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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, 2006
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 October 30, 2006:
CMS ENERGY CORPORATION:
CMS Energy Common Stock, $.01 par value 222,434,688
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, 2006
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
--------
Glossary............................................................. 3
PART I: FINANCIAL INFORMATION
CMS Energy Corporation
Management's Discussion and Analysis
Executive Overview............................................. CMS - 1
Forward-Looking Statements and Information..................... CMS - 3
Results of Operations.......................................... CMS - 5
Critical Accounting Policies................................... CMS - 16
Capital Resources and Liquidity................................ CMS - 21
Outlook........................................................ CMS - 23
Implementation of New Accounting Standards..................... CMS - 34
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
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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 - 12
Capital Resources and Liquidity................................ CE - 16
Outlook........................................................ CE - 18
Implementation of New Accounting Standards..................... CE - 27
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 - 39
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........... CO - 1
Controls and Procedures.............................................. CO - 1
PART II: OTHER INFORMATION
Item 1. Legal Proceedings........................................ CO - 2
Item 1A. Risk Factors............................................. CO - 5
Item 2. Unregistered Sales of Equity Securities and Use of
Proceeds.............................................. CO - 7
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 - 8
Signatures........................................................ CO - 9
2
GLOSSARY
Certain terms used in the text and financial statements are defined below
AFUDC............................ Allowance for Funds Used During Construction
ALJ.............................. Administrative Law Judge
APB.............................. Accounting Principles Board
APB Opinion No. 18............... APB Opinion No. 18, "The Equity Method of
Accounting for Investments in Common Stock"
ARO.............................. Asset retirement obligation
Bay Harbor....................... a residential/commercial real estate area
located near Petoskey, Michigan. In 2002,
CMS Energy sold its interest in Bay Harbor.
bcf.............................. One billion cubic feet of gas
Big Rock......................... Big Rock Point nuclear power plant, owned by
Consumers
Board of Directors............... Board of Directors of CMS Energy
CEO.............................. Chief Executive Officer
CFO.............................. Chief Financial Officer
CFTC............................. Commodity Futures Trading Commission
Clean Air Act.................... Federal Clean Air Act, as amended
CMS Energy....................... CMS Energy Corporation, the parent of
Consumers and Enterprises
CMS Energy Common Stock or
common stock.................. Common stock of CMS Energy, par value $.01
per share
CMS ERM.......................... CMS Energy Resource Management Company,
formerly CMS MST, a subsidiary of
Enterprises
CMS Field 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............. CMS Gas Transmission Company, a subsidiary
of Enterprises
CMS Midland...................... CMS Midland Inc., a subsidiary of Consumers
that has a 49 percent ownership interest in
the MCV Partnership
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.......................... 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 Energy Company, a subsidiary of
CMS Energy
CPEE............................. Companhia Paulista de Energia Eletrica, a
subsidiary of Enterprises
3
Customer Choice Act.............. Customer Choice and Electricity Reliability
Act, a Michigan statute enacted in June 2000
DCCP............................. Defined Company Contribution Plan
Detroit Edison................... The Detroit Edison Company, a non-affiliated
company
DIG.............................. Dearborn Industrial Generation, LLC, an
indirect wholly owned subsidiary of CMS
Energy
DOE.............................. U.S. Department of Energy
DOJ.............................. U.S. Department of Justice
Dow.............................. The Dow Chemical Company, a non-affiliated
company
DTE Energy....................... DTE Energy Company, a non-affiliated company
EISP............................. Executive Incentive Separation Plan
EITF............................. Emerging Issues Task Force
EITF Issue No. 02-03............. Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and
Risk Management Activities
Entergy.......................... Entergy Corporation, a non-affiliated
company
Enterprises...................... CMS Enterprises Company, a subsidiary of CMS
Energy
EPA.............................. U. S. Environmental Protection Agency
EPS.............................. Earnings per share
ERISA............................ Employee Retirement Income Security Act
Exchange Act..................... Securities Exchange Act of 1934, as amended
FASB............................. Financial Accounting Standards Board
FASB Interpretation No. 46(R).... Revised FASB Interpretation No. 46,
Consolidation of Variable Interest Entities
FERC............................. Federal Energy Regulatory Commission
FIN 47........................... FASB Interpretation No. 47, Accounting for
Conditional Asset Retirement Obligations
FIN 48........................... FASB Interpretation No. 48, Uncertainty in
Income Taxes
FMB.............................. First Mortgage Bonds
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............................. Generally Accepted Accounting Principles
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.............................. 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............................ Independent Spent Fuel Storage Installation
IRS.............................. Internal Revenue Service
4
ITC.............................. ITC Holdings Corporation
Jorf Lasfar...................... The 1,356 MW coal-fueled power plant in
Morocco, jointly owned by CMS Generation and
ABB Energy Ventures, Inc.
Jubail........................... A 240 MW natural gas cogeneration power
plant located in Saudi Arabia, in which CMS
Generation owns a 25 percent interest
kWh.............................. Kilowatt-hour (a unit of power equal to one
thousand watt hours)
Ludington........................ Ludington pumped storage plant, jointly
owned by Consumers and Detroit Edison
mcf.............................. One thousand cubic feet of gas
MCV Facility..................... A natural gas-fueled, combined-cycle
cogeneration facility operated by the MCV
Partnership
MCV Partnership.................. Midland Cogeneration Venture Limited
Partnership in which Consumers has a 49
percent interest through CMS Midland
MCV 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.
MD&A............................. Management's Discussion and Analysis
MDEQ............................. Michigan Department of Environmental Quality
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............................. Midwest Independent Transmission System
Operator, Inc.
MMBtu............................ Million British Thermal Units
Moody's.......................... Moody's Investors Service, Inc.
MPSC............................. Michigan Public Service Commission
MRV.............................. Market-Related Value of Plan assets
MSBT............................. Michigan Single Business Tax
MW............................... Megawatt (a unit of power equal to one
million watts)
NEIL............................. Nuclear Electric Insurance Limited, an
industry mutual insurance company owned by
member utility companies
Neyveli.......................... CMS Generation Neyveli Ltd, a 250 MW
lignite-fired power station located in
Neyveli, Tamil Nadu, India, in which CMS
International Ventures holds a 50 percent
interest
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............................ New York Mercantile Exchange
OPEB............................. Postretirement benefit plans other than
pensions for retired employees
Palisades........................ Palisades nuclear power plant, which is
owned by Consumers
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.............................. Polychlorinated biphenyl
Peabody Energy................... Peabody Energy Corporation, a non-affiliated
company
Pension Plan..................... The trusteed, non-contributory, defined
benefit pension plan of Panhandle, Consumers
and CMS Energy
PJM RTO.......................... Pennsylvania-Jersey-Maryland Regional
Transmission Organization
Price-Anderson 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............................. Power supply cost recovery
PURPA............................ Public Utility Regulatory Policies Act of
1978
RCP.............................. Resource Conservation Plan
ROA.............................. Retail Open Access
SAB No. 107...................... Staff Accounting Bulletin No. 107,
Share-Based Payment
SEC.............................. U.S. Securities and Exchange Commission
Section 10d(4) Regulatory Asset.. Regulatory asset as described in Section
10d(4) of the Customer Choice Act, as
amended
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........................... Sistema Electrico del Estado Nueva Esparta
C.S., a subsidiary of Enterprises
SERP............................. Supplemental Executive Retirement Plan
SFAS............................. Statement of Financial Accounting Standards
SFAS No. 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...................... SFAS No. 87, "Employers' Accounting for
Pensions"
SFAS No. 88...................... SFAS No. 88, "Employers' Accounting for
Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination
Benefits"
SFAS No. 98...................... SFAS No. 98, "Accounting for Leases"
6
SFAS No. 106..................... SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions"
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..................... SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities, as
amended and interpreted"
SFAS No. 143..................... SFAS No. 143, "Accounting for Asset
Retirement Obligations"
SFAS No. 157..................... SFAS No. 157, "Fair Value Measurement"
SFAS No. 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........................ A power and desalination plant of Emirates
CMS Power Company, in which CMS Generation
holds 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 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........................ Comprehensive Environmental Response,
Compensation and Liability Act
Takoradi......................... A 200 MW open-cycle combustion turbine crude
oil power plant located in Ghana, in which
CMS Generation owns a 90 percent interest
Taweelah......................... Al Taweelah A2, a power and desalination
plant of Emirates CMS Power Company, in
which CMS Generation holds a 40 percent
interest
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. 1 for the year
ended December 31, 2005.
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
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
businesses we retain.
In July 2006, we reached an agreement to sell the Palisades nuclear plant to
Entergy for $380 million. We also signed a 15-year power purchase agreement for
100 percent of the plant's current electric output. We are targeting to close
the sale by May 1, 2007. When completed, the sale will result 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 expect that a significant portion of the proceeds
will benefit our customers. We plan to use the cash that we retain from 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 million in Consumers,
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 as natural gas
prices continue 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.
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,
- reducing parent company debt,
- 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.
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.
These negative effects will be offset somewhat by the reduction we are
experiencing in ROA load in our service territory. At September 30, 2006,
alternative electric suppliers were providing 308 MW of generation service to
ROA customers. This is four percent of our total distribution load and
represents a decrease of 60 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 Corporation
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 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 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, and
- sales of the Palisades plant and our interest in the MCV
Partnership,
CMS-3
CMS Energy Corporation
- the impact of adverse natural 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,
- the effects on our ability to purchase capacity to serve our customers
and recover the cost of these purchases, if Consumers exercises its
regulatory out rights and the MCV Partnership exercises its right to
terminate the MCV PPA,
- federal regulation of electric sales and transmission of electricity,
including periodic re-examination 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 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 state 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 availability of
spent nuclear fuel storage,
- 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,
- 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, 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 30 2006 2005 Change
- ------------------------------- ------ ------ ------
Net Loss Available to Common Stockholders $ (103) $ (265) $ 162
Basic Earnings Per Share $(0.47) $(1.21) $0.74
Diluted Earnings Per Share $(0.47) $(1.21) $0.74
------ ------ -----
Electric Utility $ 93 $ 62 $ 31
Gas Utility (20) (16) (4)
Enterprises (Includes the MCV Partnership and
the FMLP interests) (132) (260) 128
Corporate Interest and Other (45) (51) 6
Discontinued Operations 1 - 1
------ ------ -----
Net Loss Available to Common Stockholders $ (103) $ (265) $ 162
====== ====== =====
For the three months ended September 30, 2006, net loss available to common
stockholders was $103 million compared to a net loss of $265 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 asset
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, 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
- - increase 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, 6
- - 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 earnings at Enterprises
primarily due to mark-to-market losses at Taweelah in 2006
versus gains in 2005, (17)
- - absence of income tax benefits recorded 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)
- - decrease in net income from our gas utility primarily due to a
reduction 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
====
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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.
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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, 54
- - increase 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, 18
- - 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
- - 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 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 establishment of a tax reserve related to
some of our foreign investments and lower earnings at
GasAtacama. (20)
----
Total Change $ 30
====
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CMS Energy Corporation
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2006 2005 Change
- ------------ ---- ---- ------
Three months ended $ 93 $ 62 $31
Nine months ended $159 $141 $18
==== ==== ===
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
Other operating expenses, other income, and
non-commodity revenue (44) (174)
Regulatory return on capital expenditures (9) (30)
General taxes (2) (3)
Interest charges (1) (3)
Income taxes (18) (8)
---- -----
Total change $ 31 $ 18
==== =====
ELECTRIC DELIVERIES: For 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 rates 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, electric delivery revenues increased $24
million for the three months ended September 30, 2006 and $67 million for the
nine months ended September 30, 2006 versus the same periods in 2005.
Surcharge Revenue: Effective January 1, 2006, we started collecting a surcharge
that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This
surcharge increased electric delivery revenue by $15 million for the three
months ended September 30, 2006 and $38 million for the nine months ended
September 30, 2006 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: 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, alternative electric suppliers were
providing 308 MW of generation service to ROA customers. This amount represents
a decrease of 60 percent of ROA load compared to the end of September 2005. The
return of former ROA customers to full-service rates increased electric revenues
$12 million for the three months ended September 30, 2006 and $40 million for
the nine months ended September 30, 2006 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.
OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For the three
months ended September 30, 2006, other operating expenses increased $48 million,
and non-commodity revenue increased $4 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.
The increase 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, operating and maintenance expense
increased primarily due to higher storm restoration costs. For the nine months
ended September 30, 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 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 benefit 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 was primarily due to an increase in capital-related services provided to
METC in 2006 versus 2005.
For the nine months ended September 30, 2006, the increase in other income was
primarily due to higher interest income and the absence, in 2006, of expenses
recorded in 2005 associated with the early retirement of debt. 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 for 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 both 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.
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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
higher MSBT expense, offset partially by lower property tax expense.
INTEREST CHARGES: For the three months ended September 30, 2006, interest
charges increased 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 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.
INCOME TAXES: For the three months ended September 30, 2006, 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 by
the resolution of an IRS income tax audit, which resulted in a $4 million income
tax benefit caused by the restoration and utilization of income tax credits.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2006 2005 Change
- ------------ ---- ---- ------
Three months ended $(20) $(16) $ (4)
Nine months ended $ 14 $ 39 $(25)
==== ==== ====
Three Months Ended Nine Months Ended
September 30, September 30,
Reasons for the change: 2006 vs.2005 2006 vs.2005
- ----------------------- ------------------ -----------------
Gas deliveries $(13) $(49)
Gas wholesale and retail services, other gas
revenues and other income 9 20
Operation and maintenance 3 1
General taxes and depreciation - (5)
Interest charges (3) (6)
Income taxes - 14
---- ----
Total change $ (4) $(25)
==== ====
GAS DELIVERIES: For the three months ended September 30, 2006, gas deliveries,
including miscellaneous transportation to end-use customers, decreased 1 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 slight 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 warmer weather in
2006 versus 2005 and increased customer conservation efforts in response to
higher gas prices.
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CMS Energy Corporation
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES AND OTHER INCOME: For the
three and nine months ended September 30, 2006, the increase primarily reflects
higher pipeline revenues and other income capacity optimization in 2006 versus
2005.
OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2006, operation and maintenance expenses decreased versus 2005 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. Customer service
expense increased primarily due to higher uncollectible accounts expense.
GENERAL TAXES AND DEPRECIATION: For the nine months ended September 30, 2006,
depreciation expense increased versus 2005 primarily due to higher plant in
service. The increase in general taxes reflects higher MSBT expense, offset
partially by lower property tax expense.
INTEREST CHARGES: For the three months ended September 30, 2006, interest
charges increased due to higher GCR interest expense, offset partially by a 3
basis point reduction in the average rate of interest on our debt and lower
average debt levels 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.
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-12
CMS Energy Corporation
ENTERPRISES RESULTS OF OPERATIONS
In Millions
----------------------
September 30 2006 2005 Change
- ------------ ----- ----- ------
Three months ended $(132) $(260) $128
Nine months ended $(177) $(126) $(51)
===== ===== ====
Three Months Ended Nine Months Ended
September 30, September 30,
Reasons for the change: 2006 vs. 2005 2006 vs. 2005
- ----------------------- ------------------ -----------------
Operating revenues $ (2) $ 119
Cost of gas and purchased power (15) (212)
Fuel costs mark-to-market at the MCV Partnership (225) (593)
Earnings from equity method investees (21) (30)
Gain on sale of assets - (5)
Operation and maintenance (10) (27)
General taxes, depreciation, and other income, net 84 131
Asset impairment charges 945 945
Fixed charges 6 9
Minority interest (520) (353)
Income taxes (114) (35)
----- -----
Total change $ 128 $ (51)
===== =====
OPERATING REVENUES: For the three months ended September 30, 2006, operating
revenues decreased versus 2005 due to lower revenues at CMS ERM resulting from
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. 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, cost of gas and purchased power increased versus 2005. The increase
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 decreased 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.
EARNINGS FROM EQUITY METHOD INVESTEES: For the three months ended September 30,
2006, equity earnings decreased by $21 million versus 2005. This decrease was
primarily due to mark-to-market losses on interest rate swaps associated with
our investment in Taweelah, compared to gains recorded on these instruments 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 gas shortages and higher interest
rates.
Equity earnings for the nine months ended September 30, 2006 decreased $30
million versus 2005. The decrease was due to the establishment of a tax reserve
related to some of our foreign investments and lower earnings at GasAtacama.
GAIN ON SALE OF ASSETS: For the nine months ended September 30, 2006, there were
no gains or losses on asset sales compared to a $3 million gain on the sale of
GVK and a $2 million gain on the sale of SLAP in 2005.
OPERATION AND MAINTENANCE: For the three months ended September 30, 2006,
operation and maintenance expenses increased due to a loss recorded on the
termination of the remaining prepaid gas contracts 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.
GENERAL TAXES, DEPRECIATION AND OTHER INCOME, NET: For the three 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.
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 periods
in 2005. For the three and nine months ended September 30, 2006, a charge of
$239 million was recorded for the impairment of our equity investment in
GasAtacama and related notes receivable. For the three and nine months ended
September 30, 2005, a charge 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.
INCOME TAXES: For the three months ended September 30, 2006, the income tax
benefit was lower versus 2005 as the income tax benefits related to the
impairment of our investment 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 recorded in 2005. Also contributing to the decrease was
the absence 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 GasAtacama 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.
CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS
In Millions
---------------------
September 30 2006 2005 Change
- ------------ ---- ----- ------
Three months ended $(45) $ (51) $ 6
Nine months ended $(58) $(142) $84
==== ===== ===
For the three months ended September 30, 2006, corporate interest and other net
expenses were $45 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.
For the nine months ended September 2006, corporate interest and other net
expenses were $58 million, a decrease 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 restoration and
CMS-15
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.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, we use estimates and assumptions 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 that may cause actual results to differ from estimated results,
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 by the principles in SFAS No. 5. 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, the FASB issued a new
interpretation on the recognition and measurement of uncertain tax positions.
For additional details, see the "New Accounting Standards Not Yet Effective"
section included in this MD&A.
ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS, TRADING ACTIVITIES, AND
MARKET RISK INFORMATION
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. For additional details on accounting for financial
instruments, see Note 6, Financial and Derivative Instruments.
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. For additional details on accounting for 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. 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 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 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 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 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
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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 loss 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 Utility Business Uncertainties - MCV Underrecoveries" section in
this MD&A and 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 of 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:
In Millions
-------------------------------
Non-Trading Trading Total
----------- ------- -----
Fair value of contracts outstanding at
December 31, 2005 $(63) $ 100 $ 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)
Other changes in fair value (d) (24) (40) (64)
---- ----- -----
Fair value of contracts outstanding at
September 30, 2006 $ 34 $ (65) $ (31)
==== ===== =====
(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
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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) of forward positions
as well as changes to present value and credit reserves.
Fair Value of Non-Trading Contracts at September 30, 2006 In Millions
- -----------------------------------------------------------------------------------------------
Maturity (in years)
Total ----------------------------------------------
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 - -
--- --- --- --- ---
Total $34 $12 $22 $ - $ -
=== === === === ===
Fair Value of Trading Contracts at September 30, 2006 In Millions
- -----------------------------------------------------------------------------------------------
Maturity (in years)
Total ----------------------------------------------
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) $ -
Prices obtained from external
sources or based on models and
other valuation methods (21) (12) (9) - -
---- ---- ---- ---- ---
Total $(65) $(26) $(38) $(1) $ -
==== ==== ==== === ===
MARKET RISK INFORMATION: The following is an update of our risk sensitivities
since December 31, 2005. 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 December 31, 2005
------------------ -----------------
Variable-rate financing - before-tax annual
earnings exposure $ 4 $ 4
Fixed-rate financing - potential REDUCTION
in fair value (a) 203 223
(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.
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Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market
prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
Potential REDUCTION in fair value:
Non-trading contracts
Gas supply option contracts $ - $ 1
CMS ERM gas forward contracts 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 - 2
Electricity-related swaps 10 13
Gas-related option contracts - 1
Gas-related swaps and futures 1 4
Investment Securities Price Risk Sensitivity Analysis (assuming an adverse
change in market prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
Potential REDUCTION in fair value of available-for-sale
equity securities (primarily SERP investments): $5 $5
Consumers maintains 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, these funds were invested primarily in equity securities,
fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are
recorded at fair value on our Consolidated Balance Sheets. These investments are
exposed to price fluctuations in equity markets and changes in interest rates.
Because the accounting for nuclear plant decommissioning recognizes that costs
are recovered through Consumers' electric rates, fluctuations in equity prices
or interest rates do 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.
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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.
These accounting policies were disclosed in our 2005 Form 10-K/A 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 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
purchases are recoverable from our customers, the amount paid for natural gas
stored as inventory requires additional liquidity due to the timing of the cost
recoveries. We have credit agreements with our commodity suppliers and those
agreements contain terms that have resulted in margin calls. Additional margin
calls or other credit support 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,
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.
We believe the following items will be sufficient to meet our liquidity needs:
- our current level of cash and revolving credit facilities,
- our ability to access junior secured and unsecured borrowing capacity
in the capital markets, and
- our anticipated cash flows from operating and investing activities.
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CMS Energy Corporation
In June 2006, Moody's affirmed our liquidity rating and revised the 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 reinstatement 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.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2006, $529 million consolidated cash was on hand, which
includes $70 million of restricted cash and $83 million from entities
consolidated pursuant to FASB Interpretation No. 46(R).
Our primary ongoing source of cash is dividends and other distributions from our
subsidiaries. For the nine months ended September 30, 2006, Consumers paid $71
million in common stock dividends to CMS Energy.
SUMMARY OF CONSOLIDATED STATEMENTS OF CASH FLOWS
In Millions
-------------
Nine months ended September 30 2006 2005
- ------------------------------ ----- -----
Net cash provided by (used in):
Operating activities $ 436 $ 567
Investing activities (436) (362)
----- -----
Net cash provided by operating and investing activities - 205
Financing activities (389) (82)
Effect of exchange rates on cash 1 1
----- -----
Net Increase (Decrease) in Cash and Cash Equivalents $(388) $ 124
===== =====
OPERATING ACTIVITIES: For the nine months ended September 30, 2006, net cash
provided by operating activities was $436 million, a decrease of $131 million
versus 2005. This was the result of decreases in the MCV Partnership gas
supplier funds on deposit and 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
decrease in the MCV Partnership gas supplier funds on deposit was the result of
refunds to suppliers from decreased exposure due to declining gas prices in
2006. The decrease in accounts payable was mainly due to payments for higher
priced gas that were accrued at December 31, 2005. The decrease in accounts
receivable was primarily 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, and the expiration of emergency rules initiated
by the MPSC, which delayed customer payments during the heating season.
INVESTING ACTIVITIES: For the nine months ended September 30, 2006, net cash
used in investing activities was $436 million, an increase of $74 million versus
2005. This was primarily due to the absence of short-term investment proceeds,
the absence of proceeds from asset sales, an increase in capital expenditures,
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 Corporation
FINANCING ACTIVITIES: For the nine months ended September 30, 2006, net cash
used in financing activities was $389 million, an increase of $307 million
versus 2005. This was primarily due to a decrease in proceeds from common stock
issuances of $271 million.
For additional details on long-term debt activity, see Note 4, Financings and
Capitalization.
OBLIGATIONS AND COMMITMENTS
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. These arrangements include
indemnifications, letters of credit, surety bonds, and financial and performance
guarantees. For details on 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 of accounts receivable, see
Note 4, Financings and Capitalization.
OUTLOOK
CORPORATE OUTLOOK
Over the next few years, our business strategy will focus on managing cash flow
issues, reducing parent company debt, growing earnings, reducing risk, and
positioning us to make new investments that complement our strengths.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Summer 2006 temperatures were higher than historical averages, leading
to increased 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 decline about one
percent from 2005 levels. This short-term outlook assumes a stabilizing economy
and normal weather conditions for the fourth quarter of 2006.
Over the next five years, we expect electric deliveries to grow at an average
rate of about one and one-half percent per year. However, such growth is
dependent on a modestly growing customer base and a stabilizing Michigan
economy. 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 fluctuations in weather conditions and changes in economic
conditions, including utilization and expansion or contraction of manufacturing
facilities.
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. 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
million for unexpired 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. After September 15, 2007, we expect to exercise our claim for
relief under the regulatory out provision in the MCV PPA. If we are successful
in exercising our claim, the MCV Partnership has the right to terminate the MCV
PPA, which could affect our reserve margin status. The MCV PPA represents 15
percent of our 2007 supply resources target.
ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission
service to us, increased substantially the transmission rates it charges us in
2006. The increased rates are subject to refund and to reduction based on the
outcome of hearings at the FERC scheduled for December 2006. Recovery of a
portion 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,
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.
THE ELECTRIC CAPACITY NEED FORUM: In January 2006, the MPSC Staff issued a
report on future electric capacity in the state of Michigan. The report
indicated that existing generation resources are adequate in the short term, but
could be insufficient to maintain reliability standards by 2009. The report also
indicated that new coal-fired baseload generation may be needed by 2011. The
MPSC Staff recommended an approval 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, to make
recommendations on Michigan's energy policy by the end of 2006. We will continue
to participate as the MPSC addresses
CMS-24
CMS Energy Corporation
future electric capacity needs.
BURIAL OF OVERHEAD POWER LINES: The City of Taylor, a municipality located in
Wayne County, Michigan, passed an ordinance that required Detroit Edison to bury
a section of overhead power lines at Detroit Edison's expense. In September
2004, the Michigan Court of Appeals upheld a lower court decision affirming the
legality of the ordinance over Detroit Edison's objections. Other municipalities
in our service territory adopted, or proposed the adoption of, similar
ordinances. Detroit Edison appealed the Michigan Court of Appeals ruling to the
Michigan Supreme Court. In May 2006, the Michigan Supreme Court ruled 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.
ELECTRIC UTILITY BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
results and condition. 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.
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. 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. 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.
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 this
rule by year round operation of our selective catalytic reduction control
technology units and installation of flue gas desulfurization scrubbers at an
estimated total cost of $960 million, to be incurred by 2014.
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 working with the MDEQ on the
details of these rules. We will develop a cost estimate when the details of
these rules are determined.
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, the U.S. Supreme Court has agreed to
hear a case claiming that the EPA is required by the Clean Air Act to consider
regulating carbon dioxide emissions from automobiles. The EPA asserts that it
lacks authority to regulate carbon dioxide emissions. If the Supreme Court finds
that the EPA has authority to regulate carbon dioxide emissions in this case, it
could result in new federal carbon dioxide regulations for other industries,
including the utility industry.
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 of
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 being challenged in court and we will finalize our cost estimates in
early 2007, when a decision on the final rule is anticipated. We expect to
implement the EPA approved process from 2009 to 2011.
For additional details on electric environmental matters, see Note 3,
Contingencies, "Consumers' Electric Utility Contingencies - Electric
Environmental Matters."
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, alternative electric
suppliers were providing 308 MW of generation service to ROA customers, which
represents four percent of our total distribution load. It is difficult to
predict future ROA customer trends.
Section 10d(4) Regulatory Assets: In December 2005, the MPSC issued an order
that authorized us 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. 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,
we filed an application with the MPSC related to the determination of 2004
Stranded Costs. Applying the Stranded Cost methodology used 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 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.
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.
For additional details and material changes relating to the restructuring of the
electric utility industry and electric rate matters, see Note 3, Contingencies,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric
Utility Rate Matters."
OTHER ELECTRIC UTILITY BUSINESS UNCERTAINTIES
MCV UNDERRECOVERIES: 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, the 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, our 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 such 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 indicated that it may take issue with our
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 has the right to terminate the MCV
PPA. If the MCV Partnership terminates 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.
For additional details on the MCV Partnership, see Note 3, Contingencies, "Other
Consumers' Electric Utility Contingencies - The Midland Cogeneration Venture."
NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006, we reached an agreement
to sell 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, the 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 schedule for the contested case
proceedings regarding this transaction, the sale is targeted to close by May 1,
2007. This two-month delay in the originally anticipated March 1, 2007 closing
date would result in a purchase price reduction of approximately $5 million. We
estimate that the Palisades sale will result in a $31 million premium above the
Palisades asset values at the anticipated closing date after accounting for
estimated sales-related costs. This premium is expected to benefit our
customers.
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 accepting the responsibility for the storage and
disposal of the Big Rock ISFSI. At the anticipated date of close,
decommissioning trust assets are estimated to be $587 million. We will retain
$205 million of these funds at the time of close and will be entitled to receive
a return of an additional $130 million, pending either a
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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. The disposition of the retained and receivable nuclear decommissioning
funds is subject to regulatory approval. We expect that a significant portion of
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.
As part of the transaction, Entergy will sell us 100 percent of the plant's
output up to its current capacity of 798 MW under a 15-year power purchase
agreement. During the term 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 pricing is structured such that Consumers' ratepayers
will retain the benefits of the Palisades plant's low-cost nuclear generation.
The sale is subject to various regulatory approvals, including the MPSC's
approval 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 action on the sale. The final purchase price will be subject
to various closing adjustments such as working capital 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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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 - Nuclear Plant Decommissioning."
GAS UTILITY BUSINESS OUTLOOK
GROWTH: In 2006, we project gas deliveries will decline by four percent, on a
weather-adjusted basis, from 2005 levels due to increased conservation and
overall economic conditions in the state of Michigan. Over the next five years,
we expect gas deliveries to be relatively flat. Actual gas deliveries in future
periods may be affected by:
- fluctuations in weather patterns,
- 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.
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 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."
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.
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.
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CMS Energy Corporation
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.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking
a 12 percent authorized return on equity along with a $132 million annual
increase in our gas delivery and transportation rates. As part 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 that $17 million of this amount 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 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.
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.
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CMS Energy Corporation
UNCERTAINTIES: The results of operations and the financial position of our
diversified energy businesses may be affected by a number of trends or
uncertainties. Those that could have a material impact on our income, cash
flows, or balance sheet and credit improvement include:
- our ability to sell or to improve the performance of assets and
businesses in accordance with our business plan,
- 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,
- 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 indemnity 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
demand 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 conjunction with the preparation 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 amount 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 effects and
minority interest. At September 30, 2006, the carrying value of our investment
in GasAtacama was $122 million. This remaining value continues to be exposed to
the threat of a complete gas curtailment by Argentina and the inability of
GasAtacama to pass
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CMS Energy Corporation
through the increased costs associated with such a curtailment to its regulated
customers. Therefore, if conditions do not improve, the result could be a
further impairment of our investment in GasAtacama.
For additional details, see Note 2, Asset Impairment Charges and Sales.
SENECA: SENECA operates an electric utility on Margarita Island, Venezuela under
a Concession Agreement with the Venezuelan Ministry of 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.
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 of Prairie State indirectly through a jointly
owned limited liability company. Enterprises will serve as lead developer,
construction manager, and operator 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's 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.
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CMS Energy Corporation
OTHER OUTLOOK
VOLUNTARY RULES REGARDING BILLING PRACTICES: In October 2006, the MPSC announced
a voluntary agreement relating to billing practices with us and other Michigan
natural gas and electric utilities that will provide additional help to
low-income customers for the winter heating period of November 1, 2006 through
March 31, 2007. The rules address billing practices such as billing cycles,
fees, deposits, shutoffs, and collection of unpaid bills for retail customers of
electric and gas utilities. These rules will have an estimated $3 million
negative effect on our earnings for the period of these rules and an estimated
negative effect on our cash flow of up to $50 million for 2006.
MCV PARTNERSHIP NEGATIVE EQUITY: Due to the impairment of 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.
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.
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 impact of this legislation.
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: 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. SFAS No. 123(R) was effective for us on
January 1, 2006. We elected to adopt the modified prospective method recognition
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 EFFECTIVE
FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006, the FASB
issued FIN 48, effective for us 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
authority 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 would result in a cumulative
adjustment to retained earnings.
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CMS Energy Corporation
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 the 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' 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. This standard will
require us to 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 recognize changes in the funded status of our plans in the year in which the
changes occur. Upon implementation 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 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.
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CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30 2006 2005 2006 2005
- ------------ ------ ------ ------ ------
In Millions
OPERATING REVENUE $1,462 $1,307 $4,890 $4,382
EARNINGS FROM EQUITY METHOD INVESTEES 19 40 63 92
OPERATING EXPENSES
Fuel for electric generation 300 215 782 570
Fuel costs mark-to-market at the MCV Partnership 28 (197) 226 (367)
Purchased and interchange power 235 203 567 400
Cost of gas sold 196 242 1,439 1,415
Other operating expenses 292 262 818 753
Maintenance 72 62 239 178
Depreciation, depletion and amortization 129 121 418 399
General taxes (9) 59 137 200
Asset impairment charges 239 1,184 239 1,184
------ ------ ------ ------
1,482 2,151 4,865 4,732
------ ------ ------ ------
OPERATING INCOME (LOSS) (1) (804) 88 (258)
OTHER INCOME (DEDUCTIONS)
Accretion expense - (4) (4) (14)
Gain on asset sales, net - - - 5
Interest and dividends 23 14 62 39
Regulatory return on capital expenditures 8 17 18 48
Foreign currency losses, net (1) - - (4)
Other income 7 10 29 28
Other expense (2) (13) (12) (25)
------ ------ ------ ------
35 24 93 77
------ ------ ------ ------
FIXED CHARGES
Interest on long-term debt 117 117 356 360
Interest on long-term debt - related parties 3 7 11 23
Other interest 7 3 23 13
Capitalized interest (2) (1) (7) (3)
Preferred dividends of subsidiaries 1 1 4 3
------ ------ ------ ------
126 127 387 396
------ ------ ------ ------
LOSS BEFORE MINORITY INTERESTS (92) (907) (206) (577)
MINORITY INTERESTS (OBLIGATIONS), NET 41 (479) (27) (380)
------ ------ ------ ------
LOSS BEFORE INCOME TAXES (133) (428) (179) (197)
INCOME TAX BENEFIT (31) (165) (125) (116)
------ ------ ------ ------
LOSS FROM CONTINUING OPERATIONS (102) (263) (54) (81)
INCOME FROM DISCONTINUED OPERATIONS, NET OF
$- AND $1 TAX EXPENSE IN 2006 1 - 4 -
------ ------ ------ ------
NET LOSS (101) (263) (50) (81)
PREFERRED DIVIDENDS 2 2 8 7
------ ------ ------ ------
NET LOSS AVAILABLE TO COMMON STOCKHOLDERS $ (103) $ (265) $ (58) $ (88)
====== ====== ====== ======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30 2006 2005 2006 2005
- ------------ ------ ------ ------ ------
In Millions
CMS ENERGY
NET LOSS
Net Loss Available to Common Stockholders $ (103) $ (265) $ (58) $ (88)
====== ====== ====== ======
BASIC LOSS PER AVERAGE COMMON SHARE
Loss from Continuing Operations $(0.47) $(1.21) $(0.28) $(0.42)
Income from Discontinued Operations - - 0.02 -
------ ------ ------ ------
Net Loss Attributable to Common Stock $(0.47) $(1.21) $(0.26) $(0.42)
====== ====== ====== ======
DILUTED LOSS PER AVERAGE COMMON SHARE
Loss from Continuing Operations $(0.47) $(1.21) $(0.28) $(0.42)
Income from Discontinued Operations - - 0.02 -
------ ------ ------ ------
Net Loss Attributable to Common Stock $(0.47) $(1.21) $(0.26) $(0.42)
------ ------ ------ ------
DIVIDENDS DECLARED PER COMMON SHARE $ - $ - $ - $ -
====== ====== ====== ======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NINE MONTHS ENDED
-----------------
SEPTEMBER 30 2006 2005
- ------------ ----- -------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss $ (50) $ (81)
Adjustments to reconcile net loss to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $4 per period) 418 399
Deferred income taxes and investment tax credit (223) (132)
Minority interests (obligations), net (27) (380)
Fuel costs mark-to-market at the MCV Partnership 226 (367)
Regulatory return on capital expenditures (18) (48)
Asset impairment charges 239 1,184
Capital lease and other amortization 34 30
Accretion expense 4 14
Gain on the sale of assets - (5)
Earnings from equity method investees (63) (92)
Cash distributions received from equity method investees 63 71
Changes in other assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenues 250 (18)
Increase in inventories (246) (351)
Decrease in deferred property taxes 102 106
Increase (decrease) in accounts payable (116) 184
Decrease in accrued taxes (152) (146)
Increase (decrease) in accrued expenses 35 (36)
Increase (decrease) in the MCV Partnership gas supplier funds on deposit (159) 275
Decrease in other current and non-current assets 106 7
Increase (decrease) in other current and non-current liabilities 13 (47)
----- -------
Net cash provided by operating activities $ 436 $ 567
----- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $(477) $ (435)
Cost to retire property (41) (20)
Restricted cash and restricted short-term investments 125 (149)
Investments in nuclear decommissioning trust funds (20) (5)
Proceeds from nuclear decommissioning trust funds 20 31
Proceeds from short-term investments - 295
Purchase of short-term investments - (186)
Maturity of the MCV Partnership restricted investment securities held-to-maturity 119 316
Purchase of the MCV Partnership restricted investment securities held-to-maturity (118) (267)
Proceeds from sale of assets - 59
Other investing (44) (1)
----- -------
Net cash used in investing activities $(436) $ (362)
----- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds, and other long-term debt $ 72 $ 1,086
Issuance of common stock 18 289
Retirement of bonds and other long-term debt (433) (1,381)
Payment of preferred stock dividends (8) (8)
Payment of capital lease and financial lease obligations (23) (26)
Debt issuance costs, financing fees, and other (15) (42)
----- -------
Net cash used in financing activities $(389) $ (82)
----- -------
EFFECT OF EXCHANGE RATES ON CASH 1 1
----- -------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $(388) $ 124
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 847 669
----- -------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 459 $ 793
===== =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-39
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
September 30
2006 December 31
ASSETS (Unaudited) 2005
- ------ ------------ -----------
In Millions
PLANT AND PROPERTY (AT COST)
Electric utility $ 8,434 $ 8,204
Gas utility 3,239 3,151
Enterprises 1,049 1,068
Other 31 25
------- -------
12,753 12,448
Less accumulated depreciation, depletion and amortization 5,259 5,123
------- -------
7,494 7,325
Construction work-in-progress 587 520
------- -------
8,081 7,845
------- -------
INVESTMENTS
Enterprises 554 712
Other 10 13
------- -------
564 725
------- -------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 459 847
Restricted cash and restricted short-term investments 70 198
Accounts receivable and accrued revenue, less
allowances of $31 and $31, respectively 476 809
Notes receivable 65 15
Accounts receivable, dividends receivable, and notes
receivable - related parties 83 54
Inventories at average cost
Gas in underground storage 1,293 1,069
Materials and supplies 100 96
Generating plant fuel stock 127 110
Price risk management assets 19 113
Regulatory assets - postretirement benefits 19 19
Derivative instruments 48 242
Deferred property taxes 124 160
Prepayments and other 163 167
------- -------
3,046 3,899
------- -------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 526 560
Additional minimum pension 399 399
Postretirement benefits 99 116
Customer Choice Act 197 222
Other 469 484
Price risk management assets 25 165
Nuclear decommissioning trust funds 582 555
Goodwill 30 27
Notes receivable - related parties 131 187
Notes receivable 229 187
Other 600 649
------- -------
3,287 3,551
------- -------
TOTAL ASSETS $14,978 $16,020
======= =======
CMS-40
September 30
2006 December 31
STOCKHOLDERS' INVESTMENT AND LIABILITIES (Unaudited) 2005
- ---------------------------------------- ------------ -----------
In Millions
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 350.0 shares; outstanding 222.3
shares and 220.5 shares, respectively $ 2 $ 2
Other paid-in capital 4,461 4,436
Accumulated other comprehensive loss (301) (288)
Retained deficit (1,886) (1,828)
------- -------
2,276 2,322
Preferred stock of subsidiary 44 44
Preferred stock 261 261
Long-term debt 6,644 6,800
Long-term debt - related parties 178 178
Non-current portion of capital and finance lease obligations 296 308
------- -------
9,699 9,913
------- -------
MINORITY INTERESTS 344 333
------- -------
CURRENT LIABILITIES
Current portion of long-term debt, capital and finance leases 315 316
Current portion of long-term debt - related parties - 129
Accounts payable 497 597
Accounts payable - related parties 2 16
Accrued interest 117 145
Accrued taxes 180 331
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 34 193
Other 308 241
------- -------
1,585 2,113
------- -------
NON-CURRENT LIABILITIES
Regulatory Liabilities
Regulatory liabilities for cost of removal 1,174 1,120
Income taxes, net 475 455
Other regulatory liabilities 236 178
Postretirement benefits 431 382
Deferred income taxes 4 297
Deferred investment tax credit 63 67
Asset retirement obligations 498 496
Price risk management liabilities 41 161
Gas supply contract obligations - 61
Other 428 444
------- -------
3,350 3,661
------- -------
COMMITMENTS AND CONTINGENCIES (Notes 3, 4 and 6)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $14,978 $16,020
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-41
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30 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 4,422 4,436 4,140
Common stock issued 10 7 25 288
Common stock repurchased (1) (1) (1) (1)
Common stock reissued - - 1 1
------- ------- ------- -------
At end of period 4,461 4,428 4,461 4,428
------- ------- ------- -------
ACCUMULATED OTHER COMPREHENSIVE LOSS
Minimum Pension Liability
At beginning of period (19) (26) (19) (17)
Minimum pension liability adjustments (a) - - - (9)
------- ------- ------- -------
At end of period (19) (26) (19) (26)
------- ------- ------- -------
Investments
At beginning of period 10 8 9 9
Unrealized gain on investments (a) 2 1 3 -
------- ------- ------- -------
At end of period 12 9 12 9
------- ------- ------- -------
Derivative Instruments
At beginning of period 35 (3) 35 (9)
Unrealized gain (loss) on derivative instruments (a) (22) 31 (22) 43
Reclassification adjustments included in net loss (a) (1) (1) (1) (7)
------- ------- ------- -------
At end of period 12 27 12 27
------- ------- ------- -------
Foreign Currency Translation
At beginning of period (308) (312) (313) (319)
Other foreign currency translations (a) 2 5 7 12
------- ------- ------- -------
At end of period (306) (307) (306) (307)
------- ------- ------- -------
At end of period (301) (297) (301) (297)
------- ------- ------- -------
RETAINED DEFICIT
At beginning of period (1,783) (1,557) (1,828) (1,734)
Net loss (a) (101) (263) (50) (81)
Preferred stock dividends declared (2) (2) (8) (7)
------- ------- ------- -------
At end of period (1,886) (1,822) (1,886) (1,822)
------- ------- ------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 2,276 $ 2,311 $ 2,276 $ 2,311
======= ======= ======= =======
(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
$1, $-, $1 and $-, respectively 2 1 3 -
Derivative Instruments
Unrealized gain (loss) on derivative instruments,
net of tax (tax benefit) of $(7), $15, $(14)
and $28, respectively (22) 31 (22) 43
Reclassification adjustments included in net loss,
net of tax benefit of $-, $(1), $(2) and
$(7), respectively (1) (1) (1) (7)
Foreign currency translation, net 2 5 7 12
Net loss (101) (263) (50) (81)
------- ------- ------- -------
Total Comprehensive Loss $ (120) $ (227) $ (63) $ (42)
======= ======= ======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-42
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. 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. 1 for the year ended December 31, 2005. 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. 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 in the 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
in Note 3, Contingencies.
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity
and natural gas, and the transportation, processing, and storage of natural gas
when services are provided. Sales taxes are recorded as liabilities and are not
included in revenues. Revenues on sales of marketed electricity, natural gas,
and other energy products are recognized at delivery. 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. These foreign currency translation adjustments are shown in
the stockholders' equity section on our Consolidated Balance Sheets. 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, the cumulative Foreign Currency Translation component of
stockholders' equity is $306 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 3.108
pesos per U.S. dollar was $264 million, net of tax. The cumulative foreign
currency loss due to the unfavorable exchange rate of the Brazilian real using
an exchange rate of 2.174 reais per U.S. dollar was $44 million, net of tax.
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 if
certain conditions that are other than temporary exist that may indicate the
carrying value may not be recoverable. Of our total assets, recorded at $14.978
billion at September 30, 2006, 58 percent represent long-lived assets and equity
method investments that are subject to this type of analysis.
For additional details, see Note 2, Asset Impairment Charges and Sales.
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.
CMS-44
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: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the periods presented.
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 the 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' Accounting for Defined Benefit Pension and Other
Postretirement Plans - an amendment of FASB Statements 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: In June 2006, the FASB
issued FIN 48, effective for us 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
authority 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 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, 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. If the fair value
is less than the carrying value 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 of natural gas to Chile, giving priority to domestic
demand 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.
CMS-46
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 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 conjunction with the preparation of our
consolidated financial statements for the quarter ended September 30, 2006, we
performed an impairment analysis to determine the fair value of our investment
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 party
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 on 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 million for the
nine 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 Corporation
For the nine months ended September 30, 2005, we sold the following assets:
In Millions
- --------------------------------------------------------------------------------
Pretax After-tax
Date sold Business/Project Gain Gain
- --------- ---------------- ------ ---------
February GVK $ 3 $ 2
April Scudder Latin American Power Fund 2 1
April Gas turbine and auxiliary equipment - -
--- ---
Total gain on asset sales $ 5 $ 3
=== ===
3: CONTINGENCIES
SEC AND OTHER 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 on May 17, 2002, a number of
complaints were filed against CMS Energy, Consumers, and certain officers and
directors of CMS Energy and its affiliates. The cases were consolidated into a
single lawsuit, 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 dated March 24, 2006, granting
in part and denying in part plaintiffs' amended motion for class certification.
The court conditionally certified a class consisting of "[a]ll 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. 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 names the same defendants as the shareholder action and contains
essentially the same allegations and class period. CMS Energy and the individual
defendants will defend themselves vigorously in this litigation but cannot
predict its outcome.
ERISA LAWSUITS: CMS Energy was 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 District of Michigan,
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings Plan (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, subject to court and independent
fiduciary approval, to settle the lawsuits. The settlement agreement required a
$28 million cash payment by CMS Energy's primary insurer to be used to pay Plan
participants and beneficiaries for alleged losses, as well as any legal fees and
expenses. In addition, CMS Energy agreed to certain other steps regarding
administration of the Plan. The hearing on final approval of the settlement was
held on June 15, 2006. On June 27, 2006, the judge entered the Order and Final
Judgment, approving the proposed settlement with minor modifications.
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 such acts, compel compliance with the
Commodities Exchange Act, and impose monetary penalties. CMS Energy is currently
advancing legal defense costs to the two individuals in accordance with existing
indemnification policies.
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) 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) 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 pH CKD
leachate flow to the lake. It is anticipated that by November 15, 2006,
collection trenches will be installed in all areas identified in the plan.
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.
CMS-49
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 CKD materials
and installing collection trenches in the East Park leachate release area. In
June 2006, the EPA approved an East 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 several of its subsidiaries, as well
as Bay Harbor Golf Club Inc., Bay Harbor Company LLC, David C. Johnson, and
David V. Johnson, one of the developers 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. CMS Land has
entered into various access, purchase and settlement agreements with several of
the affected landowners at Bay Harbor. CMS Land completed the purchase of four
unimproved lots and a lot with a house. It has an agreement to purchase one
additional unimproved lot and a lot with a house. At this time, CMS Land
believes it has all necessary access arrangements to complete the remediation
work required under the AOC.
CMS Energy has recorded a charge of $85 million for its obligations. 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.
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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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.
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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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 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, we have
recorded a liability for the minimum amount of our estimated probable Superfund
liability.
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 proposed a plan to deal
with the remaining materials and are awaiting a response from the EPA.
MCV Environmental Issue: In July 2004, the MDEQ, Air Control Division, issued
the MCV Partnership a Letter of Violation asserting that 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 MDEQ and the MCV Partnership have
agreed to a settlement 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.
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 Court 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. The plaintiffs have
appealed the dismissal to the United States Court of Appeals. We cannot predict
the outcome of these appeals.
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CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC ROA: 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, alternative electric suppliers were providing
308 MW of generation service to ROA customers, which represents four percent of
our total distribution load. This represents a decrease of one percent of ROA
load compared to June 30, 2006 and a decrease of 60 percent of ROA load compared
to the end of September 2005. It is difficult to predict future ROA customer
trends.
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,
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 prices during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasing 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 million for unexpired capacity and energy
contracts at September 30, 2006. At September 2006, we expect the total capacity
cost of electric capacity and energy contracts for 2006 to be $17 million.
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 actual costs for reasonableness and prudence. In September 2005, we submitted
our 2006 PSCR plan filing to the MPSC. 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 an order approving our amended 2006 PSCR plan,
which results 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 coal supply costs,
increased bundled sales, and other cost increases beyond those included in the
September 2005 and November 2005 filings. 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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In September 2006, we submitted our 2007 PSCR plan filing to the MPSC, which
includes the underrecoveries incurred in 2005 and 2006. We expect to
self-implement the proposed 2007 PSCR charge in January 2007, absent action by
the MPSC by the end of 2006. We cannot predict the outcome of this proceeding.
OTHER CONSUMERS' ELECTRIC UTILITY CONTINGENCIES
THE MIDLAND COGENERATION VENTURE: 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. 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. The sale
does not affect the MCV PPA and the associated customer rates. We are targeting
to close on the sale 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 July 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 interests 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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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, the cost that we incur under
the MCV PPA exceeds the recovery amount allowed by the MPSC. We expense all cash
underrecoveries directly to income. We estimate underrecoveries of $56 million
in 2006 and $39 million in 2007. Of the 2006 estimate, we expensed $42 million
during the nine months ended September 30, 2006. However, our direct savings
from the RCP, after allocating a portion to customers, are used to offset 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 MCV Partnership has
indicated that it may take issue with our 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 has the right to terminate the MCV PPA, 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 exercise of the regulatory out provision and the likely consequences of
such action will be reviewed by the MPSC in 2007. Some parties have suggested
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 MSPC 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 Facility on the basis of natural gas market
prices, which reduces 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 consumed 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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October 2006. The Attorney General also filed an appeal with the Michigan Court
of Appeals. We cannot predict the outcome of these matters.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in 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 indicated that we would manage the
decommissioning trust fund 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 additional nuclear fuel storage costs due 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, providing for the continuation
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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In March 2005, the NMC, which operates the Palisades plant, applied for a
20-year license renewal for the plant on behalf 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 to 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
to Entergy. As part of the transaction, Entergy will sell us 100 percent of the
plant's output up to its current capacity of 798 MW under a 15-year power
purchase agreement. Because of the 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, including real estate with equipment. In accordance with SFAS No. 98,
the transaction will be accounted for as a financing and not a sale. This is due
to forms of continuing involvement. As such, we have not classified the assets
as held for sale on our Consolidated Balance Sheets.
The sale is subject to various regulatory approvals, including the MPSC's
approval 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 action on the sale. The final purchase price will be subject
to various closing adjustments such as working capital and capital expenditure
adjustments, adjustments for nuclear fuel usage and inventory, and the date of
closing. Under the agreement, if the transaction does not close by March 1,
2007, the purchase price will 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.
NUCLEAR MATTERS: Nuclear Fuel Cost: We amortize 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 charge certain disposal costs to
nuclear fuel expense, recover these costs through electric rates, and remit 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, our DOE liability is
$150 million. This amount includes interest, which is payable upon the first
delivery of spent nuclear fuel to the DOE. The amount of this liability,
excluding a portion of interest, was recovered through electric rates. In
conjunction with the sale of Palisades and the Big Rock ISFSI, we will retain
this obligation and provide security to Entergy for this obligation in the form
of either cash, a letter of credit, or other acceptable means.
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
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the cost of spent nuclear fuel storage until the DOE takes possession as
required by law. We can make no assurance that the litigation against the DOE
will be successful.
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 maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain 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 maintain 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 maintain 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 remains insured for nuclear liability up to $544 million through
nuclear insurance and NRC indemnity, and maintains 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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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, we have
a liability of $26 million, net of $56 million of expenditures incurred to date,
and a regulatory asset of $58 million. 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.
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
- -------- ---------- ---------- ---------- ------------ -------------------------------
2004-2005 June 2005 April 2006 $2 million $1.4 billion The net overrecovery includes
interest expense through March
2005 and refunds that we
received from our suppliers
that are required to be
refunded to our customers.
2005-2006 June 2006 Pending $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.
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 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 we are unable to predict the
outcome.
GCR plan for year 2006-2007: In December 2005, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2006
through March 2007. Our request proposed using a GCR factor consisting of:
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CMS Energy Corporation
- a base GCR ceiling factor of $11.10 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.
The GCR billing factor is adjusted monthly in order to minimize the over or
under-recovery amounts in our annual GCR reconciliation. Our GCR billing factor
for the month of November 2006 is $7.83 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.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking
a 12 percent authorized return on equity along with a $132 million annual
increase in our gas delivery and transportation rates. As part 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 that $17 million of this amount 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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CMS Energy Corporation
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
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 false 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,
Missouri, Tennessee and Kansas. In February 2006, CMS MST and CMS Field Services
reached an agreement to settle 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 for $7 million. The settlement
is contingent upon 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 granting preliminary approval of the settlement, a process
that may take several months to complete. CMS Energy deemed this settlement to
be probable and accrued the payment in its consolidated financial statements at
September 30, 2006. CMS Energy and the other CMS Energy defendants will defend
themselves vigorously against all of these 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
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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, 2005 and will be
considered by a newly constituted panel.
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 recorded the $75
million payment as deferred revenue at December 31, 2005.
IRS AUDIT RESOLUTION: In August 2005, the IRS issued Revenue Ruling 2005-53 and
regulations to provide guidance with respect to the use 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 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. 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.
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.
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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:
In Millions
- ------------------------------------------------------------------------------------------------
Maximum Carrying
Guarantee Description Issue Date Expiration Date Obligation Amount
- --------------------- ------------ --------------- ---------- --------
Indemnifications from asset sales and
other agreements (a) October 1995 Indefinite $1,133 $ 1
Standby letters of credit and loans (b) Various Various through 90 -
May 2010
Surety bonds and other indemnifications Various Indefinite 10 -
Other guarantees (c) Various Various through 218 1
September 2027
Nuclear insurance retrospective
premiums 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 from 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, letters of credit issued on behalf of unconsolidated
affiliates totaling $65 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 sell our interests in the MCV Partnership and
the FMLP, subject to certain regulatory and other closing conditions. 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. The
purchaser will secure their reimbursement obligation with an irrevocable
letter of credit of up to $85 million.
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CMS Energy Corporation
The following table provides additional information regarding our guarantees:
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 guarantees Normal operating activity Nonperformance or non-payment by a
subsidiary under a related contract
Agreement to provide power and steam MCV Partnership's nonperformance or
to Dow 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 Act
premiums for nuclear incident
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 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. 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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CMS Energy Corporation
4: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
---------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
CMS ENERGY CORPORATION
Senior notes $2,271 $2,347
Other long-term debt 1 2
------ ------
Total - CMS Energy Corporation 2,272 2,349
------ ------
CONSUMERS ENERGY COMPANY
First mortgage bonds 3,173 3,175
Senior notes and other 801 852
Securitization bonds 348 369
------ ------
Total - Consumers Energy Company 4,322 4,396
------ ------
OTHER SUBSIDIARIES 353 363
------ ------
TOTAL PRINCIPAL AMOUNTS OUTSTANDING 6,947 7,108
Current amounts (288) (289)
Net unamortized discount (15) (19)
------ ------
Total Long-term debt $6,644 $6,800
====== ======
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
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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:
In Millions
- -----------------------------------------------------------------------------------------------
Amount of Amount Outstanding
Company Expiration Date Facility Borrowed Letters-of-Credit Amount Available
- --------------- --------------- --------- -------- ----------------- ----------------
CMS Energy May 18, 2010 $300 $ - $104 $196
Consumers March 30, 2007 300 - - 300
Consumers May 18, 2010 500 - 62 438
MCV Partnership August 25, 2007 25 - 7 18
In March 2006, Consumers entered into a short-term secured revolving credit
agreement with banks. This facility provides $300 million of funds for working
capital and other general corporate purposes.
DIVIDEND RESTRICTIONS: Our amended and restated $300 million secured revolving
credit facility restricts payments of dividends on our common stock during a
12-month period to $150 million, dependent on the aggregate amounts of
unrestricted cash and unused commitments under the facility.
Under the provisions of its articles of incorporation, at September 30, 2006,
Consumers had $253 million of unrestricted retained earnings available to pay
common stock dividends. Covenants in Consumers' debt facilities cap common stock
dividend payments at $300 million in a calendar year. Provisions of the Federal
Power Act and the Natural Gas Act effectively restrict dividends to the amount
of Consumers' retained earnings. For the nine months ended September 30, 2006,
we received $71 million of common stock dividends from Consumers.
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, capital lease obligations totaled $55 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 million of receivables at
September 30, 2006 and $325 million of receivables at December 31, 2005.
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.
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CMS Energy Corporation
Certain cash flows under Consumers' accounts receivable sales program are shown
in the following table:
In Millions
---------------
Nine months ended September 30 2006 2005
- ------------------------------ ------ ------
Net cash flow as a result of accounts receivable financing $ (9) $ (204)
Collections from customers $4,402 $3,782
====== ======
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.
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 30 2006 2005
- ------------------------------- ------ ------
LOSS AVAILABLE TO COMMON STOCKHOLDERS
Loss from Continuing Operations $ (102) $ (263)
Less Preferred Dividends (2) (2)
------ ------
Loss from Continuing Operations Available to
Common Stockholders - Basic and Diluted $ (104) $ (265)
====== ======
AVERAGE COMMON SHARES OUTSTANDING
Weighted Average Shares - Basic and Diluted 220.1 219.6
LOSS PER AVERAGE COMMON SHARE
AVAILABLE TO COMMON STOCKHOLDERS
Basic $(0.47) $(1.21)
Diluted $(0.47) $(1.21)
====== ======
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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)
====== ======
Contingently Convertible Securities: For the three and nine months ended
September 30, 2006, we recorded a loss from continuing operations, therefore 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 11.5 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.
Stock Options and Warrants: For the three and nine months ended September 30,
2006, due to antidilution, there was no impact to diluted EPS for options and
warrants to purchase 3.0 million shares of common stock. For the three and nine
months ended September 30, 2005, due to antidilution, there was no impact to
diluted EPS for options and warrants to purchase 3.8 million shares of common
stock.
Convertible Debentures: Due to accounting EPS dilution principles, for the three
and nine months ended September 30, 2006, 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, from an assumed reduction of interest expense, net of tax, and
- - increased the denominator of diluted EPS by 4.3 million shares.
We can revoke the conversion rights if certain conditions are met.
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.
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CMS Energy Corporation
The cost and fair value of our long-term financial instruments are as follows:
In Millions
-------------------------------------------------------------
September 30, 2006 December 31, 2005
----------------------------- -----------------------------
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
Long-term debt - related parties,
including current amounts 178 151 27 307 280 27
Available-for-sale securities:
SERP:
Equity securities 35 53 18 34 49 15
Debt securities 15 15 - 17 17 -
Nuclear decommissioning investments:
Equity securities 138 268 130 134 252 118
Debt securities 304 307 3 287 291 4
In July 2006, we reached an agreement to sell 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 $382 million of nuclear decommissioning
trust fund assets to Entergy and retain $205 million. We will also be entitled
to receive a return 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 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. The disposition
of the retained and receivable nuclear decommissioning funds is subject to
regulatory proceedings.
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 the balance sheet at its
fair value. We then adjust the resulting asset or liability each quarter to
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; otherwise, the changes are reported in earnings.
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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, 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 income
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 MW 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 of an active energy market
in Michigan. If active markets for these commodities develop in the future, some
of these contracts may qualify as derivatives. For our coal purchase contracts,
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.
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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:
In Millions
-------------------------------------------------------
September 30, 2006 December 31, 2005
-------------------------- --------------------------
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 contracts:
Non-trading electric / gas contracts (b) - 34 34 - (63) (63)
Trading electric / gas contracts (c) - (65) (65) (3) 100 103
Derivative contracts associated with equity
investments in:
Shuweihat - (15) (15) - (20) (20)
Taweelah (35) (13) 22 (35) (17) 18
Jorf Lasfar - (6) (6) - (8) (8)
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 of 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,
some of our equity method investees 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 record our proportionate share of the change in fair value of these contracts
in Accumulated other comprehensive loss if the contracts qualify for cash flow
hedge accounting; otherwise, we record our share in Earnings from Equity Method
Investees.
FOREIGN EXCHANGE DERIVATIVES: At times, we use forward exchange and option
contracts to hedge the value of investments in foreign operations. These
contracts limit 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, 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 loss 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, our total foreign currency
translation adjustment was a net loss of $306 million, which included a net
hedging loss of $26 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 enter into contracts primarily with companies in
the electric and
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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 use 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,
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 (%)
--------------- ---------- -------- ----------------- -----------------
CMS ERM $ 51 $ - $ 51 $ 2 (c) 4
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.
(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 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, the MPSC electric rate order authorized Consumers to
include $33 million
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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. This standard will
require us to 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 recognize changes in the funded status of our plans in the year in which the
changes occur. Upon implementation 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 this provision of the standard would
have a material effect on our financial statements.
8: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, "ACCOUNTING FOR ASSET RETIREMENT 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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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 on
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. 47.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
September 30, 2006 In Millions
- ---------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- --------------- ---------- ---------------------------------------- -----
Palisades-decommission plant site 1972 Palisades nuclear plant $576
Big Rock-decommission plant site 1962 Big Rock nuclear plant 6
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 -
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In Millions
- -----------------------------------------------------------------------------------------------------------------
ARO ARO
Liability Cash flow Liability
ARO Description 12/31/05 Incurred Settled (a) Accretion Revisions 9/30/06
- --------------- --------- -------- ----------- --------- --------- -----------
Palisades-decommission $375 $ - $ - $19 $ - $394
Big Rock-decommission 27 - (22) 3 - 8
JHCampbell intake line - - - - - -
Coal ash disposal areas 54 - (2) 4 - 56
Wells at gas storage fields 1 - - - - 1
Indoor gas services relocations 1 - - - - 1
Natural gas-fired power plant 1 - - - - 1
Close gas treating plant and gas wells 1 - - 1 - 2
Asbestos abatement 36 - (2) 1 - 35
---- --- ---- --- --- ----
Total $496 $ - $(26) $28 $ - $498
==== === ==== === === ====
(a) These cash payments are included in the Other current and non-current
liabilities line in Net cash provided by operating activities on our
Consolidated Statements of Cash Flows. Cash payments for the nine months
ended September 30, 2005 were $37 million.
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
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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.
CMS-82
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 was $19 million for the three months ended
September 30, 2006 and $40 million for the three months ended September 30,
2005. Earnings from equity method investments was $63 million for the nine
months ended September 30, 2006 and $92 million for the nine months ended
September 30, 2005. The most significant of these investments is our 50 percent
interest in Jorf Lasfar.
Summarized financial information for Jorf Lasfar is as follows:
Income Statement Data
In Millions
--------------------------------------
JORF LASFAR Three Months Ended Nine Months Ended
- ----------- ------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ---- ---- ---- ----
Operating revenue $121 $123 $355 $382
Operating expenses 77 82 235 255
---- ---- ---- ----
Operating income 44 41 120 127
Other expense, net 16 16 42 44
---- ---- ---- ----
Net income $ 28 $ 25 $ 78 $ 83
==== ==== ==== ====
CMS-83
CMS Energy Corporation
11: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by their
products and services. 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 and discontinued
operations. The following tables show our financial information by reportable
segment:
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ------ ------ ------ ------
Operating Revenue
Electric utility $ 976 $ 793 $2,496 $2,065
Gas utility 201 219 1,576 1,566
Enterprises 285 295 818 751
------ ------ ------ ------
Total Operating Revenue $1,462 $1,307 $4,890 $4,382
====== ====== ====== ======
Net Income (Loss) Available to Common Stockholders
Electric utility $ 93 $ 62 $ 159 $ 141
Gas utility (20) (16) 14 39
Enterprises (132) (260) (177) (126)
Other (44) (51) (54) (142)
------ ------ ------ ------
Total Net Loss Available to Common Stockholders $ (103) $ (265) $ (58) $ (88)
====== ====== ====== ======
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
Assets
Electric utility (a) $ 7,893 $ 7,743
Gas utility (a) 3,835 3,600
Enterprises 3,097 4,130
Other 153 547
------- -------
Total Assets $14,978 $16,020
======= =======
(a) Amounts include a portion of Consumers' other common assets attributable to
both the electric and gas utility businesses.
CMS-84
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.
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
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, 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 the Palisades nuclear plant to
Entergy for $380 million. We also signed a 15-year power purchase agreement for
100 percent of the plant's current electric output. We are targeting to close
the sale by May 1, 2007. When completed, the sale will result 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 expect that a significant portion of the proceeds
will benefit our customers. We plan to use the cash that we retain from the sale
to reduce utility debt.
CE-1
Consumers Energy Company
Working capital and cash flow continue to be a challenge for us, as natural gas
prices continue 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.
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.
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.
These negative effects will be offset somewhat by the reduction we are
experiencing in ROA load in our service territory. At September 30, 2006,
alternative electric suppliers were providing 308 MW of generation service to
ROA customers. This is four percent of our total distribution load and
represents a decrease of 60 percent of ROA load compared to the end of September
2005. It is, however, difficult to predict future ROA customer trends.
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:
- 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 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, and
- sales of the Palisades plant and our interest in the MCV
Partnership,
- the impact of adverse natural 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
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 recover the cost of these purchases, if we exercise our regulatory
out rights and the MCV Partnership exercises its 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 problems, or other
developments,
- our ability to collect accounts receivable from our customers,
- 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 availability of
spent nuclear fuel storage,
- 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, 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.
CE-4
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.
RESULTS OF OPERATIONS
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER
In Millions
---------------------
Three months ended September 30 2006 2005 Change
- ------------------------------- ---- ----- ------
Electric $ 93 $ 62 $ 31
Gas (20) (16) (4)
Other (Includes the MCV Partnership interest) 26 (322) 348
---- ----- ----
Net income (loss) available to common stockholder $ 99 $(276) $375
==== ===== ====
For the three months ended September 30, 2006, net income available to our
common stockholder was $99 million, compared to a net loss of $276 million for
the three 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.
CE-5
Consumers Energy Company
Specific changes to net income (loss) available to our common stockholder for
the three 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, 39
- - 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)
----
Total Change $375
====
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.
CE-6
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
=====
CE-7
Consumers Energy Company
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2006 2005 Change
- ------------ ---- ---- ------
Three months ended $ 93 $ 62 $31
Nine months ended $159 $141 $18
==== ==== ===
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
Other operating expenses, other income, and
non-commodity revenue (44) (174)
Regulatory return on capital expenditures (9) (30)
General taxes (2) (3)
Interest charges (1) (3)
Income taxes (18) (8)
---- -----
Total change $ 31 $ 18
==== =====
ELECTRIC DELIVERIES: For 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 rates 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, electric delivery revenues increased $24
million for the three months ended September 30, 2006 and $67 million for the
nine months ended September 30, 2006 versus the same periods in 2005.
Surcharge Revenue: Effective January 1, 2006, we started collecting a surcharge
that the MPSC authorized under Section 10d(4) of the Customer Choice Act. This
surcharge increased electric delivery revenue by $15 million for the three
months ended September 30, 2006 and $38 million for the nine months ended
September 30, 2006 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: 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, alternative electric suppliers were
providing 308 MW of generation service to ROA customers. This amount represents
a decrease of 60 percent of ROA load compared to the end of September 2005. The
return of former ROA customers to full-service rates increased electric revenues
$12 million for the three months ended September 30, 2006 and $40 million for
the nine months ended September 30, 2006 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.
OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For the three
months ended September 30, 2006, other operating expenses increased $48 million,
and non-commodity revenue increased $4 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.
The increase 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, operating and maintenance expense
increased primarily due to higher storm restoration costs. For the nine months
ended September 30, 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 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 benefit 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 was primarily due to an increase in capital-related services provided to
METC in 2006 versus 2005.
For the nine months ended September 30, 2006, the increase in other income was
primarily due to higher interest income and the absence, in 2006, of expenses
recorded in 2005 associated with the early retirement of debt. 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 for 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 both 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
higher MSBT expense, offset partially by lower property tax expense.
INTEREST CHARGES: For the three months ended September 30, 2006, interest
charges increased 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 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.
INCOME TAXES: For the three months ended September 30, 2006, 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 by
the resolution of an IRS income tax audit, which resulted in a $4 million income
tax benefit caused by the restoration and utilization of income tax credits.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2006 2005 Change
- ------------ ---- ---- ------
Three months ended $(20) $(16) $ (4)
Nine months ended $ 14 $ 39 $(25)
==== ==== ====
Three Months Ended Nine Months Ended
September 30, 2006 September 30, 2006
Reasons for the change: vs.2005 vs.2005
- ----------------------- ------------------ ------------------
Gas deliveries $(13) $(49)
Gas wholesale and retail services, other gas
revenues and other income 9 20
Operation and maintenance 3 1
General taxes and depreciation - (5)
Interest charges (3) (6)
Income taxes - 14
---- ----
Total change $ (4) $(25)
==== ====
GAS DELIVERIES: For the three months ended September 30, 2006, gas deliveries,
including miscellaneous transportation to end-use customers, decreased 1 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
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Consumers Energy Company
gas volumes. In 2005, this annual analysis led to a slight 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 warmer weather in
2006 versus 2005 and increased customer conservation efforts in response to
higher gas prices.
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES AND OTHER INCOME: For the
three and nine months ended September 30, 2006, the increase primarily reflects
higher pipeline revenues and other income capacity optimization in 2006 versus
2005.
OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2006, operation and maintenance expenses decreased versus 2005 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. Customer service
expense increased primarily due to higher uncollectible accounts expense.
GENERAL TAXES AND DEPRECIATION: For the nine months ended September 30, 2006,
depreciation expense increased versus 2005 primarily due to higher plant in
service. The increase in general taxes reflects higher MSBT expense, offset
partially by lower property tax expense.
INTEREST CHARGES: For the three months ended September 30, 2006, interest
charges increased due to higher GCR interest expense, offset partially by a 3
basis point reduction in the average rate of interest on our debt and lower
average debt levels 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.
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.
OTHER RESULTS OF OPERATIONS
In Millions
---------------------
September 30 2006 2005 Change
- ------------ ---- ----- ------
Three months ended $ 26 $(322) $348
Nine months ended $(29) $(267) $238
==== ===== ====
For the three months ended September 30, 2006, other operations net income was
$26 million, an increase of $348 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. A 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.
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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.
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.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, we use estimates and assumptions 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 that may cause actual results to differ from estimated results,
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 by the principles in SFAS No. 5. We consider many
factors in making these assessments, including the history and specifics of each
matter. Significant contingencies are discussed in the "Outlook" section
included in this MD&A.
ACCOUNTING FOR FINANCIAL AND DERIVATIVE INSTRUMENTS AND MARKET RISK INFORMATION
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. For additional details on accounting for financial
instruments, see Note 4, Financial and Derivative Instruments.
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. For additional details on accounting for 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
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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
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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. 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 December 31, 2005
------------------ -----------------
Variable-rate financing - before tax
annual earnings exposure $ 4 $ 3
Fixed-rate financing - potential
REDUCTION in fair value (a) 138 149
(a) Fair value reduction could only be realized if we repurchased all of our
fixed-rate financing.
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Consumers Energy Company
Commodity Price Risk Sensitivity Analysis (assuming an adverse change in market
prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
Potential REDUCTION in fair value:
Gas supply option contracts $ - $ 1
Derivative contracts associated with
the MCV Partnership:
Long-term gas contracts 13 39
Gas futures, options, and swaps 27 48
Investment Securities Price Risk Sensitivity Analysis (assuming an adverse
change in market prices of 10 percent):
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
Potential REDUCTION in fair value of
available-for-sale equity securities
(SERP investments and investment in
CMS Energy common stock) $6 $6
We maintain 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, these funds were invested primarily in equity securities,
fixed-rate, fixed-income debt securities, and cash and cash equivalents, and are
recorded at fair value on our Consolidated Balance Sheets. These investments are
exposed to price fluctuations in equity markets and changes in interest rates.
Because the accounting for nuclear plant decommissioning recognizes that costs
are recovered through our electric rates, fluctuations in equity prices or
interest rates do 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 2005 Form 10-K and there have
been no subsequent material changes.
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Consumers Energy Company
CAPITAL RESOURCES AND LIQUIDITY
Factors affecting our liquidity and capital requirements are:
- results of operations,
- capital expenditures,
- energy commodity 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
purchases are recoverable from our customers, the amount paid for natural gas
stored as inventory requires additional liquidity due to the timing of the cost
recoveries. We have credit agreements with our commodity suppliers and those
agreements contain terms that have resulted in margin calls. Additional margin
calls or other credit support 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.
We believe the following items will be sufficient to meet our liquidity needs:
- our current level of cash and revolving credit facilities,
- our ability to access junior secured and unsecured borrowing capacity
in the capital markets, and
- our anticipated cash flows from operating and investing activities.
In June 2006, Moody's revised our credit rating outlook to stable from negative.
In September 2006, Moody's upgraded our credit ratings.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2006, $185 million consolidated cash was on hand, which
includes $57 million of restricted cash and $78 million from entities
consolidated pursuant to FASB Interpretation No. 46(R).
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SUMMARY OF CONSOLIDATED STATEMENTS OF CASH FLOWS:
In Millions
-------------
Nine Months Ended September 30 2006 2005
- ------------------------------ ----- -----
Net cash provided by (used in):
Operating activities $ 89 $ 641
Investing activities (371) (511)
----- -----
Net cash provided by (used in) operating and investing
activities (282) 130
Financing activities (6) 177
----- -----
Net Increase (Decrease) in Cash and Cash Equivalents $(288) $ 307
===== =====
OPERATING ACTIVITIES: For the nine months ended September 30, 2006, net cash
provided by operating activities was $89 million, a decrease of $552 million
versus 2005. This was the result of decreases in the MCV Partnership gas
supplier funds on deposit and 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 decrease in the MCV Partnership gas
supplier funds on deposit was the result of refunds to suppliers from decreased
exposure due to declining gas prices in 2006. The decrease in accounts payable
was mainly due to payments for higher priced gas that were accrued at December
31, 2005. The decrease in accounts receivable was primarily 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, and the
expiration of emergency rules initiated by the MPSC, which delayed customer
payments during the heating season.
INVESTING ACTIVITIES: For the nine months ended September 30, 2006, net cash
used in investing activities was $371 million, a decrease of $140 million versus
2005. This decrease was due to the release of restricted cash in February 2006,
which we used to extinguish long-term debt- related parties.
FINANCING ACTIVITIES: For the nine months ended September 30, 2006, net cash
used in financing activities was $6 million, a change of $183 million versus
2005. This change was primarily due to lower stockholder's contributions from
the parent, partially offset by a decrease in payments of common stock dividends
of $136 million.
For additional details on long-term debt activity, 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.
These arrangements include indemnifications, letters of credit and surety bonds.
For details on guarantee arrangements, see Note 2, 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 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
ELECTRIC BUSINESS OUTLOOK
GROWTH: Summer 2006 temperatures were higher than historical averages, leading
to increased 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 decline about one
percent from 2005 levels. This short-term outlook assumes a stabilizing economy
and normal weather conditions for the fourth quarter of 2006.
Over the next five years, we expect electric deliveries to grow at an average
rate of about one and one-half percent per year. However, such growth is
dependent on a modestly growing customer base and a stabilizing Michigan
economy. 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 fluctuations in weather conditions and changes in economic
conditions, including utilization and expansion or contraction of manufacturing
facilities.
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. 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 million for unexpired 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. After September 15, 2007, we expect to exercise our claim for
relief under the regulatory out provision in the MCV PPA. If we are successful
in exercising our claim, the MCV Partnership has the right to terminate the MCV
PPA, which could affect our reserve margin status. The MCV PPA represents 15
percent of our 2007 supply resources target.
ELECTRIC TRANSMISSION EXPENSES: METC, which provides electric transmission
service to us, increased substantially the transmission rates it charges us in
2006. The increased rates are subject to refund and to reduction based on the
outcome of hearings at the FERC scheduled for December 2006. Recovery of a
portion 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,
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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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.
THE ELECTRIC CAPACITY NEED FORUM: In January 2006, the MPSC Staff issued a
report on future electric capacity in the state of Michigan. The report
indicated that existing generation resources are adequate in the short term, but
could be insufficient to maintain reliability standards by 2009. The report also
indicated that new coal-fired baseload generation may be needed by 2011. The
MPSC Staff recommended an approval 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, to make
recommendations on Michigan's energy policy by the end of 2006. We will continue
to participate as the MPSC addresses future electric capacity needs.
BURIAL OF OVERHEAD POWER LINES: The City of Taylor, a municipality located in
Wayne County, Michigan, passed an ordinance that required Detroit Edison to bury
a section of overhead power lines at Detroit Edison's expense. In September
2004, the Michigan Court of Appeals upheld a lower court decision affirming the
legality of the ordinance over Detroit Edison's objections. Other municipalities
in our service territory adopted, or proposed the adoption of, similar
ordinances. Detroit Edison appealed the Michigan Court of Appeals ruling to the
Michigan Supreme Court. In May 2006, the Michigan Supreme Court ruled 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.
ELECTRIC BUSINESS UNCERTAINTIES
Several electric business trends or uncertainties may affect our financial
results and condition. 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 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. 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. 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.
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 this
rule by year round operation of our selective catalytic reduction control
technology units and installation of flue gas desulfurization scrubbers at an
estimated total cost of $960 million, to be incurred by 2014.
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 mercury
emissions reductions of 90 percent by 2015. 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.
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, the U.S. Supreme Court has agreed to
hear a case claiming that the EPA is required by the Clean Air Act to consider
regulating carbon dioxide emissions from automobiles. The EPA asserts that it
lacks authority to regulate carbon dioxide emissions. If the Supreme Court finds
that the EPA has authority to regulate carbon dioxide emissions in this case, it
could result in new federal carbon dioxide regulations for other industries,
including the utility industry.
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 of
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 being challenged in court and we will finalize our cost estimates in
early 2007, when a decision on the final rule is anticipated. We expect to
implement the EPA approved process from 2009 to 2011.
For additional details on electric environmental matters, see Note 2,
Contingencies, "Electric Contingencies - Electric Environmental Matters."
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, alternative electric
suppliers were providing 308 MW of generation service to ROA customers, which
represents four percent of our total distribution load. It is difficult to
predict future ROA customer trends.
Section 10d(4) Regulatory Assets: In December 2005, the MPSC issued an order
that authorized us 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. 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,
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.
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.
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
MCV UNDERRECOVERIES: 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, the 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, our 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 such 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 indicated that it may take issue with our
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 has the right to terminate the MCV
PPA. If the MCV Partnership terminates 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.
For additional details on the MCV Partnership, see Note 2, Contingencies, "Other
Electric Contingencies - The Midland Cogeneration Venture."
NUCLEAR MATTERS: Sale of Nuclear Assets: In July 2006, we reached an agreement
to sell 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, the 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 schedule for the contested case
proceedings regarding this transaction, the sale is targeted to close by May 1,
2007. This two-month delay in the originally anticipated March 1, 2007 closing
date would result in a purchase price reduction of approximately $5 million. We
estimate that the Palisades sale will result in a $31 million premium above the
Palisades asset values at the anticipated closing date after accounting for
estimated sales-related costs. This premium is expected to benefit our
customers.
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 accepting the responsibility for the storage and
disposal of the Big Rock ISFSI. At the anticipated date of close,
decommissioning trust assets are estimated to be $587 million. We will retain
$205 million of these funds at 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. The disposition
of the retained and receivable nuclear decommissioning funds is subject to
regulatory approval. We expect that a significant portion of 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.
As part of the transaction, Entergy will sell us 100 percent of the plant's
output up to its current capacity of 798 MW under a 15-year power purchase
agreement. During the term 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
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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 pricing is structured such
that Consumers' ratepayers will retain the benefits of the Palisades plant's
low-cost nuclear generation.
The sale is subject to various regulatory approvals, including the MPSC's
approval 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 action on the sale. The final purchase price will be subject
to various closing adjustments such as working capital 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 - Nuclear
Plant Decommissioning."
GAS BUSINESS OUTLOOK
GROWTH: In 2006, we project gas deliveries will decline by four percent, on a
weather-adjusted basis, from 2005 levels due to increased conservation and
overall economic conditions in the state of Michigan. Over the next five years,
we expect gas deliveries to be relatively flat. Actual gas deliveries in future
periods may be affected by:
CE-24
Consumers Energy Company
- fluctuations in weather patterns,
- 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.
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 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.
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.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking
a 12 percent authorized return on equity along with a $132 million annual
increase in our gas delivery and transportation rates. As part 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.
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Consumers Energy Company
In February 2006, the MPSC Staff recommended granting final rate relief of $62
million. The MPSC Staff proposed that $17 million of this amount 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 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 OUTLOOK
VOLUNTARY RULES REGARDING BILLING PRACTICES: In October 2006, the MPSC announced
a voluntary agreement relating to billing practices with us and other Michigan
natural gas and electric utilities that will provide additional help to
low-income customers for the winter heating period of November 1, 2006 through
March 31, 2007. The rules address billing practices such as billing cycles,
fees, deposits, shutoffs, and collection of unpaid bills for retail customers of
electric and gas utilities. These rules will have an estimated $3 million
negative effect on our earnings for the period of these rules and an estimated
negative effect on our cash flow of up to $50 million for 2006.
MCV PARTNERSHIP NEGATIVE EQUITY: Due to the impairment of 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.
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 impact of this legislation.
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Consumers Energy Company
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
SFAS NO. 123(R) AND SAB NO. 107, SHARE-BASED PAYMENT: 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. SFAS No. 123(R) was effective for us on
January 1, 2006. We elected to adopt the modified prospective method recognition
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 EFFECTIVE
FIN 48, ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES: In June 2006, the FASB
issued FIN 48, effective for us 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
authority 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 would result in a cumulative
adjustment to retained earnings.
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 the 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' 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. This standard will
require us to 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 recognize changes in the funded status of our plans in the year in which the
changes occur. Upon implementation 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 this provision of the standard would
have a material effect on our financial statements.
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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.
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Consumers Energy Company
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CE-29
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(UNAUDITED)
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ------ ------ ------ -----
OPERATING REVENUE $1,191 $1,025 $4,111 $3,673
EARNINGS FROM EQUITY METHOD INVESTEES - 1 1 1
OPERATING EXPENSES Fuel for electric generation 213 183 557 494
Fuel costs mark-to-market at the MCV Partnership 28 (197) 226 (367)
Purchased and interchange power 183 145 427 272
Purchased power - related parties 18 19 55 50
Cost of gas sold 125 133 1,164 1,115
Other operating expenses 226 212 661 601
Maintenance 64 53 214 155
Depreciation, depletion, and amortization 119 113 387 369
General taxes (24) 46 97 164
Asset impairment charges - 1,184 - 1,184
------ ------ ------ ------
952 1,891 3,788 4,037
------ ------ ------ ------
OPERATING INCOME (LOSS) 239 (865) 324 (363)
OTHER INCOME Accretion expense - - - (1)
(DEDUCTIONS) Interest and dividends 18 9 44 24
Regulatory return on capital expenditures 8 17 18 48
Other income 3 6 17 16
Other expense (1) (2) (5) (10)
------ ------ ------ ------
28 30 74 77
------ ------ ------ ------
INTEREST CHARGES Interest on long-term debt 70 70 216 217
Interest on long-term debt - related parties - 3 1 12
Other interest 4 - 12 4
Capitalized interest (2) (1) (7) (3)
------ ------ ------ ------
72 72 222 230
------ ------ ------ ------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS 195 (907) 176 (516)
MINORITY INTERESTS (OBLIGATIONS), NET 40 (483) (35) (386)
------ ------ ------ ------
INCOME (LOSS) BEFORE INCOME TAXES 155 (424) 211 (130)
INCOME TAX (BENEFIT) EXPENSE 56 (148) 66 (44)
------ ------ ------ ------
NET INCOME (LOSS) 99 (276) 145 (86)
PREFERRED STOCK DIVIDENDS - - 1 1
------ ------ ------ ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER $ 99 $ (276) $ 144 $ (87)
====== ====== ====== ======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-30
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
In Millions
-----------------
Nine Months Ended
-----------------
September 30 2006 2005
- ------------ ----- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 145 $ (86)
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation, depletion, and amortization (includes nuclear
decommissioning of $3 per year) 387 369
Deferred income taxes and investment tax credit (267) (97)
Fuel costs mark-to-market at the MCV Partnership 226 (367)
Asset impairment charges - 1,184
Minority interests (obligations), net (35) (386)
Regulatory return on capital expenditures (18) (48)
Capital lease and other amortization 27 25
Earnings from equity method investees (1) (1)
Changes in assets and liabilities:
Decrease (increase) in accounts receivable and accrued revenue 212 (44)
Increase in inventories (256) (351)
Decrease in deferred property taxes 101 105
Increase (decrease) in accounts payable (93) 177
Increase (decrease) in accrued expenses 40 (32)
Decrease in accrued taxes (248) (121)
Increase (decrease) in the MCV Partnership gas supplier funds on deposit (159) 275
Decrease (increase) in other current and non-current assets (8) 75
Increase (decrease) in other current and non-current liabilities 36 (36)
----- -------
Net cash provided by operating activities 89 641
----- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) (461) (419)
Cost to retire property (41) (21)
Restricted cash and restricted short-term investments 126 (163)
Investments in nuclear decommissioning trust funds (20) (5)
Proceeds from nuclear decommissioning trust funds 20 31
Proceeds from short-term investments - 145
Purchase of short-term investments - (141)
Maturity of the MCV Partnership restricted investment securities held-to-maturity 119 316
Purchase of the MCV Partnership restricted investment securities held-to-maturity (118) (267)
Cash proceeds from sale of assets - 1
Other investing 4 12
----- -------
Net cash used in investing activities (371) (511)
----- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long term debt - 910
Retirement of long-term debt (208) (1,020)
Payment of common stock dividends (71) (207)
Payment of preferred stock dividends (1) (1)
Payment of capital and finance lease obligations (23) (26)
Stockholder's contribution, net 200 550
Increase in notes payable 100 -
Debt issuance and financing costs (3) (29)
----- -------
Net cash provided by (used in) financing activities (6) 177
===== =======
Net Increase (Decrease) in Cash and Cash Equivalents (288) 307
Cash and Cash Equivalents, Beginning of Period 416 171
----- -------
Cash and Cash Equivalents, End of Period $ 128 $ 478
===== =======
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CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
ASSETS
In Millions
--------------------------
September 30
2006 December 31
(Unaudited) 2005
------------ -----------
PLANT AND PROPERTY Electric $ 8,434 $ 8,204
(AT COST) Gas 3,239 3,151
Other 241 227
------- -------
11,914 11,582
Less accumulated depreciation, depletion, and amortization 4,934 4,804
------- -------
6,980 6,778
Construction work-in-progress 572 509
------- -------
7,552 7,287
------- -------
INVESTMENTS Stock of affiliates 32 33
Other 4 7
------- -------
36 40
------- -------
CURRENT ASSETS Cash and cash equivalents at cost, which approximates market 128 416
Restricted cash and restricted short-term investments 57 183
Accounts receivable and accrued revenue,
less allowances of $14 in 2006 and $13 in 2005 344 640
Notes receivable 63 13
Accounts receivable - related parties 7 9
Inventories at average cost
Gas in underground storage 1,293 1,068
Materials and supplies 80 75
Generating plant fuel stock 106 80
Deferred property taxes 124 159
Regulatory assets - postretirement benefits 19 19
Derivative instruments 48 242
Prepayments and other 111 70
------- -------
2,380 2,974
------- -------
NON-CURRENT ASSETS Regulatory assets
Securitized costs 526 560
Additional minimum pension 399 399
Postretirement benefits 99 116
Customer Choice Act 197 222
Other 469 484
Nuclear decommissioning trust funds 582 555
Other 477 520
------- -------
2,749 2,856
------- -------
TOTAL ASSETS $12,717 $13,157
======= =======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-32
STOCKHOLDER'S INVESTMENT AND LIABILITIES
In Millions
----------------------------
September 30
2006 December 31
(Unaudited) 2005
------------ -----------
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 1,632
Accumulated other comprehensive income 42 72
Retained earnings since December 31, 1992 306 233
------- -------
3,021 2,778
Preferred stock 44 44
Long-term debt 4,256 4,303
Non-current portion of capital leases and finance lease obligations 296 308
------- -------
7,617 7,433
------- -------
MINORITY INTERESTS 252 259
------- -------
CURRENT LIABILITIES Current portion of long-term debt, capital leases and finance leases 86 112
Current portion of long-term debt - related parties - 129
Notes payable - related parties 127 27
Accounts payable 386 458
Accounts payable - related parties 19 40
Accrued interest 58 82
Accrued taxes 152 400
Deferred income taxes 98 55
MCV Partnership gas supplier funds on deposit 34 193
Other 204 150
------- -------
1,164 1,646
------- -------
NON-CURRENT LIABILITIES Deferred income taxes 682 1,027
Regulatory liabilities
Regulatory liabilities for cost of removal 1,174 1,120
Income taxes, net 475 455
Other regulatory liabilities 236 178
Postretirement benefits 353 308
Asset retirement obligations 495 494
Deferred investment tax credit 63 67
Other 206 170
------- -------
3,684 3,819
------- -------
Commitments and Contingencies (Notes 2, 3, and 4)
TOTAL STOCKHOLDER'S INVESTMENT AND LIABILITIES $12,717 $13,157
======= =======
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CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(UNAUDITED)
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 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 1,632 932
Stockholder's contribution - - 200 550
------ ------ ------ ------
At end of period 1,832 1,482 1,832 1,482
------ ------ ------ ------
ACCUMULATED OTHER Minimum pension liability
COMPREHENSIVE INCOME At beginning of period (2) (2) (2) (1)
Minimum pension liability adjustment (b) - - - (1)
------ ------ ------ ------
At end of period (2) (2) (2) (2)
------ ------ ------ ------
Investments
At beginning of period 16 18 18 12
Unrealized gain on investments (b) 3 3 1 9
------ ------ ------ ------
At end of period 19 21 19 21
------ ------ ------ ------
Derivative instruments
At beginning of period 39 32 56 20
Unrealized gain (loss) on derivative instruments (b) (13) 27 (27) 50
Reclassification adjustments included in net income (loss) (b) (1) (2) (4) (13)
------ ------ ------ ------
At end of period 25 57 25 57
------ ------ ------ ------
Total Accumulated Other Comprehensive Income 42 76 42 76
------ ------ ------ ------
RETAINED EARNINGS At beginning of period 238 630 233 608
Net income (loss) 99 (276) 145 (86)
Cash dividends declared - Common Stock (31) (40) (71) (207)
Cash dividends declared - Preferred Stock - - (1) (1)
------ ------ ------ ------
At end of period 306 314 306 314
------ ------ ------ ------
TOTAL COMMON STOCKHOLDER'S EQUITY $3,021 $2,713 $3,021 $2,713
====== ====== ====== ======
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 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 gain on investments, net of tax of
$2, $2, $-, and $5, respectively $ 3 $ 3 $ 1 $ 9
Derivative instruments
Unrealized gain (loss) on derivative instruments, net of tax (tax
benefit) of $(7), $15, $(14), and $27, respectively (13) 27 (27) 50
Reclassification adjustments included in net income (loss), net of
tax benefit of $(1), $(1), $(2), and $(7), respectively (1) (2) (4) (13)
Net income (loss) 99 (276) 145 (86)
---- ----- ---- ----
Total Comprehensive Income (Loss) $ 88 $(248) $115 $(41)
==== ===== ==== ====
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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. 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. 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 in the 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
in 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.
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Consumers Energy Company
ACCOUNTING FOR MISO TRANSACTIONS: We account for MISO transactions on a net
basis for all of our generating units combined. 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 if
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)
=== === === ====
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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.
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 the 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' Accounting for Defined Benefit Pension and Other
Postretirement Plans - an amendment of FASB Statements 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: In June 2006, the FASB
issued FIN 48, effective for us 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
authority 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 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, 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: CONTINGENCIES
SEC AND OTHER 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.
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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.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
complaints were filed against CMS Energy, Consumers, and certain officers and
directors of CMS Energy and its affiliates. The cases were consolidated into a
single lawsuit, 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 dated March 24, 2006, granting
in part and denying in part plaintiffs' amended motion for class certification.
The court conditionally certified a class consisting of "[a]ll 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. 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 names the same defendants as the shareholder action and contains
essentially the same allegations and class period. CMS Energy and the individual
defendants will defend themselves vigorously in this litigation but cannot
predict its outcome.
ERISA LAWSUITS: CMS Energy was 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 District of Michigan,
brought as purported class actions on behalf of participants and beneficiaries
of the CMS Employees' Savings Plan (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, subject to court and independent
fiduciary approval, to settle the lawsuits. The settlement agreement required a
$28 million cash payment by CMS Energy's primary insurer to be used to pay Plan
participants and beneficiaries for alleged losses, as well as any legal fees and
expenses. In addition, CMS Energy agreed to certain other steps regarding
administration of the Plan. The hearing on final approval of the settlement was
held on June 15, 2006. On June 27, 2006, the judge entered the Order and Final
Judgment, approving the proposed settlement with minor modifications.
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:
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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
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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.
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.
We are a potentially responsible party at several contaminated sites
administered under 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, we have
recorded a liability for the minimum amount of our estimated probable Superfund
liability.
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 proposed a plan to deal
with the remaining materials and are awaiting a response from the EPA.
MCV Environmental Issue: In July 2004, the MDEQ, Air Control Division, issued
the MCV Partnership a Letter of Violation asserting that 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 MDEQ and the MCV Partnership have
agreed to a settlement 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.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities (the
plaintiffs), which sell
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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 Court 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. The plaintiffs have appealed the dismissal to the United
States Court of Appeals. We cannot predict the outcome of these appeals.
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC ROA: 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, alternative electric suppliers were providing
308 MW of generation service to ROA customers, which represents four percent of
our total distribution load. This represents a decrease of one percent of ROA
load compared to June 30, 2006 and a decrease of 60 percent of ROA load compared
to the end of September 2005. It is difficult to predict future ROA customer
trends.
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,
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 prices during peak
demand periods and to achieve our reserve margin target, we employ a strategy of
purchasing 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 million for unexpired capacity and energy
contracts at September 30, 2006. At September 2006, we expect the total capacity
cost of electric capacity and energy contracts for 2006 to be $17 million.
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 actual costs for reasonableness and prudence. In September 2005, we submitted
our 2006 PSCR plan filing to the MPSC. 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.
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Consumers Energy Company
In August 2006, the MPSC issued an order approving our amended 2006 PSCR plan,
which results 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 coal supply costs,
increased bundled sales, and other cost increases beyond those included in the
September 2005 and November 2005 filings. 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.
In September 2006, we submitted our 2007 PSCR plan filing to the MPSC, which
includes the underrecoveries incurred in 2005 and 2006. We expect to
self-implement the proposed 2007 PSCR charge in January 2007, absent action by
the MPSC by the end of 2006. We cannot predict the outcome of this proceeding.
OTHER ELECTRIC CONTINGENCIES
THE MIDLAND COGENERATION VENTURE: 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. 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. The sale
does not affect the MCV PPA and the associated customer rates. We are targeting
to close on the sale 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 July 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 interests 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, the cost that we incur under
the MCV PPA exceeds the recovery amount allowed by the MPSC. We expense all cash
underrecoveries directly to income. We estimate underrecoveries of $56 million
in 2006 and $39 million in 2007. Of the 2006 estimate, we expensed $42 million
during the nine months ended September 30, 2006. However, our direct savings
from the RCP, after allocating a portion to customers, are used to offset 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 MCV Partnership has
indicated that it may take issue with our 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 has the right to terminate the MCV PPA, 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 exercise of the regulatory out provision and the likely consequences of
such action will be reviewed by the MPSC in 2007. Some parties have suggested
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 MSPC 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 Facility on the basis of natural gas
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market prices, which reduces 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 consumed 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. We cannot predict the outcome of these matters.
MCV PARTNERSHIP PROPERTY TAXES: In January 2004, the Michigan Tax Tribunal
issued its decision in 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 indicated that we would manage the
decommissioning trust fund 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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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 additional nuclear fuel storage costs due 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, providing for the continuation
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, the NMC, which operates the Palisades plant, applied for a
20-year license renewal for the plant on behalf 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 to 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
to Entergy. As part of the transaction, Entergy will sell us 100 percent of the
plant's output up to its current capacity of 798 MW under a 15-year power
purchase agreement. Because of the 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, including real estate with equipment. In accordance with SFAS No. 98,
the transaction will be accounted for as a financing and not a sale. This is due
to forms of continuing involvement. As such, we have not classified the assets
as held for sale on our Consolidated Balance Sheets.
The sale is subject to various regulatory approvals, including the MPSC's
approval 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 action on the sale. The final purchase price will be subject
to various closing adjustments such as working capital and capital expenditure
adjustments, adjustments for nuclear fuel usage and inventory, and the date of
closing. Under the agreement, if the transaction does not close by March 1,
2007, the purchase price will 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.
NUCLEAR MATTERS: Nuclear Fuel Cost: We amortize 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 charge certain disposal costs to
nuclear fuel expense, recover these costs through electric rates, and remit 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, our DOE liability is
$150 million. This amount includes interest, which is payable upon the first
delivery of spent nuclear fuel to the DOE. The amount of this liability,
excluding a portion of interest, was recovered through electric rates. In
conjunction with the
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sale of Palisades and the Big Rock ISFSI, we will retain this obligation and
provide security to Entergy for this obligation in the form of either cash, a
letter of credit, or other acceptable means.
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 the cost of spent nuclear fuel storage until the DOE takes
possession as required by law. We can make no assurance that the litigation
against the DOE will be successful.
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 maintain nuclear insurance coverage on our nuclear plants. At
Palisades, we maintain 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 maintain 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 maintain 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 remains insured for nuclear liability up to $544 million through
nuclear insurance and NRC indemnity, and maintains 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, we have
a liability of $26 million, net of $56 million of expenditures incurred to date,
and a regulatory asset of $58 million. 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.
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
GCR Year Date Filed Order Date recovery Gas Sold Description of Net Overrecovery
- --------- ---------- ---------- ---------- ------------ -------------------------------
2004-2005 June 2005 April 2006 $2 million $1.4 billion The net overrecovery includes
interest expense through March
2005 and refunds that we
received from our suppliers
that are required to be
refunded to our customers.
2005-2006 June 2006 Pending $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.
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 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 we are unable to predict the
outcome.
GCR plan for year 2006-2007: In December 2005, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2006
through March 2007. Our request proposed using a GCR factor consisting of:
- a base GCR ceiling factor of $11.10 per mcf, plus
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- 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-recovery amounts in our annual GCR reconciliation. Our GCR billing factor
for the month of November 2006 is $7.83 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.
2005 GAS RATE CASE: In July 2005, we filed an application with the MPSC seeking
a 12 percent authorized return on equity along with a $132 million annual
increase in our gas delivery and transportation rates. As part 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 that $17 million of this amount 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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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 to the use 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 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.
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 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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The following table describes our guarantees at September 30, 2006:
In Millions
- --------------------------------------------------------------------------------------------------------
Maximum
Guarantee Description Issue Date Expiration Date Obligation Carrying Amount
- --------------------- ------------ --------------- ---------- ---------------
Surety bonds and other indemnifications Various Various 1 -
Guarantee (a) January 1987 March 2015 85 -
Nuclear insurance retrospective premiums Various Indefinite 137 -
(a) We have reached an agreement to sell our interests in the MCV Partnership
and the FMLP, subject to certain regulatory and other closing conditions.
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. The
purchaser will secure their reimbursement obligation with an irrevocable
letter of credit of up to $85 million.
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 Nonperformance
indemnifications activity, permits
and licenses
Guarantee Agreement to MCV Partnership's
provide power and nonperformance or non-payment
steam to Dow under a related contract
Nuclear insurance Normal operations Call by NEIL and
retrospective premiums of nuclear plants Price-Anderson Act for nuclear
incident
At September 30, 2006, none of our guarantees contained provisions allowing us
to recover, from third parties, any amount paid under the guarantees. We enter
into various agreements containing indemnification provisions in connection with
a variety of transactions. 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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3: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
First mortgage bonds $3,173 $3,175
Senior notes and other 801 852
Securitization bonds 348 369
------ ------
Principal amounts outstanding 4,322 4,396
Current amounts (59) (85)
Net unamortized discount (7) (8)
------ ------
Total Long-term debt $4,256 $4,303
====== ======
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.
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REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities
with banks are available at September 30, 2006:
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 18
In March 2006, we entered into a short-term secured revolving credit agreement
with banks. This facility provides $300 million of funds for working capital and
other general corporate purposes.
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
September 30, 2006, we had $253 million of unrestricted retained earnings
available to pay common stock dividends. Covenants in our debt facilities cap
common stock dividend payments at $300 million in a calendar year. Provisions of
the Federal Power Act and the Natural Gas Act effectively restrict dividends to
the amount of our retained earnings. For the nine months ended September 30,
2006, we paid $71 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, capital lease obligations totaled $55 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 million of receivables at September 30, 2006
and $325 million of receivables at December 31, 2005. 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 months ended September 30 2006 2005
- ------------------------------ ------ ------
Net cash flow as a result of accounts receivable financing $ (9) $ (204)
Collections from customers $4,402 $3,782
====== ======
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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 financial instruments are as follows:
In Millions
-------------------------------------------------------------
September 30, 2006 December 31, 2005
---------------------------- -----------------------------
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:
Common stock of CMS Energy 10 32 22 10 33 23
SERP:
Equity securities 17 24 7 16 22 6
Debt securities 7 7 - 8 8 -
Nuclear decommissioning investments:
Equity securities 138 268 130 134 252 118
Debt securities 304 307 3 287 291 4
In July 2006, we reached an agreement to sell 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 $382 million of nuclear decommissioning
trust fund assets to Entergy and retain $205 million. We will also be entitled
to receive a return 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 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. The disposition
of the retained and receivable nuclear decommissioning funds is subject to
regulatory proceedings.
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.
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 the balance sheet at its
fair value. We then adjust the resulting asset or liability each quarter to
reflect any
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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; 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, 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 income
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 MW 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 of an active energy market in
Michigan. If active markets for these commodities develop in the future, some of
these contracts may qualify as derivatives. For our coal purchase contracts, 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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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 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.
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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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).
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
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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 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,
our non-utility affiliates, and Panhandle, a former affiliate. The Pension
Plan's assets are not distinguishable by company.
Effective January 11, 2006, the MPSC electric rate order authorized us to
include $33 million of electric pension expense 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 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 us to
include $28 million of electric OPEB expense in our 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
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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 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 $ 12 $ 9 $ 35 $ 32
Interest cost 20 15 59 60
Expected return on plan assets (20) (17) (60) (75)
Amortization of:
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
==== ==== ==== ====
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 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
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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. This standard will
require us to 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 recognize changes in the funded status of our plans in the year in which the
changes occur. Upon implementation 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 this provision of the standard would
have a material effect on our financial statements.
6: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, "ACCOUNTING FOR ASSET RETIREMENT 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. 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, 2006 In Millions
- -----------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- --------------- ---------- ------------------------------------ -----
Palisades - decommission plant site 1972 Palisades nuclear plant $576
Big Rock - decommission plant site 1962 Big Rock nuclear plant 6
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 12/31/05 Incurred Settled (a) Accretion Revisions 9/30/06
- --------------- --------- -------- ----------- --------- --------- ---------
Palisades - decommission $375 $ - $ - $19 $ - $394
Big Rock - decommission 27 - (22) 3 - 8
JHCampbell intake line - - - - - -
Coal ash disposal areas 54 - (2) 4 - 56
Wells at gas storage fields 1 - - - - 1
Indoor gas services relocations 1 - - - - 1
Asbestos abatement 36 - (2) 1 - 35
---- --- ---- --- --- ----
Total $494 $ - $(26) $27 $ - $495
==== === ==== === === ====
(a) These cash payments are included in the Other current and non-current
liabilities line in Net cash provided by operating activities on our
Consolidated Statements of Cash Flows. Cash payments for the nine months
ended September 30, 2005 were $36 million.
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
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- withhold approving blanket regulatory asset and regulatory liability
accounting treatment related to AROs, 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.
7: 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 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 achievement of total shareholder return 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 for the year ended 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.
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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.
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 1,154,316 $10.87
Granted 456,880 $13.83
Vested (168,246) $ 7.20
Forfeited (13,913) $11.07
--------- ------
Nonvested at September 30, 2006 1,429,037 $12.24
========= ======
The total fair value of shares vested was $2 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 $5 million for the nine months ended September 30, 2006 and
$2 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 $10 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.
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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 1,714,787 $18.13 5.9 years $(6)
Granted - -
Exercised (14,000) 6.35
Cancelled or Expired (41,108) 29.38
--------- ------ --------- ---
Outstanding at September 30, 2006 1,659,679 $17.95 5.2 years $(6)
========= ====== ========= ===
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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8: REPORTABLE SEGMENTS
Our reportable segments are strategic business units organized and managed by
the nature of the products and services each provides. We evaluate performance
based upon the net income of each segment. We operate principally in two
segments: electric utility and gas utility.
The following table shows our financial information by reportable segment:
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2006 2005 2006 2005
- ------------ ------ ------ ------ ------
Operating Revenue
Electric $ 976 $ 794 $2,496 $2,071
Gas 201 219 1,576 1,566
Other 14 12 39 36
------ ------ ------ ------
Total Operating Revenue $1,191 $1,025 $4,111 $3,673
====== ====== ====== ======
Net Income (Loss) Available to Common Stockholder
Electric $ 93 $ 62 $ 159 $ 141
Gas (20) (16) 14 39
Other 26 (322) (29) (267)
------ ------ ------ ------
Total Net Income (Loss) Available to Common Stockholder $ 99 $ (276) $ 144 $ (87)
====== ====== ====== ======
In Millions
--------------------------------------
September 30, 2006 December 31, 2005
------------------ -----------------
Assets
Electric (a) $ 7,893 $ 7,743
Gas (a) 3,835 3,600
Other 989 1,814
------- -------
Total Assets $12,717 $13,157
======= =======
(a) Amounts include a portion of our other common assets attributable to both
the electric and gas utility businesses.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
CMS ENERGY
Quantitative and Qualitative Disclosures about Market Risk is contained in PART
I: CMS Energy Corporation's Management's Discussion and Analysis, which is
incorporated by reference herein.
CONSUMERS
Quantitative and Qualitative Disclosures about Market Risk is contained in PART
I: Consumers Energy Company's Management's Discussion and Analysis, which is
incorporated by reference herein.
ITEM 4. CONTROLS AND PROCEDURES
CMS ENERGY
Disclosure Controls and Procedures: CMS Energy's management, with the
participation of its CEO and CFO, has evaluated the effectiveness of its
disclosure controls and procedures (as such term is defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, CMS Energy's CEO and CFO have concluded
that, due to the fact that the material weakness in CMS Energy's internal
control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f)
under the Exchange Act) identified in its 2005 Form 10-K/A, has not had adequate
testing to confirm evidence of remediation, its disclosure controls and
procedures were not effective at September 30, 2006.
Management continues to validate the remedial actions it has taken to correct
the income tax-related material weakness identified in CMS Energy's 2005 Form
10-K/A. Management believes it has implemented the necessary processes and
procedures to overcome the material weakness relating to income taxes; however,
these processes and procedures, and correlating controls, have not been in place
for an adequate period of time to conclude that the material weakness has been
remediated at September 30, 2006. Management will continue to monitor and test
the continuous effectiveness of these controls and procedures and make
appropriate modifications, as necessary.
Management believes that the consolidated financial statements included in this
Form 10-Q fairly present, in all material respects, CMS Energy's financial
condition, results of operations and cash flows for the periods presented.
Internal Control Over Financial Reporting: There have not been any changes in
CMS Energy's internal control over financial reporting (as such term is defined
in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.
CONSUMERS
Disclosure Controls and Procedures: Consumers' management, with the
participation of its CEO and CFO, has evaluated the effectiveness of its
disclosure controls and procedures (as such term is defined in Rules 13a-15(e)
and 15d-15(e) under the Exchange Act) as of the end of the period covered by
this report. Based on such evaluation, Consumers' CEO and CFO have concluded
that, as of the end of such period, its disclosure controls and procedures are
effective.
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Internal Control Over Financial Reporting: There have not been any changes in
Consumers' internal control over financial reporting (as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the last fiscal
quarter that have materially affected, or are reasonably likely to materially
affect, its internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
The discussion below is limited to an update of developments that have occurred
in various judicial and administrative proceedings, many of which are more fully
described in CMS Energy's Form 10-K/A Amendment No. 1 and Consumers' Form 10-K
for the year ended December 31, 2005 and Forms 10-Q for the quarters ended March
31, 2006 and June 30, 2006. Reference is also made to the CONDENSED NOTES TO
CONSOLIDATED FINANCIAL STATEMENTS, in particular, Note 3, Contingencies, for CMS
Energy and Note 2, Contingencies, for Consumers, included herein for additional
information regarding various pending administrative and judicial proceedings
involving rate, operating, regulatory and environmental matters.
CMS ENERGY
SEC REQUEST
On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy
voluntarily produce documents and data relating to the SEC's inquiry into
payments made to the officials or relatives of officials of the government of
Equatorial Guinea. On August 17, 2004, CMS Energy submitted its response,
advising the SEC of the information and documentation it had available. On March
8, 2005, CMS Energy received a request from the SEC that CMS Energy voluntarily
produce certain of such documents. CMS Energy has provided responsive documents
to the SEC and will continue to provide such documents as it reviews its
electronic records in further response to the SEC's request. The SEC
subsequently issued a formal order of private investigation on this matter on
August 1, 2005. CMS Energy and several other companies who have conducted
business in Equatorial Guinea received subpoenas from the SEC to provide
documents regarding payments made to officials or relatives of officials of the
government of Equatorial Guinea. CMS Energy is cooperating and has been and will
continue to produce documents responsive to the subpoena.
GAS INDEX PRICE REPORTING LITIGATION
CMS MST and CMS Field Services (which was sold to Cantera Natural Gas, LLC and
for which CMS Energy has indemnification obligations) were defendants in a
consolidated class action lawsuit filed in the United States District Court for
the Southern District of New York. Cornerstone Propane Partners, L.P. filed the
original complaint in August 2003 as a putative class action and it was later
consolidated with two similar complaints filed by other plaintiffs. The amended
consolidated complaint, filed in January 2004, alleged that false natural gas
price reporting by the defendants manipulated the prices of NYMEX natural gas
futures and options. The complaint contained two counts under the Commodity
Exchange Act, one for manipulation and one for aiding and abetting violations.
On May 24, 2006, the judge entered a Final Judgment and Order of Dismissal
approving settlements between plaintiffs and various defendants, including CMS
MST and CMS Field Services. The settlement agreement required a $6.975 million
cash payment that CMS MST was responsible to pay. The payment was made into a
settlement fund that will be used to pay the class members as well as any legal
fees awarded to plaintiffs' attorneys. CMS Energy had established a reserve for
this amount in the fourth quarter of 2005.
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In a similar but unrelated matter, Texas-Ohio Energy, Inc. filed a putative
class action lawsuit in the United States District Court for the Eastern
District of California in November 2003 against a number of energy companies
engaged in the sale of natural gas in the United States (including CMS Energy).
The complaint alleged defendants entered into a price-fixing scheme by engaging
in activities to manipulate the price of natural gas in California. The
complaint alleged violations of the federal Sherman Act, the California
Cartwright Act, and the California Business and Professions Code relating to
unlawful, unfair and deceptive business practices. The complaint sought both
actual and exemplary damages for alleged overcharges, attorneys fees and
injunctive relief regulating defendants' future conduct relating to pricing and
price reporting. In April 2004, a Nevada Multidistrict Litigation (MDL) Panel
ordered the transfer of the Texas-Ohio case to a pending MDL matter in the
Nevada federal district court that at the time involved seven complaints
originally filed in various state courts in California. These complaints make
allegations similar to those in the Texas-Ohio case regarding price reporting,
although none contain a federal Sherman Act claim. In November 2004, those seven
complaints, as well as a number of others that were originally filed in various
state courts in California and subsequently transferred to the MDL proceeding,
were remanded back to California state court. The Texas-Ohio case remained in
Nevada federal district court, and defendants, with CMS Energy joining, filed a
motion to dismiss. The court issued an order granting the motion to dismiss on
April 8, 2005 and entered a judgment in favor of the defendants on April 11,
2005. Texas-Ohio has appealed the dismissal to the Ninth Circuit Court of
Appeals.
Three federal putative class actions, Fairhaven Power Company v. Encana Corp. et
al., Utility Savings & Refund Services LLP v. Reliant Energy Resources Inc. et
al., and Abelman Art Glass v. Encana Corp. et al., all of which make allegations
similar to those in the Texas-Ohio case regarding price manipulation and seek
similar relief, were originally filed in the United States District Court for
the Eastern District of California in September 2004, November 2004 and December
2004, respectively. The Fairhaven and Abelman Art Glass cases also include
claims for unjust enrichment and a constructive trust. The three complaints were
filed against CMS Energy and many of the other defendants named in the
Texas-Ohio case. In addition, the Utility Savings case names CMS MST and Cantera
Resources Inc. (Cantera Resources Inc. is the parent of Cantera Natural Gas,
LLC. and CMS Energy is required to indemnify Cantera Natural Gas, LLC and
Cantera Resources Inc. with respect to these actions.)
The Fairhaven, Utility Savings and Abelman Art Glass cases have been transferred
to the MDL proceeding, where the Texas-Ohio case was pending. Pursuant to
stipulation by the parties and court order, defendants were not required to
respond to the Fairhaven, Utility Savings and Abelman Art Glass complaints until
the court ruled on defendants' motion to dismiss in the Texas-Ohio case.
Plaintiffs subsequently filed a consolidated class action complaint alleging
violations of federal and California antitrust laws. Defendants filed a motion
to dismiss, arguing that the consolidated complaint should be dismissed for the
same reasons as the Texas-Ohio case. The court issued an order granting the
motion to dismiss on December 19, 2005 and entered judgment in favor of
defendants on December 23, 2005. Plaintiffs have appealed the dismissal to the
Ninth Circuit Court of Appeals.
Commencing in or about February 2004, 15 state law complaints containing
allegations similar to those made in the Texas-Ohio case, but generally limited
to the California Cartwright Act and unjust enrichment, were filed in various
California state courts against many of the same defendants named in the federal
price manipulation cases discussed above. In addition to CMS Energy, CMS MST is
named in all of the 15 state law complaints. Cantera Gas Company and Cantera
Natural Gas, LLC (erroneously sued as Cantera Natural Gas, Inc.) are named in
all but one complaint.
In February 2005, these 15 separate actions, as well as nine other similar
actions that were filed in California state court but do not name CMS Energy or
any of its former or current subsidiaries, were
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ordered coordinated with pending coordinated proceedings in the San Diego
Superior Court. The 24 state court complaints involving price reporting were
coordinated as Natural Gas Antitrust Cases V. Plaintiffs in Natural Gas
Antitrust Cases V were ordered to file a consolidated complaint, but a
consolidated complaint was filed only for the two putative class action
lawsuits. Pursuant to a ruling dated August 23, 2006, CMS Energy, Cantera Gas
Company and Cantera Natural Gas, LLC were dismissed as defendants in the master
class action and the thirteen non-class actions, due to lack of personal
jurisdiction. CMS MST remains a defendant in all of these actions. In September
2006, CMS MST reached an agreement in principle to settle the master class
action for $7 million. The settlement is contingent upon 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 granting
preliminary approval of the settlement, a process that may take several months
to complete.
Samuel D. Leggett, et al v. Duke Energy Corporation, et al, a class action
complaint brought on behalf of retail and business purchasers of natural gas in
Tennessee, was filed in the Chancery Court of Fayette County, Tennessee in
January 2005. The complaint contains claims for violations of the Tennessee
Trade Practices Act based upon allegations of false reporting of price
information by defendants to publications that compile and publish indices of
natural gas prices for various natural gas hubs. The complaint seeks statutory
full consideration damages and attorneys fees and injunctive relief regulating
defendants' future conduct. The defendants include CMS Energy, CMS MST and CMS
Field Services. On August 10, 2005, certain defendants, including CMS MST, filed
a motion to dismiss and CMS Energy and CMS Field Services filed a motion to
dismiss for lack of personal jurisdiction. Defendants attempted to remove the
case to federal court, but it was remanded to state court by a federal judge.
Plaintiffs have opposed the motions to dismiss and they remain pending.
J.P. Morgan Trust Company, in its capacity as Trustee of the FLI Liquidating
Trust, filed an action in Kansas state court in August 2005 against a number of
energy companies, including CMS Energy, CMS MST and CMS Field Services. The
complaint alleges various claims under the Kansas Restraint of Trade Act
relating to reporting false natural gas trade information to publications that
report trade information. Plaintiff is seeking statutory full consideration
damages for its purchases of natural gas between January 1, 2000 and December
31, 2001. The case was removed to the United States District Court for the
District of Kansas on September 8, 2005 and transferred to the MDL proceeding on
October 13, 2005. A motion to remand the case back to Kansas state court was
denied on April 21, 2006.
On November 20, 2005, CMS MST was served with a summons and complaint which
named CMS Energy, CMS MST and CMS Field Services as defendants in a new putative
class action filed in Kansas state court, Learjet, Inc., et al. v. Oneok, Inc.,
et al. Similar to the other actions that have been filed, the complaint alleges
that during the putative class period, January 1, 2000 through October 31, 2002,
defendants engaged in a scheme to violate the Kansas Restraint of Trade Act by
knowingly reporting false or inaccurate information to the publications, thereby
affecting the market price of natural gas. Plaintiffs, who allege they purchased
natural gas from defendants and others for their facilities, are seeking
statutory full consideration damages consisting of the full consideration paid
by plaintiffs for natural gas. On December 7, 2005, the case was removed to the
United States District Court for the District of Kansas and later that month a
motion was filed to transfer the case to the MDL proceeding. On January 6, 2006,
plaintiffs filed a motion to remand the case to Kansas state court. On January
23, 2006, a conditional transfer order transferring the case to the MDL
proceeding was issued. On February 7, 2006, plaintiffs filed an opposition to
the conditional transfer order. The court issued an order dated August 3, 2006
denying the motion to remand the case to Kansas state court.
Breckenridge Brewery of Colorado, LLC and BBD Acquisition Co. v. Oneok, Inc., et
al., a class action complaint brought on behalf of retail direct purchasers of
natural gas in Colorado, was filed in Colorado state court in May 2006.
Defendants, including CMS Energy, CMS Field Services, and CMS MST are
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alleged to have violated the Colorado Antitrust Act of 1992 in connection with
their natural gas price reporting activities. Plaintiffs are seeking full refund
damages. The case was removed to the United States District Court for the
District of Colorado on June 12, 2006 and a conditional transfer order
transferring the case to the MDL proceeding was entered on June 27, 2006.
Plaintiffs are seeking to have the case remanded back to Colorado state court.
On October 30, 2006, CMS Energy and CMS MST were each served with a summons and
complaint which named CMS Energy, CMS MST and CMS Field Services as defendants
in an action filed in Missouri state court, titled Missouri Public Service
Commission v. Oneok Inc. The Missouri Public Service Commission purportedly is
acting as an assignee of six local distribution companies, and it alleges that
from at least January 2000 through at least October 2002, defendants knowingly
reported false natural gas prices to publications that compile and publish
indices of natural gas prices, and engaged in wash sales. The complaint contains
claims for violation of the Missouri Anti-Trust Law, fraud and unjust
enrichment.
CMS Energy and the other CMS defendants will defend themselves vigorously
against all of these matters but cannot predict their outcome.
CMS ENERGY AND CONSUMERS
SECURITIES CLASS ACTION LAWSUITS
Beginning on May 17, 2002, a number of complaints were filed against CMS Energy,
Consumers, and certain officers and directors of CMS Energy and its affiliates.
The cases were consolidated into a single lawsuit, 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 dated March 24, 2006, granting in part and denying in part
plaintiffs' amended motion for class certification. The court conditionally
certified a class consisting of "[a]ll 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. 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 names the same
defendants as the shareholder action and contains essentially the same
allegations and class period. CMS Energy and the individual defendants will
defend themselves vigorously in this litigation but cannot predict its outcome.
ENVIRONMENTAL MATTERS
CMS Energy, Consumers and their subsidiaries and affiliates are subject to
various federal, state and local laws and regulations relating to the
environment. Several of these companies have been named parties to various
actions involving environmental issues. Based on their present knowledge and
subject to future legal and factual developments, CMS Energy and Consumers
believe that it is unlikely that these actions, individually or in total, will
have a material adverse effect on their financial condition. See CMS Energy's
and Consumers' MANAGEMENT'S DISCUSSION AND ANALYSIS and CMS Energy's and
Consumers' CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 1A. RISK FACTORS
Other than discussed below, there have been no material changes to the Risk
Factors as previously disclosed in CMS Energy's Form 10-K/A Amendment No. 1 and
Consumers' Form 10-K for the year ended December 31, 2005 and CMS Energy's and
Consumers' Forms 10-Q for the quarters ended March 31, 2006 and June 30, 2006.
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RISKS RELATED TO CMS ENERGY
CMS ENERGY'S NATURAL GAS PIPELINE AND ELECTRIC GENERATION PROJECT LOCATED
IN ARGENTINA AND CHILE MAY BE NEGATIVELY IMPACTED BY ARGENTINE GOVERNMENTAL
RESTRICTIONS PLACED ON NATURAL GAS EXPORTS TO CHILE AND THE EFFECTS OF THESE
RESTRICTIONS ON THE PROJECT'S CONTRACTS FOR THE SALE OF POWER.
On March 24, 2004, the Argentine government authorized the restriction of
exports of natural gas to Chile, giving priority to domestic demand 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 they would no longer deliver gas to GasAtacama under the Argentine
government's current policy. This situation indicated GasAtacama's operations
would be adversely affected. In conjunction with the preparation of its
consolidated financial statements for the quarter ended September 30, 2006, CMS
Energy performed an impairment analysis, which concluded that the fair value of
its investment was lower than the carrying amount and that this decline was
other than temporary. CMS Energy recognized an impairment charge of $239 million
on its Consolidated Statements of Income (Loss). As a result, CMS Energy's net
income was reduced by $169 million after considering tax effects and minority
interest. At September 30, 2006, the carrying value of CMS Energy's investment
in GasAtacama was $122 million. This remaining value continues to be exposed to
the threat of a complete gas curtailment by Argentina and the inability of
GasAtacama to pass through the increased costs associated with such a
curtailment to its regulated customers. Therefore, if conditions do not improve,
the result could be a further impairment of CMS Energy's investment in
GasAtacama.
RISKS RELATED TO CMS ENERGY AND CONSUMERS
CONSUMERS CURRENTLY UNDERRECOVERS IN ITS RATES ITS PAYMENTS TO THE MCV
PARTNERSHIP FOR CAPACITY AND ENERGY, AND IS ALSO EXPOSED TO FUTURE CHANGES IN
THE MCV PARTNERSHIP'S FINANCIAL CONDITION THROUGH ITS EQUITY AND LESSOR
INVESTMENTS.
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.
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
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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.
Further, the 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, Consumers' 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 such 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.
The MCV Partnership has indicated that it may take issue with our 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 has the right to terminate the MCV PPA, 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 exercise of the regulatory out provision and the likely
consequences of such action will be reviewed by the MPSC in 2007. Some parties
have suggested that in the event that the MCV Partnership ceases performance
under the MCV PPA, prior orders could limit our recovery of replacement power
costs to the amounts that the MSPC authorized for recovery under the MCV PPA. We
cannot predict the outcome of any future disputes concerning these issues.
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. We cannot predict the outcome of these matters.
CMS Energy and Consumers cannot estimate, at this time, the impact of these
issues on their future earnings or cash flow from its interest in the MCV
Partnership. It is not presently possible to predict the future price of natural
gas, or the actions of the MPSC in 2007 or later. For these reasons, at this
time CMS Energy and Consumers cannot predict the impact of these issues on their
future earnings or cash flows or on the value of its equity interest in the MCV
Partnership and its lessor interest in 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. We are targeting to close on the sale by the end of 2006. The sale will
result in reduced exposure to sustained high natural gas prices.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
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ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
ITEM 5. OTHER INFORMATION
A shareholder who wishes to submit a proposal for consideration at the CMS
Energy 2007 Annual Meeting pursuant to the applicable rules of the SEC must send
the proposal to reach CMS Energy's Corporate Secretary on or before December 15,
2006. In any event, if CMS Energy has not received written notice of any matter
to be proposed at that meeting by February 28, 2007, the holders of proxies may
use their discretionary voting authority on such matter. The proposals should be
addressed to: Corporate Secretary, CMS Energy Corporation, One Energy Plaza,
Jackson, MI 49201.
ITEM 6. EXHIBITS
(31)(a) CMS Energy Corporation's certification of the CEO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(b) CMS Energy Corporation's certification of the CFO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(c) Consumers Energy Company's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(d) Consumers Energy Company's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(32)(a) CMS Energy Corporation's certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(32)(b) Consumers Energy Company's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized. The signature for each undersigned
company shall be deemed to relate only to matters having reference to such
company or its subsidiary.
CMS ENERGY CORPORATION
(Registrant)
Dated: November 2, 2006 By: /s/ Thomas J. Webb
------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
CONSUMERS ENERGY COMPANY
(Registrant)
Dated: November 2, 2006 By: /s/ Thomas J. Webb
------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
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CMS ENERGY AND CONSUMERS EXHIBITS
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
(31)(a) CMS Energy Corporation's certification of the CEO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(b) CMS Energy Corporation's certification of the CFO pursuant to Section
302 of the Sarbanes-Oxley Act of 2002
(31)(c) Consumers Energy Company's certification of the CEO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(31)(d) Consumers Energy Company's certification of the CFO pursuant to
Section 302 of the Sarbanes-Oxley Act of 2002
(32)(a) CMS Energy Corporation's certifications pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002
(32)(b) Consumers Energy Company's certifications pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002