from NEIL.
Insurance policy terms, limits, and conditions are subject to change during the
year as we renew our policies.
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CMS Energy Corporation
CONSUMERS' GAS UTILITY CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remediation
costs at a number of sites under the Michigan Natural Resources and
Environmental Protection Act, a Michigan statute that covers environmental
activities including remediation. These sites include 23 former manufactured gas
plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or
may own only a portion of the original site. In 2005, we estimated our remaining
costs to be between $29 million and $71 million, based on 2005 discounted costs,
using a discount rate of three percent. The discount rate represents a 10-year
average of U.S. Treasury bond rates reduced for increases in the consumer price
index. We expect to fund most of these costs through proceeds derived from a
settlement with insurers and MPSC-approved rates. At September 30, 2006,March 31, 2007, we have a
liability of $26$22 million, net of $56$60 million of expenditures incurred to date,
CMS-52
CMS Energy Corporation
and a regulatory asset of $58$55 million. The timing of payments related to the
remediation of our manufactured gas plant sites is uncertain. Any significant
change in assumptions, such as an increase in the number of sites, different
remediation techniques, nature and extent of contamination, and legal and
regulatory requirements, could affect our estimate of remedial action costs.costs and
the timing our remediation payments.
CONSUMERS' GAS UTILITY RATE MATTERS
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our
purchased natural gas costs if incurred under reasonable and prudent policies
and practices. The MPSC reviews these costs, policies, and practices for
prudency in annual plan and reconciliation proceedings.
The following table summarizes our GCR reconciliation filings with the MPSC:
Gas Cost Recovery Reconciliation
Net Over- GCR Cost of
GCR Year Date Filed Order Date recovery Gas Sold Description of Net Overrecovery
- -------- ---------- ---------- ---------- ------------ ----------------------------------------------------------------
2004-20052005-2006 June 20052006 April 2006 $22007 $3 million $1.4$1.8 billion The net overrecovery includes $1
million interest expenseincome through
March 2005 and refunds that we
received2006, which resulted from our suppliers
that are requireda
net underrecovery position during
the majority of the GCR period.
In 2007, the MPSC approved a
settlement agreement, agreeing to
be
refunded to our customers.
2005-2006 June 2006 Pendinga $3 million $1.8 billion The net overrecovery
includes
$1 million interest income
through March 2006, which
resulted from a net
underrecovery position during
the majority of the GCR
period.amount.
Overrecoveries in cost of gas sold are included in Accrued rate refunds on our
Consolidated Balance Sheets.
GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our
2005-2006 GCR Plan year, which resulted in approval of a settlement agreement
and established a fixed price cap of $10.10 per mcf for the December 2005
through March 2006 billing period. We were able to maintain our GCR billing GCR
factor below the authorized level for that period. The order was appealed to the
Michigan Court of Appeals by one intervenor. No action has been taken by the
Court of Appeals on the merits of the appeal and weWe are unable to predict the
outcome.outcome of this proceeding.
GCR plan for year 2006-2007: In August 2006, the MPSC issued an order for our
2006-2007 GCR Plan year, which resulted in approval of a settlement agreement
that allowed a base GCR ceiling factor of $9.48 per mcf for the 12-month period
of April 2006 through March 2007. We were able to maintain our GCR billing
factor below the authorized level for that period.
GCR plan for year 2007-2008: In December 2005,2006, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 20062007
through March 2007.2008. Our request proposed using a GCR factor consisting of:
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CMS Energy Corporation
- a base GCR ceiling factor of $11.10$8.47 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future
events.
In July 2006, all parties signed a partial settlement agreement, which calls for
a base GCR ceiling factor of $9.48 per mcf. The settlement agreement base GCR
ceiling factor is subject to a quarterly GCR ceiling price adjustment mechanism.
The adjustment mechanism allows an adjustment of the base ceiling factor to
reflect a portion of cost increases, if the average NYMEX price for a specified
period is greater than that used in calculating the base GCR factor. The MPSC
approved the settlement agreement in August 2006.CMS-53
CMS Energy Corporation
The GCR billing factor is adjusted monthly in order to minimize the over or
under-recoveryunderrecovery amounts in our annual GCR reconciliation. Our GCR billing factor
for the month of November 2006May 2007 is $7.83$8.24 per mcf.
2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued
Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously-ordered $34 million reduction in our
depreciation expense,
- required us to undertake a study to determine why our plant removal
costs are in excess of other regulated Michigan natural gas utilities,
and
- required us to file a study report with the MPSC Staff on or before
December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.
We are also required to file our next gas depreciation case within 90 days after
the MPSC issuance of a final order in the pending case related to ARO
accounting. We cannot predict when the MPSC will issue a final order in the ARO
accounting case.
If the depreciation case order is issued after the gas general rate case order,
we proposed to incorporate its results into the gas general rates using a
surcharge mechanism, a process used to incorporate specialty items into customer
rates.
20052007 GAS RATE CASE: In July 2005,February 2007, we filed an application with the MPSC
seeking a 12an 11.25 percent authorized return on equity along with a $132an $88 million
annual increase in our gas delivery and transportation rates. As partrates, of this filing,
we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony in October
2005. In its testimony, the MPSC Staff recommended granting interim rate relief
of $38 million.
In February 2006, the MPSC Staff recommended granting final rate relief of $62
million. The MPSC Staff proposed thatwhich $17
million of this amountwould be contributed to a low income and energy efficiency fund. The MPSC Staff also recommended
reducing our allowed return on common equity to 11.15 percent, from our current
11.4 percent.
In March 2006,We have
proposed the MPSC Staff revised its recommended final rate relief to $71
million, which includes $17 million to be contributed to a low income and energy
efficiency fund. In April 2006, we revised our request for final rate relief
downward to $118 million.
In May 2006, the MPSC issued an order granting us interim gas rate relief of $18
million annually, which is under bond and subject to refund if final rate relief
is granted in a lesser amount. The order
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CMS Energy Corporation
also extended the temporary two-year surcharge of $58 million granted in October
2004 until the issuanceuse of a final order in this proceeding. The MPSC has not
setRevenue Decoupling and Conservation Incentive Mechanism
for residential and general service rate classes to help assure a date for issuancereasonable
opportunity to recover costs regardless of an order granting final rate relief.
In July 2006, the ALJ issued a Proposal for Decision recommending final rate
relief of $74 million above current rate levels, which include interim and
temporary rate relief. The $74 million includes $17 million to be contributed to
a low income and energy efficiency fund. The Proposal for Decision also
recommended reducing our return on common equity to 11 percent, from our current
11.4 percent.sales levels.
OTHER CONTINGENCIES
EQUATORIAL GUINEA TAX CLAIM: CMS Energy received a request for indemnification
from Perenco, the purchaser of CMS Oil and Gas. The indemnification claim
relates to the sale by CMS Energy of its oil, gas and methanol projects in
Equatorial Guinea and the claim of the government of Equatorial Guinea that $142
million in taxes is owed it in connection with that sale. Based on information
currently available, CMS Energy and its tax advisors have concluded that the
government's tax claim is without merit, and Perenco has submitted a response to
the government rejecting the claim. CMS Energy cannot predict the outcome of
this matter.
GAS INDEX PRICE REPORTING LITIGATION: CMS Energy, CMS MST, CMS Field Services,
Cantera Natural Gas, Inc. (the company that purchased CMS Field Services) and
Cantera Gas Company are named as defendants in various lawsuits arising as a
result of falseclaimed inaccurate natural gas price reporting. Allegations include
manipulation of NYMEX natural gas futures and options prices, price-fixing
conspiracies, and artificial inflation of natural gas retail prices in
California, Colorado, Kansas, Missouri, Tennessee, and Kansas. In February 2006,Wisconsin. CMS MST and CMS Field Services
reached an agreement to settlehas
settled a similar action that had been filed in New York.
The court approved the settlement in May 2006 and the $6.975 million settlement
has been paid. In September 2006, CMS MST reached an agreement in principle to
settle the master class action suit in California state court for $7 million. The settlement
is contingent uponIn
March 2007, CMS Energy paid $7 million into a settlement agreement being signed and the settlement being
approved by the court. The settlement payment is not due until after the court
has entered an order grantingtrust fund account following
preliminary approval of the settlement by the judge. The settlement remains
subject to final approval pending notice to members of the class, who have an
opportunity to opt out of or object to the settlement.
In January 2007, CMS MST entered into a process
that may take several monthssettlement agreement to complete. CMS Energy deemedcollectively
settle four class action suits originally filed in California federal courts for
$700,000. On April 3, 2007, plaintiffs filed a motion for preliminary approval
of this settlement to
be probable and accrued the payment in its consolidated financial statements at
September 30, 2006.other settlements. CMS Energy and the other CMS Energy defendants
will continue to defend themselves vigorously againstin all of thesethe remaining matters
but cannot predict their outcome.
DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD), the
primary construction contractor for the DIG facility, presented DIG with a
change order to their construction contract and filed an action in Michigan
state court against DIG, claiming contractual damages in the amount of $110
million, plus interest and costs. DFD also filed a construction lien for the
$110 million. DIG is contesting both of the claims made by DFD. In addition to
drawing down on three letters of credit totaling $30 million that it obtained
from DFD, DIG filed an arbitration claim against DFD asserting in excess of an
additional $75 million in claims against DFD. The judge in the Michigan state
court case entered an order staying DFD's prosecution of its claims in the court
case and permitting the arbitration to proceed. The arbitration hearing
concluded on September 28, 2006 and the arbitration panel is expected to issue
an award on or before December 31, 2006. DIG will continue to defend itself
vigorously and pursue its claims. CMS Energy cannot predict the outcome of this
matter.
FORMER CMS OIL AND GAS OPERATIONS: A Michigan trial judge granted Star Energy,
Inc. and White Pine Enterprises, LLC a declaratory judgment in an action filed
in 1999 that claimed Terra Energy Ltd., a former CMS Oil and Gas subsidiary,
violated an oil and gas lease and other arrangements by failing to
CMS-61
CMS Energy Corporation
drill wells it had committed to drill. A jury then awarded the plaintiffs a $7.6
million award. Appeals were filed of the original verdict and a subsequent
decision of the court on remand. The court of appeals issued an opinion on May
26, 2005 remanding the case to the trial court for a new trial on damages. At a
status conference on April 10, 2006, the judge set a six-month discovery period.
On May 19, 2006, the court issued a scheduling order and the case has been set
for trial in February 2007. The parties attended a court-ordered mediation on
July 14, 2006 and the matter was not resolved. Enterprises has an indemnity
obligation with regard to losses to Terra that might result from this
litigation.
CMS ENSENADA CUSTOMER DISPUTE: Pursuant to a long-term power purchase agreement,
CMS Ensenada sells power and steam to YPF Repsol at the YPF refinery in La
Plata, Argentina. As a result of the so-called "Emergency Laws," payments by YPF
Repsol under the power purchase agreement have been converted to pesos at the
exchange rate of one U.S. dollar to one Argentine peso. Such payments are
currently insufficient to cover CMS Ensenada's operating costs, including
quarterly debt service payments to the Overseas Private Investment Corporation
(OPIC). Enterprises is party to a Sponsor Support Agreement pursuant to which
Enterprises has guaranteed CMS Ensenada's debt service payments to OPIC up to an
amount which is in dispute, but which Enterprises estimates to be approximately
$7 million.
The Argentine commercial court granted injunctive relief to CMS Ensenada
pursuant to an ex parte action, and such relief remained in effect until
completion of arbitration on the matter, administered by the International
Chamber of Commerce (the ICC). The arbitration hearing was held in July 2005.
The ICC released the arbitral tribunal's partial award dated August 22, 2006.
The partial award is favorable to CMS Ensenada, providing it with approximately
90 percent of all the additional payments CMS Ensenada would have received
during the period 2002 through 2006, but for the conversion of the contract into
Argentine pesos. CMS Ensenada expects the amount to be between $20 million and
$25 million, which includes interest. The award further provides that for 2007
and beyond, the method for calculating the amount due to CMS Ensenada will again
be stated in U.S. dollars. The final award will not be issued until the parties
agree to the amounts due to CMS Ensenada, inclusive of interest, based upon the
tribunal's ruling in the partial award. If the parties cannot agree, the
tribunal has established an expedited procedure to have the amount determined by
a panel of expert accountants. Therefore, CMS Energy has not yet recognized
income from this award.
ARGENTINA: As part of its energy privatization incentives, Argentina directed
CMS Gas Transmission to calculate tariffs in U.S. dollars, then convert them to
pesos at the prevailing exchange rate, and to adjust tariffs every six months to
reflect changes in inflation. Starting in early 2000, Argentina suspended the
inflation adjustments.
In January 2002, the Republic of Argentina enacted the Public Emergency and
Foreign Exchange System Reform Act. This law repealed the fixed exchange rate of
one U.S. dollar to one Argentine peso, converted all dollar-denominated utility
tariffs and energy contract obligations into pesos at the same one-to-one
exchange rate, and directed the Government of Argentina to renegotiate such
tariffs.
CMS Gas Transmission began arbitration proceedings against the Republic of
Argentina (Argentina) under the auspices of the International Centre for the
Settlement of Investment Disputes (ICSID) in mid-2001, citing breaches by
Argentina of the Argentine-U.S. Bilateral Investment Treaty (BIT). In May 2005,
an ICSID tribunal concluded, among other things, that Argentina's economic
emergency did not excuse Argentina from liability for violations of the BIT. The
ICSID tribunal found in favor of CMS Gas Transmission, and awarded damages of
U.S. $133 million, plus interest.
The ICSID Convention provides that either party may seek annulment of the award
based upon five CMS-62
CMS Energy Corporation
possible grounds specified in the Convention. Argentina's
Application for Annulment was formally registered by ICSID on September 27,
20052005. In March 2007, the Annulment matter was heard before a panel in Paris, and
will be
considered bythe matter is now before the panel pending a newly constituted panel.decision.
CMS-54
CMS Energy Corporation
On December 28, 2005, certain insurance underwriters paid the sum of $75 million
to CMS Gas Transmission in respect of their insurance obligations resulting from
non-payment of the ICSID award. The payment, plus interest, is subject to
repayment by CMS Gas Transmission in the event that the ICSID award is annulled.
Pending the outcome of the annulment proceedings, CMS Energy has recorded the
$75 million payment as a long-term deferred revenue at December 31, 2005.
IRS AUDIT RESOLUTION: In August 2005, the IRS issued Revenue Ruling 2005-53credit.
QUICKSILVER RESOURCES, INC.: Quicksilver sued CMS MST for breach of contract in
connection with a Contract for Sale and regulationsPurchase of natural gas, pursuant to
provide guidancewhich Quicksilver agreed to sell, and CMS MST agreed to buy, natural gas.
Quicksilver believes that it is entitled to more payments for natural gas than
it has received. CMS MST disagrees with respectQuicksilver's analysis and believes that
it has paid all amounts owed for delivery of gas pursuant to the usecontract.
Quicksilver is seeking damages of up to approximately $126 million, plus
prejudgment interest and attorney fees, which in our judgment is unsupported by
the facts.
The matter was tried before a jury in March 2007. The jury made a finding that
CMS MST has breached the agreement with Quicksilver, but found that Quicksilver
had failed to prove damages and accordingly awarded zero compensatory damages to
Quicksilver. However, the jury awarded $10 million in punitive damage against
CMS MST. CMS MST will oppose the award of punitive damages on the basis that
Texas law will not permit an award of punitive damages if no compensatory
damages have been awarded. The trial court has scheduled a date in early May
2007 to consider motions to enter judgment by the opposing sides of the
"simplified
service cost" method of tax accounting. We have been using this tax accounting
method, generally allowed by the IRS under section 263A of the Internal Revenue
Code, with respect to the allocation of certain indirect overhead costs to the
tax basis of self-constructed utility assets.
In June 2006, the IRS concluded its most recent audit oflitigation. CMS Energy and its
subsidiaries and proposed changescannot predict the ultimate outcome of this matter.
T.E.S. FILER CITY AIR PERMIT ISSUE: In January 2007, we received a Notice of
Violation from the EPA alleging that TES Filer City, a generating facility in
which we have a 50 percent partnership interest, exceeded certain air permit
limits. We are in discussions with the EPA with regard to taxable income forthese allegations, but
cannot predict the years ended December
31, 1987 through December 31, 2001. The proposed overall cumulative increase to
taxable income related primarily to the disallowancefinancial impact or outcome of the simplified service
cost method with respect to certain self-constructed utility assets. We have
accepted these proposed adjustments to taxable income, which resulted in the
payment of $76 million of tax in July 2006, and a reduction of our June 2006
income tax provision of $62 million, net of interest expense, primarily for the
restoration and utilization of previously written off income tax credits.this issue.
OTHER: In addition to the matters disclosed within this Note, Consumers and
certain other subsidiaries of CMS Energy are parties to certain lawsuits and
administrative proceedings before various courts and governmental agencies
arising from the ordinary course of business. These lawsuits and proceedings may
involve personal injury, property damage, contractual matters, environmental
issues, federal and state taxes, rates, licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this
Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or future results of
operations.
CMS-63CMS-55
CMS Energy Corporation
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS
FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: The
Interpretation requires the guarantor, upon issuance of a guarantee, to
recognize a liability for the fair value of the obligation it undertakes in
issuing the guarantee.
The following table describes our guarantees at September 30, 2006:March 31, 2007:
In Millions
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
FIN 45
Maximum Carrying
Guarantee Description Issue Date Expiration Date Obligation Amount
- --------------------- ------------ ---------------------------------------- ---------- --------
Indemnifications from asset sales and
other agreements (a) October 1995 Indefinite $1,133$1,113 $ 1
Standby letters of credit and loans (b) Various Various through 90 -
May 2010 84 --
Surety bonds and other indemnifications Various Indefinite 10 -
Other guarantees9 --
Guarantees and put options (c) Various Various through 218September 207 1
September
2027
Nuclear insurance retrospective
premiums (d) Various Indefinite 137 --
- ------------
(a) The majority of this amount arises from routine provisions in stock and
asset sales agreements under which we indemnify the purchaser for losses
resulting from events such as claims resulting fromrelated to tax disputes and the failure of title to
the assets or stock sold by us to the purchaser. We believe the likelihood
of a loss for any remaining indemnifications to be remote.
(b) Standby letters of credit include letters of credit issued under an amended
credit agreement with Citicorp USA, Inc. The amended credit agreement is
supported by a guaranty issued by certain subsidiaries of CMS Energy. At
September 30, 2006,March 31, 2007, letters of credit issued on behalf of unconsolidated
affiliates totaling $65$64 million were outstanding.
(c) Maximum obligation includes $85 million related to the MCV Partnership's
non-performance under a steam and electric power agreement with Dow. We
have reached an agreement to sellsold our interests in the MCV Partnership and the FMLP, subject to certain regulatory and other closing conditions.FMLP. The sales agreement
calls for the purchaser, an affiliate of GSO Capital Partners and Rockland
Capital Energy Investments, to pay $85 million, subject to certain
reimbursement rights, if Dow terminates an agreement under which it is provided power and steam by the MCV
Partnership.Partnership provides it steam and electric power. This agreement expires in
March 2016, subject to certain terms and conditions. The purchaser will securesecured
their reimbursement obligation with an irrevocable letter of credit of up
to $85 million.
CMS-64(d) We maintained nuclear insurance coverage on our nuclear plants until
Palisades and the Big Rock ISFSI were sold in April 2007. For more details
on the sale of Palisades and Big Rock, see Note 3, Contingencies, "Other
Consumers' Electric Utility Contingencies - The Sale of Nuclear Assets and
the Palisades Power Purchase Agreement."
CMS-56
CMS Energy Corporation
The following table provides additional information regarding our guarantees:
Events That
Guarantee Description How Guarantee Arose Events That Would Require Performance
- --------------------- ----------------------------------- ------------------------------------ ---------------------------------------------------------------------
Indemnifications from asset sales Stock and asset sales agreements Findings of misrepresentation,
and other agreements breach of warranties, and other
specific events or circumstances
Standby letters of credit and loans Credit agreement Non-payment by CMS Energy and
Enterprises of obligations under
the credit agreement
Surety bonds and other Normal operating activity, permits Nonperformance
indemnifications and licenses
Other guaranteesGuarantees and put options Normal operating activity Nonperformance or non-payment by
a subsidiary under a related
contract
Agreement to provide power and steam MCV Partnership's nonperformance
orsteam to Dow or non-payment under a related
contract
Bay Harbor remediation efforts Owners exercising put options
requiring us to purchase
property
Nuclear insurance retrospective Normal operations of nuclear plants Call by NEIL and Price-Anderson
premiums Act
premiums for nuclear incident
At March 31, 2007, certain contracts contained provisions allowing us to
recover, from third parties, amounts paid under the guarantees. For example, if
we are required to purchase a property under a put option agreement, we may sell
the property to recover the amount paid under the option.
We enter into various agreements containing tax and other indemnification
provisions in connection with a variety of transactions, including the sale of
our interests in the MCV Partnership and the FMLP. In April 2007, we sold our
interest in Palisades and the Big Rock ISFSI to Entergy. As part of the
transaction, we entered into agreements containing tax and other indemnification
provisions. While we are unable to estimate the maximum potential obligation
related to these indemnities, we consider the likelihood that we would be
required to perform or incur significant losses related to these indemnities and
the guarantees listed in the preceding tables to be remote.
Project Financing: We enter into various project-financing security arrangements
such as equity pledge agreements and share mortgage agreements to provide
financial or performance assurance to third parties on behalf of certain
unconsolidated affiliates. Expiration dates for these agreements vary from March
2015 to June 2020 or terminate upon payment or cancellation of the obligation.
Non-payment or other act of default by an unconsolidated affiliate would trigger
enforcement of the security. If we were required to perform under these
agreements, the maximum amount of our obligation under these agreements would be
equal to the value of the shares relinquished to the guaranteed party at the
time of default.
At September 30, 2006, certain contracts contained provisions allowing usIn May 2007, we sold our ownership interests in businesses in the Middle East,
Africa, and India to recover, from third parties, amounts paid under the guarantees. For example, if
we are required to purchase a property under a put option agreement, we may sell
the property to recover the amount paid under the option.
We enter into various agreements containing tax and other indemnification
provisions in connection with a variety of transactions. While we are unable to
estimate the maximum potential obligationTAQA. TAQA has assumed all contingent obligations related
to these indemnities, we
consider the likelihood that we would be required to perform or incur
significant losses related to these indemnities and the guarantees listed in the
preceding tables to be remote.
CMS-65our project-financing
CMS-57
CMS Energy Corporation
security agreements. For more details on the sale of our ownership interests to
TAQA, see Note 2, Asset Sales, Discontinued Operations and Impairment Charges.
4: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
---------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
CMS ENERGY CORPORATION
Senior notes $2,271 $2,347$2,271
Other long-term debt 1 21
------ ------
Total - CMS Energy Corporation 2,272 2,3492,272
------ ------
CONSUMERS ENERGY COMPANY
First mortgage bonds 3,173 3,1753,172 3,172
Senior notes and other 801 852654 652
Securitization bonds 348 369332 340
------ ------
Total - Consumers Energy Company 4,322 4,3964,158 4,164
------ ------
OTHER SUBSIDIARIES 353 363325 331
------ ------
TOTAL PRINCIPAL AMOUNTS OUTSTANDING 6,947 7,1086,755 6,767
Current amounts (288) (289)(710) (551)
Net unamortized discount (15) (19)(13) (14)
------ ------
Total Long-term debt $6,644 $6,800$6,032 $6,202
====== ======
FINANCINGS: The following is a summary of significant long-term debt retirements
during the nine months ended September 30, 2006:
Principal Interest Rate
(in millions) (%) Retirement Date Maturity Date
------------- ------------- ------------------ -------------
CMS ENERGY
Senior notes $ 76 9.875 January through October 2007
April 2006
CONSUMERS
Long-term debt - related parties 129 9.00 February 2006 June 2031
FMLP debt 56 13.25 July 2006 July 2006
ENTERPRISES
CMS Generation Investment Co. IV Bank June and September
Loan 35 Variable 2006 December 2008
----
TOTAL $296
====
REGULATORY AUTHORIZATION FOR FINANCINGS: In May 2006, the FERC issued an order
authorizing Consumers to issue up to $2.0 billion of secured and unsecured
short-term securities for the following purposes:
- - up to $1.0 billion for general corporate purposes, and
- - up to $1.0 billion of FMB or other securities to be issued solely as
collateral for other short-term securities.
Also in May 2006, the FERC issued an order authorizing Consumers to issue up to
$5.0 billion of secured and unsecured long-term securities for the following
purposes:
- - up to $1.5 billion for general corporate purposes,
- - up to $1.0 billion for purposes of refinancing or refunding existing
long-term debt, and
CMS-66
CMS Energy Corporation
- - up to $2.5 billion of FMB or other securities to be issued solely as
collateral for other long-term securities.
The authorizations are for a two-year period beginning July 1, 2006 and ending
June 30, 2008. Any long-term issuances during the two-year authorization period
are exempt from the FERC's competitive bidding and negotiated placement
requirements.
REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities
with banks are available at September 30, 2006:March 31, 2007:
In Millions
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Amount of Amount Outstanding
Company Expiration Date Facility Borrowed Letters-of-Credit Amount Available
- ------------------------- --------------- --------- -------- ----------------- ----------------
CMS Energy May 18, 2010 $300 $ - $104 $196$-- $87 $213
Consumers March 30, 2007 300 - - 300
Consumers May 18, 20102012 500 - 62 438
MCV Partnership August 25, 2007 25 - 7 18-- 59 441
In March 2006, Consumers entered into a short-term secured revolving credit
agreement with banks. This facility providesWe replaced our $300 million of fundsfacility in April 2007 with a new $300 million
credit facility that expires April 2, 2012. Consumers replaced its $500 million
facility with a new $500 million credit facility in March 2007. The new
facilities contain less restrictive covenants, and provide for working
capitallower fees and
other general corporate purposes.lower interest margins than the previous credit facilities.
DIVIDEND RESTRICTIONS: Under provisions of our senior notes indenture, at March
31, 2007, we had $400 million of unrestricted net assets available to pay common
stock dividends. Our amended and restated $300 million secured revolving credit facility restrictsrestricted
payments of dividends on our common stock during a 12-month period to $150
million. This restriction was removed with the new $300 million dependent on the aggregate amounts of
unrestricted cash and unused commitments under the facility.credit facility
effective April 2, 2007.
Under the provisions of its articles of incorporation, at September 30, 2006,March 31, 2007,
Consumers had $253$227 million of unrestricted retained earnings available to pay
common stock dividends. CovenantsThe dividend restrictions in Consumers' debt facilities cap common stock
dividend payments at $300 millionits
CMS-58
CMS Energy Corporation
credit facility were removed in a calendar year.March 2007. Provisions of the Federal Power Act
and the Natural Gas Act effectively restrict dividends to the amount of
Consumers' retained earnings. For the ninethree months ended September 30, 2006,March 31, 2007, we
received $71$94 million of common stock dividends from Consumers.
PREFERRED STOCK: In February 2007, our non-voting preferred subsidiary interest
of $11 million was repurchased and redeemed for a cash payment of $32 million.
The original $19 million addition to paid-in-capital was reversed and a $1
million redemption premium was charged to retained deficit.
CONTINGENTLY CONVERTIBLE SECURITIES: In March 2007, the $11.87 per share
conversion trigger price contingency was met for our $250 million 4.50 percent
contingently convertible preferred stock and the $12.81 per share conversion
trigger price contingency was met for our $150 million 3.375 percent
contingently convertible senior notes. As a result, these securities are
convertible at the option of the security holders for the three months ending
June 30, 2007, with the par value or principal payable in cash. As of April
2007, none of the security holders have notified us of their intention to
convert these securities.
Because the 3.375 percent senior notes are convertible on demand, they are
classified as current liabilities.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly of leased
service vehicles, power purchase agreements, and office furniture. At September 30, 2006,March 31,
2007, capital lease obligations totaled $55$64 million. In order to
obtain permanent financing for the MCV Facility, the MCV Partnership entered
into a sale and leaseback agreement with a lessor group, which includes the
FMLP, for substantially all of the MCV Partnership's fixed assets. In accordance
with SFAS No. 98, the MCV Partnership accounted for the transaction as a
financing arrangement. At September 30, 2006, finance lease obligations totaled
$268 million, which represents the third-party portion of the MCV Partnership's
finance lease obligation.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, Consumers sells certain accounts receivable to a wholly owned,
consolidated, bankruptcy remote special purpose entity. In turn, the special
purpose entity may sell an undivided interest in up to $325 million of the
receivables. The special purpose entity sold $316$10 million of receivables at September 30, 2006March
31, 2007 and $325 million of receivables at December 31, 2005.2006. Consumers
continues to service the receivables sold to the special purpose entity. The
purchaser of the receivables has no recourse against Consumers' other assets for
failure of a debtor to pay when due and no right to any receivables not sold.
Consumers has neither recorded a gain or loss on the receivables sold nor
retained interest in the receivables sold.
CMS-67
CMS Energy Corporation
Certain cash flows under Consumers' accounts receivable sales program are shown
in the following table:
In Millions
---------------
NineThree months ended September 30Ended March 31 2007 2006
2005
- --------------------------------------------------------- ------ ------
Net cash flow as a result of accounts receivable financing $ (9)(315) $ (204)(325)
Collections from customers $4,402 $3,782$1,928 $1,817
====== ======
CONTINGENTLY CONVERTIBLE SECURITIES: In September 2006, the $11.87 per share
conversion trigger price contingency was met for our $250 million 4.50 percent
contingently convertible preferred stock. As a result, these securities are
convertible at the option of the security holders for the three months ending
December 31, 2006, with the par value payable in cash. As of October 2006, none
of the security holders have notified us of their intention to convert these
securities.
In September 2006, the $12.81 per share conversion trigger price contingency was
met for our $150 million 3.375 percent contingently convertible senior notes. As
a result, these securities are convertible at the option of the security holders
for the three months ending December 31, 2006, with the principal payable in
cash. Because they are convertible on demand, they are classified as current
liabilities. As of October 2006, none of the security holders have notified us
of their intention to convert these securities.CMS-59
CMS Energy Corporation
5: EARNINGS PER SHARE
The following table presents the basic and diluted earnings per share
computations based on Loss from Continuing Operations:
In Millions, Except Per Share Amounts
-------------------------------------
Three Months Ended September 30March 31 2007 2006
2005
- ---------------------------------------------------------- ------ ------
LOSS AVAILABLE TO COMMON STOCKHOLDERS
Loss from Continuing Operations $ (102)(31) $ (263)(32)
Less Preferred Dividends (2) (2)and Redemption Premium (4) (3)
------ ------
Loss from Continuing Operations Available to
Common Stockholders - Basic and Diluted $ (104)(35) $ (265)(35)
====== ======
AVERAGE COMMON SHARES OUTSTANDING
Weighted Average Shares - Basic and Diluted 220.1 219.6221.5 219.1
LOSS PER AVERAGE COMMON SHARE
AVAILABLE TO COMMON STOCKHOLDERS
Basic $(0.47) $(1.21)$(0.16) $(0.16)
Diluted $(0.47) $(1.21)
====== ======
CMS-68
CMS Energy Corporation
In Millions, Except Per Share Amounts
-------------------------------------
Nine Months Ended September 30 2006 2005
- ------------------------------ ------ ------
LOSS AVAILABLE TO COMMON STOCKHOLDERS
Loss from Continuing Operations $ (54) $ (81)
Less Preferred Dividends (8) (7)
------ ------
Loss from Continuing Operations Available to
Common Stockholders - Basic and Diluted $ (62) $ (88)
====== ======
AVERAGE COMMON SHARES OUTSTANDING
Weighted Average Shares - Basic and Diluted 219.6 211.0
LOSS PER AVERAGE COMMON SHARE
AVAILABLE TO COMMON STOCKHOLDERS
Basic $(0.28) $(0.42)
Diluted $(0.28) $(0.42)$(0.16) $(0.16)
====== ======
Contingently Convertible Securities: For the three and nine months ended September 30, 2006,March 31, 2007,
we recorded a loss from continuing operations, therefore dueoperations. Due to antidilution, there was no
impact to diluted EPS from our contingently convertible securities. Assuming
positive income from continuing operations, our contingently convertible
securities dilute EPS to the extent that the conversion value, which is based on
the average market price of our common stock, exceeds the principal or par
value. Had there been positive income from continuing operations, our
contingently convertible securities would have contributed an additional 11.519.1
million shares to the calculation of diluted EPS for the three months ended
September 30, 2006 and 10.2 million shares for the nine months
ended September 30, 2006.March 31, 2007.
Stock Options, Warrants and Warrants:Restricted Stock: For the three and nine months ended September 30,March
31, 2007, due to antidilution, there was no impact to diluted EPS for 1.9
million shares of unvested restricted stock awards and for options and warrants
to purchase 0.4 million shares of common stock. For the three months ended March
31, 2006, due to antidilution, there was no impact to diluted EPS for options and
warrants to purchase 3.00.9
million shares of common stock. For the threeunvested restricted stock awards and nine
months ended September 30, 2005, due to antidilution, there was no impact to
diluted EPS for options and warrants
to purchase 3.80.5 million shares of common stock. An additional 1.4 million stock
options at March 31, 2007 and 1.9 million stock options at March 31, 2006, were
excluded from the diluted EPS calculation because the exercise price was greater
than the average market price of our common stock. These stock options have the
potential to dilute EPS in the future.
Convertible Debentures: Due to accounting EPS dilution principles, forFor the three and nine months ended September 30, 2006,March 31, 2007, due to
antidilution, there was no impact to diluted EPS from our 7.75 percent
convertible subordinated debentures. Using the if-converted method, the
debentures would have:
- - increased the numerator of diluted EPS by $2 million for the three
months ended September 30, 2006 and $7 million for the nine months ended September
30, 2006,March 31, 2007, from an assumed reduction of interest
expense, net of tax, and
- - increased the denominator of diluted EPS by 4.34.2 million shares.
We can revoke the conversion rights if certain conditions are met.
CMS-60
CMS Energy Corporation
6: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and
current liabilities approximate their fair values because of their short-term
nature. We estimate the fair values of long-term financial instruments based on
quoted market prices or, in the absence of specific market prices, on quoted
market prices of similar instruments or other valuation techniques.
CMS-69
CMS Energy Corporation
The cost and fair value of our long-term financialdebt instruments including current
maturities are as follows:
In Millions
-------------------------------------------------------------
September 30, 2006March 31, 2007 December 31, 20052006
----------------------------- -----------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain (Loss) Cost Value Gain (Loss)
------ ------ ----------- ------ ------ -----------
Long-term debt $6,932 $7,097 $(165) $7,089 $7,315 $(226)
including current amounts$6,742 $7,028 $(286) $6,753 $6,949 $(196)
Long-term debt - related parties including current amounts 178 151 27152 26 178 155 23
====== ====== ===== ====== ====== =====
The summary of our available-for-sale investment securities is as follows:
In Millions
-------------------------------------------------------------------------------
March 31, 2007 December 31, 2006
-------------------------------------- --------------------------------------
Unrealized Unrealized Fair Unrealized Unrealized Fair
Cost Gains Losses Value Cost Gains Losses Value
---- ---------- ---------- ----- ---- ---------- ---------- -----
Nuclear decommissioning investments: (a)
Equity securities $142 $149 $(4) $287 $140 $150 $(4) $286
Debt securities 228 2 (2) 228 307 280 27
Available-for-sale securities:4 (2) 309
SERP:
Equity securities 35 53 18 34 49 1536 22 (1) 57 36 21 -- 57
Debt securities 15 15 - 17 17 -
Nuclear decommissioning investments:
Equity securities 138 268 130 134 252 118
Debt securities 304 307 3 287 291 413 -- -- 13 13 -- -- 13
==== ==== === ==== ==== ==== === ====
(a) In July 2006,preparation for the sale of Palisades, these investments also held cash
and cash equivalents totaling $91 million at March 31, 2007. In April 2007,
we reached an agreement to sellsold Palisades and the Big Rock ISFSI to Entergy. Entergy will assume responsibility for the future decommissioning of
the plant and for storage and disposal of spent nuclear fuel. Accordingly, upon
completion of the sale, we
will transfer $382transferred $252 million of nuclear decommissioningin trust fund assets to EntergyEntergy. For additional
details on the sale of Palisades and retain $205 million. We will also be entitled
to receive a returnthe Big Rock ISFSI, see Note 3,
Contingencies, "Other Consumers' Electric Utility Contingencies - The Sale
of $130 million, pending either a favorable federal tax
ruling regarding the release of the funds, or if no such ruling is issued, after
decommissioning ofNuclear Assets and the Palisades site is complete. These estimates increased
approximately $20 million compared to second quarter 2006 estimates primarily
because of market appreciation during the third quarter of 2006. The disposition
of the retained and receivable nuclear decommissioning funds is subject to
regulatory proceedings.Power Purchase Agreement."
DERIVATIVE INSTRUMENTS: In order to limit our exposure to certain market risks,
we may enter into various risk management contracts, such as swaps, options,
futures, and forward contracts. These contracts, used primarily to manage our
exposure to changes in interest rates, commodity prices, and currency exchange
rates, are classified as either non-trading or trading. We enter into these
contracts using established policies and procedures, under the direction of
both:
- an executive oversight committee consisting of senior management
representatives, and
- a risk committee consisting of business unit managers.
The contracts we use to manage market risks may qualify as derivative
instruments that are subject to derivative and hedge accounting under SFAS No.
133. If a contract is a derivative, it is recorded on theour consolidated balance
sheet at its fair value. We then adjust the resulting asset or liability each
quarter to
CMS-61
CMS Energy Corporation
reflect any change in the market value of the contract, a practice known as
marking the contract to market. From time to time, we enter into cash flow
hedges. If a derivative qualifies for cash flow hedge accounting treatment, the
changes in fair value (gains or losses) are reported in accumulated other
comprehensive income;AOCL; otherwise, the
changes are reported in earnings.
CMS-70
CMS Energy Corporation
For a derivative instrument to qualify for cash flow hedge accounting:
- the relationship between the derivative instrument and the forecasted
transaction being hedged must be formally documented at inception,
- the derivative instrument must be highly effective in offsetting the
hedged transaction's cash flows, and
- the forecasted transaction being hedged must be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or
losses are recorded in accumulated other comprehensive income,AOCL, those gains or losses will be reclassified into
earnings in the same period or periods the hedged forecasted transaction affects
earnings. If a cash flow hedge is terminated early because it is determined that
the forecasted transaction will not occur, any gain or loss recorded in accumulated other comprehensive incomeAOCL at
that date is recognized immediately in earnings. If a cash flow hedge is
terminated early for other economic reasons, any gain or loss as of the
termination date is deferred and then reclassified to earnings when the
forecasted transaction affects earnings. The ineffective portion, if any, of all
hedges is recognized in earnings.
To determine the fair value of our derivatives, we use information from external
sources (i.e., quoted market prices and third-party valuations), if available.
For certain contracts, this information is not available and we use mathematical
valuation models to value our derivatives. These models require various inputs
and assumptions, including commodity market prices and volatilities, as well as
interest rates and contract maturity dates. The cash returns we actually realize
on these contracts may vary, either positively or negatively, from the results
that we estimate using these models. As part of valuing our derivatives at
market, we maintain reserves, if necessary, for credit risks arising from the
financial condition of our counterparties.
The majority of our commodity purchase and sale contracts are not subject to
derivative accounting under SFAS No. 133 because:
- they do not have a notional amount (that is, a number of units
specified in a derivative instrument, such as MWMWh of electricity or
bcf of natural gas),
- they qualify for the normal purchases and sales exception, or
- there is not an active market for the commodity.
Our coal purchase contracts are not derivatives because there is not an active
market for the coal we purchase. Similarly, certain of our electric capacity and
energy contracts are not derivatives due to the lack ofIf an active energy market in Michigan. If active markets for these commodities developcoal develops in the
future, some of these contracts may qualify as derivatives. For our coal purchase contracts,derivatives and the resulting
mark-to-market impact on earnings could be material. For our
electric capacity and energy contracts, we believe that we would be able to
apply the normal purchases and sales exception to the majority of these
contracts (including the MCV PPA) and, therefore, would not be required to mark
these contracts to market.
In 2005, the MISO began operating the Midwest Energy Market. As a result, the
MISO now centrally dispatches electricity and transmission service throughout
much of the Midwest and provides day-ahead and real-time energy market
information. At this time, we believe that the establishment of this market does
not represent the development of an active energy market in Michigan, as defined
by SFAS No. 133. However, as the Midwest Energy Market matures, we will continue
to monitor its activity level and evaluate whether or not an active energy
market may exist in Michigan.
CMS-71
CMS Energy Corporation
Derivative accounting is required for certain contracts used to limit our
exposure to interest rate risk, commodity price risk, and foreign exchange risk.
The following table summarizes our derivative instruments:
CMS-62
CMS Energy Corporation
In Millions
-------------------------------------------------------
September 30, 2006March 31, 2007 December 31, 20052006
-------------------------- --------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- ---------------------- ---- ----- ----------- ---- ----- -----------
Non-trading:
Gas supply option contracts $ - $ - $ - $ 1 $ (1) $ (2)
FTRs - - - - 1 1
Derivative contracts associated with the MCV
Partnership:
Long-term gas contracts (a) - 43 43 - 205 205
Gas futures, options, and swaps (a) - 66 66 - 223 223
CMS ERM derivative
contracts:
Non-trading electric
/ gas contracts (b) --- 34 34 - (63) (63)-- 31 31
Trading electric
/ gas contracts (c) - (65) (65) (3) 100 103(9) (68) (59) (11) (68) (57)
Derivative contracts
associated with equity
investments in:
Shuweihat - (15) (15) - (20) (20)-- (14) (14) -- (14) (14)
Taweelah (35) (13) 22(12) 23 (35) (17) 18(11) 24
Jorf Lasfar - (6) (6) - (8) (8)-- (4) (4) -- (5) (5)
Other --- 1 1 --- 1 1
(a) The fair value of the MCV Partnership's long-term gas contracts and gas
futures, options, and swaps has decreased significantly from December 31,
2005 partly due to a decrease in natural gas prices since that time. The
decrease is also the result of the normal reversal of such derivative
assets. As gas has been purchased under the long-term gas contracts and the
gas futures, options, and swap contracts have been settled, the fair value
of the contracts has decreased.
(b) The fair value of CMS ERM's non-trading electric and gas contracts has
increased significantly from December 31, 2005 due to the termination of
certain gas contracts. CMS ERM had recorded derivative liabilities,
representing cumulative unrealized mark-to-market losses, associated with
these gas contracts. As the contracts are now settled, the related
derivative liabilities are no longer included in the balance of CMS ERM's
non-trading electric and gas contracts.
(c) The fair value of CMS ERM's trading electric and gas contracts has
decreased significantly from December 31, 2005 due to the termination of
certain gas contracts. CMS ERM had recorded derivative assets, representing
cumulative unrealized mark-to-market gains, associated with these gas
contracts. As the contracts are now settled, the related derivative assets
are no longer included in the balance of CMS ERM's trading electric and gas
contracts.
We record the fair value of our gas supply option contracts, FTRs, and the
derivative contracts associated with the MCV Partnership in Derivative
instruments, Other assets, or Other liabilities on our Consolidated Balance
Sheets. We include the fair value of the derivative contracts held by CMS ERM in either
Price risk management assets or Price risk management liabilities on our
Consolidated Balance Sheets. The fair value of derivative contracts associated
with our equity investments is included in Investments - Enterprises on our
Consolidated Balance Sheets.
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GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses fixed-priced
weather-based gas supply call options and fixed-priced gas supply call and put
options to meet our regulatory obligation to provide gas to our customers at a
reasonable and prudent cost. As part of regulatory accounting, the
mark-to-market gains and losses associated with these options are reported
directly in earnings as part of Other income, and then immediately reversed out
of earnings and recorded on the balance sheet as a regulatory asset or
liability.
FTRS: With the creation of the Midwest Energy Market, FTRs were established.
FTRs are financial instruments that manage price risk related to electricity
transmission congestion. An FTR entitles its holder to receive compensation (or,
conversely, to remit payment) for congestion-related transmission charges. As
part of regulatory accounting, the mark-to-market gains and losses associated
with these instruments are reported directly in earnings as part of Other
income, and then immediately reversed out of earnings and recorded on the
balance sheet as a regulatory asset or liability.
DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: Long-term gas
contracts: The MCV Partnership uses long-term gas contracts to purchase and
manage the cost of the natural gas it needs to generate electricity and steam.
The MCV Partnership believes that certain of these contracts qualify as normal
purchases under SFAS No. 133. Accordingly, we have not recognized these
contracts at fair value on our Consolidated Balance Sheets at September 30,
2006.
The MCV Partnership also holds certain long-term gas contracts that do not
qualify as normal purchases because these contracts contain volume optionality
or because the gas will not be used to generate electricity or steam.
Accordingly, all of these contracts are accounted for as derivatives, with
changes in fair value recorded in earnings each quarter.
For the nine months ended September 30, 2006, we recorded a $161 million loss,
before considering tax effects and minority interest, associated with the
decrease in fair value of these long-term gas contracts. This loss is included
in the total Fuel costs mark-to-market at the MCV Partnership on our
Consolidated Statements of Income (Loss). Because of the volatility of the
natural gas market, the MCV Partnership expects future earnings volatility on
these contracts, since gains and losses will be recorded each quarter. We will
continue to record these gains and losses in our consolidated financial
statements until we close the sale of our interest in the MCV Partnership.
We have recorded derivative assets totaling $43 million associated with the fair
value of long-term gas contracts on our Consolidated Balance Sheets at September
30, 2006. The MCV Partnership expects almost all of these assets, which
represent cumulative net mark-to-market gains, to reverse as losses through
earnings during 2007 and 2008 as the gas is purchased, with the remainder
reversing between 2009 and 2011. As the MCV Partnership recognizes future losses
from the reversal of these derivative assets, we will continue to assume a
portion of the limited partners' share of those losses, in addition to our
proportionate share, but only until we close the sale of our interest in the MCV
Partnership.
These long-term gas contracts will be sold in conjunction with the sale of our
interest in the MCV Partnership. At the date we close the sale, we will record
any additional mark-to-market gains or losses associated with these contracts in
earnings. After the closing, we will no longer record the fair value of these
long-term gas contracts on our Consolidated Balance Sheets and will not be
required to recognize gains or losses related to changes in the fair value of
these contracts on our Consolidated Statements of Income (Loss).
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Gas Futures, Options, and Swaps: The MCV Partnership enters into natural gas
futures, options, and over-the-counter swap transactions in order to hedge
against unfavorable changes in the market price of natural gas. The MCV
Partnership uses these financial instruments to:
- ensure an adequate supply of natural gas for the projected generation
and sales of electricity and steam, and
- manage price risk by fixing the price to be paid for natural gas on
some of its long-term gas contracts.
At September 30, 2006, the MCV Partnership held natural gas futures, options,
and swaps. We have recorded a net derivative asset amount of $66 million on our
Consolidated Balance Sheets at September 30, 2006 associated with the fair value
of these contracts. Certain of the futures and swaps qualify for cash flow hedge
accounting and we record our proportionate share of their mark-to-market gains
and losses in Accumulated other comprehensive loss. The remaining contracts are
not cash flow hedges and their mark-to-market gains and losses are recorded to
earnings.
Those contracts that qualify as cash flow hedges represent assets of $79 million
of the net $66 million derivative assets recorded on our Consolidated Balance
Sheets. We have recorded a cumulative net gain of $25 million, net of tax and
minority interest, in Accumulated other comprehensive loss at September 30,
2006, representing our proportionate share of mark-to-market gains and losses
from these contracts. If we have not closed the sale of our interest in the MCV
Partnership within the next 12 months, we can expect to reclassify $11 million
of this balance, net of tax and minority interest, as an increase to earnings as
the contracts settle, offsetting the costs of gas purchases. There was no
ineffectiveness associated with any of these cash flow hedges.
The remaining futures, options, and swap contracts, representing derivative
liabilities of $13 million, do not qualify as cash flow hedges and we record any
changes in their fair value in earnings each quarter. The MCV Partnership
expects these derivative liabilities, which represent cumulative net
mark-to-market losses, to be realized during 2006 and 2007 as the contracts
settle.
For the nine months ended September 30, 2006, we recorded a $65 million loss,
before considering tax effects and minority interest, associated with the
decrease in fair value of these instruments. This loss is included in the total
Fuel costs mark-to-market at the MCV Partnership on our Consolidated Statements
of Income (Loss). Because of the volatility of the natural gas market, the MCV
Partnership expects future earnings volatility on these contracts, since gains
and losses will be recorded each quarter. We will continue to record these gains
and losses in our consolidated financial statements until we close the sale of
our interest in the MCV Partnership.
In conjunction with the sale of our interest in the MCV Partnership, these
futures, options, and swaps will be sold. At the date we close the sale, we will
record any additional mark-to-market gains or losses associated with these
contracts in Accumulated other comprehensive loss or earnings, accordingly.
Then, for those futures and swaps that qualify as cash flow hedges, the related
balance of net cumulative gains recorded in Accumulated other comprehensive loss
will be reclassified and recognized in earnings. After the closing, we will no
longer record the fair value of these contracts on our Consolidated Balance
Sheets and will not be required to recognize gains or losses related to changes
in the fair value of these contracts on our Consolidated Statements of Income
(Loss).
Any changes in the fair value of the long-term gas contracts or these futures,
options, and swaps recognized before the closing will not affect the sale price
of our interest in the MCV Partnership. For
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additional details on the sale of our interest in the MCV Partnership, see Note
3, Contingencies, "Other Consumers' Electric Utility Contingencies - The Midland
Cogeneration Venture."
CMS ERM CONTRACTS: CMS ERM enters into and owns energy contracts as a part of
activities considered to be an integral part ofthat support
CMS Energy's ongoing operations. CMS ERM holds certain contracts for the future
purchase and sale of natural gas that will result in physical delivery of the
commodity at contractual prices. These forward contracts are generally long-term
in nature and are classified as non-trading. CMS ERM also uses various financial
instruments, including swaps, options, and futures, to manage commodity price
risks associated with its forward purchase and sale contracts and with
generation assets owned by CMS Energy or its subsidiaries. These financial
contracts are classified as trading activities.
In accordance with SFAS No. 133, non-trading and trading contracts that qualify
as derivatives are recorded at fair value on our Consolidated Balance Sheets.
The resulting assets and liabilities are marked to market each quarter, and
changes in fair value are recorded in earnings as a component of Operating
Revenue. For trading contracts, these gains and losses are recorded net in
accordance with EITF Issue No. 02-03. Contracts that do not meet the definition
of a derivative are accounted for as executory contracts (that is, on an accrual
basis).
DERIVATIVE CONTRACTS ASSOCIATED WITH EQUITY INVESTMENTS: At September 30, 2006,March 31, 2007, some
of our equity method investees, specifically Taweelah, Shuweihat, Jorf Lasfar,
and Jubail, held:
- interest rate contracts that hedged the risk associated with
variable-rate debt, and
- foreign exchange contracts that hedged the foreign currency risk
associated with payments to be made under operating and maintenance
service agreements.
We recordrecorded our proportionate share of the change in fair value of these
contracts in Accumulated other comprehensive lossAOCL if the contracts qualifyqualified for cash flow hedge accounting;
otherwise, we recordrecorded our share in Earnings from Equity Method Investees. At
March 31, 2007, there was no ineffectiveness associated with any of the
contracts that qualify for cash flow hedge accounting.
In May 2007, we sold our ownership interest in businesses in the Middle East,
Africa, and India, including Taweelah, Shuweihat,
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Jorf Lasfar, and Jubail. As a result of that sale, we will no longer recognize
gains or losses related to changes in the fair value of the derivative contracts
held by these equity method investees. At March 31, 2007, we had accumulated a
cumulative net loss of $14 million, net of tax, in AOCL representing our
proportionate share of mark-to-market gains and losses from cash flow hedges
held by the equity method investees. At the date we closed the sale, this
amount, adjusted for any additional changes in fair value, was reclassified and
recognized in earnings as part of the sale. This amount comprised the total
amount we had recorded in AOCL related to derivative instruments.
Any changes in the fair value of these contracts recognized before the closing
did not affect the sales price of our interest in these equity method investees.
For additional details on the sale of our interest in these equity method
investees, see Note 2, Asset Sales, Discontinued Operations and Impairment
Charges.
FOREIGN EXCHANGE DERIVATIVES: At times,In the past, we usehave used forward exchange and
option contracts to hedge the value of investments in foreign operations. These
contracts limitlimited the risk from currency exchange rate movements because gains
and losses on such contracts offset losses and gains, respectively, on the
hedged investments. At September 30, 2006,March 31, 2007, we had no outstanding foreign exchange
contracts. However, the impact of previous hedges on our investments in foreign
operations is reflected in Accumulated other comprehensive lossAOCL as a component of the foreign currency
translation adjustment on our Consolidated Balance Sheets. Gains or losses from
the settlement of these hedges are maintained in the foreign currency
translation adjustment until we sell or liquidate the hedged investments. At
September 30, 2006,March 31, 2007, our total foreign currency translation adjustment was a net loss
of $306$169 million, which included a net hedging loss of $26$22 million, net of tax,
related to the settlement of these contracts.
CREDIT RISK: Our swaps, options, and forward contracts contain credit risk,
which is the risk that counterparties will fail to perform their contractual
obligations. We reduce this risk through established credit policies. For each
counterparty, we assess credit quality by using credit ratings, financial
condition, and other available information. We then establish a credit limit for
each counterparty based upon our evaluation of credit quality. We monitor the
degree to which we are exposed to potential loss under each contract and take
remedial action, if necessary.
CMS ERM and the MCV Partnership enterenters into contracts primarily with companies in the electric and
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CMS Energy Corporation gas
industry. This industry concentration may have an impact on our exposure to
credit risk, either positively or negatively, based on how these counterparties
are affected by similar changes in economic conditions, the weather, or other
conditions. CMS ERM and the MCV Partnership typically useuses industry-standard agreements that allow for
netting positive and negative exposures associated with the same counterparty,
thereby reducing exposure. These contracts also typically provide for the
parties to demand adequate assurance of future performance when there are
reasonable grounds for doing so.
The following table illustrates our exposure to potential losses at September
30, 2006,March 31,
2007, if each counterparty within this industry concentration failed to perform
its contractual obligations. This table includes contracts accounted for as
financial instruments. It does not include trade accounts receivable, derivative
contracts that qualify for the normal purchases and sales exception under SFAS
No. 133, or other contracts that are not accounted for as derivatives.
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In Millions
- -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Net Net Exposure
from NetExposure Exposure from Exposurefrom
Before Investment Investment
Collateral Collateral Net Investment Grade Investment Grade
Collateral
(a) Held (b) Exposure Companies Companies (%)
------------------------- ---------- -------- ----------------- ------------------------------ -------------
CMS ERM $ 51$46 $ - $46 $ 51 $ 2 (c) 4
MCV Partnership 120 36 84 84 100- 0%
(a) Exposure is reflected net of payables or derivative liabilities if netting
arrangements exist.
(b) Collateral held includes cash and letters of credit received from
counterparties.
(c) The majority of the remaining balance of CMS ERM's net exposure was from
a counterparty whose credit rating fell below investment grade after
December 31, 2005.
Based on our credit policies, our current exposures, and our credit reserves, we
do not expect a material adverse effect on our financial position or future
earnings as a result of counterparty nonperformance.
7: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- a non-contributory, defined benefit Pension Plan,
- a cash balance pension planPension Plan for certain employees hired between July
1, 2003 and August 31, 2005,
- a DCCP for employees hired on or after September 1, 2005,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) Savings Plan,
- benefits to a select group of management under the EISP, and
- health care and life insurance benefits under OPEB.
Pension Plan: The Pension Plan includes funds for most of our current employees,
the employees of our subsidiaries, and Panhandle, a former subsidiary. The
Pension Plan's assets are not distinguishable by company.
Effective January 11, 2006,In April 2007, we sold the MPSC electric rate order authorized ConsumersPalisades nuclear plant to include $33Entergy. Employees
transferred to Entergy as a result of the sale no longer participate in our
retirement benefit plans. In April 2007, we recorded a net reduction of $27
million CMS-76in pension SFAS No. 158 regulatory assets with a corresponding decrease
of $27 million in pension liabilities on our Consolidated Balance Sheets. We
also recorded a net reduction of $15 million in OPEB regulatory SFAS No. 158
assets with a corresponding decrease of $15 million in OPEB liabilities. The
following table shows the net adjustment:
Pension OPEB
------- ----
Plan liability transferred to Entergy $44 $20
Trust assets transferred to Entergy 17 5
--- ---
Net adjustment $27 $15
=== ===
Beginning May 1, 2007, the CMS Energy Common Stock Fund will no longer be an
investment option available for new investments in the 401(k) Savings Plan and
the employer's match will no longer be in CMS Energy Stock. Participants will
have an opportunity to reallocate investments in the CMS Energy Stock Fund to
other plan investment alternatives. Beginning November 1, 2007, any remaining
shares in the CMS Energy Stock Fund will be sold and the sale proceeds will be
reallocated to other plan investment options. At March 31, 2007, there were 10
million shares of CMS Energy Common Stock in the CMS Energy Stock Fund.
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CMS Energy Corporation
of electric pension expense in its electric rates. Due to the volatility of
these particular costs, the order also established a pension equalization
mechanism to track actual costs. If actual pension expenses are greater than the
$33 million included in electric rates, the difference will be recognized as a
regulatory asset for future recovery from customers. If actual pension expenses
are less than the $33 million included in electric rates, the difference will be
recognized as a regulatory liability, and refunded to our customers. The
difference between pension expense allowed in our electric rates and pension
expense under SFAS No. 87 resulted in a net reduction in pension expense of $3
million for the three months ended September 30, 2006 and $8 million for the
nine months ended September 30, 2006. We have established a corresponding
regulatory asset of $8 million.
OPEB: Effective January 11, 2006, the MPSC electric rate order authorized
Consumers to include $28 million of electric OPEB expense in its electric rates.
Due to the volatility of these particular costs, the order also established an
OPEB equalization mechanism to track actual costs. If actual OPEB expenses are
greater than the $28 million included in electric rates, the difference will be
recognized as a regulatory asset for future recovery from our customers. If
actual OPEB expenses are less than the $28 million included in electric rates,
the difference will be recognized as a regulatory liability, and refunded to our
customers. The difference between OPEB expense allowed in our electric rates and
OPEB expense under SFAS No. 106 resulted in a net reduction in OPEB expense of
less than $1 million for the three months ended September 30, 2006 and $1
million for the nine months ended September 30, 2006. We have established a
corresponding regulatory asset of $1 million.
Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
--------------------------------------
Pension
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Service cost $ 13 $ 9 $ 37 $ 34
Interest cost 20 15 62 64
Expected return on plan assets (20) (17) (63) (80)
Amortization of:
Net loss 10 11 32 25
Prior service cost 1 1 5 5
---- ---- ---- ----
Net periodic cost 24 19 73 48
Regulatory adjustment (3) - (8) -
---- ---- ---- ----
Net periodic cost after regulatory adjustment $ 21 $ 19 $ 65 $ 48
==== ==== ==== ====
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In Millions
--------------------------------------
OPEB
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Service cost $ 6 $ 6 $ 18 $ 17
Interest cost 15 15 47 47
Expected return on plan assets (14) (14) (43) (42)
Amortization of:
Net loss 5 6 15 15
Prior service cost (3) (3) (8) (7)
---- ---- ---- ----
Net periodic cost 9 10 29 30
Regulatory adjustment - - (1) -
---- ---- ---- ----
Net periodic cost after regulatory adjustment $ 9 $ 10 $ 28 $ 30
==== ==== ==== ====
SERP: On April 1, 2006, we implemented a Defined Contribution Supplemental
Executive Retirement Plan (DC SERP) and froze further new participation in the
defined benefit SERP. The DC SERP provides promoted and newly hired participants
benefits ranging from 5 to 15 percent of total compensation. The DC SERP
requires a minimum of five years of participation before vesting. Our
contributions to the plan, if any, will be placed in a grantor trust. For the
nine months ended September 30, 2006, no contributions were made to the plan.
MCV: The MCV Partnership sponsors defined cost postretirement health care plans
that cover all full-time employees, except key management. Participants in the
postretirement health care plans become eligible for the benefits if they retire
on or after the attainment of age 65 or upon a qualified disability retirement,
or if they have 10 or more years of service and retire at age 55 or older. The
MCV Partnership's net periodic postretirement health care cost for the three
months and nine months ended September 30, 2006 and 2005 was less than $1
million.
SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other
Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and
132(R): In September 2006, the FASB issued SFAS No. 158. ThisPhase one of this
standard will
requirerequired us to recognize the funded status of our defined benefit
postretirement plans on our balance sheetsConsolidated Balance Sheets at December 31, 2006.
SFAS No. 158 will require us
to recognize changesPhase one was implemented in the funded status of our plans in the year in which the
changes occur. Upon implementationDecember 2006. Phase two of this standard we expect to record an
additional postretirement benefit liability of approximately $653 million and a
regulatory asset of $612 million. We expect a reduction of $26 million to other
comprehensive income, after tax. Regulatory asset treatment is consistent with
past MPSC and FERC guidance. This standard also requires
that we change our plan measurement date from November 30 to December 31,
effective December 31, 2008. We do not believe that implementation of phase two
of this provision of the standard wouldwill have a material effect on our consolidated financial
statements. We expect to adopt the measurement date provisions of SFAS No. 158
in 2008.
Costs: The following table recaps the costs, other changes in plan assets, and
benefit obligations incurred in our retirement benefits plans:
In Millions
-------------------------
Pension OPEB
----------- -----------
Three Months Ended March 31 2007 2006 2007 2006
- --------------------------- ---- ---- ---- ----
Service cost $ 12 $ 12 $ 6 $ 6
Interest expense 22 21 17 16
Expected return on plan assets (20) (22) (16) (14)
Amortization of:
Net loss 11 11 6 5
Prior service cost (credit) 2 2 (2) (3)
---- ---- ---- ----
Net periodic cost 27 24 11 10
Regulatory adjustment (4) (3) (2) --
---- ---- ---- ----
Net periodic cost after regulatory adjustment $ 23 $ 21 $ 9 $ 10
==== ==== ==== ====
8: INCOME TAXES
The principal components of deferred tax assets (liabilities) recognized on our
Consolidated Balance Sheets both before and after the adoption of FIN 48 are as
follows:
In Millions
-------------------
01/01/07 12/31/06
-------- --------
Property $(592) $(790)
Securitized costs (177) (177)
Employee benefits 38 38
Gas inventories (168) (168)
Tax loss and credit carryforwards 700 867
SFAS No. 109 regulatory liabilities, net 189 189
Foreign investments inflation indexing 86 86
Valuation allowances (216) (116)
Other, net 103 106
----- -----
Net deferred tax assets (liabilities) $ (37) $ 35
===== =====
As a result of the implementation of FIN 48, we have identified additional
uncertain tax benefits of $11 million as of January 1, 2007. Included in this
amount is an increase in our valuation allowance of $100 million, decreases to
tax reserves of $61 million and a decrease to deferred tax liabilities of $28
million. In addition, our equity method investment, Jorf Lasfar, in which we
held a 50 percent interest,
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CMS Energy Corporation
identified $26 million of uncertain tax benefits in its adoption of FIN 48 for
U.S. GAAP purposes. We have reflected our share of this amount, $13 million, as
a reduction to our beginning retained earnings balance and in our investment in
the subsidiary. Thus, our beginning retained earnings was reduced by $24 million
as a result of the adoption of FIN 48.
CMS Energy and its subsidiaries file a consolidated U.S. federal income tax
return as well as unitary and combined income tax returns in several states. CMS
Energy and its subsidiaries also file separate company income tax returns in
several states. The only significant state tax paid by CMS Energy is in
Michigan. However, since the Michigan Single Business Tax is not an income tax,
it is not part of the FIN 48 analysis. For the U.S. federal income tax return,
CMS Energy completed examinations by federal taxing authorities for its taxable
years prior to 2002. The federal income tax returns for the years 2002 through
2005 are open under the statute of limitations.
We have reflected a net interest liability of $3 million related to our
uncertain income tax positions on our Consolidated Balance Sheets as of January
1, 2007. We have not accrued any penalties with respect to uncertain tax
benefits. We recognize accrued interest and penalties, where applicable, related
to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against
certain U.S. and foreign deferred tax assets totaling $216 million and other
uncertain tax positions of $31 million, resulting in total unrecognized benefits
of $247 million. Of this amount, $217 million would result in a decrease in our
effective tax rate, if recognized. We released $81 million of our valuation
allowance in the first quarter of 2007, due to the anticipated sales of our
foreign investments, as reflected in our effective tax rate reconciliation.
Therefore, remaining uncertain tax benefits that would reduce our effective tax
rate beyond this quarter are $136 million. As we continue to market our foreign
investments, it is reasonably possible that additional valuation allowance
adjustments could be made. We are not in a position to estimate any additional
adjustment at this date, other than to state that we have no expectation of
reversing any of the $86 million valuation allowance attributable to the
inflation indexing of our Venezuelan investment. We are not expecting any other
material changes to our uncertain tax positions over the next 12 months.
The actual income tax benefit on continuing operations differs from the amount
computed by applying the statutory federal tax rate of 35 percent to loss before
income taxes as follows:
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In Millions
-------------
Quarters ended March 31 2007 2006
- ----------------------- ------ ----
Loss before income taxes $(101) $(60)
----- ----
Statutory federal income tax rate x 35% x 35%
----- ----
Expected income tax benefit (35) (21)
Increase (decrease) in taxes from:
Property differences 5 6
Income tax effect of foreign investments 2 (1)
Indefinite deferral projects for U.S. tax 43 (8)
Income tax credit amortization (1) (1)
Medicare Part D exempt income (2) (2)
Tax exempt income (1) (1)
Valuation allowance (81) --
----- ----
Recorded income benefit $ (70) $(28)
----- ----
Effective tax rate 69% 47%
===== ====
U.S. income taxes are not recorded on the undistributed earnings of foreign
subsidiaries that have been or are intended to be reinvested indefinitely. Upon
distribution, those earnings may be subject to both U.S. income taxes (adjusted
for foreign tax credits or deductions) and withholding taxes payable to various
foreign countries. During the first quarter of 2007, we announced we had signed
agreements or plans to sell substantially all of our foreign assets or
subsidiaries. These anticipated sales resulted in the recognition in 2007 of $63
million of U.S. income tax expense associated with the change in our
determination of our permanent reinvestment of these undistributed earnings,
with $43 million of this amount reflected in income from continuing operations
and $20 million in discontinued operations. With this recognition, U.S. tax has
now been provided on all foreign undistributed earnings.
9: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, "ACCOUNTINGACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS":OBLIGATIONS: This standard
requires companies to record the fair value of the cost to remove assets at the
end of their useful life, if there is a legal obligation to remove them. We have
legal obligations to remove some of our assets, including our nuclear plants, at
the end of their useful lives.
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CMS Energy Corporation
The fair value of ARO liabilities has been calculated using an expected present
value technique. This technique reflects assumptions such as costs, inflation,
and profit margin that third parties would consider to assume the settlement of
the obligation. Fair
value, to the extent possible, should include a market risk premium for
unforeseeable circumstances. No market risk premium was included in our ARO fair
value estimate since a reasonable estimate could not be made. If a five percent
market risk premium were assumed, our ARO liability would increase by $25
million.
If a reasonable estimate of fair value cannot be made in the period in which the
ARO is incurred, such as for assets with indeterminate lives, the liability is
to be recognized when a reasonable estimate of fair value can be made.
Generally, electric and gas transmission and distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets or associated obligations related to potential future
abandonment. Also, no liability has been recorded for assets that have
insignificant cumulative disposal costs, such as substation batteries. The
measurement of the ARO liabilities for Palisades and Big Rock are based oninclude use of
decommissioning studies that largely utilize third-party cost estimates.
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CMS Energy Corporation
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarified the term "conditional asset
retirement obligation" as used in SFAS No. 143. The term refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event. We determined that
abatement of asbestos included in our plant investments qualifies as a
conditional ARO, as defined by FASB Interpretation No.FIN 47.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
September 30, 2006March 31, 2007 In Millions
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long LivedLong-Lived Assets Fund
- --------------- ---------- ---------------------------------------------------------------------------- -----
Palisades-decommission
plant site 1972 Palisades nuclear plant $576$604
Big Rock-decommission
plant site 1962 Big Rock nuclear plant 62
JHCampbell intake/discharge
water line 1980 Plant intake/discharge water line ---
Closure of coal ash disposal
areas Various Generating plants coal ash areas ---
Closure of wells at gas
storage fields Various Gas storage fields ---
Indoor gas services equipment
relocations Various Gas meters located inside structures ---
Asbestos abatement 1973 Electric and gas utility plant ---
Natural gas-fired power plant 1997 Gas fueled power plant ---
Close gas treating plant and
gas wells Various Gas transmission and storage ---
CMS-79
CMS Energy Corporation
In Millions
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
ARO ARO
Liability Cash flow Liability
ARO Description 12/31/0506 Incurred Settled (a) Accretion Revisions 9/30/063/31/07
- --------------- --------- -------- ----------- --------- --------- --------------------
Palisades-decommission $375Palisades - decommission $401 $-- $-- $ 7 $ 2 $410
Big Rock - $ - $19 $ - $394
Big Rock-decommission 27 - (22)decommission 2 -- -- 1 -- 3 - 8
JHCampbell intake line - - - - - --- -- -- -- -- --
Coal ash disposal areas 54 - (2) 4 - 5657 -- (1) 1 -- 57
Wells at gas storage fields 1 - - - --- -- -- -- 1
Indoor gas services relocations 1 - - - --- -- -- -- 1
Asbestos abatement 35 -- (1) 1 -- 35
Natural gas-fired power plant 1 - - - - 1-- (1) -- -- --
Close gas treating plant and
gas wells 1 - - 1 - 2 Asbestos abatement 36 - (2)-- (1) -- -- 1 - 35
---- --- ------- --- --- ----
Total $496$500(a) $-- $(4) $10 $ - $(26) $28 $ - $4982 $508
==== === ======= === === ====
(a) $2 million in ARO liabilities moved to Noncurrent liabilities held for sale
on our Consolidated Balance Sheets at December 31, 2006. These cashAROs were
subsequently settled as a result of the sale of our businesses in Argentina
and our northern Michigan non-utility natural gas assets to Lucid Energy.
Cash payments of $2 million are included in the Other current and
non-current liabilities line in Net cash provided by operating activities
onin our Consolidated Statements of Cash Flows.
Cash paymentsIn April 2007, we sold Palisades to Entergy and paid Entergy to assume ownership
and responsibility for the nine monthsBig Rock ISFSI. Our AROs related to Palisades and Big
Rock ISFSI ended September 30, 2005 were $37 million.with the sale and the related ARO liabilities will be removed
from our Consolidated Balance Sheets. We also expect to
CMS-69
CMS Energy Corporation
remove the Big Rock ARO related to the plant in the second quarter of 2007 due
to the completion of decommissioning.
In October 2004, the MPSC initiated a generic proceeding to review SFAS No. 143,
FERC Order No. 631, Accounting, Financial Reporting, and Rate Filing
Requirements for Asset Retirement Obligations, and related accounting and
ratemaking issues for MPSC-jurisdictional electric and gas utilities. In December 2005, the ALJ issued a Proposal for Decision recommending that the MPSC
dismiss the proceeding. In March 2006, the MPSC remanded the case to the ALJ for
findings and recommendations. In August
2006, the ALJ issued a second Proposal for Decision that included recommendations that
the MPSC:
- - adopt SFAS No. 143 and FERC Order No. 631 for accounting purposes but not
for ratemaking purposes,
- - consider adopting standardized retirement units for certain accounts,
- - consider revising the method of determining cost of removal, and
- - withhold approving blanket regulatory asset and regulatory liability
accounting treatment related to ARO, stating that modifications to the
MPSC's Uniform System of Accounts should precede any such accounting
approval.
We consider the proceeding a clarification of accounting and reporting issues
that relate to all Michigan utilities. We cannot predict the outcome of the
proceeding.
9: EXECUTIVE INCENTIVE COMPENSATION
We provide a Performance Incentive Stock Plan (the Plan) to key employees and
non-employee directors based on their contributions to the successful management
of the company. The Plan has a five-year term, expiring in May 2009.
All grants awarded under the Plan for the nine months ended September 30, 2006
and in 2005 were in the form of restricted stock. Restricted stock awards are
outstanding shares to which the recipient has full voting and dividend rights
and vest 100 percent after three years of continued employment. Restricted stock
awards granted to officers in 2006, 2005, and 2004 are also subject to the
achievement
CMS-80
CMS Energy Corporation
of specified levels of total shareholder return, including a comparison to a
peer group of companies. All restricted stock awards are subject to forfeiture
if employment terminates before vesting. However, if certain minimum service
requirements are met, restricted shares may continue to vest upon retirement or
disability and vest fully if control of CMS Energy changes, as defined by the
Plan. In April 2006, the Plan was amended to allow awards not subject to the
achievement of total shareholder returns to vest fully upon retirement, subject
to the participant not accepting employment with a direct competitor. This
modification did not have a material impact on the consolidated financial
statements.
The Plan also allows for the following types of awards:
- stock options,
- stock appreciation rights,
- phantom shares, and
- performance units.
For the nine months ended September 30, 2006 and in 2005, we did not grant any
of these types of awards.
Select participants may elect to receive all or a portion of their incentive
payments under the Officer's Incentive Compensation Plan in the form of cash,
shares of restricted common stock, shares of restricted stock units, or any
combination of these. These participants may also receive awards of additional
restricted common stock or restricted stock units, provided the total value of
these additional grants does not exceed $2.5 million for any fiscal year.
Shares awarded or subject to stock options, phantom shares, and performance
units may not exceed 6 million shares from June 2004 through May 2009, nor may
such awards to any participant exceed 250,000 shares in any fiscal year. We may
issue awards of up to 4,378,300 shares of common stock under the Plan at
September 30, 2006. Shares for which payment or exercise is in cash, as well as
shares or stock options that are forfeited, may be awarded or granted again
under the Plan.
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: SFAS No. 123(R) was
effective for us on January 1, 2006. SFAS No. 123(R) requires companies to use
the fair value of employee stock options and similar awards at the grant date to
value the awards. Companies must expense this value over the required service
period of the awards. As a result, future compensation costs for share-based
awards with accelerated service provisions upon retirement will need to be fully
expensed by the period in which the employee becomes eligible to retire. At
January 1, 2006, unrecognized compensation cost for such share-based awards held
by retirement-eligible employees was not material.
We elected to adopt the modified prospective method of recognition provisions of
this Statement instead of retrospective restatement. The modified prospective
method applies the recognition provisions to all awards granted or modified
after the adoption date of this Statement. We adopted the fair value method of
accounting for share-based awards effective December 2002. Therefore, SFAS No.
123(R) did not have a significant impact on our results of operations when it
became effective.
The SEC issued SAB No. 107 to express the views of the staff regarding the
interaction between SFAS No. 123(R) and certain SEC rules and regulations. Also,
the SEC issued SAB No. 107 to provide the staff's view regarding the valuation
of share-based payments, including assumptions such as expected volatility and
expected terms. We applied the additional guidance provided by SAB No. 107 upon
implementation of SFAS No. 123(R) with no impact on our consolidated results of
operations.
CMS-81
CMS Energy Corporation
The following table summarizes restricted stock activity under the Plan:
Weighted-Average Grant
Restricted Stock Number of Shares Date Fair Value
- ---------------- ---------------- ----------------------
Nonvested at December 31, 2005 1,682,056 $10.64
Granted 587,830 $13.84
Vested (300,136) $ 7.64
Forfeited (54,250) $10.76
--------- ------
Nonvested at September 30, 2006 1,915,500 $12.09
========= ======
The total fair value of shares vested was $4 million for the nine months ended
September 30, 2006 and September 30, 2005.
We calculate the fair value of restricted shares granted based on the price of
our common stock on the grant date and expense the fair value over the required
service period. Total compensation cost recognized in income related to
restricted stock was $7 million for the nine months ended September 30, 2006 and
$3 million for the nine months ended September 30, 2005. The total related
income tax benefit recognized in income was $2 million for the nine months ended
September 30, 2006 and $1 million for the nine months ended September 30, 2005.
At September 30, 2006, there was $13 million of total unrecognized compensation
cost related to restricted stock. We expect to recognize this cost over a
weighted-average period of 1.7 years.
The following table summarizes stock option activity under the Plan:
Weighted-
Options Weighted- Average Aggregate
Outstanding, Average Remaining Intrinsic
Fully Vested, Exercise Contractual Value
Stock Options and Exercisable Price Term (In Millions)
- --------------------------------- --------------- --------- ----------- -------------
Outstanding at December 31, 2005 3,541,338 $21.21 5.4 years $(24)
Granted - -
Exercised (53,000) $ 7.08
Cancelled or Expired (490,568) $30.53
--------- ------ --------- ----
Outstanding at September 30, 2006 2,997,770 $19.93 5.0 years $(16)
========= ====== ========= ====
Stock options give the holder the right to purchase common stock at a price
equal to the fair value of our common stock on the grant date. Stock options are
exercisable upon grant, and expire up to 10 years and one month from the grant
date. We issue new shares when participants exercise stock options. The total
intrinsic value of stock options exercised was less than $1 million for the nine
months ended September 30, 2006 and $1 million for the nine months ended
September 30, 2005. Cash received from exercise of these stock options was less
than $1 million for the nine months ended September 30, 2006 and $1 million for
the nine months ended September 30, 2005. Since we have utilized tax loss
carryforwards, we were not able to realize the excess tax benefits upon exercise
of stock options. Therefore, we did not recognize the related excess tax
benefits in equity.
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CMS Energy Corporation
10: EQUITY METHOD INVESTMENTS
Where ownership is more than 20 percent but less than a majority, we account for
certain investments in other companies, partnerships, and joint ventures by the
equity method of accounting, in accordance with APB Opinion No. 18. Earnings
from equity method investments waswere $19 million for the three months ended September 30, 2006March
31, 2007 and $40$36 million for the three months ended September 30,
2005. EarningsMarch 31, 2006. The amount
of consolidated retained earnings that represent undistributed earnings from
these equity method investments was $63were $6 million for the nine
months ended September 30, 2006as of March 31, 2007 and $92$15
million for the nine months ended
September 30, 2005.as of March 31, 2006. The most significant of these investments iswas our
50 percent interest in Jorf Lasfar.Lasfar, which was sold in May 2007.
Summarized financial information for Jorf Lasfar is as follows:
Income Statement Data
In Millions
--------------------------------------------------------
JORF LASFAR Three Months Ended
Nine Months Ended
- ----------- ------------------
-----------------
September 30March 31 2007 2006
2005 2006 2005
- ------------ ---- ------------ ---- ----
Operating revenue $121 $123 $355 $382$124 $118
Operating expenses 77 82 235 255
---- ----expense 83 78
---- ----
Operating income 44 41 120 12740
Other expense, net 16 16 42 44
---- ----36 15
---- ----
Net income $ 285 $ 25 $ 78 $ 83
==== ====
==== ====
CMS-83CMS-70
CMS Energy Corporation
11: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by theirthe
nature of products and services.services each provides. We evaluate performance based
upon the net income of each segment. We operate principally in three reportable
segments: electric utility, gas utility, and enterprises.
The "Other" segment includes corporate interest and other expenses and discontinued
operations.benefits. The
following tables show our financial information by reportable segment:
In Millions
--------------------------------------------------------
Three Months Ended
Nine Months Ended
------------------
-----------------
September 30March 31 2007 2006
2005 2006 2005
- ------------ ------ ------ ------ -------------- ---- ----
Operating Revenue
Electric utility $ 976844 $ 793 $2,496 $2,065729
Gas utility 201 219 1,576 1,5661,211 1,041
Enterprises 285 295 818 751
------ ------182 167
------ ------
Total Operating Revenue $1,462 $1,307 $4,890 $4,382
====== ====== ====== ======$2,237 $1,937
------ ------
Net Income (Loss) Available to Common Stockholders
Electric utility $ 9351 $ 62 $ 159 $ 14129
Gas utility (20) (16) 14 3957 37
Enterprises (132) (260) (177) (126)(187) (58)
Discontinued operations (180) 8
Other (44) (51) (54) (142)
------ ------44 (43)
------ ------
Total Net Loss Available to Common Stockholders $ (103)(215) $ (265) $ (58) $ (88)
====== ======(27)
====== ======
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Assets
Electric utility (a) $ 7,8938,557 $ 7,7438,516
Gas utility (a) 3,835 3,6003,410 3,950
Enterprises 3,097 4,130(b) 2,313 2,339
Other 153 547997 566
------- -------
Total Assets $14,978 $16,020$15,277 $15,371
======= =======
(a) Amounts include a portion of Consumers' other common assets attributable to
both the electric and gas utility businesses.
CMS-84(b) Includes $273 million of assets classified as held for sale at March 31,
2007 and $469 million at December 31, 2006.
CMS-71
Consumers Energy Company
CONSUMERS ENERGY COMPANY
MANAGEMENT'S DISCUSSION AND ANALYSIS
In this MD&A, Consumers Energy, which includes Consumers Energy Company and all
of its subsidiaries, is at times referred to in the first person as "we," "our"
or "us." This MD&A has been prepared in accordance with the instructions to Form
10-Q and Item 303 of Regulation S-K. This MD&A should be read in conjunction
with the MD&A contained in Consumers Energy's Form 10-K for the year ended
December 31, 2005.2006.
EXECUTIVE OVERVIEW
Consumers, a subsidiary of CMS Energy, a holding company, is a combination
electric and gas utility company serving Michigan's Lower Peninsula. Our
customer base includes a mix of residential, commercial, and diversified
industrial customers.
We manage our business by the nature of services each provides and operate
principally in two business segments: electric utility and gas utility. Our
electric utility operations include the generation, purchase, distribution, and
sale of electricity. Our gas utility operations include the purchase,
transportation, storage, distribution, and sale of natural gas.
We earn our revenue and generate cash from operations by providing electric and
natural gas utility services, electric power generation, gas distribution,
transmission, and storage, and other energy related services. Our businesses are
affected primarily by:
- weather, especially during the normal heating and cooling seasons,
- economic conditions,
- regulation and regulatory issues,
- energy commodity prices,
- interest rates, and
- our debt credit rating.
During the past several years, our business strategy has involved improving our
consolidated balance sheet and maintaining focus on our core strength: utility
operations and service.
We are focused on growing the equity base of our company and have been
refinancing our debt to reduce interest rate costs. In 2006,April 2007, we received $200
million of cash contributions from CMS Energy and we extinguished, through a
legal defeasance, $129 million of 9 percent related party notes.
In July 2006, we reached an agreement to sell thesold Palisades nuclear plant to Entergy for $380 million. The final purchase
price was subject to various closing adjustments resulting in us receiving $361
million. We also signedpaid Entergy $30 million to assume ownership and responsibility
for the Big Rock Independent Spent Fuel Storage Installation (ISFSI). We entered
into a 15-year power purchase agreement with Entergy for 100 percent of the
plant's current electric output. We are targeting to close
theThe sale by May 1, 2007. When completed, the sale will resultresulted in an immediate improvement
in our cash flow, a reduction in our nuclear operating and decommissioning risk,
and an improvement in our financial flexibility to support other utility
investments. We expectThe MPSC order approving the transaction requires that a significant portion$255 million
be credited to our retail customers through refunds applied over the remainder
of the proceeds
will benefit our customers. We plan to use the cash that we retain from the sale
to reduce utility debt.
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Consumers Energy Company
Working2007 and 2008.
Natural gas prices are volatile and have an impact on working capital and cash
flow continue to be a challenge for us, as natural gas
prices continue to be volatile.flow. Although our natural gas purchasescosts are recoverable from our utility customers,
higher pricedhigher-priced natural gas stored as inventory requires additional liquidity due
to the lag in cost recovery.
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Consumers Energy Company
In addition to causing working capital issues for us, historically high natural
gas prices caused the MCV Partnership to reevaluate the economics of operating
the MCV Facility and to record an impairment charge in 2005. If gas prices
increase from their current levels, it could result in a further impairment of
our interest in the MCV Partnership.
Due to the impairment of the MCV Facility, and operating losses from
mark-to-market adjustments on derivative instruments, the equity held by a
Consumers' subsidiary and the other minority interest owners in the MCV
Partnership has decreased significantly and is now negative. As the MCV
Partnership recognizes future, losses, we will assume an additional seven percent
of the MCV Partnership's negative equity, which is a portion of the limited
partners' negative equity, in addition to our proportionate share.
In July 2006, we reached an agreement to sell our interests in the MCV
Partnership and the FMLP. The sale is subject to various regulatory approvals
including the MPSC. If the sale closes by the end of 2006, as expected, it will
have a $56 million positive impact on our 2006 cash flow. The sale will reduce
our exposure to sustained high natural gas prices. We will use the proceeds to
reduce utility debt. If the sale is not completed, the viability of the MCV
Facility is still in question.
Going forward, our strategy will continue to focus on:
- managing cash flow issues,
- growing earnings, and
- investing in our utility system to enable us to meet our customer
commitments, comply with increasing environmental performance
standards, and maintain adequate supply and capacity.capacity,
- growing earnings while controlling operating costs, and
- managing cash flow issues.
As we execute our strategy, we will need to overcome a sluggish Michigan economy
that has been hampered by negative developments in Michigan's automotive
industry and limited growth in the non-automotive sectors of the state's
economy. TheseThe return of ROA customer load has offset some of these negative
effects will be offset somewhat by the reduction we are
experiencing in ROA load in our service territory.effects. At September 30, 2006,March 31, 2007, alternative electric suppliers were providing 308283 MW
of generation service to ROA customers. This is four3 percent of our total
distribution load and represents a decrease of 6019 percent of ROA load compared
to the end of September
2005. It is, however, difficult to predict future ROA customer trends.March 31, 2006.
FORWARD-LOOKING STATEMENTS AND INFORMATION
This Form 10-Q and other written and oral statements that we make contain
forward-looking statements as defined by the Private Securities Litigation
Reform Act of 1995. Our intention with the use of words such as "may," "could,"
"anticipates," "believes," "estimates," "expects," "intends," "plans," and other
similar words is to identify forward-looking statements that involve risk and
uncertainty. We designed this discussion of potential risks and uncertainties to
highlight important factors that may impact our business and financial outlook.
We have no obligation to update or revise forward-looking statements regardless
of whether new information, future events, or any other factors affect the
information
CE-2
Consumers Energy Company contained in the statements. These forward-looking statements are
subject to various factors that could cause our actual results to differ
materially from the results anticipated in these statements. Such factors
include our inability to predict and (or) control:
- the price of CMS Energy Common Stock, capital and financial market
conditions, and the effect of such market conditions on the Pension
Plan, interest rates, and access to the capital markets, including
availability of financing to Consumers, CMS Energy, or any of their
affiliates, and the energy industry,
- market perception of the energy industry, Consumers, CMS Energy, or
any of their affiliates,
- credit ratings of Consumers, CMS Energy, or any of their affiliates,
- factors affecting utility and diversified energy operations, such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs, environmental
incidents, or electric transmission or gas pipeline system
constraints,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including those related to
environmental laws and regulations, and potential environmental
remediation costs associated with such decisions,
- potentially adverse regulatory treatment and (or) regulatory lag
concerning a number of significant questions presently before the MPSC
including:
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Consumers Energy Company
- recovery of Clean Air Act capital and operating costs and other
environmental and safety-related expenditures,
- power supply and natural gas supply costs when fuel prices are
increasing and (or) fluctuating,
- timely recognition in rates of additional equity investments in
Consumers,
- adequate and timely recovery of additional electric and gas rate-based
investments,
- adequate and timely recovery of higher MISO energy and transmission
costs,
- recovery of Stranded Costs incurred due to customers choosing
alternative energy suppliers,
- recovery of Palisades plant sale-related costs, and
- sales of the Palisades plant and our interest in the MCV
Partnership,
- the impact of adverse naturalpossible regulation or legislation regarding carbon dioxide
and other greenhouse gas prices on the MCV Partnership and
the FMLP investments, regulatory decisions that limit recovery of
capacity and fixed energy payments, and our ability to complete the
sale of our interests in the MCV Partnership and the FMLP,emissions,
- the negative impact on the MCV Partnership's financial performance, if
we are successful in exercising the regulatory out provision of the
MCV PPA, and if the sale of our interests in the MCV Partnership and
the FMLP is not completed,
CE-3
Consumers Energy Company - the effects on our ability to purchase capacity to serve our customers and
fully recover the cost of these purchases, if we exercise our regulatory
out rights and the owners of the MCV Partnership exercises itsFacility exercise their right to
terminate the MCV PPA,
- - federal regulation of electric sales and transmission of electricity,
including periodic re-examination by federal regulators of our market-based
sales authorizations in wholesale power markets without price restrictions,
- - energy markets, including availability of capacity and the timing and
extent of changes in commodity prices for oil, coal, natural gas, natural
gas liquids, electricity and certain related products due to lower or
higher demand, shortages, transportation costs problems, or other
developments,
- - our ability to collect accounts receivable from our customers,
- - earnings volatility as a result of the GAAP requirement that we utilize
mark-to-market accounting on certain energy commodity contracts and
interest rate swaps, which may have, in any given period, a significant
positive or negative effect on earnings, which could change dramatically or
be eliminated in subsequent periods,
and could add to earnings volatility,- - the effect on our electric utility of the direct and indirect impacts of
the continued economic downturn experienced by our automotive and
automotive parts manufacturing customers,
- - potential disruption or interruption of facilities or operations due to
accidents or terrorism, and the ability to obtain or maintain insurance
coverage for such events,
- nuclear power plant performance, operation, decommissioning, policies,
procedures, incidents, and regulation, including- the availabilityoutcome of pending litigation regarding the DOE liability for spent
nuclear fuel storage during former ownership and operation of nuclear power
plants,
- - technological developments in energy production, delivery, and usage,
- - achievement of capital expenditure and operating expense goals,
- - changes in financial or regulatory accounting principles or policies,
- - changes in tax laws or new IRS interpretations of existing or past tax
laws,
- - outcome, cost, and other effects of legal and administrative proceedings,
settlements,
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Consumers Energy Company
investigations and claims,
- disruptions in the normal commercial insurance and surety bond markets
that may increase costs or reduce traditional insurance coverage,
particularly terrorism and sabotage insurance and performance bonds,
- other business or investment considerations that may be disclosed from
time to time in Consumers' or CMS Energy's SEC filings, or in other
publicly issued written documents, and
- other uncertainties that are difficult to predict, many of which are
beyond our control.
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Consumers Energy Company
For additional information regarding these and other uncertainties, see the
"Outlook" section included in this MD&A, Note 2, Contingencies, and Part II,
Item 1A. Risk Factors.
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Consumers Energy Company
RESULTS OF OPERATIONS
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER
In Millions
-----------------------------------------
Three months ended September 30March 31 2007 2006 2005 Change
- ---------------------------------------------------------- ---- --------- ------
Electric $ 9351 $ 6229 $ 3122
Gas (20) (16) (4)57 37 20
Other (Includes the MCV Partnership interest) 26 (322) 348and FMLP interests) 4 (56) 60
---- --------- ----
Net income (loss) available to common stockholder $112 $ 99 $(276) $37510 $102
==== ========= ====
For the three months ended September 30, 2006,March 31, 2007, net income available to our common
stockholder was $99$112 million, compared to a net loss of $276$10 million for the three months ended
September 30, 2005.March 31, 2006. The increase is primarily due toreflects the absence,sale of our ownership
interest in 2006, of a 2005 impairment charge to property, plant,the MCV Partnership in late 2006. Accordingly, in 2007 we are no
longer experiencing mark-to-market losses on certain long-term gas contracts and
equipmentassociated financial hedges at the MCV Partnership to reflect the excess of the carrying value of these
assets over their estimated fair value.Partnership. The increase also reflects
higher net income from our electric utility revenues primarilyand gas utilities due to an electrichigher,
weather-driven sales caused by colder weather compared to 2006, and a gas rate
increase authorized in December 2005.November 2006. Partially offsetting these increasesgains are
higher operating and maintenance costsexpenses at our electricgas utility.
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Consumers Energy Company
Specific changes to net income (loss) available to our common stockholder for the three months ended September 30,2007
versus 2006 versus 2005 are:
In Millions
-----------
- - increasedecrease in earningslosses from our ownership interest in the MCV
Partnership primarily due to the absence, in 2007, of
mark-to-market losses on certain long-term gas contracts and
financial hedges, $ 57
- - increase in gas delivery revenue primarily due to the MPSC's
November 2006 of a 2005
impairment charge to property, plant, and equipment at the MCV
Partnership to reflect the excess of the carrying value of these
assets over their estimated fair value, $385gas rate order, 21
- - increase in electric delivery revenue primarily due to a December
2005 electric rate order, 39colder
weather, and 15
- - increase in earnings due to the expiration of rate caps that, in
2005, would not allow us to recover fully our power supply costs
from our residential customers, 30
- - other net increases, 1
- - decrease in earnings from other activities at the MCV Partnership as
mark-to-market losses on long-term gas contracts and associated
hedges, which partially reduced gains recorded in 2005, more than
offset the recognition of a property tax refund, (39)
- - increase in operating expenses primarily due to higher depreciation
and amortization expense, higher electric maintenance
expense, and higher customer service expense, (26)
- - decrease in gas delivery revenue primarily due to the impact of the
annual unbilled gas volume analysis, and (9)
- - decrease in return on electric utility capital expenditures in
excess of depreciation base as allowed by the Customer Choice
Act. (6)colder
weather 9
----
Total Change $375$102
====
In Millions
--------------------
Nine months ended September 30 2006 2005 Change
- ------------------------------ ---- ---- ------
Electric $159 $141 $ 18
Gas 14 39 (25)
Other (Includes the MCV Partnership interest) (29) (267) 238
---- ---- ----
Net income (loss) available to common stockholder $144 $(87) $231
==== ==== ====
For the nine months ended September 30, 2006, net income available to our common
stockholder was $144 million, compared to a net loss of $87 million for the nine
months ended September 30, 2005. The increase is primarily due to the absence,
in 2006, of a 2005 impairment charge to property, plant, and equipment at the
MCV Partnership to reflect the excess of the carrying value of these assets over
their estimated fair value. The increase also reflects higher electric utility
revenues primarily due to an electric rate increase authorized in December 2005.
Partially offsetting these increases are higher operating and maintenance costs
at our electric utility, and the impact of reduced gas prices on the market
value of certain long-term gas contracts and financial hedges at the MCV
Partnership. In order to reflect the current market value of theses gas
contracts, mark-to-market losses were recorded in 2006 as opposed to gains
recorded on these contracts in 2005.
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Consumers Energy Company
Specific changes to net income (loss) available to our common stockholder for
the nine months ended September 30, 2006 versus 2005 are:
In Millions
-----------
- - increase in earnings due to the absence, in 2006, of a 2005
impairment charge to property, plant, and equipment at the MCV
Partnership to reflect the excess of the carrying value of these
assets over their estimated fair value, $ 385
- - increase in electric delivery revenue primarily due to a December
2005 electric rate order, 116
- - increase in earnings due to the expiration of rate caps that, in
2005, would not allow us to recover fully our power supply costs
from our residential customers, 38
- - decrease in income taxes primarily due to an IRS audit settlement, 14
- - increase in gas wholesale and retail services and other gas revenue
associated with pipeline capacity optimization, 13
- - decrease in earnings from other activities at the MCV Partnership
as mark-to-market losses on long-term gas contracts and
associated hedges, which partially reduced gains recorded in
2005, more than offset the recognition of a property tax refund, (161)
- - increase in operating expenses primarily due to higher depreciation
and amortization expense, higher electric maintenance
expense, and higher customer service expense, (82)
- - decrease in gas delivery revenue primarily due to warmer weather
and increased conservation efforts, (32)
- - increase in operating expenses primarily due to costs related to a
planned refueling outage at our Palisades nuclear plant, (32)
- - decrease in return on electric utility capital expenditures in
excess of depreciation base as allowed by the Customer Choice
Act, and (20)
- - other net decreases. (8)
-----
Total Change $ 231
=====
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Consumers Energy Company
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30March 31 2007 2006 2005 Change
- -------------------- ---- ---- ------
ThreeNet Income for the three months ended $ 93 $ 62 $31
Nine months ended $159 $141 $18
==== ====$51 $29 $22
=== === ===
Three Months Ended Nine Months Ended
September 30, 2006 vs. September 30, 2006
Reasons for the change:
2005 vs. 2005
- ----------------------- ---------------------- ------------------
Electric deliveries $ 59 $ 178
Power supply costs and related revenue 46 58$24
Other operating expenses, other income
and non-commodity revenue (44) (174)
Regulatory return on capital expenditures (9) (30)9
General taxes (2) (3)(4)
Interest charges (1) (3)1
Income taxes (18) (8)
---- --------
Total change $ 31 $ 18
==== =====$22
===
ELECTRIC DELIVERIES: ForIn the three months ended September 30, 2006, electric
deliveries, excluding intersystem sales, decreased 0.3 billion kWh or 2.3
percent versus 2005. For the nine months ended September 30, 2006, electric
deliveries, excluding intersystem sales, decreased 0.6 billion kWh or 2.0
percent versus 2005. The decrease in electric deliveries for both periods is
primarily due to weather. Despite lower electric deliveries, electric delivery
revenue increased primarily due to an electric rate order, increased surcharge
revenue, and the return to full-service ratesfirst quarter of customers previously using
alternative energy suppliers (ROA customer deliveries). These three issues, and
their relative impact on electric delivery revenue, are discussed in the
following paragraphs.
Electric Rate Order: In December 2005, the MPSC issued an order authorizing an
annual rate increase of $86 million for service rendered on and after January
11, 2006. As a result of this order,2007, electric delivery revenues
increased by $24 million forover 2006 as deliveries to end-use customers were 9.5
billion kWh, an increase of 0.2 billion kWh or 2 percent versus 2006. The
increase in electric deliveries was primarily due to colder weather in the three months ended September 30,first
quarter of 2007 versus 2006 and $67 million forresulted in an increase in electric delivery
revenue of $17 million. Average temperatures in the nine months ended September 30, 2006 versusfirst quarter of 2007 were
3.8 degrees colder than the same periods in 2005.
Surcharge Revenue: Effective January 1,period last year.
In the first quarter of 2006, we started collecting a surcharge that the MPSC
authorized under Section 10d(4) of the Customer Choice Act. ThisDue to timing
considerations, this surcharge increased electric delivery revenue by $15$5 million
forin the three
months ended September 30, 2006 and $38 million for the nine months ended
September 30, 2006first quarter of 2007 versus the same periods in 2005. In addition, on January 1,
2006, we began recovering customer choice transition costs from our residential
customers, thereby increasing electric delivery revenue by another $4 million
for the three months ended September 30, 2006 and $9 million for the nine months
ended September 30, 2006 versus the same periods in 2005.
CE-8
Consumers Energy Company
ROA Customer Deliveries:2006.
The Customer Choice Act allows all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. At September 30, 2006,March
31, 2007, alternative electric suppliers were providing 308283 MW of generation
service to ROA customers. This amount represents a decrease of 6019 percent of ROA load
compared to the end of September 2005.March 31, 2006. The return of former ROA customers to full-service
rates increased electric revenues
$12delivery revenue $2 million forin the three months ended September 30, 2006 and $40 million for
the nine months ended September 30, 2006first quarter of
2007 versus the same periods in 2005.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2005, power supply costs exceeded
power supply revenue due to rate caps for our residential customers. Rate caps
for our residential customers expired on December 31, 2005. In 2006, the absence
of rate caps allows us to record power supply revenue to offset fully our power
supply costs. Our ability to recover these power supply costs resulted in a $46
million increase to electric revenue for the three months ended September 30,
2006 and $58 million for the nine months ended September 30, 2006 versus the
same periods in 2005.2006.
OTHER OPERATING EXPENSES, OTHER INCOME AND NON-COMMODITY REVENUE: ForIn the three
months ended September 30, 2006,first
quarter of 2007, other operating expenses decreased $1 million, other income
increased $48$6 million, and non-commodity revenue increased $4$2 million versus
2005. For the nine months
ended September 30, 2006, other operating expenses increased $183 million, other
income increased $8 million, and non-commodity revenue increased $1 million
versus 2005.2006.
The increasedecrease in other operating expenses reflects higher operating and
maintenance, customer service, depreciation and amortization, and pension and
benefit expenses.
For the three months ended September 30, 2006,was primarily due to lower operating
and maintenance expense, increasedincluding reductions to certain workers' compensation
and injuries and damages expense. These decreases were offset partially by
higher depreciation, amortization, and overhead expense. Operating and
maintenance expense decreased primarily due to higher storm restoration costs. For the nine months
ended September 30,absence, in 2007, of costs
incurred in 2006 operating and maintenance expense increased primarily
due to costs related to a planned refueling outage at our Palisades nuclear
plant, higher tree trimming,and lower overhead line maintenance and storm restoration costs.
Higher customer service expense reflects contributions, beginning in January
2006 pursuant to a December 2005 MPSC order, to a fund that provides energy
assistance to low-income customers.
Depreciation and amortization expense increased due to higher plant in service
and greater amortization of certain regulatory assets. Pension and benefitOverhead expense
reflects changes in actuarial
assumptions in 2005, and the latest collective bargaining agreement between the
Utility Workers Union of America and Consumers.
For the three months ended September 30, 2006, the increase in non-commodity
revenue wasincreased primarily due to an increase in capital-related services providedcosts related to METC in 2006 versus 2005.
For the nine months ended September 30, 2006, theour voluntary separation program and
costs associated with our utility reorganization.
The increase in other income was primarily due to higher interest income andassociated with
our Section 10d(4) Regulatory Asset. This increase reflects the absence, in
2006,2007, of expenses
recordedthe impact of the MPSC's final order in
2005 associated with the early retirement of debt.CE-6
Consumers Energy Company
this case. The increase in non-commodity revenue was primarily due to an increase in miscellaneous service
revenues offset partially by a decrease in capital-related services provided to
METC in 2006 versus 2005.
REGULATORY RETURN ON CAPITAL EXPENDITURES: The $9 million decrease forhigher
revenue from customer late payment fees.
GENERAL TAXES: In the three
months ended September 30, 2006 and $30 million decrease for the nine months
ended September 30, 2006 versus the same periods in 2005, were bothfirst quarter of 2007, general tax expense increased
primarily due to lower
income associated with recording a return on capital
CE-9
Consumers Energy Company
expenditures in excess of our depreciation base as allowed by the Customer
Choice Act. In December 2005, the MPSC issued an order that authorized us to
recover $333 million of Section 10d(4) costs. The order authorized recovery of a
lower level of costs versus the level used to record 2005 income.
GENERAL TAXES: For the three months ended September 30, 2006, the increase in
general taxes reflects higher MSBT expense and higher property tax expense. For
the nine months ended September 30, 2006, the increase in general taxes reflects
higherand MSBT expense offset partially by lower property tax expense.versus 2006.
INTEREST CHARGES: ForIn the three months ended September 30, 2006,first quarter of 2007, interest charges increaseddecreased due
to higher associated company interest expense, offset
partially by a 3 basis point reduction in the average rate of interest on our
debt and lower average debt levels and lower interest expense associated with
potential customer refunds versus the same period in 2005. For the nine
months ended September 30, 2006, interest charges increased primarily due to an
IRS income tax audit settlement. The settlement recognized that Consumers'
taxable income for prior years was higher than originally filed, resulting in
interest on the tax liability for these prior years.2006.
INCOME TAXES: ForIn the three months ended September 30, 2006,first quarter of 2007, income taxes increased versus 2005 primarily due to higher earnings by the electric utility.
For the nine months ended September 30, 2006, income taxes increased versus 2005 primarily due
to higher earnings by the electric utility offset partially byversus 2006. Partially offsetting
this increase is the resolutionabsence, in 2007, of an IRS incomeadjustments to certain deferred tax
audit, which resulted in a $4 million income
tax benefit caused by the restoration and utilization of income tax credits.balances. For additional details, see Note 7, Income Taxes.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30March 31 2007 2006 2005 Change
- -------------------- ---- ---- ------
Three months ended $(20) $(16) $ (4)
NineNet Income for the three months ended $ 1457 $37 $ 39 $(25)20
==== === ==== ====
Three Months Ended Nine Months Ended
September 30, 2006 September 30, 2006
Reasons for the change:
vs.2005 vs.2005
- ----------------------- ------------------ ------------------
Gas deliveries $(13) $(49)$ 14
Gas wholesale and retail services, otherrate increase 33
Other gas revenuesrevenue and other income 9 204
Operation and maintenance 3 1
General(13)
Depreciation and general taxes and depreciation - (5)
Interest charges (3) (6)(2)
Income taxes - 14
----(11)
----
Total change $ (4) $(25)
==== ====20
----
GAS DELIVERIES: ForIn the three months ended September 30,first quarter of 2007, gas delivery revenues increased by
$14 million over 2006 gasas deliveries, including miscellaneous transportation to
end-use customers, decreased 1were 137 bcf, an increase of 14 bcf or 5.4 percent. This decrease reflects the impact of the annual unbilled gas volume
analysis on 2006 results. In 2006, this analysis supported a decrease in
CE-10
Consumers Energy Company
gas volumes. In 2005, this annual analysis led to a slight11 percent versus
2006. The increase in gas
volumes.
For the nine months ended September 30, 2006, gas deliveries, including
miscellaneous transportation to end-use customers, decreased 29 bcf or 13.3
percent. The decrease in gas deliveries was primarily due to warmercolder weather in the
first quarter of 2007 versus 2006. Average temperatures in the first quarter of
2007 were 3.8 degrees colder than the same period last year.
GAS RATE INCREASE: In November 2006, the MPSC issued an order authorizing an
annual rate increase of $81 million. As a result of this order, gas revenues
increased $33 million for the first quarter of 2007 versus 2005 and increased customer conservation efforts in response to
higher gas prices.
GAS WHOLESALE AND RETAIL SERVICES,2006.
OTHER GAS REVENUESREVENUE AND OTHER INCOME: ForIn the three and nine months ended September 30, 2006, the increase primarily reflects
higher pipeline revenuesfirst quarter of 2007, other gas
revenue and other income increased $4 million versus 2006 primarily due to
higher pipeline capacity optimization in 2006 versus
2005.revenue.
OPERATION AND MAINTENANCE: ForIn the three and nine months ended September 30,
2006,first quarter of 2007, operation and
maintenance expenses decreasedincreased versus 20052006 primarily due to lower operating expenses offset partially by higher pension and benefit and customer
service expenses. Pension and benefit expense reflects changes in
actuarial assumptions in 2005 and the latest collective bargaining agreement
between the Utility Workers Union of America and Consumers.overhead expense. Customer service expense increased primarily due
to higher uncollectible accounts expense.expense and contributions, beginning in
November 2006 pursuant to a November 2006 MPSC order, to a fund that provides
energy assistance to low-income customers. Overhead expense increased primarily
due to costs related to our voluntary
CE-7
Consumers Energy Company
separation program and costs associated with our utility reorganization.
DEPRECIATION AND GENERAL TAXES AND DEPRECIATION: ForTAXES: In the nine months ended September 30, 2006,first quarter of 2007, depreciation
expense increased versus 20052006 primarily due to higher plant in service. The increase in general taxes reflectsGeneral
tax expense also increased, primarily due to higher MSBT expense, offset
partially by lower property tax expense.
INTEREST CHARGES: ForIn the three months ended September 30, 2006,first quarter of 2007, interest charges increased due toreflect higher GCR interest expense, offset partially by a 3
basis point reduction in the average rate of
interest on our debt andGCR overrecovery balance, offset partially by lower average debt
levels versus 2006.
INCOME TAXES: In the same period in 2005. For the nine months ended
September 30,first quarter of 2007, income taxes increased versus 2006 interest charges increased
primarily due to an IRS income
tax audit settlement. The settlement recognized that Consumers' taxable income
for prior years was higher than originally filed, resulting in interest on the
tax liability for these prior years.
INCOME TAXES: For the nine months ended September 30, 2006, income taxes
decreased versus 2005 primarily due to lower earnings by the gas utility and the
resolution of an IRS income tax audit, which resulted in a $3 million income tax
benefit caused by the restoration and utilization of income tax credits.utility.
OTHER NONUTILITY RESULTS OF OPERATIONS
In Millions
---------------------
September 30--------------------
March 31 2007 2006 2005 Change
- -------------------- ---- --------- ------
Three--- ---- ---
Net Income for the three months ended $ 26 $(322) $348
Nine months ended $(29) $(267) $238$4 $(56) $60
=== ==== ===== =======
ForIn the three months ended September 30, 2006, other operationsfirst quarter of 2007, net income from other nonutility operations was $26$4
million, an increase of $348$60 million versus 2005. The increase2006. In late 2006 we sold our
ownership interest in the MCV PartnershipPartnership. The change in earnings is primarily due toreflects the
absence, in 2006,2007, of a 2005
impairment charge$57 million loss related to property, plant, and equipment to reflect the excess of the
carrying value of these assets over their estimated fair value. A decreaseour ownership interest in
earnings from other activities at the
MCV Partnership asPartnership. The loss in 2006 primarily reflects mark-to-market losses on
certain long-term gas contracts and associated hedges, which partially reduced gains
recorded in 2005, more than offset the recognition of a property tax refund.
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Consumers Energy Company
For the nine months ended September 30, 2006, other operations net loss was $29
million, a decrease of $238 million versus 2005. The increase in the MCV
Partnership earnings is primarily due to the absence, in 2006, of a 2005
impairment charge to property, plant, and equipment to reflect the excess of the
carrying value of these assets over their estimated fair value. The decrease in
earnings from other activities at the MCV Partnership as mark-to-market losses
on long-term gas contracts and associated hedges, which partially reduced gains
recorded in 2005, more than offset the recognition of a property tax refund.financial hedges.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results of operations and financial condition and should be considered an
integral part of our MD&A. For additional accounting policies, see Note 1,
Corporate Structure and Accounting Policies.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, weWe use estimates and assumptions in preparing our consolidated financial
statements that may affect reported amounts and disclosures. We use accounting
estimates for asset valuations, depreciation, amortization, financial and
derivative instruments, employee benefits, and contingencies. For example, we
estimate the rate of return on plan assets and the cost of future health-care
benefits to determine our annual pension and other postretirement benefit costs.
There are risks and
uncertainties thatActual results may cause actual results to differ from estimated results due to factors such as changes
in the regulatory environment, competition, regulatory decisions, and lawsuits.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that
arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that a loss is probable and the amount
of loss can be reasonably estimated. The recording of estimated liabilities for
contingencies is guided byWe use the principles in SFAS No. 5.5 when
recording estimated liabilities for contingencies. We consider many factors in
making these assessments, including the history and specifics of each matter. SignificantWe
discuss significant contingencies are discussed in the "Outlook" section included in this
MD&A.
CE-8
Consumers Energy Company
ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION
FINANCIAL INSTRUMENTS: We account for investmentsDebt and equity securities classified as
available-for-sale are reported at fair value determined from quoted market
prices. Debt and equity securities classified as held-to-maturity are reported
at cost.
Unrealized gains or losses resulting from changes in fair value of certain
available-for-sale debt and equity securities using SFAS No. 115. For additional detailsare reported, net of tax, in
equity as part of AOCI. Unrealized gains or losses are excluded from earnings
unless the related changes in fair value are determined to be other than
temporary. Unrealized gains or losses on accounting for financial
instruments, see Note 4, Financial and Derivative Instruments.our nuclear decommissioning investments
are reflected as regulatory liabilities on our Consolidated Balance Sheets.
Realized gains or losses would not affect our consolidated earnings or cash
flows.
DERIVATIVE INSTRUMENTS: We account for derivative instruments in accordance with
SFAS No. 133. Except as noted within this section, there have been no material
changes to the accounting for derivative instruments sinceSince the year ended December 31, 2005.2006, there have been no
significant changes in the amount or types of derivatives that we hold or to how
we account for derivatives. For additional details on accounting forour derivatives, see Note
4, Financial and Derivative Instruments.
To determine the fair value of our derivatives, we use information from external
sources (i.e., quoted market prices and third-party valuations), if available.
For certain contracts, this information is not available and we use mathematical
valuation models to value our derivatives. These models require various inputs
and assumptions, including commodity market prices and volatilities, as well as
interest rates and contract maturity dates. Changes in forward prices or
volatilities could significantly change the CE-12
Consumers Energy Company
calculated fair value of our
derivative contracts. The cash returns we actually realize on these contracts
may vary, either positively or negatively, from the results that we estimate
using these models. As part of valuing our derivatives at market, we maintain
reserves, if necessary, for credit risks arising from the financial condition of
our counterparties.
The following table summarizes the interest rate and volatility rate assumptions
we used to value these contracts at September 30, 2006:
Interest Rates (%) Volatility Rates (%)
------------------ --------------------
Long-term gas contracts associated with the MCV
Partnership 5.08 - 5.37 32 - 88
Establishment of the Midwest Energy Market: In 2005, the MISO began operating
the Midwest Energy Market. As a result, the MISO now centrally dispatches
electricity and transmission service throughout much of the Midwest and provides
day-ahead and real-time energy market information. At this time, we believe that
the establishment of this market does not represent the development of an active
energy market in Michigan, as defined by SFAS No. 133. As the Midwest Energy
Market matures, we will continue to monitor its activity level and evaluate
whether or not an active energy market may exist in Michigan. If an active
market develops in the future, some of our electric purchase and sale contracts
may qualify as derivatives. However, we believe that we would be able to apply
the normal purchases and sales exception of SFAS No. 133 to these contracts and,
therefore, would not be required to mark these contracts to market.
Derivatives Associated with the MCV Partnership: Certain of the MCV
Partnership's long-term gas contracts, as well as its futures, options, and
swaps, are accounted for as derivatives, with changes in fair value recorded in
earnings each quarter. The changes in fair value recorded to earnings in 2006
were as follows:
In Millions
-------------------------------------
2006
-------------------------------------
First Second Third Year to
Quarter Quarter Quarter Date
------- ------- ------- -------
Long-term gas contracts $(111) $(34) $(16) $(161)
Related futures, options, and swaps (45) (8) (12) (65)
----- ---- ---- -----
Total $(156) $(42) $(28) $(226)
===== ==== ==== =====
These losses, shown before consideration of tax effects and minority interest,
are included in the total Fuel costs mark-to-market at the MCV Partnership on
our Consolidated Statements of Income (Loss). Because of the volatility of the
natural gas market, the MCV Partnership expects future earnings volatility on
both its long-term gas contracts and its futures, options, and swap contracts,
since gains and losses will be recorded each quarter. We will continue to record
these gains and losses in our consolidated financial statements until we close
the sale of our interest in the MCV Partnership.
We have recorded derivative assets totaling $30 million associated with the fair
value of all of these contracts on our Consolidated Balance Sheets at September
30, 2006. The MCV Partnership expects almost all of these assets, which
represent cumulative net mark-to-market gains, to reverse as losses
CE-13
Consumers Energy Company
through earnings during 2007 and 2008 as the gas is purchased and the futures,
options, and swaps settle, with the remainder reversing between 2009 and 2011.
Due to the impairment of the MCV Facility and subsequent losses, the value of
the equity held by all of the owners of the MCV Partnership has decreased
significantly and is now negative. Since we are one of the general partners of
the MCV Partnership, we have recognized a portion of the limited partners'
negative equity. As the MCV Partnership recognizes future losses from the
reversal of these derivative assets, we will continue to assume a portion of the
limited partners' share of those losses, in addition to our proportionate share,
but only until we close the sale of our interest in the MCV Partnership.
In conjunction with the sale of our interest in the MCV Partnership, all of the
long-term gas contracts and the related futures, options, and swaps will be
sold. As a result, we will no longer record the fair value of these contracts on
our Consolidated Balance Sheets and will not be required to recognize gains or
losses related to changes in the fair value of these contracts on our
Consolidated Statements of Income (Loss). Additionally, at September 30, 2006,
we have recorded a cumulative net gain of $25 million, net of tax and minority
interest, in Accumulated other comprehensive income representing our
proportionate share of mark-to-market gains and losses from cash flow hedges
held by the MCV Partnership. At the date we close the sale, this amount,
adjusted for any additional changes in fair value, will be reclassified and
recognized in earnings.
Any changes in the fair value of these contracts recognized before the closing
will not affect the sale price of our interest in the MCV Partnership. For
additional details on the sale of our interest in the MCV Partnership, see the
"Other Electric Business Uncertainties - MCV Underrecoveries" section in this
MD&A and Note 2, Contingencies, "Other Electric Contingencies - The Midland
Cogeneration Venture."
MARKET RISK INFORMATION: The following is an update of our risk sensitivities
since December 31, 2005.2006. These sensitivities indicate the potential loss in fair
value, cash flows, or future earnings from our financial instruments, including
our derivative contracts, assuming a hypothetical adverse change in market rates
or prices of 10 percent. Changes in excess of the amounts shown in the
sensitivity analyses could occur if changes in market rates or prices exceed the
10 percent shift used for the analyses.
Interest Rate Risk Sensitivity Analysis (assuming an increase in market interest
rates of 10 percent):
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Variable-rate financing - before tax annual earnings exposure $ 42 $ 3
Fixed-rate financing - potential REDUCTION in fair value (a) 138 149128 134
(a) Fair value reduction could only be realized if we repurchased all of our
fixed-rate financing.
CE-14CE-9
Consumers Energy Company
Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market
prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Potential REDUCTION in fair value:
Gas supply optionvalue of fixed fuel price
contracts $ - $ 1
Derivative contracts associated with
the MCV Partnership:
Long-term gas contracts 13 39
Gas futures, options, and swaps 27 48(a) $-- $1
(a) In 2006, we entered into two contracts that fix the prices we pay for
gasoline and diesel fuel used in our fleet vehicles and equipment through
September 2007. These contracts are derivatives with an immaterial fair
value at March 31, 2007.
Investment Securities Price Risk Sensitivity Analysis (assuming an adverse
change in market prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
Potential REDUCTION in fair value of available-for-sale
equity securities (SERP investments and investment in CMS
Energy common stock) $6 $6
We maintainmaintained trust funds, as required by the NRC, for the purpose of funding
certain costs of nuclear plant decommissioning. At September 30, 2006 and
December 31, 2005, thesedecommissioning through April 2007, the date of
the sale of Palisades. These funds were invested primarily in equity securities,
fixed-rate, fixed-income debt securities, and cash and cash equivalents, and
arehave been recorded at fair value on our Consolidated Balance Sheets. These
investments arewere exposed to price fluctuations in equity markets and changes in
interest rates. Because the accounting for nuclear plant decommissioning
recognizesrecognized that costs arewere recovered through our electric rates, fluctuations in
equity prices or interest rates dodid not affect our consolidated earnings or cash
flows.
For additional details on market risk and derivative activities, see Note 4,
Financial and Derivative Instruments. For additional details on nuclear plant
decommissioning at Big Rock and Palisades, see the "Other Electric Business
Uncertainties - Nuclear Matters" section included in this MD&A.
OTHER
Other accounting policies important to an understanding of our results of
operations and financial condition include:
- - accounting for long-lived assets and equity method investments,
- - accounting for the effects of industry regulation,
- - accounting for pension and OPEB,
-
- accounting for asset retirement obligations,
- - accounting for nuclear decommissioning costs, and
-
- accounting for related party transactions.
These accounting policies were disclosed in our 20052006 Form 10-K and there have
been no subsequent material changes.
CE-15CE-10
Consumers Energy Company
CAPITAL RESOURCES AND LIQUIDITY
Factors affecting our liquidity and capital requirements are:
- results of operations,
- capital expenditures,
- energy commodity and transportation costs,
- contractual obligations,
- regulatory decisions,
- debt maturities,
- credit ratings,
- working capital needs, and
- collateral requirements.
During the summer months, we purchase natural gas and store it for resale
primarily during the winter heating season. Although our prudent natural gas
purchasescosts are recoverable from our customers, the amount paid for natural gas stored
as inventory requires additional liquidity due to the timing of thelag in cost recoveries.recovery. We
have credit agreements with our commodity suppliers and those
agreements containcontaining terms that have resultedcan
result in margin calls. AdditionalWhile we currently have no outstanding margin calls
or other credit supportassociated with our natural gas purchases, they may be required if agency
ratings are lowered or if market conditions become unfavorable relative to our
obligations to those parties.
Our current financial plan includes controlling operating expenses and capital
expenditures and evaluating market conditions for financing opportunities. Due
to the adverse impact of the MCV Partnership asset impairment charge recorded in
2005 and the MCV Partnership fuel cost mark-to-market charges during 2006, our
ability to issue FMB as primary obligations or as collateral for financing is
expected to be limited to $298 million through December 31, 2006. After December
31, 2006, our ability to issue FMB in excess of $298 million is based on
achieving a two-times FMB interest coverage ratio.opportunities, if
needed.
We believe the following items will be sufficient to meet our liquidity needs:
- our current level of cash and revolving credit facilities,
- our anticipated cash flows from operating and investing activities,
and
- our ability to access junior secured and unsecured borrowing capacity in the
capital markets, if necessary.
In the first quarter of 2007, Moody's and - our anticipated cash flows from operating and investing activities.
In June 2006, Moody's revisedS&P affirmed our credit ratings and
revised the rating outlook to stablepositive from negative.
In September 2006, Moody'sstable. Additionally, Fitch Ratings
upgraded credit ratings on certain of our credit ratings.securities.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2006, $185March 31, 2007, we had $97 million of consolidated cash, was on hand, which includes $57$58
million of restricted cash and $78 million from entities
consolidated pursuant to FASB Interpretation No. 46(R).
CE-16
Consumers Energy Companycash.
SUMMARY OF CONSOLIDATED STATEMENTS OF CASH FLOWS:
In Millions
-------------
Nine------------
Three Months Ended September 30March 31 2007 2006
2005
- --------------------------------------------------------- ----- ---------
Net cash provided by (used in):
Operating activities $ 89371 $ 64169
Investing activities (371) (511)(221) (23)
----- ---------
Net cash provided by (used in) operating and investing activities (282) 130150 46
Financing activities (6) 177(148) (9)
----- ---------
Net Increase (Decrease) in Cash and Cash Equivalents $(288) $ 3072 $ 37
===== =========
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Consumers Energy Company
OPERATING ACTIVITIES: For the ninethree months ended September 30, 2006,March 31, 2007, net cash
provided by operating activities was $89$371 million, a decreasean increase of $552$302 million
versus 2005.2006. This increase was primarily due to increased earnings, the resulttiming
of decreasesaccounts payable, increased usage of gas inventory in storage, and the
absence of the MCV Partnership gas supplier funds on deposit, andpartially offset
by the timing of accounts payable and income tax payments to the
parent. These changes were offset partially by a decrease in accounts receivable
and reduced inventory purchases. The decreasereceivable. We experienced colder weather in the MCV Partnership gas
supplier funds on deposit was the resultfirst
quarter of refunds to suppliers from decreased
exposure due to declining gas prices in2007 versus 2006. The decreasetiming of payments for increased natural gas
purchases to meet customer demand in accounts payable
was mainly due tothe first quarter of 2007, coupled with the
absence of payments for higher priced gas thatmade during the first quarter of 2006,
increased our operating cash flow. A mild winter in 2006 allowed us to
accumulate more gas in our underground storage facilities. The increased usage
of gas already in storage during the first quarter of 2007 also increased our
operating cash flow. These increases were accrued at December
31, 2005. The decreasereduced partially by the timing of our
collection of increased billings in accounts receivable was primarilythe first quarter of 2007 due to the increased
sales of accounts receivable in 2006, the collection of receivables in 2006
reflecting higher gas prices billed during the latter part of 2005,recent
regulatory actions and the
expiration of emergency rules initiated by the MPSC, which delayed customer
payments during the heating season.weather-driven demand.
INVESTING ACTIVITIES: For the ninethree months ended September 30, 2006,March 31, 2007, net cash used
in investing activities was $371$221 million, a decreasean increase of $140$198 million versus
2005.2006. This decreaseincrease was due to the releaseabsence in 2007 of $128 million of restricted
cash released in February 2006 which we used to extinguish long-term debt- related parties.and an increase in capital expenditures.
FINANCING ACTIVITIES: For the ninethree months ended September 30, 2006,March 31, 2007, net cash used
in financing activities was $6$148 million, a changean increase of $183$139 million versus
2005.2006. This changeincrease was primarily due to lower stockholder's contributions from
the parent, partially offset by a decreasean increase in payments of common stock dividends
to the parent and the absence of $136 million.a cash infusion from the parent.
OBLIGATIONS AND COMMITMENTS
REVOLVING CREDIT FACILITY: For additional details on long-term debt activity,our revolving credit facility, see
Note 3, Financings and Capitalization.
OBLIGATIONS AND COMMITMENTS
DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 3,
Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: We enter into various arrangements in the normal
course of business to facilitate commercial transactions with third-parties.third parties.
These arrangements include indemnifications, letters of credit and surety bonds.
We enter into agreements containing indemnifications standard in the industry
and indemnifications specific to a transaction, such as the sale of a
subsidiary. Indemnifications are usually agreements to reimburse other companies
if those companies incur losses due to third-party claims or breach of contract
terms. Banks, on our behalf, issue letters of credit guaranteeing payment to a
third-party. Letters of credit substitute the bank's credit for ours and reduce
credit risk for the third-party beneficiary. We monitor these obligations and
believe it is unlikely that we would be required to perform or otherwise incur
any material losses associated with these guarantees. For additional details on
guaranteethese arrangements, see Note 2, Contingencies, "Other Contingencies -FASB- FASB
Interpretation No. 45, Guarantor's Accounting and Disclosure Requirements for
Guarantees, Including Indirect Guarantees of Indebtedness of Others."
REVOLVING CREDIT FACILITIES:SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. The
highly liquid and efficient market for securitized financial assets provides a
lower cost source of funding compared to unsecured debt. For additional details, on revolving credit facilities,
see Note 3, Financings and Capitalization.
SALE OF ACCOUNTS RECEIVABLE: For details on the sale of accounts receivable, see
Note 3, Financings and Capitalization.
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Consumers Energy Company
OUTLOOK
CORPORATE OUTLOOK
Our business strategy will focus on investing in our utility system to enable us
to meet our customer commitments, comply with increasing environmental
performance standards, and maintain adequate supply and capacity.
In the first quarter of 2007, we completed a reorganization of the company that
we announced in November 2006. The reorganization improves operating efficiency,
reliability, and customer service.
ELECTRIC BUSINESS OUTLOOK
GROWTH: Summer 2006 temperatures were higher than historical averages, leading
to increasedIn 2007, we expect electric deliveries to electric customers. The summer 2006 also posted
record peak demand surpassing the record peak demand set in 2005 by five
percent. In 2006, we project annual electric deliveries will declinegrow about one-half of one
percent from 2005compared to 2006 levels. This short-termThe outlook for 2007 assumes a stabilizing economysmall decline in
industrial economic activity and normal weather conditions forthroughout the
fourth quarterremainder of 2006.the year.
Over the next five years, we expect electric deliveries to grow at an average
rate of about one and one-half1.5 percent per year. However, such growth is
dependent onThis outlook assumes a modestly growing customer
base and a stabilizing Michigan economy.economy after 2007. This growth rate includes
both full-service sales and delivery service to customers who choose to buy
generation service from an alternative electric supplier, but excludes
transactions with other wholesale market participants and other electric
utilities. This growth rate reflects a long-range expected trend of growth.
Growth from year to year may vary from this trend due to customer response to
the following:
- energy conservation measures,
- fluctuations in weather conditions, and
- changes in economic conditions, including utilization and expansion or
contraction of manufacturing facilities.
ELECTRIC CUSTOMER REVENUE OUTLOOK: Our electric utility customer base includes a
mix of residential, commercial, and diversified industrial customers. In 2006,
Michigan's automotive industry experienced manufacturing facility closures and
restructurings. Our electric utility results are not dependent upon a single
customer, or even a few customers, and customers in the automotive sector
represented five percent of our total 2006 electric revenue. We cannot predict
the impact of current or possible future restructuring plans or possible future
actions by our industrial customers.
ELECTRIC RESERVE MARGIN: We are currently planning for a reserve margin of approximately
11 percent for summer 2007, or supply resources equal to 111 percent of
projected firm summer peak load. Of the 2007 supply resources target of 111
percent, we expect 96 percent to come from our electric generating plants and
long-term power purchase contracts, and 15 percent to come from other
contractual arrangements. Our 15-year power purchase agreement with Entergy for
100 percent of the Palisades facility's current electric output will offset the
reduction in the owned capacity represented by the sale of the Palisades
facility in April 2007. We have purchased capacity and energy contracts covering
partially the estimated reserve margin requirements for 2007 through 2010. As a
result, we recognized an asset of $63$62 million for unexpired seasonal capacity
and energy contracts at September 30, 2006. Upon the completion of the sale of
the Palisades plant, the power purchase agreement will offset, for the 15-year
term of the agreement, the reduction in the owned capacity represented by the
Palisades plant.
The MCV PPA is not affected by our agreement to sell our interest in the MCV
Partnership.March 31, 2007.
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Consumers Energy Company
After September 15, 2007, we expect to exercise our claim for
relief under the regulatory out provision in
the MCV PPA.PPA, resulting in a reduction in the amount paid to the MCV Partnership
to equal the amount we are allowed to recover in the rate charged to customers.
If we are successful in exercising our claim,this provision, the MCV Partnership hasmay,
under certain circumstances, have the right to terminate the MCV PPA, which
could affect our reserve margin status. The MCV PPA represents 1513 percent of our
2007 supply resources target.
ELECTRIC UTILITY PLANT OUTAGE: In September 2006, we removed from service unit
three of the J.H. Campbell electric generating plant, representing 765 MW of our
capacity. The scheduled outage was for installation of equipment necessary to
comply with environmental standards. We expected the unit to return to service
in March 2007. However, the outage extended to May 1, 2007 due to unanticipated
delays in construction due to labor shortages, the collapse of an outdoor crane
on unit three and problems with a major generator component that was refurbished
by the original equipment manufacturer. The MPSC allows for the recovery of
reasonable and prudent replacement power costs.
ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission
service to us, increased substantially the transmission rates it chargescharged us in
2006. The increasedrevenue collected by METC under those rates areis subject to refund
and to reduction based onpending a FERC ruling. In January 2007, the outcome of hearings atparties filed a settlement agreement
with the FERC. This settlement, if approved by the FERC, scheduled for December 2006. Recoverywill result in a refund
of 2006 transmission charges of $18 million and a portioncorresponding reduction of these costs is included in our approved 2006 PSCR plan. The PSCR
process allows recovery of all reasonable and prudent
power supply costs. However, we cannot predict when recovery of the transmission costs associated
with the rate increase will commence. To the extent that we incur and are unable
to collect these increased costs in a timely manner, our cash flows from
electric utility operations will be affected negatively. For additional details on power supply costs, see Note 2,
Contingencies, "Electric Rate Matters - Power Supply Costs."
In May 2006, ITC, a company that operates electric transmission facilities
through a wholly owned subsidiary, including the transmission system within
Detroit Edison's territory, filed an application with
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Consumers Energy Company
the FERC to acquire METC. The FERC subsequently delayed hearings concerning the
METC transmission rates. In October 2006, ITC's acquisition of METC was
completed. We are unable to predict the nature and timing of any action by the
FERC on transmission rates but we will continue to participate in the FERC
proceeding concerning the METC transmission rates.
INDUSTRIAL REVENUE OUTLOOK: Our electric utility customer base includes a mix of
residential, commercial, and diversified industrial customers. In March 2006,
Delphi Corporation, a large industrial customer of Consumers with six facilities
in our service territory, announced plans to sell or close all but one of their
manufacturing operations in Michigan as part of their bankruptcy restructuring.
Our electric utility operations are not dependent upon a single customer, or
even a few customers, and customers in the automotive sector constitute four
percent of our total electric revenue. In addition, returning former ROA
industrial customers will benefit our electric utility revenue. However, we
cannot predict the impact of these restructuring plans or possible future
actions by other industrial customers.
THE21ST CENTURY ELECTRIC CAPACITY NEED FORUM:ENERGY PLAN: In January 2006,2007, the chairman of the MPSC
Staff issued a
report on future electric capacity inproposed three major policy initiatives to the stategovernor of Michigan. The
reportinitiatives involve the use of more renewable energy resources by all
load-serving entities such as Consumers, the creation of an energy efficiency
program, and a procedure for reviewing proposals to construct new generation
facilities. The January proposal indicated that existing generation resources are adequate in the short term, but
could be insufficient to maintain reliability standardsMichigan needs new base-load
capacity by 2009. The report also
indicated that new coal-fired baseload generation may be needed by 2011. The
MPSC Staff recommended an approval2015 and bid process for new power plants. To
address revenue stability risks, the MPSC Staff also proposed a special
reliability charge that a utility would assess on all electric distribution
customers. In April 2006, the governor of Michigan issued an executive directive
calling for the development of a comprehensive energy plan for the state of
Michigan. The directive calls for the Chairman of the MPSC, working in
cooperation with representatives from the public and private sectors,recommends measures to make recommendations on Michigan's energy policy by the end of 2006.it easier to predict customer
demand and revenues. The proposed initiatives will require changes to current
legislation. We will continue to participate as the MPSC, addresseslegislature, and other
stakeholders address future electric capacityresource needs.
BURIAL OF OVERHEAD POWER LINES:BALANCED ENERGY INITIATIVE: In May 2007, we filed a "Balanced Energy Initiative"
with the MPSC providing a comprehensive energy resource plan to meet our
projected short-term and long-term electric power requirements. The Cityplan is
responsive to the 21st Century Electric Energy Plan and assumes that Michigan
will implement a state-wide energy efficiency program and a renewable energy
portfolio standard. The filing requests the MPSC to rule that the Balanced
Energy Initiative represents a reasonable and prudent plan for the acquisition
of Taylor, a municipality locatednecessary electric utility resources.
As acknowledged in Wayne County, Michigan, passed an ordinance that required Detroit Edison to bury
a sectionthe 21st Century Electric Energy Plan, implementation of overhead power lines at Detroit Edison's expense. In September
2004,the
Balanced Energy Initiative will require legislative repeal or significant reform
of the Michigan Courtcustomer choice law. In addition, we endorse the 21st Century
Electric Energy Plan recommendation to adopt a new, up-front certification
policy for major power plant investments. Our filing requests the MPSC to find
that the addition of Appeals upheld a lower court decision affirming500 MW of gas-fired combined cycle generating capacity is
reasonable and prudent. This addition could be in the legalityform of the ordinance over Detroit Edison's objections. Other municipalitiesconstruction
of a new gas-fired generating plant to begin service in our service territory adopted,2011, or proposedin the adoptionform of
similar
ordinances. Detroit Edison appealeda purchase of an existing gas-fired facility. The filing also recommends
construction of a new 750 MW clean coal generating facility on an existing
Consumers site to begin operation in 2015. Ownership of 250 MW of the total
capacity is assumed to be allocated to municipal entities or other interested
parties, resulting in 500 MW dedicated to us.
PROPOSED RENEWABLE ENERGY LEGISLATION: There are various bills introduced into
in the U.S. Congress and the Michigan Courtlegislature relating to mandatory
renewable energy standards. If enacted, these bills generally would require
electric utilities to acquire a certain percentage of Appeals ruling totheir power from renewable
sources or otherwise pay fees or purchase allowances in lieu of having the
Michigan Supreme Court. In May 2006, the Michigan Supreme Court ruledresources. We cannot predict whether any such bill will be enacted or in favor
of Detroit Edison. The Court found that the MPSC has primary jurisdiction over
this issue and accordingly, the Taylor ordinance is subject to any applicable
rules and regulations of the MPSC, including issues concerning who should bear
the expense of underground facilities. If incurred, we would seek recovery of
such costs from the municipality, or from our customers located in the
municipality, subject to MPSC approval.what
form.
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Consumers Energy Company
ELECTRIC BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
condition and future results and condition.of operations. These trends or uncertainties have,
or we reasonably expect could have, a material impact on revenues or income from
continuing electric operations.
ELECTRIC ENVIRONMENTAL ESTIMATES: Our operations are subject to environmental
laws and regulations. Costs to operate our facilities in compliance with these
laws and regulations generally have been recovered in customer rates.
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Consumers Energy Company
Clean Air Act: Compliance with the federal Clean Air Act and resulting
regulations has been, and will continuecontinues to be a significant focus for us. The Nitrogen Oxide State
Implementation Plan requires significant reductions in nitrogen oxide emissions.
To comply with the regulations, we expect to incur capital expenditures totaling
$835 million. AsThese expenditures include installing selective catalytic
reduction control technology on four of September 2006,our coal-fired electric generating
units. The key assumptions in the capital expenditure estimate include:
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- an AFUDC capitalization rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 7.8 percent. From 1998 to present, we have
incurred $660$760 million in capital expenditures to comply with the federal Clean
Air Act and resulting regulations and anticipate that the remaining $175$75 million
of capital expenditures will be made in 20062007 through 2011.
In addition to modifying coal-fired electric generating plants, our compliance
plan includes the use of nitrogen oxide emission allowances until all of the
control equipment is operational in 2011. The nitrogen oxide emission allowance
annual expense is projected to be $4$3 million per year, which we expect to
recover from our customers through the PSCR process. The projected annual
expense is based on market price forecasts and forecasts of regulatory
provisions, known as progressive flow control, that restrict the usage in any
given year of allowances banked from previous years. The allowances and their
cost are accounted for as inventory. The allowance inventory is expensed at the
rolling average cost as the electric generating plants emit nitrogen oxide.
Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air
Interstate Rule that requires additional coal-fired electric generating plant
emission controls for nitrogen oxides and sulfur dioxide. We plan to meet the
nitrogen oxide requirements of this rule by year roundyear-round operation of our
selective catalytic reduction control technology units, installation of low
nitrogen oxide burners, and purchasing emission allowances. We plan to meet the
sulfur dioxide requirements of this rule using sorbent injection, installation
of flue gas desulfurization scrubbers atand purchasing emission allowances. Our
total cost for equipment installation is expected to reach approximately $700
million by 2015. Additional purchases of sulfur dioxide emission allowances in
2012 and 2013 will be needed for an estimated total cost of $960$12 million per year,
which we expect to be incurred by 2014.recover from our customers through the PSCR process.
Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury
Rule, which requires initial reductions of mercury emissions from coal-fired
electric generating plants by 2010 and further reductions by 2018. Based on
current technology, we anticipate our capital costs for mercury emissions
reductions required by Phase I of the Clean Air Mercury Rule to be less than $50
million and these reductions implemented by 2010. Phase II requirements of the
Clean Air Mercury Rule are not yet known and a cost estimate has not been
determined.
In April
2006, Michigan's governor announced a plan that would result in
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Consumers Energy Company
mercury emissions reductions of 90 percent by 2015. We are currently working
with the MDEQ on the details of these rules. We will developthis rule; however, we have developed
preliminary cost estimates and a cost estimate whenmercury emissions reduction plan based on our
best knowledge of control technology options and anticipated requirements. Our
plan includes expenditures of approximately $550 million for mercury control
equipment and continuous emissions monitoring systems through 2014.
The following table compares the details of
these rules are determined.federal Clean Air Mercury Rule to the proposed
state mercury rule:
2010 2015 2018
-------------------------- -------------------------- -------------------------
Clean Air Mercury Rule 30% reduction by 2010 70% reduction by 2018
with interstate trading with interstate trading
of allowances of allowances
$4 million in capital $136 million in capital
plus $30 million annually
in allowance purchases
Proposed State Mercury Rule 30% reduction by 2010 90% reduction by 2015
without interstate trading without interstate trading
of allowances of allowances
$4 million in capital $546 million in capital
Greenhouse gases: Several legislative proposals have been introduced in the
United States Congress that would require reductions in emissions of greenhouse
gases, including potentially carbon dioxide. We cannot predict whether any
federal mandatory greenhouse gas emission reduction rules ultimately will be
enacted, or the specific requirements of any of these rules and their effect on
our operations and financial results. Also,On April 2, 2007, the U.S. Supreme Court has agreed to
hear a case claimingruled
that the EPA is required by the Clean Air Act to consider
regulating carbon dioxide emissions from automobiles. Thegives the EPA asserts that it
lacksthe authority to regulate emissions of
carbon dioxide emissions. Ifand other greenhouse gases from automobiles. In its decision, the
Supreme Court finds
thatcourt ordered the EPA to revisit its contention that it has authoritythe discretion not
to regulate carbon dioxidegreenhouse gas emissions in this case, it
could result in new federal carbon dioxide regulations for other industries,
including the utility industry.from automobiles.
To the extent that greenhouse gas emission reduction rules come into effect, the
mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sector. We cannot estimate the potential
effect of
federal or state level greenhouse gas policy on our future consolidated results of
operations, cash flows, or financial position due to the uncertain nature of the
policies at this time. However, we stay abreast ofwill continue to monitor greenhouse gas
policy developments and will continue to assess and respond to their potential implications on
our business operations.
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Consumers Energy Company
Water: In March 2004, the EPA issued rules that govern electric generating plant
cooling water intake systems. The rules require significant reduction in fish
killed by operating equipment. Fish kill reduction studies are required to be
submitted to the EPA in 2007 and 2008. EPA compliance options in the rule are
currently beingwere
challenged in court. In January 2007, the court rejected many of the compliance
options favored by industry and we will finalize our cost estimates in
early 2007, when a decision onremanded the finalbulk of the rule is anticipated. We expectback to
implement the EPA
approved process from 2009for reconsideration. The court's ruling is expected to 2011.increase significantly
the cost of complying with this rule. However, the cost to comply will not be
known until the EPA's reconsideration is complete. At this time, the EPA has not
established a schedule to address the court decision.
For additional details on electric environmental matters, see Note 2,
Contingencies, "Electric Contingencies - Electric Environmental Matters."
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Consumers Energy Company
COMPETITION AND REGULATORY RESTRUCTURING: The Customer Choice Act allows all of
our electric customers to buy electric generation service from us or from an
alternative electric supplier. At September 30, 2006,March 31, 2007, alternative electric suppliers
were providing 308283 MW of generation service to ROA customers, which
represents fourcustomers. This is 3 percent
of our total distribution load.load and represents a decrease of 19 percent of ROA
load compared to March 31, 2006. In prior orders, the MPSC approved recovery of
Stranded Costs incurred from 2002 through 2003 through a surcharge applied to
ROA customers. If downward ROA trends continue, it may extend the time it takes
to recover fully our Stranded Costs. It is difficult to predict future ROA
customer trends.
Section 10d(4) Regulatory Assets: In December 2005, the MPSC issued an order
that authorized ustrends, which affect our ability to recover $333 million in Section 10d(4) costs. Instead of
collecting these costs evenly over five years, the order instructed us to
collect 10 percent of the regulatory asset total in the first year, 15 percent
in the second year, and 25 percent in each of the third, fourth, and fifth
years.timely our Stranded Costs.
ELECTRIC RATE CASE: In January 2006, we filed a petition for rehearing with the MPSC that
disputed the aspect of the order dealing with the timing of our collection of
these costs. In April 2006, the MPSC issued an order that denied our petition
for rehearing.
Stranded Costs: Prior MPSC orders adopted a mechanism pursuant to the Customer
Choice Act to provide recovery of Stranded Costs that occur when customers leave
our system to purchase electricity from alternative suppliers. In November 2005,March 2007, we filed an application with the MPSC related toseeking
an 11.25 percent authorized return on equity and an annual increase in revenues
of $157 million. The increase includes a $23 million base rate reduction, the
determinationaddition of 2004
Stranded Costs. Applyinga $13 million surcharge for the Stranded Cost methodology usedreturn on investments in prior MPSC
orders, we concluded that we experienced Stranded Costs in 2004; however, we
also concluded that these costs were offset completely by our net sales of
excess power into the bulk electricity market. In September 2006, the MPSC
issued an order approving our proposalBig Rock,
and the resulting conclusion that our
Stranded Costs for 2004 were fully offset by wholesale saleselimination of $167 million Palisades base rate recovery credit in the
PSCR. If approved as requested, the rate requests would go into effect in
January 2008 and would apply to all retail electric customers. We cannot predict
the bulk
electricity market. Theamount or timing of any MPSC also determined that this order completesdecision on the series of Stranded Cost cases resulting from the Customer Choice Act.
Through and Out Rates: From December 2004 to March 2006, we paid a transitional
charge pursuant to a FERC order eliminating regional "through and out" rates. In
May 2006, the FERC approved an agreement between the PJM RTO transmission owners
and Consumers concerning these transitional charges. The agreement resolves all
issues regarding transitional charges for Consumers and eliminates the potential
for refunds or additional charges to Consumers. In May 2006, Baltimore Gas &
Electric filed a notice of withdrawal from the settlement. Consumers, PJM, and
others filed responses with the FERC on this matter. The FERC has not ruled on
whether the notice of withdrawal is effective, but we do not believe this action
will have any material impact on us.requests.
For additional details and material changes relating to the restructuring of the
electric utility industry and electric rate matters, see Note 2, Contingencies,
"Electric Restructuring Matters," and "Electric Rate Matters."
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Consumers Energy Company
OTHER ELECTRIC BUSINESS UNCERTAINTIES
THE MCV UNDERRECOVERIES:PARTNERSHIP: The MCV Partnership, which leases and operates the MCV
Facility, contracted to sell electricity to Consumers for a 35-year period
beginning in 1990.
We hold a 49 percent partnership interest in the MCV
Partnership, and a 35 percent lessor interest in the MCV Facility.
Sale of our Interest in the MCV Partnership and the FMLP: In July 2006, we
reached an agreement to sell 100 percent of the stock of CMS Midland, Inc. and
CMS Midland Holdings Company to an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments for $60.5 million. These Consumers'
subsidiaries hold our interests in the MCV Partnership and the FMLP. The sales
agreement calls for the purchaser, an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments, to pay $85 million, subject to certain
conditions and reimbursement rights, if Dow terminates an agreement under which
it is provided power and steam by the MCV Partnership. The purchaser will secure
their reimbursement obligation with an irrevocable letter of credit of up to $85
million. The MCV PPA and the associated customer rates are not affected by the
sale. We are targeting to close the sale before the end of 2006. The sale is
subject to various regulatory approvals, including the MPSC's approval and the
expiration of the waiting period under the Hart-Scott-Rodino Antitrust
Improvements Act of 1976. The MPSC has established a contested case proceeding
schedule, which will allow for a decision from the MPSC by the end of 2006. In
October 2006, we reached a settlement agreement with the MPSC Staff and the
parties involved, which recommends that the MPSC grant all authorizations
necessary to complete the sale of our interests in the MCV Partnership and the
FMLP. The MPSC's approval of the settlement agreement is required for it to
become effective. We cannot predict the timing or the outcome of the MPSC's
decision. We further cannot predict with certainty whether or when this
transaction will be completed.
For additional details on the sale of our interests in the MCV Partnership and
the FMLP, see Note 2, Contingencies, "Other Electric Contingencies - The Midland
Cogeneration Venture".
Financial Condition of the MCV Partnership: Under the MCV PPA, variable energy
payments to the MCV Partnership are based on the cost of coal burned at our coal
plants and our operation and maintenance expenses. However, the MCV
Partnership's costs of producing electricity are tied to the cost of natural
gas. Historically high natural gas prices have caused the MCV Partnership to
reevaluate the economics of operating the MCV Facility and to record an
impairment charge in 2005. If natural gas prices remain at present levels or
increase, the operations of the MCV Facility would be adversely affected and
could result in the MCV Partnership failing to meet its obligations under the
sale and leaseback transactions and other contracts.
Underrecoveries related to the MCV PPA: Further, theThe cost that we incur under the MCV PPA
exceeds the recovery amount allowed by the MPSC. As a result, we estimate cash
underrecoveries of capacity and fixed energy payments of $56
million in 2006 and $39 million in 2007. However, ourwe use the direct savings from
the RCP, after allocating a portion to customers, are used to offset a portion of our
capacity and fixed energy underrecoveries expense. After September 15, 2007, we
expect to claim relief under the regulatory out provision in the MCV PPA,
thereby limiting our capacity and fixed energy payments to the MCV Partnership
to the amounts that we collect from our customers. The effect of any suchThis action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on the MCV Partnership's financial performance, and
- eliminate
our underrecoveries of capacity and fixed energy payments.
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Consumers Energy Company
In addition, the MPSC's future actions on the capacity and fixed energy payments
recoverable from customers subsequent to September 15, 2007 may also further
affect negatively the financial performance of the MCV Partnership, if such
action resulted in us claiming additional relief under the regulatory out
provision. The MCV Partnership has indicatednotified us that it may taketakes issue with our intended
exercise of the regulatory out provision after September 15, 2007. We believe
that the provision is valid and fully effective, but cannot assure that it will
prevail in the event of a dispute. If we are successful in exercising the
regulatory out provision, the MCV Partnership hasmay, under certain circumstances,
have the right to terminate or reduce the amount of capacity sold under the MCV
PPA. If the MCV Partnership terminates the MCV PPA or reduces the amount of
capacity sold under the MCV PPA, we would seek to replace the lost capacity to
maintain an adequate electric reserve margin. This could involve entering into a
new PPA and (or) entering into electric capacity contracts on the open market.
We cannot predict our ability to enter into such contracts at a reasonable
price. We are also unable to predict regulatory approval of the terms and
conditions of such contracts, or that the MPSC would allow full recovery of our
incurred costs.
To comply with a prior MPSC order, we made a filing in May 2007 with the MPSC,
which asked the MPSC to make a determination regarding whether it wished to
reconsider the amount of the MCV PPA payments that we recover from customers. We
are unable to predict the outcome of this request. For
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Consumers Energy Company
additional details on the MCV Partnership, see Note 2, Contingencies, "Other
Electric Contingencies - The Midland Cogeneration Venture.MCV PPA."
NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006,April 2007, we reached an agreement
to sellsold Palisades and the Big Rock Independent Spent Fuel Storage Installation
(ISFSI) to
Entergy for $380 million. Under the agreement, if the transaction
does not close by March 1, 2007, theThe final purchase price will be reduced by
approximately $80,000 per day with additional costs if the deal does not close
by June 1, 2007. Based on the MPSC's published schedulewas subject to various
closing adjustments resulting in us receiving $361 million. We also paid Entergy
$30 million to assume ownership and responsibility for the contested case
proceedings regarding this transaction,Big Rock ISFSI.
Because of the sale is targeted to close by May 1,
2007. This two-month delayof Palisades, we will also pay the NMC, the former operator
of the Palisades plant, $7 million in exit fees and will forfeit our investment
in the originally anticipated March 1, 2007 closing
date would result in a purchase price reductionNMC of approximately $5 million.
We
estimate thatThe MPSC order approving the Palisades saletransaction allows us to recover the book
value of the Palisades plant. This will result in a $31estimated excess proceeds of
$66 million premium abovebeing credited to our customers through refunds applied over the
Palisades asset values atremainder of 2007 and 2008. Final proceeds in excess of the anticipatedbook value are
subject to closing date after accounting foradjustments and review by the MPSC. The MPSC order deferred
ruling on the recovery of $30 million in estimated sales-related costs. This premium is expectedtransaction costs, including
the NMC exit fees, and the $30 million payment to benefit our
customers.Entergy related to the Big
Rock ISFSI until the next general rate case.
Entergy will assume responsibility for the future decommissioning of the plant
and for storage and disposal of spent nuclear fuel. We will be required to pay
Entergy $30 million for acceptingfuel located at the responsibility for the storagePalisades and
disposal of
the Big Rock ISFSI. AtISFSI sites. We transferred $252 million in trust fund assets to
Entergy. Estimated decommissioning funds of $189 million will be credited to our
retail customers through refunds applied over the anticipated dateremainder of close,
decommissioning trust assets are estimated to be $587 million. We will retain
$205 million2007 and 2008.
Final disposition of these funds atis subject to closing date balances and is
subject to review by the time of close and will be entitled to receive
a return of an additional $130 million, pending either a favorable federal tax
ruling regarding the release of the funds or, if no such ruling is issued, after
decommissioning of the Palisades site is complete. These estimates increased
approximately $20 million compared to second quarter 2006 estimates primarily
because of market appreciation during the third quarter of 2006.MPSC. The disposition of the retained and receivable nuclearremaining decommissioning
funds is subject to regulatory approval. We expect that a significant portion ofreview by the proceeds will
be used to benefit our customers. We plan to use the cash that we retain from
the sale to reduce utility debt.MPSC.
As part of the transaction, Entergy will sell us 100 percent of the plant's
output up to its current annual average capacity of 798 MW under a 15-year power
purchase agreement. During the termBecause of the power purchase agreement, Entergy is obligated
to supply, and we are obligated to take, all capacity and energy from the
Palisades plant, exclusive of uprates above the plant's presently specified
capacity. When the plant is not operating or is derated, under certain
circumstances, Entergy can elect to provide replacement power from another
source at the rates set in the power purchase agreement. Otherwise, we would
have to obtain replacement power from the market. However, we are only obligated
to pay Entergy for capacity and energy actually delivered by Entergy either from
the plant or from an allowable replacement source
CE-23
Consumers Energy Company
chosen by Entergy. If Entergy schedules a plant outage in June, July or August,
Entergy is required to provide replacement power at power purchase agreement
rates. There are significant penalties incurred by Entergy if the delivered
energy fails to achieve a minimum capacity factor level during July and August.
Over the term of the power purchase agreement, the
pricingtransaction is structured such
that Consumers' ratepayers will retain the benefits ofa lease for accounting purposes. Due to our continuing
involvement with the Palisades plant's
low-cost nuclear generation.
The sale is subject to various regulatory approvals, includingassets, we will account for the MPSC's
approvalPalisades plant
as a financing for accounting purposes and not a sale. This will result in the
recognition of the power purchase agreement, the FERC's approval for Entergy to
sell power to us under the power purchase agreement and other related matters,
and the NRC's approval of the transfer of the operating license to Entergy and
other related matters. In October 2006, the Federal Trade Commission issued a notice that neither it nor the Department of Justice's Antitrust Division plan
to take enforcement actionfinance obligation.
For additional details on the sale. The final purchase price will be subject
to various closing adjustments such as working capitalsale of Palisades and capital expenditure
adjustments, adjustments for nuclear fuel usage and inventory, and the date of
closing. However, the sale agreement can be terminated if the closing does not
occur within 18 months of the execution of the agreement. The closing can be
extended for up to six months to accommodate delays in receiving regulatory
approval. We cannot predict with certainty whether or when the closing
conditions will be satisfied or whether or when this transaction will be
completed.
Big Rock: Decommissioning of the site is nearing completion. Demolition of the
last remaining plant structure, the containment building, and removal of
remaining underground utilities and temporary office structures was completed in
August 2006. Final radiological surveys are now being completed to ensure that
the site meets all requirements for free, unrestricted release in accordance
with the NRC approved License Termination Plan (LTP) for the project. We
anticipate NRC approval to return approximately 475 acres of the site, including
the area formerly occupied by the nuclear plant, to a natural setting for
unrestricted use by early 2007. An area of approximately 107 acres including the Big Rock ISFSI, where eight casks loaded with spent fuel and other high-level
radioactive material are stored, is part of the sale of nuclear assets as
previously discussed.
Palisades: The amount of spent nuclear fuel at Palisades exceeds the plant's
temporary onsite wet storage pool capacity. We are using dry casks for temporary
onsite dry storage to supplement the wet storage pool capacity. As of September
2006, we have loaded 29 dry casks with spent nuclear fuel.
Palisades' current license from the NRC expires in 2011. In March 2005, the NMC,
which operates the Palisades plant, applied for a 20-year license renewal for
the plant on behalf of Consumers. In October 2006, the NRC issued its final
environmental impact statement on Palisades' license renewal. The NRC found that
there were no environmental impacts that would preclude license renewal for an
additional 20 years of operation. We expect a decision from the NRC on the
license renewal application in 2007.
For additional details on nuclear plant decommissioning at Big Rock and
Palisades, see Note
2, Contingencies, "Other Electric Contingencies - The Sale of Nuclear Plant Decommissioning.Assets and
the Palisades Power Purchase Agreement."
GAS BUSINESS OUTLOOK
GROWTH: In 2006,2007, we project gas deliveries will decline by four percent,slightly, on a
weather-adjusted basis, from 20052006 levels due to increasedcontinuing conservation and
overall economic conditions in the state of Michigan. Over the next five years,
we expect gas deliveries to be relatively flat.decline by less than one-half of one percent
annually. Actual gas deliveries in future periods may be affected by:
CE-24
Consumers Energy Company
- fluctuations in weather patterns,conditions,
- use by independent power producers,
- competition in sales and delivery,
- changes in gas commodity prices,
- Michigan economic conditions,
- the price of competing energy sources or fuels,
and
- gas consumption per customer.customer,
- improvements in gas appliance efficiency, and
- use of a Revenue Decoupling and Conservation Incentive mechanism.
CE-18
Consumers Energy Company
GAS BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our future financial
results and financial condition. These trends or uncertainties could have a
material impact on future revenues or income from gas operations.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. For additional details, see Note 2, Contingencies, "Gas Contingencies -
Gas Environmental Matters."
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our
purchased natural gas costs if incurred under reasonable and prudent policies
and practices. The MPSC reviews these costs, policies, and practices for
prudency in annual plan and reconciliation proceedings. For additional details
on gas cost recovery, see Note 2, Contingencies, "Gas Rate Matters - Gas Cost
Recovery."
2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued
Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously-ordered $34 million reduction in our
depreciation expense,
- required us to undertake a study to determine why our plant removal
costs are in excess of other regulated Michigan natural gas utilities,
and
- required us to file a study report with the MPSC Staff on or before
December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.DEPRECIATION: We are also required to file our next gas depreciation case with
the MPSC within 90 days after the MPSC issuance of a final order in the pending
case related to ARO accounting. We cannot predict when the MPSC will issue a
final order in the ARO accounting case.
If a final order in our next gas depreciation case is not issued concurrently
with a final order in a general gas rate case, the MPSC may incorporate the
results of the depreciation case order is issued after theinto general gas general rate case order,
we proposed to incorporate its results into the gas general rates usingthrough use of a
surcharge mechanism a process used to incorporate specialty items into customer
rates.
2005(which may be either positive or negative).
2007 GAS RATE CASE: In July 2005,February 2007, we filed an application with the MPSC
seeking a 12an 11.25 percent authorized return on equity along with a $132an $88 million
annual increase in our gas delivery and transportation rates. As partrates, of this filing,
we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony in October
2005. In its testimony, the MPSC Staff recommended granting interim rate relief
of $38 million.
CE-25
Consumers Energy Company
In February 2006, the MPSC Staff recommended granting final rate relief of $62
million. The MPSC Staff proposed thatwhich $17
million of this amountwould be contributed to a low income and energy efficiency fund. The MPSC Staff also recommended
reducing our allowed return on common equity to 11.15 percent, from our current
11.4 percent.
In March 2006,We have
proposed the MPSC Staff revised its recommended final rate relief to $71
million, which includes $17 million to be contributed to a low income and energy
efficiency fund. In April 2006, we revised our request for final rate relief
downward to $118 million.
In May 2006, the MPSC issued an order granting us interim gas rate relief of $18
million annually, which is under bond and subject to refund if final rate relief
is granted in a lesser amount. The order also extended the temporary two-year
surcharge of $58 million granted in October 2004 until the issuanceuse of a final
order in this proceeding. The MPSC has not setRevenue Decoupling and Conservation Incentive Mechanism
for residential and general service rate classes to help assure a date for issuancereasonable
opportunity to recover costs regardless of an order
granting final rate relief.
In July 2006, the ALJ issued a Proposal for Decision recommending final rate
relief of $74 million above current rate levels, which include interim and
temporary rate relief. The $74 million includes $17 million to be contributed to
a low income and energy efficiency fund. The Proposal for Decision also
recommended reducing our return on common equity to 11 percent, from our current
11.4 percent.sales levels.
OTHER OUTLOOK
VOLUNTARY
RULES REGARDING BILLING PRACTICES: In OctoberDecember 2006, the MPSC announced
a voluntary agreement relatingissued proposed
rule changes to residential customer billing practices with usstandards and other Michigan
natural gas and electric utilities that willpractices. These
changes, if adopted, would provide additional helpprotection to low-income customers
forduring the winter heating period ofseason that will be defined as November 1 2006 through
March 31, 2007. The rules addressextend the time between billing practices such as billing cycles,
fees, deposits, shutoffs,date and collection of unpaid bills for retail customers of
electricdue date from 17 days to 22
days, and gas utilities. These rules will have aneliminate estimated $3 million
negative effect on our earnings formetering readings unless actual readings are not
feasible. We are presently evaluating the periodimpacts of these proposed rules and
an estimated
negative effect on our cash flow of up to $50 million for 2006.
MCV PARTNERSHIP NEGATIVE EQUITY: Dueare working with other Michigan utilities in providing comments to the impairment ofMPSC
regarding the MCV Facility and
operating losses from mark-to-market adjustments on derivative instruments, the
equity held by Consumers and by all of the owners of the MCV Partnership has
decreased significantly and is now negative. Since Consumers is one of the
general partners of the MCV Partnership, we have recognized a portion of the
limited partners' negative equity. As the MCV Partnership recognizes future
losses, we will continue to assume a portion of the limited partners' share of
those losses, in addition to our proportionate share.proposed rule changes.
LITIGATION AND REGULATORY INVESTIGATION: CMS Energy is the subject of various
investigations as a result of round-trip trading transactions by CMS MST,
including an investigation by the DOJ. For additional details regarding this
investigation and litigation, see Note 2, Contingencies.
PENSION REFORM: In August 2006, the President signed into law the Pension
Protection Act of 2006. The bill reforms the funding rules for employer-provided
pension plans, effective for plan years beginning after 2007. We are in the
process of determining the impactAs a result of
this legislation.
CE-26bill, we expect to reduce our contributions to the Pension Plan over the
next 10 years by a present value amount of $53 million.
CE-19
Consumers Energy Company
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 123(R)158, EMPLOYERS' ACCOUNTING FOR DEFINED BENEFIT PENSION AND SABOTHER
POSTRETIREMENT PLANS - AN AMENDMENT OF FASB STATEMENTS NO. 107, SHARE-BASED PAYMENT:87, 88, 106, AND
132(R): In September 2006, the FASB issued SFAS No. 123(R)158. Phase one of this
standard required us to recognize the funded status of our defined benefit
postretirement plans on our Consolidated Balance Sheets at December 31, 2006.
Phase one was implemented in December 2006. Phase two of this standard requires
companiesthat we change our plan measurement date from November 30 to use the fair valueDecember 31,
effective December 31, 2008. We do not believe that implementation of employee stock options and similar awards at
the grant date to value the awards. SFAS No. 123(R) was effective for usphase two
of this standard will have a material effect on January 1, 2006.our consolidated financial
statements. We electedexpect to adopt the modified prospective method recognitionmeasurement date provisions of this Statement instead of retrospective restatement. We adopted
the fair value method of accounting for share-based awards effective December
2002. Therefore, SFAS No. 123(R) did not have a significant impact on our
results of operations when it became effective. We applied the additional
guidance provided by SAB No. 107 upon implementation of SFAS No. 123(R). For
additional details, see Note 7, Executive Incentive Compensation.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE158
in 2008.
FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006,We adopted the FASB
issuedprovisions of
FIN 48 effective for uson January 1, 2007. This interpretation provides a two-step approach for
the recognition and measurement of uncertain tax positions taken, or expected to
be taken, by a company on its income tax returns. The first step is to evaluate
the tax position to determine if, based on management's best judgment, it is
greater than 50 percent likely that the taxing
authoritywe will sustain the tax position. The second
step is to measure the appropriate amount of the benefit to recognize. This is
done by estimating the potential outcomes and recognizing the greatest amount
that has a cumulative probability of at least 50 percent. We are presently evaluating the impacts, if
any. Any initial impacts of implementing FIN 48 requires
interest and penalties, if applicable, to be accrued on differences between tax
positions recognized in our consolidated financial statements and the amount
claimed, or expected to be claimed, on the tax return.
As a result of the implementation of FIN 48, we have identified additional
uncertain tax benefits of $5 million as of January 1, 2007. Included in this
amount is an increase in our valuation allowance of $7 million, increases to tax
reserves of $55 million and a decrease to deferred tax liabilities of $57
million.
Consumers joins in the filing of a consolidated U.S. federal income tax return
as well as unitary and combined income tax returns in several states. Consumers
and its subsidiaries also file separate company income tax returns in several
states. The only significant state tax paid by Consumers or any of its
subsidiaires is in Michigan. However, since the Michigan Single Business Tax is
not an income tax, it is not part of the FIN 48 analysis. The IRS has completed
its audits for all the consolidated federal returns, of which Consumers is a
member, for years through 2001. The federal income tax returns for the years
2002 through 2005 are open under the statute of limitations.
We have reflected a net interest liability of $1 million related to our
uncertain income tax positions on our Consolidated Balance Sheets as of January
1, 2007. We have not accrued any penalties with respect to uncertain tax
benefits. We recognize accrued interest and penalties, where applicable, related
to uncertain tax benefits as part of income tax expense.
As of the date of adoption of FIN 48, we had valuation allowances against
certain deferred tax assets totaling $22 million and other net uncertain tax
positions of $55 million, resulting in total uncertain benefits of $77 million.
Of this amount, $24 million would result in a cumulative
adjustmentdecrease in our effective tax
rate, if recognized. We are not expecting any material changes to retained earnings.our uncertain
tax positions over the next 12 months.
CE-20
Consumers Energy Company
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 157, FAIR VALUE MEASUREMENTS: In September 2006, the FASB issued SFAS
No. 157, effective for us January 1, 2008. The standard provides a revised
definition of "fair value" and gives guidance on how to measure the fair value
of assets and liabilities. Under the standard, fair value is defined as the
price that would be received to sell an asset or paid to transfer a liability in
an orderly exchange between market participants. The standard does not expand
the use of fair value in any new circumstances. However, additional disclosures
will be required on the impact and reliability of fair value measurements
reflected in theour consolidated financial statements. The standard will also
eliminate the existing prohibition of recognizing "day one" gains or losses on
derivative instruments, and will generally require such gains and losses to be
recognized through earnings. We are presently evaluating the impacts, if any, of
implementing SFAS No. 157. We currently do not hold any derivatives that would
involve day one gains or losses.
SFAS NO. 158, EMPLOYERS' ACCOUNTING159, THE FAIR VALUE OPTION FOR DEFINED BENEFIT PENSIONFINANCIAL ASSETS AND OTHER
POSTRETIREMENT PLANS -FINANCIAL
LIABILITIES, INCLUDING AN AMENDMENT OFTO FASB STATEMENTSSTATEMENT NO. 87, 88, 106, AND
132(R):115: In September 2006,February 2007,
the FASB issued SFAS No. 158.159, effective for us January 1, 2008. This standard
will requiregive us the option to select certain financial instruments and other items,
which otherwise are not required to be measured at fair value, and measure those
items at fair value. If we choose to elect the fair value option for an item, we
would recognize the funded status of our defined benefit postretirement
plans on our balance sheets at December 31, 2006. SFAS No. 158 will require us
to recognizeunrealized gains and losses associated with changes in the funded statusfair
value of our plans in the year initem over time. The statement will also require disclosures for
items for which the changes occur. Upon implementation of this standard,fair value option has been elected. We are presently
evaluating whether we expectwill choose to record an
additional postretirement benefit liability of approximately $617 million and a
regulatory asset of $612 million. We expect a reduction of $3 million toelect the fair value option for any
financial instruments or other comprehensive income, after tax. Regulatory asset treatment is consistent with
past MPSC and FERC guidance. This standard also requires that we change our plan
measurement date from November 30 to December 31, effective December 31, 2008.
We do not believe that implementation of this provision of the standard would
have a material effect on our financial statements.
CE-27
Consumers Energy Company
STAFF ACCOUNTING BULLETIN NO. 108, CONSIDERING THE EFFECTS OF PRIOR YEAR
MISSTATEMENTS WHEN QUANTIFYING MISSTATEMENTS IN CURRENT YEAR FINANCIAL
STATEMENTS: In September 2006, the SEC issued SAB No. 108, effective for us
December 31, 2006. This accounting bulletin clarifies how registrants should
assess the materiality of prior period financial statement errors in the current
period. We do not presently believe that adoption of this standard would have a
material effect on our financial position or results of operations.
CE-28
Consumers Energy Company
(This page intentionally left blank)
CE-29items.
CE-21
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(LOSS)
(UNAUDITED)
In Millions
--------------------------------------------------------
Three Months Ended
Nine Months Ended
------------------
-----------------
September 30March 31 2007 2006
2005 2006 2005
- -------------------- ------ ------
------ -----
OPERATING REVENUE $1,191 $1,025 $4,111 $3,673
EARNINGS FROM EQUITY METHOD INVESTEES - 1 1 1$2,055 $1,782
OPERATING EXPENSES Fuel for electric generation 213 183 557 49488 172
Fuel costs mark-to-market at the MCV Partnership 28 (197) 226 (367)-- 156
Purchased and interchange power 183 145 427 272307 110
Purchased power - related parties 18 19 55 5018
Cost of gas sold 125 133 1,164 1,115935 816
Other operating expenses 226 212 661 601220 215
Maintenance 64 53 214 15557 71
Depreciation depletion, and amortization 119 113 387 369156 152
General taxes (24) 46 97 164
Asset impairment charges - 1,184 - 1,18464 65
------ ------
------ ------
952 1,891 3,788 4,037
------ ------1,846 1,775
------ ------
OPERATING INCOME (LOSS) 239 (865) 324 (363)209 7
OTHER INCOME Accretion expense - - - (1)
(DEDUCTIONS) Interest and dividends 18 9 44 2411 10
(DEDUCTIONS) Regulatory return on capital expenditures 8 17 18 483
Other income 3 6 17 167 4
Other expense (1) (2) (5) (10)(3) (3)
------ ------
------ ------
28 30 74 77
------ ------23 14
------ ------
INTEREST CHARGES Interest on long-term debt 70 70 216 21759 72
Interest on long-term debt - related parties - 32 1 12
Other interest 4 - 12 41 3
Capitalized interest (3) (2) (1) (7) (3)
------ ------
------ ------
72 72 222 230
------ ------59 74
------ ------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY
INTERESTS 195 (907) 176 (516)OBLIGATIONS, NET 173 (53)
MINORITY INTERESTS (OBLIGATIONS),OBLIGATIONS, NET 40 (483) (35) (386)
------ -------- (72)
------ ------
INCOME (LOSS) BEFORE INCOME TAXES 155 (424) 211 (130)173 19
INCOME TAX (BENEFIT) EXPENSE 56 (148) 66 (44)
------ ------60 9
------ ------
NET INCOME (LOSS) 99 (276) 145 (86)113 10
PREFERRED STOCK DIVIDENDS - - 1 1
------ --------
------ ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER $ 99112 $ (276) $ 144 $ (87)
====== ======10
====== ======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-30CE-22
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
In Millions
-----------------
Nine------------------
Three Months Ended
-----------------
September 30------------------
March 31 2007 2006
2005
- -------------------- ----- ------------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 145113 $ (86)10
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation depletion, and amortization (includes nuclear
decommissioning of $3$1 per year) 387 369period) 156 152
Deferred income taxes and investment tax credit (267) (97)9 (51)
Fuel costs mark-to-market at the MCV Partnership 226 (367)
Asset impairment charges - 1,184-- 156
Minority interests (obligations),obligations, net (35) (386)-- (72)
Regulatory return on capital expenditures (18) (48)(8) (3)
Capital lease and other amortization 27 25
Earnings from equity method investees (1) (1)9 9
Changes in assets and liabilities:
Decrease (increase)Increase in accounts receivable, notes
receivable and accrued revenue 212 (44)
Increase(448) (212)
Decrease (increase) in accrued power supply and
gas revenue 27 (26)
Decrease in inventories (256) (351)
Decrease in deferred property taxes 101 105504 366
Increase (decrease) in accounts payable (93) 177
Increase (decrease)20 (120)
Decrease in accrued expenses 40 (32)(53) (85)
Decrease in accrued taxes (248) (121)
Increase (decrease) in the MCV Partnership gas supplier
funds on deposit (159) 275-- (90)
Decrease (increase) in other current and
non-current assets (8) 7557 (4)
Increase (decrease) in other current and
non-current liabilities 36 (36)(15) 39
----- ------------
Net cash provided by operating activities 89 641371 69
----- ------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under
capital lease) (461) (419)(218) (125)
Cost to retire property (41) (21)(5) (19)
Restricted cash and restricted short-term investments 126 (163)(1) 128
Investments in nuclear decommissioning trust funds (20) (5)(1) (17)
Proceeds from nuclear decommissioning trust funds 20 31
Proceeds from short-term investments - 145
Purchase of short-term investments - (141)2 4
Maturity of the MCV Partnership restricted investment
securities held-to-maturity 119 316-- 28
Purchase of the MCV Partnership restricted investment
securities held-to-maturity (118) (267)
Cash proceeds from sale of assets - 1-- (26)
Other investing 2 4
12
----- ------------
Net cash used in investing activities (371) (511)(221) (23)
----- ------------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long term debt - 910
Retirement of long-term debt (208) (1,020)(8) (136)
Payment of common stock dividends (71) (207)
Payment of preferred stock dividends (1) (1)(94) (40)
Payment of capital and finance lease obligations (23) (26)(2) (3)
Stockholder's contribution, net -- 200
550
IncreasePayment of preferred stock dividends (1) --
Decrease in notes payable, 100 -net (42) (27)
Debt issuance and financing costs (1) (3)
(29)
----- ------------
Net cash provided by (used in)used in financing activities (6) 177
===== =======(148) (9)
----- -----
Net Increase (Decrease) in Cash and Cash Equivalents (288) 3072 37
Cash and Cash Equivalents, Beginning of Period 37 416
171
----- ------------
Cash and Cash Equivalents, End of Period $ 12839 $ 478453
===== ============
CE-31THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-23
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
In Millions
--------------------------
September 30
2006-------------------------
March 31
2007 December 31
(Unaudited) 2005
------------2006
----------- -----------
PLANT AND PROPERTY Electric $ 8,4348,583 $ 8,2048,504
(AT COST) Gas 3,239 3,1513,283 3,273
Other 241 22715 15
------- -------
11,914 11,58211,881 11,792
Less accumulated depreciation,
depletion, and amortization 4,934 4,8045,073 5,018
------- -------
6,980 6,7786,808 6,774
Construction work-in-progress 572 509751 639
------- -------
7,552 7,2877,559 7,413
------- -------
INVESTMENTS Stock of affiliates 32 33 36
Other 4 75 5
------- -------
36 4038 41
------- -------
CURRENT ASSETS Cash and cash equivalents at
cost, which approximates market 128 41639 37
Restricted cash and restricted short-term investmentsat cost, which
approximates market 58 57
183
Accounts receivable, notes
receivable, and accrued
revenue, less allowances of $14
in 2007 and $14 in 2006 849 435
Accrued power supply and $13 in 2005 344 640
Notes receivable 63 13gas
revenue 129 156
Accounts receivable - related
parties 7 95 5
Inventories at average cost
Gas in underground storage 1,293 1,068619 1,129
Materials and supplies 80 7586 81
Generating plant fuel stock 106 80105
Deferred property taxes 124 159131 150
Regulatory assets - postretirement
benefits 19 19
Derivative instruments 48 242
Prepayments and other 111 7049 50
------- -------
2,380 2,9742,090 2,224
------- -------
NON-CURRENT ASSETS Regulatory assets
Securitized costs 526 560
Additional minimum pension 399 399502 514
Postretirement benefits 99 1161,111 1,131
Customer Choice Act 197 222179 190
Other 469 484506 497
Nuclear decommissioning trust funds 582 555606 602
Other 477 520188 233
------- -------
2,749 2,8563,092 3,167
------- -------
TOTAL ASSETS $12,717 $13,157$12,779 $12,845
======= =======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-32CE-24
STOCKHOLDER'S INVESTMENT AND LIABILITIES
In Millions
----------------------------
September 30
2006-------------------------
March 31
2007 December 31
(Unaudited) 2005
------------2006
----------- -----------
CAPITALIZATION Common stockholder's equity
Common stock, authorized 125.0
shares; outstanding
84.1 shares for all periods $ 841 $ 841
Paid-in capital 1,832 1,6321,832
Accumulated other comprehensive
income 42 7214 15
Retained earnings since December 31, 1992 306 233283 270
------- -------
3,021 2,7782,970 2,958
Preferred stock 44 44
Long-term debt 4,256 4,3033,962 4,127
Non-current portion of capital
leases and finance lease obligations 296 30852 42
------- -------
7,617 7,433
------- -------
MINORITY INTERESTS 252 2597,028 7,171
------- -------
CURRENT LIABILITIES Current portion of long-term debt
LIABILITIES and capital leases and finance leases 86 112
Current portion of long-term debt - related parties - 129202 44
Notes payable - related parties 127 27-- 42
Accounts payable 386 458442 421
Accrued revenue for refund 5 37
Accounts payable - related parties 19 4017 18
Accrued interest 58 8247 62
Accrued taxes 152 400343 295
Deferred income taxes 98 55
MCV Partnership gas supplier funds on deposit 34 19315 11
Other 204 150124 184
------- -------
1,164 1,6461,195 1,114
------- -------
NON-CURRENT LIABILITIES Deferred income taxes 682 1,027794 847
LIABILITIES Regulatory liabilities
Regulatory liabilities for cost
of removal 1,174 1,1201,200 1,166
Income taxes, net 475 455547 539
Other regulatory liabilities 236 178240 249
Postretirement benefits 353 3081,002 993
Asset retirement obligations 495 494507 497
Deferred investment tax credit 63 6761 62
Other 206 170205 207
------- -------
3,684 3,8194,556 4,560
------- -------
Commitments and Contingencies (Notes 2, 3, and 4)
TOTAL STOCKHOLDER'S INVESTMENT AND LIABILITIES $12,717 $13,157$12,779 $12,845
======= =======
CE-33CE-25
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(UNAUDITED)
In Millions
--------------------------------------------------------
Three Months Ended
Nine Months Ended
------------------
-----------------
September 30March 31 2007 2006
2005 2006 2005
- ------------ ------ ------ -------------- ------- ------
COMMON STOCK At beginning and end of period (a) $ 841 $ 841
$ 841 $ 841
------ ------ ------ ------
OTHER PAID-IN CAPITAL At beginning of period 1,832 1,482 1,632
932CAPITAL Stockholder's contribution - --- 200 550
------ ------
------ ------
At end of period 1,832 1,482 1,832 1,482
------ ------
------ ------
ACCUMULATED OTHER Minimum pensionRetirement benefits liability
COMPREHENSIVE INCOME At beginning of period (2) (2) (2) (1)
Minimum pension liability adjustment (b) - - - (1)
------ ------ ------ ------
Atand end
INCOME of period (8) (2) (2) (2) (2)
------ ------
------ ------
Investments
At beginning of period 1623 18
18 12
Unrealized gainloss on investments
(b) 3 3 1 9
------ ------(1) (2)
------ ------
At end of period 19 21 19 21
------ ------22 16
------ ------
Derivative instruments
At beginning of period 39 32-- 56
20
Unrealized gain (loss)loss on derivative
instruments (b) (13) 27 (27) 50-- (10)
Reclassification adjustments
included in net income (loss) (b) (1)-- (2) (4) (13)
------ ------
------ ------
At end of period 25 57 25 57
------ -------- 44
------ ------
Total Accumulated Other
Comprehensive Income 42 76 42 76
------ ------14 58
------ ------
RETAINED EARNINGS At beginning of period 238 630270 233
608Adjustment to initially apply
FIN 48 (5) --
Net income (loss) 99 (276) 145 (86)113 10
Cash dividends declared -
Common Stock (31)(94) (40) (71) (207)
Cash dividends declared - Preferred
Stock - - (1) (1)
------ --------
------ ------
At end of period 306 314 306 314
------ ------283 203
------ ------
TOTAL COMMON STOCKHOLDER'S EQUITY $3,021 $2,713 $3,021 $2,713
====== ======$2,970 $2,934
====== ======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-34CE-26
In Millions
--------------------------------------------------------
Three Months Ended
Nine Months Ended
------------------
-----------------
September 30March 31 2007 2006
2005 2006 2005
- ------------ ---- ------------- ---- ----
(a) Number of shares of common stock outstanding was
84,108,789 for all periods presented.
(b) Disclosure of Other Comprehensive Income:
Minimum Pension Liability
Minimum pension liability adjustment, net of tax of
$-, $-, $-, and $-, respectively $ - $ - $ - $ (1)
Investments
Unrealized gainloss on investments, net of tax of
$2, $2, $-,$(1) in 2007 and $5, respectively$(1) in 2006 $ 3(1) $ 3 $ 1 $ 9(2)
Derivative instruments
Unrealized gain (loss)loss on derivative instruments, net of
tax (tax
benefit) of $(7), $15, $(14),$-- in 2007 and $27, respectively (13) 27 (27) 50$(5) in 2006 -- (10)
Reclassification adjustments included in net
income, (loss), net of tax benefit of $(1), $(1), $(2),$-- in 2007 and
$(7), respectively (1)$(1) in 2006 -- (2) (4) (13)
Net income (loss) 99 (276) 145 (86)
---- -----113 10
---- ----
Total Comprehensive Income (Loss)$112 $ 88 $(248) $115 $(41)
==== =====(4)
==== ====
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Consumers Energy Company
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CE-28
Consumers Energy Company
CONSUMERS ENERGY COMPANY
CONDENSED
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
These interim Consolidated Financial Statements have been prepared by Consumers
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in consolidated financial statements prepared in
accordance with accounting principles generally accepted in the United States
have been condensed or omitted. Certain prior year amounts have been
reclassified to conform to the presentation in the current year. In management's
opinion, the unaudited information contained in this report reflects all
adjustments of a normal recurring nature necessary to assure the fair
presentation of financial position, results of operations and cash flows for the
periods presented. The Condensed Notes to Consolidated Financial Statements and the
related Consolidated Financial Statements should be read in conjunction with the
Consolidated Financial Statements and related Notes contained in the Consumers'
Form 10-K for the year ended December 31, 2005.2006. Due to the seasonal nature of
Consumers' operations, the results as presented for this interim period are not
necessarily indicative of results to be achieved for the fiscal year.
1: CORPORATE STRUCTURE AND ACCOUNTING POLICIES
CORPORATE STRUCTURE: Consumers, a subsidiary of CMS Energy, a holding company,
is a combination electric and gas utility company serving Michigan's Lower
Peninsula. Our customer base includes a mix of residential, commercial, and
diversified industrial customers. We manage our business by the nature of
services each provides and operate principally in two business segments:
electric utility and gas utility.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include
Consumers, and all other entities in which we have a controlling financial
interest or are the primary beneficiary, in accordance with FASB Interpretation
No.FIN 46(R). We use
the equity method of accounting for investments in companies and partnerships
that are not consolidated, where we have significant influence over operations
and financial policies, but are not the primary beneficiary. We eliminate
intercompany transactions and balances.
USE OF ESTIMATES: We prepare our consolidated financial statements in conformity
with U.S. GAAP. We are required to make estimates using assumptions that may
affect the reported amounts and disclosures. Actual results could differ from
those estimates.
We are required to record estimated liabilities for contingencies in theour consolidated financial
statements when it is probable that a loss will be incurred in the future as a
result of a current event, and when the amount can be reasonably estimated. We
have used this accounting principle to record estimated liabilities as discussed
inFor
additional details, see Note 2, Contingencies.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity
and natural gas, and the storage of natural gas when services are provided. Sales taxes are recorded as liabilities and are not included in revenues.
CE-37
Consumers Energy Company
ACCOUNTING FOR MISO TRANSACTIONS: We
account for MISO transactionsrecord sales tax on a net basis for all of our generating units combined.and exclude it from revenues.
RECLASSIFICATIONS: We record billing adjustments
when invoices are received and also record an expense accrual for future
adjustments based on historical experience.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. We periodically perform tests of impairment ifhave reclassified certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $12.717
billion at September 30, 2006, 60 percent represent long-lived assets and equity
method investments that are subject to this type of analysis.
In August 2006, we auctioned off 36 parcels of land near Ludington, Michigan. We
held a majority share of the land, which we co-owned with DTE Energy. We closed
on all 36 parcels in October 2006. Our portion of the proceeds is approximately
$6 million.
DETERMINATION OF PENSION MRV OF PLAN ASSETS: We determine the MRV for pension
plan assets, as defined in SFAS No. 87, as the fair value of plan assets on the
measurement date, adjusted by the gains or losses that will not be admitted into
MRV until future years. We reflect each year's assets gain or loss in MRV in
equal amounts over a five-year period beginning on the date the original amount
was determined. The MRV is used in the calculation of net pension cost.
OTHER INCOME AND OTHER EXPENSE: The following tables show the components of
Other income and Other expense:
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Other income
Electric restructuring return $1 $1 $ 3 $ 5
Return on stranded and security costs 1 1 4 4
Nitrogen oxide allowance sales 1 1 7 2
Gain on stock - - 1 1
All other - 3 2 4
--- --- --- ---
Total other income $3 $6 $17 $16
=== === === ===
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Other expense
Loss on reacquired debt $ - $ - $ - $ (6)
Civic and political expenditures (1) (1) (2) (2)
Donations - - (1) -
Loss on SERP investment - (1) - (1)
All other - - (2) (1)
--- --- --- ----
Total other expense $(1) $(2) $(5) $(10)
=== === === ====
CE-38
Consumers Energy Company
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the periods presented.
CE-29
Consumers Energy Company
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE: SFAS No. 157, Fair Value
Measurements: In September 2006, the FASB issued SFAS No. 157, effective for us
January 1, 2008. The standard provides a revised definition of "fair value" and
gives guidance on how to measure the fair value of assets and liabilities. Under
the standard, fair value is defined as the price that would be received to sell
an asset or paid to transfer a liability in an orderly exchange between market
participants. The standard does not expand the use of fair value in any new
circumstances. However, additional disclosures will be required on the impact
and reliability of fair value measurements reflected in theour consolidated
financial statements. The standard will also eliminate the existing prohibition
of recognizing "day one" gains or losses on derivative instruments, and will
generally require such gains and losses to be recognized through earnings. We
are presently evaluating the impacts, if any, of implementing SFAS No. 157. We
currently do not hold any derivatives that would involve day one gains or
losses.
SFAS No. 158, Employers' Accounting159, The Fair Value Option for Defined Benefit PensionFinancial Assets and Other
Postretirement Plans -Financial
Liabilities, Including an amendment ofto FASB StatementsStatement No. 87, 88, 106, and
132(R): For details on SFAS No. 158, see Note 5, Retirement Benefits.
FIN 48, Accounting for Uncertainty in Income Taxes:115: In June 2006,February 2007,
the FASB issued FIN 48,SFAS No. 159, effective for us January 1, 2007.2008. This interpretation provides a
two-step approach forstandard
will give us the recognitionoption to select certain financial instruments and measurement of uncertain tax positions
taken, or expectedother items,
which otherwise are not required to be taken, by a company on its income tax returns. The
first step ismeasured at fair value, and measure those
items at fair value. If we choose to evaluateelect the tax position to determine if, based on
management's best judgment, it is greater than 50 percent likely thatfair value option for an item, we
would recognize unrealized gains and losses associated with changes in the taxing
authority will sustain the tax position. The second step is to measure the
appropriate amountfair
value of the benefit to recognize. This is done by estimatingitem over time. The statement will also require disclosures for
items for which the potential outcomes and recognizing the greatest amount thatfair value option has a cumulative
probability of at least 50 percent.been elected. We are presently
evaluating whether we will choose to elect the impacts, if
any. Any initial impacts of implementing FIN 48 would result in a cumulative
adjustment to retained earnings.
Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year
Misstatements when Quantifying Misstatements in Current Year Financial
Statements: In September 2006, the SEC issued SAB No. 108, effectivefair value option for us
December 31, 2006. This accounting bulletin clarifies how registrants should
assess the materiality of prior periodany
financial statement errors in the current
period. We do not presently believe that adoption of this standard would have a
material effect on our financial positioninstruments or results of operations.other items.
2: CONTINGENCIES
SEC AND OTHERDOJ INVESTIGATIONS: During the period of May 2000 through January 2002,
CMS MST engaged in simultaneous, prearranged commodity trading transactions in
which energy commodities were sold and repurchased at the same price. These so
called round-trip trades had no impact on previously reported consolidated net
income, earnings per share or cash flows, but had the effect of increasing
operating revenues and operating expenses by equal amounts.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip
trading, which the DOJ commenced in May 2002. CMS Energy is unable to predict
the outcome of this matter and what effect, if any, this investigation will have
on its business. In March 2004, the SEC approved a cease-and-desist order
settling an administrative action against CMS Energy related to round-trip
trading. The order did not assess a fine and CMS Energy neither admitted to nor
denied the order's findings. CE-39
Consumers Energy Company
The settlement resolved the SEC investigation
involving CMS Energy and CMS MST. Also in March 2004, the SEC filed an action
against three former employees related to round-trip trading at CMS MST. One of
the individuals has settled with the SEC. CMS Energy is currently advancing
legal defense costs for the remaining two individuals in accordance with
existing indemnification policies. Those two individuals filed a motion to
dismiss the SEC action, which was denied.
CE-30
Consumers Energy Company
SECURITIES CLASS ACTION LAWSUITS: Beginning onin May 17, 2002, a number of complaints
were filed against CMS Energy, Consumers and certain officers and directors of
CMS Energy and its affiliates.affiliates in the United States District Court for the
Eastern District of Michigan. The cases were consolidated into a single lawsuit
(the "Shareholder Action"), which generally seeks unspecified damages based on
allegations that the defendants violated United States securities laws and
regulations by making allegedly false and misleading statements about CMS
Energy's business and financial condition, particularly with respect to revenues
and expenses recorded in connection with round-trip trading by CMS MST. In
January 2005, the court granted a motion to dismiss Consumers and three of the
individual defendants, but denied the motions to dismiss CMS Energy and the 13
remaining individual defendants. The court issued an opinion and order datedIn March 24, 2006, granting
in part and denying in part plaintiffs' amended motion for class certification.
Thethe court conditionally
certified a class consisting of "[a]ll"all persons who purchased CMS Common Stock
during the period of October 25, 2000 through and including May 17, 2002 and who
were damaged thereby." The court excluded purchasers of CMS Energy's 8.75
percent Adjustable Convertible Trust Securities ("ACTS") from the class. Trial has been scheduled for March 2007. Inclass and, in
response, to
the court's opinion and order excluding purchasers of ACTS from the shareholder
class, a new class action lawsuit was filed on behalf of ACTS purchasers. The
new lawsuit namespurchasers (the
"ACTS Action") against the same defendants asnamed in the shareholder actionShareholder Action. The
settlement described in the following paragraph, if approved, will resolve both
the Shareholder and contains
essentially the same allegations and class period.ACTS Actions.
On January 3, 2007, CMS Energy and the individual
defendants will defend themselves vigorously in this litigation but cannot
predict its outcome.
ERISA LAWSUITS: CMS Energy wasother parties entered into a named defendant, along with Consumers, CMS MST,
and certain named and unnamed officers and directors, in two lawsuits, filed in
July 2002 in United States District Court for the Eastern DistrictMemorandum of
Michigan,
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings PlanUnderstanding (the Plan). Plaintiffs alleged breaches of
fiduciary duties under ERISA and sought restitution on behalf of the Plan with
respect to a decline in value of the shares of CMS Energy Common Stock held in
the Plan, as well as other equitable relief and legal fees. On March 1, 2006,
CMS Energy and Consumers reached an agreement,"MOU"), subject to court and independent
fiduciary approval, to settleregarding settlement of
the two class action lawsuits. The settlement agreement requiredwas approved by a $28special
committee of independent directors and by the full board of directors of CMS
Energy. Both judged that it was in the best interests of shareholders to
eliminate this business uncertainty. The MOU is expected to lead to a detailed
stipulation of settlement that will be presented to the assigned federal judge
and the affected class in the second quarter of 2007. Under the terms of the
MOU, the litigation will be settled for a total of $200 million, cash payment by CMS Energy's primary insurer to be used to pay Plan
participantsincluding the
cost of administering the settlement and beneficiaries for alleged losses, as well as any legalattorney fees and
expenses. In addition,the court awards. CMS
Energy agreedwill make a payment of approximately $123 million plus an amount
equivalent to certain other steps regarding
administrationinterest on the outstanding unpaid settlement balance beginning on
the date of the Plan. The hearing on finalpreliminary approval of the court and running until the balance of
the settlement was
held on June 15,funds is paid into a settlement account. Out of the total
settlement, CMS Energy's insurers will pay approximately $77 million directly to
the settlement account. CMS Energy took an approximate $123 million net pre-tax
charge to 2006 earnings in the fourth quarter of 2006. On June 27, 2006,In entering into the judge enteredMOU,
CMS Energy makes no admission of liability under the OrderShareholder Action and Final
Judgment, approving the
proposed settlement with minor modifications.ACTS Action.
ELECTRIC CONTINGENCIES
ELECTRIC ENVIRONMENTAL MATTERS: Our operations are subject to environmental laws
and regulations. Costs to operate our facilities in compliance with these laws
and regulations generally have been recovered in customer rates.
Clean Air Act: Compliance with the federal Clean Air Act and resulting
regulations has been, and will continue to be, a significant focus for us. The
Nitrogen Oxide State Implementation Plan requires significant reductions in
nitrogen oxide emissions. To comply with the regulations, we expect to incur
capital expenditures totaling $835 million through 2011. The key assumptions in
the capital expenditure estimate include:
CE-40
Consumers Energy Company
- construction commodity prices, especially construction material and
labor,
- project completion schedules,
- cost escalation factor used to estimate future years' costs, and
- an AFUDC capitalization rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 7.8 percent. As of September 2006, we have
incurred $660 million in capital expenditures to comply with the federal Clean
Air Act and resulting regulations and anticipate that the remaining $175 million
of capital expenditures will be made in 2006 through 2011. These expenditures
include installing selective catalytic reduction control technology at four of
our coal-fired electric generating plants.
In addition to modifying coal-fired electric generating plants, our compliance
plan includes the use of nitrogen oxide emission allowances until all of the
control equipment is operational in 2011. The nitrogen oxide emission allowance
annual expense is projected to be $4 million per year, which we expect to
recover from our customers through the PSCR process. The projected annual
expense is based on market price forecasts and forecasts of regulatory
provisions, known as progressive flow control, that restrict the usage in any
given year of allowances banked from previous years. The allowances and their
cost are accounted for as inventory. The allowance inventory is expensed at the
rolling average cost as the coal-fired electric generating plants emit nitrogen
oxide.
Clean Air Interstate Rule: In March 2005, the EPA adopted the Clean Air
Interstate Rule that requires additional coal-fired electric generating plant
emission controls for nitrogen oxides and sulfur dioxide. The rule involves a
two-phase program to reduce emissions of nitrogen oxides by more than 60 percent
and sulfur dioxide by more than 70 percent from 2003 levels by 2015. The final
rule will require that we run our selective catalytic reduction control
technology units year round beginning in 2009 and may require that we purchase
additional nitrogen oxide allowances beginning in 2009.
In addition to the selective catalytic reduction control technology installed to
meet the nitrogen oxide standards, our current plan includes installation of
flue gas desulfurization scrubbers. The scrubbers are to be installed by 2014 to
meet the Phase I reduction requirements of the Clean Air Interstate Rule, at an
estimated total cost of $960 million. Our capital cost estimates include an
escalation rate of 2.6 percent and an AFUDC capitalization rate of 8.4 percent.
We currently have a surplus of sulfur dioxide allowances, which were granted by
the EPA and are accounted for as inventory. In January 2006, we sold some of our
excess sulfur dioxide allowances for $61 million and recognized the proceeds as
a regulatory liability.
Clean Air Mercury Rule: Also in March 2005, the EPA issued the Clean Air Mercury
Rule, which requires initial reductions of mercury emissions from coal-fired
electric generating plants by 2010 and further reductions by 2018. The Clean Air
Mercury Rule establishes a cap-and-trade system for mercury emissions that is
similar to the system used in the Clean Air Interstate Rule. The industry has
not reached a consensus on the technical methods for curtailing mercury
emissions. However, based on current technology, we anticipate our capital costs
for mercury emissions reductions required by Phase I of the Clean Air Mercury
Rule to be less than $50 million and these reductions implemented by 2010. Phase
II requirements of the Clean Air Mercury Rule are not yet known and a cost
estimate has not been determined.
In August 2005, the MDEQ filed a Motion to Intervene in a court challenge to
certain aspects of EPA's
CE-41
Consumers Energy Company
Clean Air Mercury Rule, asserting that the rule is inadequate. We cannot predict
the outcome of this proceeding.
In April 2006, Michigan's governor announced a plan that would result in mercury
emissions reductions of 90 percent by 2015. This plan would adopt the Clean Air
Mercury Rule through its first phase. Beginning in year 2015, the mercury
emissions reduction standards outlined in the governor's plan would become more
stringent than those included in the Clean Air Mercury Rule. We are working with
the MDEQ on the details of these rules. We will develop a cost estimate when the
details of these rules are determined.Routine Maintenance Classification: The EPA has alleged that some utilities have
incorrectly classified plant modifications as "routine maintenance" rather than
seeking permits to modify the plant from the EPA. We have received and responded
to information requests from the EPA on this subject. We believe that we have
properly interpreted the requirements of "routine maintenance." If our
interpretation is found to be incorrect, we may be required to install
additional pollution controls at some or all of our coal-fired electric
generating plants and potentially pay fines. Additionally, the viability of
certain plants remaining in operation could be called into question.
Cleanup and Solid Waste: Under the Michigan Natural Resources and Environmental
Protection Act, we expect that we will ultimately incur investigation and
remedial action costs at a number of sites. We believe that these costs will be
recoverable in rates under current ratemaking policies.
CE-31
Consumers Energy Company
We are a potentially responsible party at several contaminated sites
administered under the Superfund. Superfund liability is joint and several,
meaning that many other creditworthy parties with substantial assets are
potentially responsible with respect to the individual sites. Based on our
experience, we estimate that our share of the total liability for the known
Superfund sites will be between $1 million and $10 million. At September 30, 2006,March 31, 2007,
we have recorded a liability for the minimum amount of our estimated probable in
accordance with FIN 14. The timing of payments related to the remediation of our
Superfund liability.sites is uncertain. Any significant change in assumptions, such as
different remediation techniques, nature and extent of contamination, and legal
and regulatory requirements, could affect our estimate of remedial action costs
and the timing of our remediation payments.
Ludington PCB: In October 1998, during routine maintenance activities, we
identified PCB as a component in certain paint, grout, and sealant materials at
Ludington. We removed and replaced part of the PCB material. We have proposedSince proposing a
plan to deal with the remaining materials, andwe have had several conversations
with the EPA. The EPA has proposed a rule which would authorize continued use of
such material in place, subject to certain restrictions. We are awaitingnot able to
predict when a responsefinal rule will be issued.
Electric Utility Plant Air Permit Issues: In April 2007, we received a Notice of
Violation/Finding of Violation from the EPA.
MCV Environmental Issue: In July 2004,EPA alleging that fourteen of our
utility boilers exceeded visible emission limits in their associated air
permits. The utility boilers are located at the MDEQ, Air Control Division, issuedD.E. Karn/J.C. Weadock
Generating Complex, the MCV Partnership a Letter of Violation asserting thatJ.H. Campbell Plant, the MCV Facility
violated its Air Use Permit to Install (PTI) by exceeding the carbon monoxide
emission limit on the Unit 14 duct burner and failing to maintain certain
records in the required format. The MCV Partnership thereafter declared five of
the six duct burners in the MCV Facility as unavailable for operational use
(which reduced the generation capability of the MCV Facility by approximately
100 MW) and took other corrective action to address the MDEQ's assertions.
Following voluntary settlement discussions, the MDEQ issued the MCV Partnership
a new PTI, which established higher carbon monoxide emissions limits on the five
duct burners that had been declared unavailable. The MCV Partnership has
returned those duct burners to service. The MDEQBC Cobb Electric Generating
Station and the MCV Partnership have
agreed to a settlementJR Whiting Plant. We are preparing for discussions with the EPA
regarding these allegations, but cannot predict the financial impact or outcome
of the emission violation, which will also satisfy state
and federal requirements and remove the MCV Partnership from the EPA's High
Priority Violators List. The settlement involves a fine of $45,000. The
settlement is subject to public notice and comment. The MCV Partnership believes
it has resolved all issues associated with this Letter of Violation and does not
expect further MDEQ action on this matter.issue.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities (the
plaintiffs), which sell
CE-42
Consumers Energy Company power to us, filed a lawsuit in Ingham County Circuit
Court. The lawsuit alleged that we incorrectly calculated the energy charge
payments made pursuant to power purchase agreements with qualifying facilities.
In February 2004, the Ingham
County Circuit CourtThe judge deferred to the primary jurisdiction of the MPSC, dismissing the
circuit court case without prejudice. The Michigan Court of
Appeals upheld this order on the primary jurisdiction question, but remanded the
case back on another issue. In February 2005, the MPSC issued an order
in the 2004 PSCR plan case concluding that we have been correctly administering
the energy charge calculation methodology. The plaintiffs have appealed the MPSC
order to the Michigan Court of Appeals. The plaintiffs also filed suit in the
United States Court for the Western District of Michigan, which the judge
subsequently dismissed.dismissed on the basis that the pending state court litigation
would fully resolve any federal issue before the courts. The plaintiffs havethen
appealed the dismissal to the United States Court of Appeals.Appeals, which held that
the district court matter should be stayed rather than dismissed, pending the
outcome of the state appeal. We cannot predict the outcome of these appeals.
CE-32
Consumers Energy Company
ELECTRIC RESTRUCTURINGRATE MATTERS
ELECTRIC ROA: The Customer Choice Act allows allIn prior orders, the MPSC approved recovery of Stranded Costs
incurred from 2002 through 2003 plus the cost of money through the period of
collection. At March 31, 2007, we had a regulatory asset for Stranded Costs of
$66 million on our electric customers to
buy electric generation service from us or from an alternative electric
supplier.Consolidated Balance Sheets. We collect Stranded Costs
through a surcharge on ROA customers. At September 30, 2006,March 31, 2007, alternative electric
suppliers were providing 308283 MW of generation service to ROA customers, which
represents four percent of
our total distribution load. This representsrepresent a decrease of one19 percent of ROA load compared to June 30, 2006 and a decrease of 60 percent ofMarch 31, 2006. This
downward trend has affected negatively our ability to recover timely our
Stranded Costs. If downward ROA load comparedtrends continue, it may require legislative or
regulatory assistance to recover fully our Stranded Costs. However, the end of September 2005.Customer
Choice Act allows electric utilities to recover their net Stranded Costs. It is
difficult to predict future ROA customer trends.
STRANDED COSTS: Prior MPSC orders adopted a mechanism pursuant totrends and their effect on the Customer
Choice Act to providetimely
recovery of Stranded Costs that occur when customers leave
our system to purchase electricity from alternative suppliers. In November 2005,
we filed an application with the MPSC related to the determination of 2004
Stranded Costs. Applying the Stranded Cost methodology used in prior MPSC
orders, we concluded that we experienced Stranded Costs in 2004; however, we
also concluded that these costs were offset completely by our net sales of
excess power into the bulk electricity market. In September 2006, the MPSC
issued an order approving our proposal and the resulting conclusion that our
Stranded Costs for 2004 were fully offset by wholesale sales into the bulk
electricity market. The MPSC also determined that this order completes the
series of Stranded Cost cases resulting from the Customer Choice Act.
ELECTRIC RATE MATTERS
POWER SUPPLY COSTS: To reduce the risk of high electric pricespower supply costs during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasingpurchase electric
capacity and energy contracts for the physical delivery of electricity primarily
in the summer months and to a lesser degree in the winter months. We have
purchased capacity and energy contracts covering partially the estimated reserve
margin requirements for 2007 through 2010. As a result, we have recognized an asset of $63$62
million for unexpired seasonal capacity and energy contracts at September 30, 2006. At September 2006,March 31, 2007.
As of March 31, 2007, we expect the total capacity cost ofcosts for these primarily seasonal
electric capacity and energy contracts for 2006 to be $17 million.$14 million for 2007.
PSCR: The PSCR process allows recovery of reasonable and prudent power supply
costs. Revenues from the PSCR charges are subject to reconciliation after review
of actualThe MPSC reviews these costs for reasonableness and prudence.prudency in annual
plan proceedings and in plan reconciliation proceedings. The following table
summarizes our PSCR reconciliation filings with the MPSC:
Power Supply Cost Recovery Reconciliation
PSCR Cost
Net Under- of Power Description of Net
PSCR Year Date Filed Order Date recovery Sold Underrecovery
- --------- ---------- ---------- ------------ -------------- -----------------------------------------
2005 Reconciliation March 2006 Pending $ 39 million $1.086 billion Underrecovery relates to our commercial
and industrial customers and includes the
cost of money.
2006 Reconciliation March 2007 Pending $115 million $1.492 billion Underrecovery relates to our increased
METC costs and coal supply costs,
increased bundled sales, and other cost
increases beyond those included in the
2006 PSCR plan filings.
2007 PSCR Plan: In September 2006, we filed our 2007 PSCR plan with the MPSC.
The plan sought authorization to incorporate our 2005 we submitted
ourand 2006 PSCR
plan filing to the MPSC. In November 2005, we submitted an amended
2006underrecoveries into our 2007 PSCR plan to the MPSC to include higher estimates for METC and coal supply
costs.monthly factor. In December 2005,2006, the MPSC
issued an order that temporarily excluded
these increased costs from our PSCR charge and further reduced the charge by one
mill per kWh. We implemented thea temporary order allowing us to implement our 2007 PSCR monthly factor
on January 1, 2007, as filed. The order also allowed us to continue to roll in
January 2006.
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Consumers Energy Company
In August 2006, the MPSC issued an order approving our amended 2006 PSCR plan,
which resultsUnderrecoveries in an increased PSCR factor for the remainder of 2006. We expect
PSCR underrecoveries for 2006 of $116 million. These underrecoveries are due to
the MPSC delaying recovery of our increased METC and coalpower supply costs increased bundled sales, and other cost increases beyond thoseare included in the
September 2005Accrued power supply and
November 2005 filings.gas revenue on our Consolidated Balance Sheets. We expect to recover fully all
of our
2006 PSCR costs. When we are unable to collect these costs as they are
incurred, there is a negative impact on our cash flows from electric utility
operations. In March 2006, we submitted our 2005 PSCR reconciliation filing to the MPSC. We
estimate an underrecovery of $39 million for commercial and industrial
customers, which we expect to recover fully. We cannot predict the outcome of these PSCR proceedings.
ELECTRIC RATE CASE: In September 2006,March 2007, we submitted our 2007 PSCR plan filingfiled an application with the MPSC seeking
an 11.25 percent authorized return on equity and an annual increase in revenues
of $157 million as shown in the following table:
In Millions
-----------
Components of the increase in revenue
Reduction in base rates (a) $(23)
Surcharge for return on nuclear investments (b) 13
Elimination of Palisades base rate recovery credit (c) 167
----
Total increase in revenues $157
====
(a) The reduction in base rates is due to the removal of Palisades related
costs offset by Clean Air Act related and other utility expenditures,
changes in the capital structure, and increased distribution system
operation and maintenance costs including employee pension and health care
costs.
(b) The nuclear surcharge is a proposal to earn a return on funds spent on Big
Rock spent nuclear fuel storage, decommissioning, and site restoration
expenditures until pending DOE litigation and future MPSC which
includesproceedings
regarding this issue are concluded.
(c) Palisades power purchase agreement costs are currently offset through
feedback in the underrecoveries incurred in 2005 and 2006. We expectPSCR related to self-implementPalisades base rate revenues via a base
rate recovery credit. The Palisades base rate recovery credit will be
discontinued once Palisades' costs are removed from base rates.
If approved as requested, the proposed 2007 PSCR chargerate requests would go into effect in January 2007, absent action by
the MPSC by the end of 2006.2008
and would apply to all retail electric customers. We cannot predict the outcomeamount
or timing of this proceeding.any MPSC decision on the requests.
OTHER ELECTRIC CONTINGENCIES
THE MIDLAND COGENERATION VENTURE:MCV PPA: The MCV Partnership, which leases and operates the MCV Facility,
contracted to sell 1,240 MW of electricity to Consumers forunder a 35-year periodpower
purchase agreement beginning in 1990. We hold a 49 percent partnership interest inestimate that capacity and energy
payments under the MCV Partnership, and a 35 percent lessor interest in the MCV Facility. In 2004, we
consolidated the MCV Partnership and the FMLP into our consolidated financial
statements in accordance with FASB Interpretation No. 46(R).
Sale of our Interest in the MCV Partnership and the FMLP: In July 2006, we
reached an agreement to sell 100 percent of the stock of CMS Midland, Inc. and
CMS Midland Holdings Company to an affiliate of GSO Capital Partners and
Rockland Capital Energy Investments for $60.5 million. These Consumers'
subsidiaries hold our interest in the MCV Partnership and the FMLP.PPA will be $620 million per year. The sale
does not affect the MCV PPA and the
associated customer rates. Werates are targeting
to close on the saleunaffected by the end of 2006. The sale is subject to various
regulatory approvals, including the MPSC's approval and the expiration of the
waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976.
In JulyNovember 2006 the MPSC issued an order establishing a contested case proceeding
and provided a schedule, which will allow for a decision from the MPSC by the
end of 2006. In October 2006, we reached a settlement agreement with the MPSC
Staff and the parties involved, which recommends that the MPSC grant all
authorizations necessary to complete the sale of our
interestsinterest in the MCV Partnership and the FMLP. The MPSC's approval of the settlement agreement is
required for it to become effective. If approved by the MPSC, the settlement
agreement requires us to file reports subsequent to the closing providing
details of the amount of net proceeds available for debt reduction and what type
of debt was reduced, and to file an amended 2007 through 2011 PSCR plan to
address potential changes related to the MCV PPA and the RCP. We cannot predict
the timing or the outcome of the MPSC's decision nor can we predict with
certainty whether or when this transaction will be completed.
Because of the power purchase agreement in place between Consumers and the MCV
Partnership, the transaction is effectively a sale and leaseback for accounting
purposes. SFAS No. 98 specifies the accounting required for a seller's sale and
simultaneous leaseback transaction involving real estate, including real estate
with equipment. In accordance with SFAS No. 98, the transaction will be required
to be accounted for as a financing and not a sale. This is due to forms of
continuing involvement we will have with the MCV Partnership. At closing, we
will remove from our Consolidated Balance Sheets all of the assets, liabilities,
and minority interest associated with both the MCV Partnership and
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Consumers Energy Company
the FMLP except for the real estate assets and equipment of the MCV Partnership.
Those assets will remain at their carrying value. If the fair value is
determined to be less than the present carrying value, an impairment charge
would result.
Further, as disclosed in Note 4, Financial and Derivative Instruments,
"Derivative Contracts Associated with the MCV Partnership," we will reflect in
earnings certain cumulative amounts of the MCV Partnership-related derivative
fair value changes that are accounted for in other comprehensive income. We will
also reflect in earnings income related to certain of the MCV Partnership gas
contracts, which are being sold. The transaction will not result in the MCV
Partnership or the FMLP assets being classified as held for sale on our
Consolidated Balance Sheets.
Financial Condition of the MCV Partnership: Under the MCV PPA, variable energy
payments to the MCV Partnership are based on the cost of coal burned at our coal
plants and our operation and maintenance expenses. However, the MCV
Partnership's costs of producing electricity are tied to the cost of natural
gas. Historically high natural gas prices have caused the MCV Partnership to
reevaluate the economics of operating the MCV Facility and to record an
impairment charge in 2005. If natural gas prices remain at present levels or
increase, the operations of the MCV Facility would be adversely affected and
could result in the MCV Partnership failing to meet its obligations under the
sale and leaseback transactions and other contracts. Due to the impairment of
the MCV Facility and subsequent losses, the value of the equity held by all of
the owners of the MCV Partnership has decreased significantly and is now
negative. Since we are one of the general partners of the MCV Partnership, we
have recognized a portion of the limited partners' negative equity. At September
30, 2006, the negative minority interest for the other general partners' share,
including their portion of the limited partners' negative equity, is $101
million and is included in Other Non-current Assets on our Consolidated Balance
Sheets.
Underrecoveries related to the MCV PPA: Further, theThe cost that we incur under the MCV PPA
exceeds the recovery amount allowed by the MPSC. We expense allestimate cash
underrecoveries directly to income. We estimate underrecoveries of $56 million
in 2006our capacity and fixed energy payments of $39 million in 2007. Of the 2006 estimate,2007
of which we have expensed $42$13 million during the ninethree months ended September 30, 2006.March 31,
2007. However, our directwe use savings from the RCP, after allocating a portion to
customers, are used to offset a portion of our capacity and fixed energy underrecoveries
expense.
RCP: In January 2005, we implemented the MPSC-approved RCP with modifications.
The RCP allows us to recover the same amount of capacity and fixed energy
charges from customers as approved
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Consumers Energy Company
in prior MPSC orders. However, we are able to dispatch the MCV Facility based on
natural gas market prices. This results in fuel cost savings for the MCV
Facility, which the MCV Partnership shares with us. The RCP also requires us to
contribute $5 million annually to a renewable resources program. As of March
2007, we have contributed $12 million to the renewable resources program. The
underlying RCP agreement between Consumers and the MCV Partnership extends
through the term of the MCV PPA. However, either party may terminate that
agreement under certain conditions. In January 2007, the Michigan Attorney
General filed an appeal with the Michigan Supreme Court regarding the MPSC's
order approving the RCP. We cannot predict the outcome of this matter.
Regulatory Out Provision in the MCV PPA: After September 15, 2007, we expect to
claim relief under the regulatory out provision in the MCV PPA, thereby limiting
our capacity and fixed energy payments to the MCV Partnership to the amounts
that we collect from our customers. The MCV Partnership has indicatednotified us that it
may taketakes issue with our intended exercise of the regulatory out provision after September 15, 2007.provision. We
believe that the provision is valid and fully effective, but cannot assure that
it will prevail in the event of a dispute. If we are successful in exercising
the regulatory out provision, the MCV Partnership hasmay, under certain
circumstances, have the right to terminate or reduce the amount of capacity sold
under the MCV PPA from 1,240 MW to 806 MW, which could affect our reserve
margin. In addition, the MPSC's future actions on the capacity and fixed
energy payments after September 15, 2007 may further affect negatively the
financial performance of the MCV Partnership, if such action resulted in us
claiming additional relief under the regulatory out provision. We anticipate that the MPSC will review our exercise of the regulatory
out provision and the likely consequences of such action will be reviewed by the MPSC in 2007. Some parties have suggestedIt is possible
that in the event that the MCV Partnership ceases performance under the MCV PPA,
prior orders could limit recovery of replacement power costs to the amounts that
the MSPCMPSC authorized for recovery under the MCV PPA. We cannot predict the
outcome of any future disputes concerning these issues.
RCP: In January 2005, the MPSC issued an order approving the RCP, with
modifications. The RCP allows us to recover the same amount of capacity and
fixed energy charges from customers as approved in prior MPSC orders. However,
we are able to dispatch the MCV FacilityDepending on the basiscost of
natural gas
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Consumers Energy Company
market prices, which reducesreplacement power, this could result in our costs exceeding the MCV Facility's annual production of electricity
and, as a result, reduces the MCV Facility's consumption of natural gas by an
estimated 30 to 40 bcf annually. This decrease in the quantity of high-priced
natural gas consumedrecovery amount
allowed by the MCV Facility benefits our interest in the MCV
Partnership. The RCP also calls for us to contribute $5 million annually to a
renewable resources program. As of September 2006, we have contributed $9
million to the renewable resources program.
In January 2005, we implemented the RCP. The underlying agreement for the RCP
between Consumers and the MCV Partnership extends through the term of the MCV
PPA. However, either party may terminate that agreement under certain
conditions. In February 2005, a group of intervenors in the RCP case filed for
rehearing of the MPSC order approving the RCP, which the MPSC denied in October
2006. The Attorney General also filed an appeal with the Michigan Court of
Appeals.MPSC. We cannot predict the outcome of these matters.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004,To comply with a prior MPSC order, we made a filing in May 2007 with the Michigan Tax Tribunal
issued its decision inMPSC,
which asked the MPSC to make a determination regarding whether it wished to
reconsider the amount of the MCV Partnership's tax appeal against the City of
Midland for tax years 1997 through 2000. The City of Midland appealed the
decision to the Michigan Court of Appeals, and the MCV Partnership filed a
cross-appeal at the Michigan Court of Appeals. The MCV Partnership also has a
pending case with the Michigan Tax Tribunal for tax years 2001 through 2006. The
MCV Partnership estimates that the 1997 through 2005 tax year cases will result
in a refund to the MCV Partnership of $88 million, inclusive of interest, if the
decision of the Michigan Tax Tribunal is upheld. In February 2006, the Michigan
Court of Appeals largely affirmed the Michigan Tax Tribunal decision, but
remanded the case back to the Michigan Tax Tribunal to clarify certain aspects
of the Tax Tribunal decision. In April 2006, the City of Midland filed an
application for Leave to Appeal with the Michigan Supreme Court. The remanded
proceedings may result in the determination of a greater refund to the MCV
Partnership. In July 2006, the Michigan Supreme Court denied the City of
Midland's application, which resulted in the MCV Partnership recognizing the $88
million refund as a reduction in property tax expense.
NUCLEAR PLANT DECOMMISSIONING: The MPSC and the FERC regulate the recovery of
costs to decommission, or remove from service, our Big Rock and Palisades
nuclear plants. Decommissioning funding practices approved by the MPSC require
us to file a report on the adequacy of funds for decommissioning at three-year
intervals. We prepared and filed updated cost estimates for Big Rock and
Palisades in March 2004. Excluding additional costs for spent nuclear fuel
storage due to the DOE's failure to accept this spent nuclear fuel on schedule,
these reports show a decommissioning cost of $361 million for Big Rock and $868
million for Palisades. Since Big Rock is currently in the process of
decommissioning, this estimated cost includes historical expenditures in nominal
dollars and future costs in 2003 dollars, with all Palisades costs given in 2003
dollars. Updated cost projections for Big Rock indicate an anticipated
decommissioning cost of $393 million as of June 2006.
Big Rock: In December 2000, funding of the Big Rock trust fund stopped because
the MPSC-authorized decommissioning surcharge collection period expired. In our
March 2004 report to the MPSC, we indicatedPPA payments that we would manage the
decommissioning trust fundrecover from customers. We
are unable to meet annual NRC financial assurance requirements
by withdrawing NRC radiological decommissioning costs from the fund and
initially funding non-NRC, greenfield costs out of corporate funds. In March
2006, we contributed $16 million to the trust fund from our corporate funds to
support NRC radiological decommissioning costs. Excluding the additional nuclear
fuel storage costs due to the DOE's failure to accept spent fuel on schedule, we
are projecting that the level of funds provided by the trust will fall short of
the amount needed to complete the decommissioning by $39 million, which is the
amount projected for non-NRC, greenfield costs. We plan initially to fund the
$39 million out of corporate funds. Therefore, at this
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Consumers Energy Company
time, we plan to provide a total of $55 million from corporate funds for costs
associated with NRC radiological and non-NRC greenfield decommissioning work. We
plan to seek recovery of such expenditures. We cannot predict the outcome of these efforts.
Palisades: Excluding additionalthis request.
THE SALE OF NUCLEAR ASSETS AND THE PALISADES POWER PURCHASE AGREEMENT: Sale of
Nuclear Assets: In April 2007, we sold Palisades to Entergy for $380 million.
The final purchase price was subject to various closing adjustments such as
working capital and capital expenditure adjustments and nuclear fuel storage costs dueusage and
inventory adjustments resulting in us receiving $361 million. We also paid
Entergy $30 million to the DOE's
failure to accept spent fuel on schedule, we concluded, based on the cost
estimates filed in March 2004, that the existing Palisades' surcharge of $6
million needed to be increased to $25 million annually, beginning January 2006.
A settlement agreement was approved by the MPSC, providingassume ownership and responsibility for the continuationBig Rock
ISFSI. Because of the existing $6 million annual decommissioning surcharge through 2011, our
current license expiration date, and for the next periodic review to be filed in
March 2007. Amounts collected from electric retail customers and deposited in
trusts, including trust earnings, are credited to a regulatory liability.
In March 2005,sale of Palisades, we will also pay the NMC, which operatesthe former
operator of the Palisades plant, applied for a
20-year license renewal$7 million in exit fees and will forfeit our
investment in the NMC of $5 million.
Entergy will assume responsibility for the future decommissioning of the
Palisades plant on behalfand for storage and disposal of Consumers. We expect a
decision from the NRC on the license renewal application in 2007. At this time,
we cannot determine what impact this will have on decommissioning costs or the
adequacy of funding. Initial estimates of decommissioning costs, assuming a
plant retirement date of 2031, show decommissioning costs of either $818 million
or $1.049 billion for Palisades, depending on the decommissioning methodology
assumed. These costs, which exclude additional costs for spent nuclear fuel storage due tolocated at
the DOE's failure to accept spent nuclear fuel on schedule, are
given in 2003 dollars.
In July 2006, we reached an agreement to sell Palisades and the Big Rock ISFSI sites. At closing, we transferred $252
million in decommissioning trust fund balances to Entergy.
As partThe MPSC order approving the Palisades transaction allows us to recover the
estimated $314 million book value of the Palisades plant. As a result, we
estimate that we will credit excess proceeds of $66 million to our retail
customers through refunds applied over the remainder of 2007 and 2008. The MPSC
order deferred ruling on the recovery of $30 million in estimated transaction
costs, including the NMC exit fees, and the $30 million payment to Entergy
related to the Big Rock ISFSI until the next general rate case. We will defer
these costs as a regulatory asset on our Consolidated Balance Sheets as recovery
is probable.
In April 2007, the NRC, through its staff, issued an order approving the
transfer of the Palisades operating license. Subsequently, in April 2007, the
NRC issued an order requiring that certain intervenors be given, under a
protective order, information related to the buyer's financial capability. If,
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Consumers Energy Company
after the review of the information, the intervenors wished to seek additional
proceedings on the license transfer, the NRC would consider the request. The NRC
did not alter or stay the prior order approving the license transfer. We believe
that it is unlikely that the NRC will conduct further proceedings, but we cannot
predict the outcome of the matter. These events did not hold up the closing of
the sale of Palisades.
The following table summarizes the estimated impacts of the Palisades and the
Big Rock ISFSI transactions:
In Millions
- ------------------------------------------------------------------------------------------------------------------------
Customer Benefits (a) Deferred costs
- --------------------- ----------------------------------------
Purchase price $380 NMC exit fee $ 7
Less: Estimated book value of Palisades plant 314 Forfeiture of the NMC investment 5
----
Excess proceeds to be refunded to customers 66(b) Estimated selling expenses 18
Excess decommissioning trust funds to be refunded to customers 189(c) Big Rock ISFSI operation and maintenance
fee to Entergy 30
---- ---
Total estimated customer refunds $255 Total regulatory asset $60
==== ===
(a) In the FERC's February 2007 order regarding the Palisades transaction, the
FERC granted our request to apply $11 million in FERC decommissioning trust
fund balances for the Palisades plant toward the Big Rock decommissioning
shortfall, as described in "Big Rock Nuclear Plant Decommissioning" within
this section. The order was contingent upon the NRC approving the transfer
of operating licenses, which the NRC approved in April 2007. This
determination is the subject of a clarification request filed by a
wholesale customer with the FERC.
(b) Final proceeds in excess of the book value are subject to closing
adjustments and review by the MPSC.
(c) In the MPSC's March 2007 order approving the Palisades transaction, the
MPSC indicated that $189 million of MPSC jurisdictional decommissioning
funds must be credited to our retail customers through refunds applied over
the remainder of 2007 and 2008. Final disposition of these funds is subject
to closing date balances and is subject to review by the MPSC. The
remaining estimated $116 million of the MPSC jurisdictional decommissioning
funds, which is subject to closing date reconciliation will be used to
benefit our retail customers and is expected to be addressed in a separate
filing made with the MPSC.
Palisades Power Purchase Agreement: Entergy contracted to sell us 100 percent of
the plant's output up to its current annual average capacity of 798 MW under a
15-year power purchase agreement.agreement beginning in April 2007. We provided $30
million in security to Entergy for our power purchase agreement obligation in
the form of a letter of credit. We estimate that capacity and energy payments
under the Palisades power purchase agreement will be $300 million per year.
Because of the Palisades power purchase agreement, that will be in
place between Consumers and Entergy, the transaction is effectively a sale and
leaseback for accounting purposes. SFAS No. 98 specifies the accounting required
for a seller's sale and simultaneous leaseback transaction involving real estate, includingestate. We will
have continuing involvement with the Palisades plant through security provided
to Entergy for our power purchase agreement obligation, our DOE liability, and
other forms of involvement. As a result, we will account for the Palisades
plant, which is the real estate with equipment. In accordance with SFAS No. 98,asset subject to the transaction will be accounted forleaseback, as a financing
for accounting purposes and not a sale. This is due
to forms of continuing involvement.We will account for the remaining
non-real estate assets and liabilities associated with the transaction as a
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Consumers Energy Company
sale.
As such, we have not classifieda financing, the assets
as held for salePalisades plant will remain on our Consolidated Balance
Sheets.Sheets and the related proceeds will be recorded as a financing obligation. The
sale is subject to various regulatory approvals, including the MPSC's
approvalvalue of the power purchase agreement,finance obligation is based on an allocation of the FERC's approval for Entergytransaction
proceeds to sell power to usthe fair values of the net assets sold and fair value of the
Palisades plant assets under the power purchase agreement and other related matters,financing.
BIG ROCK NUCLEAR PLANT DECOMMISSIONING: The MPSC and the NRC's approvalFERC regulate the
recovery of costs to decommission the Big Rock nuclear plant. In December 2000,
funding of the transferBig Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. In a March 2007 report to
the MPSC, we indicated that we have managed the decommissioning trust fund to
meet the annual NRC financial assurance requirements by withdrawing NRC
radiological decommissioning costs from the trust fund and initially funding
non-NRC greenfield costs out of corporate funds. In March 2006, we contributed
corporate funds of $16 million to the trust fund to support the NRC radiological
decommissioning costs. Excluding the additional nuclear fuel storage costs due
to the DOE's failure to accept spent nuclear fuel on schedule, we are projecting
the level of funds provided by the trust will fall short of the operating licenseamount needed to
Entergycomplete decommissioning by an additional $36 million. This total of $52
million, which are costs associated with NRC radiological and other related matters. In October 2006, the Federal Trade Commission issued a
notice that neither it nor the Departmentnon-NRC greenfield
decommissioning work, are being funded out of Justice's Antitrust Divisioncorporate funds. We plan to take enforcement actionseek
recovery of expenditures that we have funded in future filings with the MPSC
and have a $36 million regulatory asset recorded on our Consolidated Balance
Sheets as of March 31, 2007.
Cost projections for Big Rock indicate a decommissioning cost of $389 million as
of March 2007, of which we have incurred $387 million. These amounts exclude the
sale. The final purchase price will be subject
to various closing adjustments such as working capital and capital expenditure
adjustments, adjustmentsadditional costs for spent nuclear fuel usage and inventory, andstorage due to the dateDOE's failure to
accept this spent nuclear fuel on schedule. They also exclude post September 11
increased security costs that we are recovering through the security cost
recovery provisions of closing. Under the agreement, if the transaction does not close by March 1,
2007, the purchase pricePublic Act 609 of 2002. These activities had no material
impact on consolidated net income. Any remaining Big Rock decommissioning costs
will initially be reduced by $80,000 per day with additional
costs if the sale does not close by June 1, 2007. We cannot predict with
certainty whether or when the closing conditions will be satisfied or whether or
when this transaction will be completed.funded out of corporate funds.
NUCLEAR MATTERS: Nuclear Fuel Cost: We amortizeamortized nuclear fuel cost to fuel
expense based on the quantity of heat produced for electric generation. For
nuclear fuel used after April 6, 1983, we chargecharged certain disposal costs to
nuclear fuel expense, recoverrecovered these costs through electric rates, and remitremitted
them to the DOE quarterly. We elected to defer payment for disposal of spent
nuclear fuel burned before April 7, 1983. At September 30, 2006, ourOur DOE liability is $150 million.$154 million at
March 31, 2007. This amount includes interest, which is payable upon the first
delivery of spent nuclear fuel to the DOE. TheWe have recovered, through electric
rates, the amount of this liability, excluding a portion of interest, was recovered through electric rates.interest. In
conjunction with the
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Consumers Energy Company sale of Palisades and the Big Rock ISFSI, we will retainretained this
obligation and provideprovided $155 million in security to Entergy for this obligation
in the form of either cash, a letter of credit, or other acceptable means.credit.
DOE Litigation: In 1997, a U.S. Court of Appeals decision confirmed that the DOE
was to begin accepting deliveries of spent nuclear fuel for disposal by January
1998. Subsequent U.S. Court of Appeals litigation, in which we and other
utilities participated, has not been successful in producing more specific
relief for the DOE's failure to accept the spent nuclear fuel.
There are two court decisions that support the right of utilities to pursue
damage claims in the United States Court of Claims against the DOE for failure
to take delivery of spent nuclear fuel. Over 60 utilities have initiated
litigation in the United States Court of Claims. We filed our complaint in
December 2002. If our litigation against the DOE is successful, we plan to use
any recoveries to payas reimbursement for the costincurred costs of spent nuclear fuel
storage until the DOE takes
possession as required by law.during our ownership of Palisades
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Consumers Energy Company
and Big Rock. We can make no assurance that the litigation against the DOE will
be successful. The sale of Palisades and the Big Rock ISFSI did not transfer the
right to any recoveries from the DOE related to costs of spent nuclear fuel
storage incurred during our ownership of Palisades and Big Rock.
In 2002, the site at Yucca Mountain, Nevada was designated for the development
of a repository for the disposal of high-level radioactive waste and spent
nuclear fuel. We expect that the DOE, in due course, will submit a final license
application to the NRC for the repository. The application and review process is
estimated to take several years.
Insurance: We maintainmaintained nuclear insurance coverage on our nuclear plants.plants until
Palisades and the Big Rock ISFSI were sold in April 2007. At Palisades, we
maintainmaintained nuclear property insurance from NEIL totaling $2.750 billion and
insurance that would partially cover the cost of replacement power during
certain prolonged accidental outages. Because NEIL is a mutual insurance
company, we could be subject to assessments of up to $30 million in any policy
year if insured losses in excess of NEIL's maximum policyholders surplus occur
at our, or any other member's, nuclear facility. NEIL's policies include
coverage for acts of terrorism.
At Palisades, we maintainmaintained nuclear liability insurance for third-party bodily
injury and off-site property damage resulting from a nuclear energy hazard for
up to approximately $10.761 billion, the maximum insurance liability limits
established by the Price-Anderson Act. Part of the Price-Anderson Act's
financial protection is a mandatory industry-wide program under which owners of
nuclear generating facilities could be assessed if a nuclear incident occurs at
any nuclear generating facility. The maximum assessment against us could be $101
million per occurrence, limited to maximum annual installment payments of $15
million.
We also maintainmaintained insurance under a program that covers tort claims for bodily
injury to nuclear workers caused by nuclear hazards. The policy contains a $300
million nuclear industry aggregate limit. Under a previous insurance program
providing coverage for claims brought by nuclear workers, we remain responsible
for a maximum assessment of up to $6 million. This requirement will end December
31, 2007.
Big Rock remainswas insured for nuclear liability up to $544 million through nuclear
insurance and the NRC indemnity, and maintainswe maintained a nuclear property insurance
policy from NEIL.
Insurance policy terms, limits, and conditions are subject to change during the
year as we renew our policies.
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GAS CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to incur investigation and remediation
costs at a number of sites under the Michigan Natural Resources and
Environmental Protection Act, a Michigan statute that covers environmental
activities including remediation. These sites include 23 former manufactured gas
plant facilities. We operated the facilities on these sites for some part of
their operating lives. For some of these sites, we have no current ownership or
may own only a portion of the original site. In 2005, we estimated our remaining
costs to be between $29 million and $71 million, based on 2005 discounted costs,
using a discount rate of three percent. The discount rate represents a 10-year
average of U.S. Treasury bond rates reduced for increases in the consumer price
index. We expect to fund most of these costs through proceeds derived from a
settlement with insurers and MPSC-approved rates. At September 30, 2006,March 31, 2007, we have a
liability of $26$22 million, net of $56$60 million of expenditures incurred to date,
and a regulatory asset of $58$55 million. The timing of payments related to the
remediation of our
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manufactured gas plant sites is uncertain. Any significant change in
assumptions, such as an increase in the number of sites, different remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could affect our estimate of remedial action costs.costs and the timing
our remediation payments.
GAS RATE MATTERS
GAS COST RECOVERY: The GCR process is designed to allow us to recover all of our
purchased natural gas costs if incurred under reasonable and prudent policies
and practices. The MPSC reviews these costs, policies, and practices for
prudency in annual plan and reconciliation proceedings.
The following table summarizes our GCR reconciliation filings with the MPSC:
Gas Cost Recovery Reconciliation
- ---------------------------------------------------------------------------------------
Net Over- GCR Cost of Description of
GCR Year Date Filed Order Date recovery Gas Sold Description of Net Overrecovery
- ----------------- ---------- ---------- ---------- ------------ ----------------------------------------------------
2004-20052005-2006 June 20052006 April 2006 $22007 $3 million $1.4$1.8 billion The net overrecovery
includes $1 million
interest expenseincome
through March 2005 and refunds that we
received2006,
which resulted from our suppliers
that are requireda
net underrecovery
position during the
majority of the GCR
period. In 2007, the
MPSC approved a
settlement agreement,
agreeing to be
refunded to our customers.
2005-2006 June 2006 Pendinga $3
million $1.8 billion The net
overrecovery includes
$1 million interest income
through March 2006, which
resulted from a net
underrecovery position during
the majority of the GCR period.amount.
Overrecoveries in cost of gas sold are included in Accrued rate refunds on our
Consolidated Balance Sheets.
GCR plan for year 2005-2006: In November 2005, the MPSC issued an order for our
2005-2006 GCR Plan year, which resulted in approval of a settlement agreement
and established a fixed price cap of $10.10 per mcf for the December 2005
through March 2006 billing period. We were able to maintain our GCR billing GCR
factor below the authorized level for that period. The order was appealed to the
Michigan Court of Appeals by one intervenor. No action has been taken by the
Court of Appeals on the merits of the appeal and weWe are unable to predict the
outcome.outcome of this proceeding.
GCR plan for year 2006-2007: In August 2006, the MPSC issued an order for our
2006-2007 GCR Plan year, which resulted in approval of a settlement agreement
that allowed a base GCR ceiling factor of $9.48 per mcf for the 12-month period
of April 2006 through March 2007. We were able to maintain our GCR billing
factor below the authorized level for that period.
GCR plan for year 2007-2008: In December 2005,2006, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 20062007
through March 2007.2008. Our request proposed using a GCR factor consisting of:
- a base GCR ceiling factor of $11.10$8.47 per mcf, plus
CE-49
Consumers Energy Company
- a quarterly GCR ceiling price adjustment contingent upon future
events.
In July 2006, all parties signed a partial settlement agreement, which calls for
a base GCR ceiling factor of $9.48 per mcf. The settlement agreement base GCR
ceiling factor is subject to a quarterly GCR ceiling price adjustment mechanism.
The adjustment mechanism allows an adjustment of the base ceiling factor to
reflect a portion of cost increases, if the average NYMEX price for a specified
period is greater than that used in calculating the base GCR factor. The MPSC
approved the settlement agreement in August 2006.
The GCR billing factor is adjusted monthly in order to minimize the over or
under-recoveryunderrecovery amounts in our annual GCR reconciliation. Our GCR billing factor
for the month of November 2006May 2007 is $7.83$8.24 per mcf.
2001 GAS DEPRECIATION CASE: In October and December 2004, the MPSC issued
Opinions and Orders in our gas depreciation case, which:
- reaffirmed the previously-ordered $34 million reduction in our
depreciation expense,
- required us to undertake a study to determine why our plant removal
costs are in excess of other regulated Michigan natural gas utilities,
and
- required us to file a study report with the MPSC Staff on or before
December 31, 2005.
We filed the study report with the MPSC Staff on December 29, 2005.
We are also required to file our next gas depreciation case within 90 days after
the MPSC issuance of a final order in the pending case related to ARO
accounting. We cannot predict when the MPSC will issue a final order in the ARO
accounting case.
If the depreciation case order is issued after the gas general rate case order,
we proposed to incorporate its results into the gas general rates using a
surcharge mechanism, a process used to incorporate specialty items into customer
rates.
2005CE-39
Consumers Energy Company
2007 GAS RATE CASE: In July 2005,February 2007, we filed an application with the MPSC
seeking a 12an 11.25 percent authorized return on equity along with a $132an $88 million
annual increase in our gas delivery and transportation rates. As partrates, of this filing,
we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony in October
2005. In its testimony, the MPSC Staff recommended granting interim rate relief
of $38 million.
In February 2006, the MPSC Staff recommended granting final rate relief of $62
million. The MPSC Staff proposed thatwhich $17
million of this amountwould be contributed to a low income and energy efficiency fund. The MPSC Staff also recommended
reducing our allowed return on common equity to 11.15 percent, from our current
11.4 percent.
In March 2006, the MPSC Staff revised its recommended final rate relief to $71
million, which includes $17 million to be contributed to a low income and energy
efficiency fund. In April 2006, we revised our request for final rate relief
downward to $118 million.
In May 2006, the MPSC issued an order granting us interim gas rate relief of $18
million annually, which is under bond and subject to refund if final rate relief
is granted in a lesser amount. The order
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Consumers Energy Company
also extended the temporary two-year surcharge of $58 million granted in October
2004 until the issuance of a final order in this proceeding. The MPSC has not
set a date for issuance of an order granting final rate relief.
In July 2006, the ALJ issued a Proposal for Decision recommending final rate
relief of $74 million above current rate levels, which include interim and
temporary rate relief. The $74 million includes $17 million to be contributed to
a low income and energy efficiency fund. The Proposal for Decision also
recommended reducing our return on common equity to 11 percent, from our current
11.4 percent.
OTHER CONTINGENCIES
IRS AUDIT RESOLUTION: In August 2005, the IRS issued Revenue Ruling 2005-53 and
regulations to provide guidance with respect toWe have
proposed the use of the "simplifieda Revenue Decoupling and Conservation Incentive Mechanism
for residential and general service cost" methodrate classes to help assure a reasonable
opportunity to recover costs regardless of tax accounting. We have been using this tax accounting
method, generally allowed by the IRS under section 263A of the Internal Revenue
Code, with respect to the allocation of certain indirect overhead costs to the
tax basis of self-constructed utility assets.
In June 2006, the IRS concluded its most recent audit of CMS Energy and its
subsidiaries, and proposed changes to taxable income for the years ended
December 31, 1987 through December 31, 2001. The proposed overall cumulative
increase to taxable income related primarily to the disallowance of the
simplified service cost method with respect to certain self-constructed utility
assets. CMS Energy has accepted these proposed adjustments to taxable income,
which have been allocated based upon Consumers' separate taxable income in
accordance with CMS Energy's tax sharing agreement. We had tax related payables
to CMS Energy with respect to its share of audit adjustments of $232 million,
and a reduction of our June 2006 income tax provision of $14 million, net of
interest expense, primarily for the restoration and utilization of previously
written off income tax credits.sales levels.
OTHER CONTINGENCIES
OTHER: In addition to the matters disclosed within this Note, we are party to
certain lawsuits and administrative proceedings before various courts and
governmental agencies arising from the ordinary course of business. These
lawsuits and proceedings may involve personal injury, property damage,
contractual matters, environmental issues, federal and state taxes, rates,
licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed within this
Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or future results of
operations.
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS
FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: The
Interpretation requires the guarantor, upon issuance of a guarantee, to
recognize a liability for the fair value of the obligation it undertakes in
issuing the guarantee.
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Consumers Energy Company
The following table describes our guarantees at September 30, 2006:March 31, 2007:
In Millions
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
FIN 45
Expiration Maximum Carrying
Guarantee Description Issue Date Expiration Date Obligation Carrying Amount
- --------------------- ------------ --------------- ---------- ------------------------- --------
Surety bonds and other indemnifications Various Various $ 1 ---
Guarantee (a) January 1987 March 20152016 85 ---
Nuclear insurance retrospective premiumspremiums(a) Various Indefinite 137 ---
(a) We have reached an agreement to sellmaintained nuclear insurance coverage on our interests in the MCV Partnershipnuclear plants until
Palisades and the FMLP, subject to certain regulatoryBig Rock ISFSI were sold in April 2007. For more details
on the sale of Palisades and other closing conditions.Big Rock, see Note 2, Contingencies, "Other
Electric Contingencies - The sales agreement calls forSale of Nuclear Assets and the purchaser, an affiliate of GSO Capital
Partners and Rockland CapitalPalisades Power
Purchase Agreement."
CE-40
Consumers Energy Investments to pay $85 million,
subject to certain reimbursement rights, if Dow terminates an agreement
under which it is provided power and steam by the MCV Partnership. The
purchaser will secure their reimbursement obligation with an irrevocable
letter of credit of up to $85 million.Company
The following table provides additional information regarding our guarantees:
Events That Would Require
Guarantee Description How Guarantee Arose Performance
- --------------------- ------------------- -------------------------------------------------------- --------------------------------
Surety bonds and other Normal operating activity, Nonperformance
indemnifications activity, permits and licenses
Guarantee Agreement to provide power MCV Partnership's provide powernonperformance
and nonperformance or non-payment steam to Dow or non-payment under a related
contract
Nuclear insurance retrospective Normal operations of Call by NEIL and retrospectivePrice-Anderson
premiums of nuclear plants Price-Anderson Act for nuclear incident
At September 30, 2006, none ofMarch 31, 2007, only our guaranteesguarantee to provide power and steam to Dow
contained provisions allowing us to recover, from third parties, any amountamounts paid
under the guarantees.
We sold our interests in the MCV Partnership and the FMLP. The sales agreement
calls for the purchaser, an affiliate of GSO Capital Partners and Rockland
Capital Energy Investments, to pay Consumers $85 million, subject to certain
reimbursement rights, if Dow terminates an agreement under which the MCV
Partnership provides it steam and electric power. This agreement expires in
March 2016, subject to certain terms and conditions. The purchaser secured their
reimbursement obligation with an irrevocable letter of credit of up to $85
million.
We enter into various agreements containing tax and other indemnification
provisions in connection with a variety of transactions.transactions, including the sale of
our interests in the MCV Partnership and the FMLP. In April 2007, we sold our
interest in Palisades and the Big Rock ISFSI to Entergy. As part of the
transaction, we entered into agreements containing tax and other indemnification
provisions. While we are unable to estimate the maximum potential obligation
related to these indemnities, we consider the likelihood that we would be
required to perform or incur significant losses related to these indemnities and
the guarantees listed in the preceding tables to be remote.
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Consumers Energy Company
3: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
--------------------------------------
September 30, 2006----------------------------------
March 31, 2007 December 31, 2005
------------------2006
-------------- -----------------
First mortgage bonds $3,173 $3,175$3,172 $3,172
Senior notes and other 801 852654 652
Securitization bonds 348 369332 340
------ ------
Principal amounts outstanding 4,322 4,3964,158 4,164
Current amounts (59) (85)(190) (31)
Net unamortized discount (7) (8)
------ ------(6) (6)
Total Long-term debt $4,256 $4,303$3,962 $4,127
====== ======
DEBT RETIREMENTS: The following is a summary of significant long-term debt
retirements during the nine months ended September 30, 2006:
Principal Interest Rate
(in millions) (%) Retirement Date Maturity Date
------------- ------------- --------------- -------------
Long-term debt - related parties $129 9.00 February 2006 June 2031
FMLP debt 56 13.25 July 2006 July 2006
----
Total $185
====
REGULATORY AUTHORIZATION FOR FINANCINGS: In May 2006, the FERC issued an order
authorizing us to issue up to $2.0 billion of secured and unsecured short-term
securities for the following purposes:
- up to $1.0 billion for general corporate purposes, and
- up to $1.0 billion of FMB or other securities to be issued solely as
collateral for other short-term securities.
Also in May 2006, the FERC issued an order authorizing us to issue up to $5.0
billion of secured and unsecured long-term securities for the following
purposes:
- up to $1.5 billion for general corporate purposes,
- up to $1.0 billion for purposes of refinancing or refunding existing
long-term debt, and
- up to $2.5 billion of FMB or other securities to be issued solely as
collateral for other long-term securities.
The authorizations are for a two-year period beginning July 1, 2006 and ending
June 30, 2008. Any long-term issuances during the two-year authorization period
are exempt from FERC's competitive bidding and negotiated placement
requirements.
CE-53CE-41
Consumers Energy Company
REVOLVING CREDIT FACILITIES:FACILITY: The following secured revolving credit facilitiesfacility with
banks areis available at September 30, 2006:March 31, 2007:
In Millions
- ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Amount of Amount Outstanding
Company Expiration Date Facility Borrowed Letters-of-Credit Amount Available
------- --------------- --------- -------- ----------------- ----------------
Consumers March 30, 2007 $300 $ - $ - $300
Consumers May 18, 2010 500 - 62 438
MCV Partnership August 25, 2007 25 - 7 182012 $500 $-- $59 $441
InWe replaced our $500 million facility in March 2006, we entered into2007 with a short-term secured revolvingnew $500 million
credit agreement
with banks. This facility that expires in March 2012. The new facility contains less
restrictive covenants, and provides $300 million of funds for working capitallower fees and other general corporate purposes.lower interest margins
than the previous credit facilities.
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
September 30, 2006,March 31, 2007, we had $253$227 million of unrestricted retained earnings available
to pay common stock dividends. CovenantsThe dividend restrictions in our debt facilities cap
common stock dividend payments at $300 millionrevolving credit
facility were removed in a calendar year.March 2007. Provisions of the Federal Power Act and the
Natural Gas Act effectively restrict dividends to the amount of our retained
earnings. For the ninethree months ended September 30,
2006,March 31, 2007, we paid $71$94 million in
common stock dividends to CMS Energy.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly of leased
service vehicles, power purchase agreements, and office furniture. At September 30, 2006,March 31,
2007, capital lease obligations totaled $55$64 million. In order to
obtain permanent financing for the MCV Facility, the MCV Partnership entered
into a sale and leaseback agreement with a lessor group, which includes the
FMLP, for substantially all of the MCV Partnership's fixed assets. In accordance
with SFAS No. 98, the MCV Partnership accounted for the transaction as a
financing arrangement. At September 30, 2006, finance lease obligations totaled
$268 million, which represents the third-party portion of the MCV Partnership's
finance lease obligation.
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we sell certain accounts receivable to a wholly owned, consolidated,
bankruptcy remote special purpose entity. In turn, the special purpose entity
may sell an undivided interest in up to $325 million of the receivables. The
special purpose entity sold $316$10 million of receivables at September 30, 2006March 31, 2007 and
$325 million of receivables at December 31, 2005.2006. We continue to service the
receivables sold to the special purpose entity. The purchaser of the receivables
has no recourse against our other assets for failure of a debtor to pay when due
and no right to any receivables not sold. We have neither recorded a gain or
loss on the receivables sold nor retained interest in the receivables sold.
Certain cash flows under our accounts receivable sales program are shown in the
following table:
In Millions
---------------
Nine----------------
Three months ended September 30Ended March 31 2007 2006
2005
- --------------------------------------------------------- ------ ------
Net cash flow as a result of accounts receivable financing $ (9)(315) $ (204)(325)
Collections from customers $4,402 $3,782$1,928 $1,817
====== ======
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Consumers Energy Company
4: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and
current liabilities approximate their fair values because of their short-term
nature. We estimate the fair values of long-term financial instruments based on
quoted market prices or, in the absence of specific market prices, on quoted
market prices of similar instruments or other valuation techniques.
The cost and fair value of our long-term financialdebt instruments including current
maturities are as follows:
In Millions
-------------------------------------------------------------
September 30, 2006-----------------------------------------------------------
March 31, 2007 December 31, 20052006
---------------------------- ---------------------------------------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain Cost Value Gain
(Loss)
------ ------ ---------- ------ ------ ---------------------
Long-term debt including current amounts $4,315 $4,291 $ 24 $4,388 $4,393 $ (5)
Long-term debt - related parties,
including current amounts - - - 129 131 (2)
Available-for-sale securities:$4,152 $4,145 $7 $4,158 $4,111 $47
The summary of our available-for-sale investment securities is as follows:
In Millions
-----------------------------------------------------------------------------------
March 31, 2007 December 31, 2006
----------------------------------------- ---------------------------------------
Unrealized Unrealized Fair Unrealized Unrealized Fair
Cost Gains Losses Value Cost Gains Losses Value
---- ---------- ---------- ----- ---- ---------- ---------- ------
Common stock of CMS Energy (a) $ 8 $ 25 $-- $ 33 $ 10 32 22 10 33 23$ 26 $-- $ 36
Nuclear decommissioning investments: (b)
Equity securities 142 149 (4) 287 140 150 (4) 286
Debt securities 228 2 (2) 228 307 4 (2) 309
SERP:
Equity securities 17 24 7 16 22 69 -- 26 17 9 -- 26
Debt securities 7 7 - 8 8 -
Nuclear decommissioning investments:
Equity securities 138 268 130 134 252 118
Debt securities 304 307 3 287 291 46 -- -- 6 6 -- -- 6
In July(a) At March 31, 2007, we held 1.8 million shares and at December 31, 2006, we
reached an agreement to sellheld 2.2 million shares of CMS Energy Common Stock.
(b) In preparation for the sale of Palisades, these investments also held cash
and cash equivalents totaling $91 million at March 31, 2007. In April 2007,
we sold Palisades and the Big Rock ISFSI to Entergy. Entergy will assume responsibility for the future decommissioning of
the plant and for storage and disposal of spent nuclear fuel. Accordingly, upon
completion of the sale, we
will transfer $382transferred $252 million of nuclear decommissioningin trust fund assets to EntergyEntergy. For additional
details on the sale of Palisades and retain $205 million. We will also be entitled
to receive a returnthe Big Rock ISFSI, see Note 2,
Contingencies, "Other Electric Contingencies - The Sale of $130 million, pending either a favorable federal tax
ruling regarding the release of the funds, or if no such ruling is issued, after
decommissioning ofNuclear Assets
and the Palisades site is complete. These estimates increased
approximately $20 million compared to second quarter 2006 estimates primarily
because of market appreciation during the third quarter of 2006. The disposition
of the retained and receivable nuclear decommissioning funds is subject to
regulatory proceedings.Power Purchase Agreement."
DERIVATIVE INSTRUMENTS: In order to limit our exposure to certain market risks,
we may enter into various risk management contracts, such as swaps, options,
futures, and forward contracts. These contracts, used primarily to manage our
exposure to changes in interest rates and commodity prices, are entered into for
purposes other than trading. We enter into these contracts using established
policies and procedures, under the direction of both:
- an executive oversight committee consisting of senior management
representatives, and
- a risk committee consisting of business unit managers.
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Consumers Energy Company
The contracts we use to manage market risks may qualify as derivative
instruments that are subject to derivative and hedge accounting under SFAS No.
133. If a contract is a derivative, it is recorded on theour consolidated balance
sheet at its fair value. We then adjust the resulting asset or liability each
quarter to reflect any
CE-55
Consumers Energy Company change in the market value of the contract, a practice
known as marking the contract to market. From time to time, we enter into cash
flow hedges. If a derivative qualifies for cash flow hedge accounting treatment,
the changes in fair value (gains or losses) are reported in accumulated other comprehensive
income;AOCI; otherwise, the
changes are reported in earnings.
For a derivative instrument to qualify for cash flow hedge accounting:
- the relationship between the derivative instrument and the forecasted
transaction being hedged must be formally documented at inception,
- the derivative instrument must be highly effective in offsetting the
hedged transaction's cash flows, and
- the forecasted transaction being hedged must be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or
losses are recorded in accumulated other comprehensive income,AOCI, those gains or losses will be reclassified into
earnings in the same period or periods the hedged forecasted transaction affects
earnings. If a cash flow hedge is terminated early because it is determined that
the forecasted transaction will not occur, any gain or loss recorded in accumulated other comprehensive incomeAOCI at
that date is recognized immediately in earnings. If a cash flow hedge is
terminated early for other economic reasons, any gain or loss as of the
termination date is deferred and then reclassified to earnings when the
forecasted transaction affects earnings. The ineffective portion, if any, of all
hedges is recognized in earnings.
To determine the fair value of our derivatives, we use information from external
sources (i.e., quoted market prices and third-party valuations), if available.
For certain contracts, this information is not available and we use mathematical
valuation models to value our derivatives. These models require various inputs
and assumptions, including commodity market prices and volatilities, as well as
interest rates and contract maturity dates. The cash returns we actually realize
on these contracts may vary, either positively or negatively, from the results
that we estimate using these models. As part of valuing our derivatives at
market, we maintain reserves, if necessary, for credit risks arising from the
financial condition of our counterparties.
The majority of our commodity purchase and sale contracts are not subject to
derivative accounting under SFAS No. 133 because:
- they do not have a notional amount (that is, a number of units
specified in a derivative instrument, such as MWMWh of electricity or
bcf of natural gas),
- they qualify for the normal purchases and sales exception, or
- there is not an active market for the commodity.
Our coal purchase contracts are not derivatives because there is not an active
market for the coal we purchase. Similarly, our electric capacity and energy
contracts are not derivatives due to the lack ofIf an active energy market in
Michigan. If active markets for these commodities developcoal develops in the
future, some of these contracts may qualify as derivatives. For our coal purchase contracts,derivatives and the resulting
mark-to-market impact on earnings could be material. For our electric
capacity and energy contracts, we believe that we would be able to apply the
normal purchases and sales exception, and, therefore, would not be required to
mark these contracts to market.
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Consumers Energy Company
In 2005, the MISO began operating the Midwest Energy Market. As a result, the
MISO now centrally dispatches electricity and transmission service throughout
much of the Midwest and provides day-ahead and real-time energy market
information. At this time, we believe that the establishment of this market does
not represent the development of an active energy market in Michigan, as defined
by SFAS No. 133. However, as the Midwest Energy Market matures, we will continue
to monitor its activity level and evaluate whether or not an active energy
market may exist in Michigan.
Derivative accounting is required for certain contracts used to limit our
exposure to commodity price risk. The following table summarizes our derivative
instruments:
In Millions
------------------------------------------------------
September 30, 2006 December 31, 2005
------------------------- --------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain Cost Value Gain (Loss)
- ---------------------- ---- ----- ---------- ---- ----- -----------
Gas supply option contracts $ - $ - $ - $ 1 $ (1) $ (2)
FTRs - - - - 1 1
Derivative contracts associated with the
MCV Partnership:
Long-term gas contracts (a) - 43 43 - 205 205
Gas futures, options, and swaps (a) - 66 66 - 223 223
(a) The fair value of the MCV Partnership's long-term gas contracts and gas
futures, options, and swaps has decreased significantly from DecemberAt March 31, 2005 partly due to a decrease in natural gas prices since that time. The
decrease is also the result of the normal reversal of such derivative
assets. As gas has been purchased under the long-term gas contracts and the
gas futures, options, and swap contracts have been settled, the fair value
of the contracts has decreased.
We record the fair value of our derivative contracts in Derivative instruments,
Other assets, or Other liabilities on our Consolidated Balance Sheets.
GAS SUPPLY OPTION CONTRACTS: Our gas utility business uses fixed-priced
weather-based gas supply call options and fixed-priced gas supply call and put
options to meet our regulatory obligation to provide gas to our customers at a
reasonable and prudent cost. As part of regulatory accounting, the
mark-to-market gains and losses associated with these options are reported
directly in earnings as part of Other income, and then immediately reversed out
of earnings and recorded on the balance sheet as a regulatory asset or
liability.
FTRS: With the creation of the Midwest Energy Market, FTRs were established.
FTRs are financial instruments that manage price risk related to electricity
transmission congestion. An FTR entitles its holder to receive compensation (or,
conversely, to remit payment) for congestion-related transmission charges. As
part of regulatory accounting, the mark-to-market gains and losses associated
with these instruments are reported directly in earnings as part of Other
income, and then immediately reversed out of earnings and recorded on the
balance sheet as a regulatory asset or liability.
DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: Long-term gas
contracts: The MCV Partnership uses long-term gas contracts to purchase and
manage the cost of the natural gas it needs to generate electricity and steam.
The MCV Partnership believes that certain of these contracts qualify as normal
purchases under SFAS No. 133. Accordingly, we have not recognized these
contracts at fair
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Consumers Energy Company
value on our Consolidated Balance Sheets at September 30, 2006.
The MCV Partnership also holds certain long-term gas contracts that do not
qualify as normal purchases because these contracts contain volume optionality
or because the gas will not be used to generate electricity or steam.
Accordingly, all of these contracts are accounted for as derivatives, with
changes in fair value recorded in earnings each quarter.
For the nine months ended September 30, 2006, we recorded a $161 million loss,
before considering tax effects and minority interest, associated with the
decrease in fair value of these long-term gas contracts. This loss is included
in the total Fuel costs mark-to-market at the MCV Partnership on our
Consolidated Statements of Income (Loss). Because of the volatility of the
natural gas market, the MCV Partnership expects future earnings volatility on
these contracts, since gains and losses will be recorded each quarter. We will
continue to record these gains and losses in our consolidated financial
statements until we close the sale of our interest in the MCV Partnership.
We have recorded derivative assets totaling $43 million associated with the fair
value of long-term gas contracts on our Consolidated Balance Sheets at September
30, 2006. The MCV Partnership expects almost all of these assets, which
represent cumulative net mark-to-market gains, to reverse as losses through
earnings during 2007, and 2008 as the gas is purchased, with the remainder
reversing between 2009 and 2011. As the MCV Partnership recognizes future losses
from the reversal of these derivative assets, we will continue to assume a
portion of the limited partners' share of those losses, in addition to our
proportionate share, but only until we close the sale of our interest in the MCV
Partnership.
These long-term gas contracts will be sold in conjunction with the sale of our
interest in the MCV Partnership. At the date we close the sale, we will record
any additional mark-to-market gains or losses associated with these contracts in
earnings. After the closing, we will no longer record the fair value of these
long-term gasderivative contracts on our Consolidated Balance Sheets and will not be
required to recognize gains or losses related to changes in the fair value of
these contracts on our Consolidated Statements of Income (Loss).
Gas Futures, Options, and Swaps: The MCV Partnership enters into natural gas
futures, options, and over-the-counter swap transactions in order to hedge
against unfavorable changes in the market price of natural gas. The MCV
Partnership uses these financial instruments to:
- ensure an adequate supply of natural gas for the projected generation
and sales of electricity and steam, and
- manage price risk by fixing the price to be paid for natural gas on
some of its long-term gas contracts.
At September 30, 2006, the MCV Partnership held natural gas futures, options,
and swaps. We have recorded a net derivative asset amount of $66 million on our
Consolidated Balance Sheets at September 30, 2006 associated with the fair value
of these contracts. Certain of the futures and swaps qualify for cash flow hedge
accounting and we record our proportionate share of their mark-to-market gains
and losses in Accumulated other comprehensive income. The remaining contracts
are not cash flow hedges and their mark-to-market gains and losses are recorded
to earnings.
Those contracts that qualify as cash flow hedges represent assets of $79 million
of the net $66 million derivative assets recorded on our Consolidated Balance
Sheets. We have recorded a cumulative net gain of $25 million, net of tax and
minority interest, in Accumulated other comprehensive income at September 30,
2006, representing our proportionate share of mark-to-market gains and losses
from
CE-58was immaterial.
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Consumers Energy Company
these contracts. If we have not closed the sale of our interest in the MCV
Partnership within the next 12 months, we can expect to reclassify $11 million
of this balance, net of tax and minority interest, as an increase to earnings as
the contracts settle, offsetting the costs of gas purchases. There was no
ineffectiveness associated with any of these cash flow hedges.
The remaining futures, options, and swap contracts, representing derivative
liabilities of $13 million, do not qualify as cash flow hedges and we record any
changes in their fair value in earnings each quarter. The MCV Partnership
expects these derivative liabilities, which represent cumulative net
mark-to-market losses, to be realized during 2006 and 2007 as the contracts
settle.
For the nine months ended September 30, 2006, we recorded a $65 million loss,
before considering tax effects and minority interest, associated with the
decrease in fair value of these instruments. This loss is included in the total
Fuel costs mark-to-market at the MCV Partnership on our Consolidated Statements
of Income (Loss). Because of the volatility of the natural gas market, the MCV
Partnership expects future earnings volatility on these contracts, since gains
and losses will be recorded each quarter. We will continue to record these gains
and losses in our consolidated financial statements until we close the sale of
our interest in the MCV Partnership.
In conjunction with the sale of our interest in the MCV Partnership, these
futures, options, and swaps will be sold. At the date we close the sale, we will
record any additional mark-to-market gains or losses associated with these
contracts in Accumulated other comprehensive income or earnings, accordingly.
Then, for those futures and swaps that qualify as cash flow hedges, the related
balance of net cumulative gains recorded in Accumulated other comprehensive
income will be reclassified and recognized in earnings. After the closing, we
will no longer record the fair value of these contracts on our Consolidated
Balance Sheets and will not be required to recognize gains or losses related to
changes in the fair value of these contracts on our Consolidated Statements of
Income (Loss).
Any changes in the fair value of the long-term gas contracts or these futures,
options, and swaps recognized before the closing will not affect the sale price
of our interest in the MCV Partnership. For additional details on the sale of
our interest in the MCV Partnership, see Note 2, Contingencies, "Other Electric
Contingencies - The Midland Cogeneration Venture."
CREDIT RISK: Our swaps and forward contracts contain credit risk, which is the
risk that counterparties will fail to perform their contractual obligations. We
reduce this risk through established credit policies. For each counterparty, we
assess credit quality by using credit ratings, financial condition, and other
available information. We then establish a credit limit for each counterparty
based upon our evaluation of credit quality. We monitor the degree to which we
are exposed to potential loss under each contract and take remedial action, if
necessary.
The MCV Partnership enters into contracts primarily with companies in the
electric and gas industry. This industry concentration may have an impact on our
exposure to credit risk, either positively or negatively, based on how these
counterparties are affected by similar changes in economic conditions, the
weather, or other conditions. The MCV Partnership typically uses
industry-standard agreements that allow for netting positive and negative
exposures associated with the same counterparty, thereby reducing exposure.
These contracts also typically provide for the parties to demand adequate
assurance of future performance when there are reasonable grounds for doing so.
The following table illustrates our exposure to potential losses at September
30, 2006, if each counterparty within this industry concentration failed to
perform its contractual obligations. This table includes contracts accounted for
as financial instruments. It does not include trade accounts receivable,
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derivative contracts that qualify for the normal purchases and sales exception
under SFAS No. 133, or other contracts that are not accounted for as
derivatives.
In Millions
-------------------------------------------------------------------------------
Net Exposure from Net Exposure from
Exposure Before Collateral Net Investment Grade Investment Grade
Collateral (a) Held (b) Exposure Companies Companies (%)
--------------- ---------- -------- ----------------- -----------------
MCV Partnership $120 $36 $84 $84 100
(a) Exposure is reflected net of payables or derivative liabilities if netting
arrangements exist.
(b) Collateral held includes cash and letters of credit received from
counterparties.
Based on our credit policies and our current exposures, we do not expect a
material adverse effect on our financial position or future earnings as a result
of counterparty nonperformance.
5: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- a non-contributory, defined benefit Pension Plan,
- a cash balance pension planPension Plan for certain employees hired between July
1, 2003 and August 31, 2005,
- a DCCP for employees hired on or after September 1, 2005,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) Savings Plan,
- benefits to a select group of management under the EISP, and
- health care and life insurance benefits under OPEB.
Pension Plan: The Pension Plan includes funds for most of our current employees,
the employees of our non-utility affiliates,subsidiaries, and Panhandle, a former affiliate.subsidiary. The
Pension Plan's assets are not distinguishable by company.
Effective January 11, 2006,In April 2007, we sold the MPSC electric rate order authorized usPalisades nuclear plant to include $33 millionEntergy. Employees
transferred to Entergy as a result of electric pension expensethe sale no longer participate in our
electric rates. Due to
the volatility of these particular costs, the order also established a pension
equalization mechanism to track actual costs. If actual pension expenses are
greater than the $33 million included in electric rates, the difference will be
recognized as a regulatory asset for future recovery from customers. If actual
pension expenses are less than the $33 million included in electric rates, the
difference will be recognized as a regulatory liability, and refunded to our
customers. The difference between pension expense allowed in our electric rates
and pension expense under SFAS No. 87 resulted inretirement benefit plans. In April 2007, we recorded a net reduction of $27
million in pension expense of $3 million for the three months ended September 30, 2006 and $8
million for the nine months ended September 30, 2006. We have establishedSFAS No. 158 regulatory assets with a corresponding regulatory assetdecrease
of $8 million.
OPEB: Effective January 11, 2006, the MPSC electric rate order authorized us to
include $28$27 million of electric OPEB expense in pension liabilities on our electric rates. Due to the
volatility of these particular costs, the orderConsolidated Balance Sheets. We
also established an OPEB
equalization mechanism to track actual costs. If actual OPEB expenses are
greater than the $28 million included in electric rates, the difference will be
recognized as a regulatory
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asset for future recovery from our customers. If actual OPEB expenses are less
than the $28 million included in electric rates, the difference will be
recognized as a regulatory liability, and refunded to our customers. The
difference between OPEB expense allowed in our electric rates and OPEB expense
under SFAS No. 106 resulted inrecorded a net reduction of $15 million in OPEB expense of less than $1
million for the three months ended September 30, 2006 and $1 million for the
nine months ended September 30, 2006. We have establishedregulatory SFAS No. 158
assets with a corresponding regulatory assetdecrease of $1 million.
Costs:$15 million in OPEB liabilities. The
following table recapsshows the costs incurred in our retirement benefits
plans:net adjustment:
In Millions
--------------------------------------
Pension --------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ----OPEB
------- ----
Service cost $ 12 $ 9 $ 35 $ 32
Interest cost 20 15 59 60
Expected return on planPlan liability transferred to Entergy $44 $20
Trust assets (20) (17) (60) (75)
Amortization of:transferred to Entergy 17 5
--- ---
Net loss 10 11 30 25
Prior service cost 1 1 5 4
---- ---- ---- ----
Net periodic cost 23 19 69 46
Regulatory adjustment (3) - (8) -
---- ---- ---- ----
Net periodic cost after regulatory adjustment $ 20 $ 19 $ 61 $ 46
==== ==== ==== ====$27 $15
=== ===
In Millions
--------------------------------------
OPEB
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Service cost $ 6 $ 7 $ 18 $ 17
Interest cost 15 15 47 45
Expected return on plan assets (14) (14) (43) (40)
Amortization of:
Net loss 5 5 15 15
Prior service cost (3) (3) (8) (7)
---- ---- ---- ----
Net periodic cost 9 10 29 30
Regulatory adjustment - - (1) -
---- ---- ---- ----
Net periodic cost after regulatory adjustment $ 9 $ 10 $ 28 $ 30
==== ==== ==== ====
SERP: On AprilBeginning May 1, 2006, we implemented a Defined Contribution Supplemental
Executive Retirement Plan (DC SERP) and froze further2007, the CMS Energy Common Stock Fund will no longer be an
investment option available for new participationinvestments in the defined benefit SERP. The DC SERP provides promoted401(k) Savings Plan and
newly hired participants
benefits ranging from 5the employer's match will no longer be in CMS Energy Stock. Participants will
have an opportunity to 15 percent of total compensation. The DC SERP
requires a minimum of five years of participation before vesting. Our
contributionsreallocate investments in the CMS Energy Stock Fund to
other plan investment alternatives. Beginning November 1, 2007, any remaining
shares in the plan, if any,CMS Energy Stock Fund will be placed in a grantor trust. Forsold and the nine months ended September 30, 2006, no contributionssale proceeds will be
reallocated to other plan investment options. At March 31, 2007, there were made to the plan.
MCV: The MCV Partnership sponsors defined cost postretirement health care plans
that cover all full-time employees, except key management. Participants10
million shares of CMS Energy Common Stock in the postretirement health care plans become eligible for the benefits if they retire
on or after the attainment of age 65 or upon a qualified disability retirement,
or if they have 10 or more years of service and retire at age 55 or older. The
MCV Partnership's net periodic postretirement health care cost for the three
months and nine months ended
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September 30, 2006 and 2005 was less than $1 million.Stock Fund.
SFAS No. 158, Employers' Accounting for Defined Benefit Pension and Other
Postretirement Plans - an amendment of FASB Statements No. 87, 88, 106, and
132(R): In September 2006, the FASB issued SFAS No. 158. ThisPhase one of this
standard will
requirerequired us to recognize the funded status of our defined benefit
postretirement plans on our balance sheetsConsolidated Balance Sheets at December 31, 2006.
SFAS No. 158 will require us
to recognize changesPhase one was implemented in the funded status of our plans in the year in which the
changes occur. Upon implementationDecember 2006. Phase two of this standard we expect to record an
additional postretirement benefit liability of approximately $617 million and a
regulatory asset of $612 million. We expect a reduction of $3 million to other
comprehensive income, after tax. Regulatory asset treatment is consistent with
past MPSC and FERC guidance. This standard also requires
that we change our plan measurement date from November 30 to December 31,
effective December 31, 2008. We do not believe that implementation of phase two
of this provision of the standard wouldwill have a material effect on our consolidated financial
statements. We expect to adopt the measurement date provisions of SFAS No. 158
in 2008.
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Costs: The following table recaps the costs, other changes in plan assets, and
benefit obligations incurred in our retirement benefits plans:
In Millions
-------------------------
Pension OPEB
----------- -----------
Three Months Ended March 31 2007 2006 2007 2006
---- ---- ---- ----
Service cost $ 12 $ 12 $ 6 $ 6
Interest expense 20 19 17 16
Expected return on plan assets (19) (20) (16) (14)
Amortization of:
Net loss 11 10 6 5
Prior service cost (credit) 2 2 (2) (3)
---- ---- ---- ----
Net periodic cost 26 23 11 10
Regulatory adjustment (4) (3) (2) --
---- ---- ---- ----
Net periodic cost after regulatory adjustment $ 22 $ 20 $ 9 $ 10
==== ==== ==== ====
6: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, "ACCOUNTINGACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS":OBLIGATIONS: This standard
requires companies to record the fair value of the cost to remove assets at the
end of their useful life, if there is a legal obligation to remove them. We have
legal obligations to remove some of our assets, including our nuclear plants, at
the end of their useful lives.
The fair value of ARO liabilities has been calculated using an expected present
value technique. This technique reflects assumptions such as costs, inflation,
and profit margin that third parties would consider to assume the settlement of
the obligation. Fair
value, to the extent possible, should include a market risk premium for
unforeseeable circumstances. No market risk premium was included in our ARO fair
value estimate since a reasonable estimate could not be made. If a five percent
market risk premium were assumed, our ARO liability would increase by $25
million.
If a reasonable estimate of fair value cannot be made in the period in which the
ARO is incurred, such as for assets with indeterminate lives, the liability is
to be recognized when a reasonable estimate of fair value can be made.
Generally, gas transmission and electric and gas distribution assets have
indeterminate lives. Retirement cash flows cannot be determined and there is a
low probability of a retirement date. Therefore, no liability has been recorded
for these assets or associated obligations related to potential future
abandonment. Also, no liability has been recorded for assets that have
insignificant cumulative disposal costs, such as substation batteries. The
measurement of the ARO liabilities for Palisades and Big Rock include use of
decommissioning studies that largely utilize third-party cost estimates.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarified the term "conditional asset
retirement obligation" as used in SFAS No. 143. The term refers to a legal
obligation to perform an asset retirement activity in which the timing and (or)
method of settlement are conditional on a future event. We determined that
abatement of asbestos included in our plant investments qualifies as a
conditional ARO, as defined by FASB Interpretation No.FIN 47.
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The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
September 30, 2006March 31, 2007 In Millions
- -----------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long LivedLong-Lived Assets Fund
- --------------- ---------- ------------------------------------ -----
Palisades - decommission plant site 1972 Palisades nuclear plant $576$604
Big Rock - decommission plant site 1962 Big Rock nuclear plant 62
JHCampbell intake/discharge water line 1980 Plant intake/discharge water line ---
Closure of coal ash disposal areas Various Generating plants coal ash areas ---
Closure of wells at gas storage fields Various Gas storage fields ---
Indoor gas services equipment relocations Various Gas meters located inside structures ---
Asbestos abatement 1973 Electric and gas utility plant ---
In Millions
- --------------------------------------------------------------------------------------------------------
ARO ARO
Liability Cash flow Liability
ARO Description 12/31/0506 Incurred Settled (a) Accretion Revisions 9/30/063/31/07
- --------------- --------- -------- ----------- --------- --------- ---------
Palisades - decommission