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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, 2005
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 Registrants are accelerated filers (as
defined in Rule 12b-2 of the Exchange Act).
CMS ENERGY CORPORATION: Yes [X] No [ ]
CONSUMERS ENERGY COMPANY: Yes [ ] No [X]
Indicate by check mark whether the Registrants are 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]
Number of shares outstanding of each of the issuer's classes of common stock at
October 31, 2005:
CMS ENERGY CORPORATION:
CMS Energy Common Stock, $.01 par value 220,095,482
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, 2005
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............................................................. 4
PART I: FINANCIAL INFORMATION
CMS Energy Corporation
Management's Discussion and Analysis
Executive Overview............................................. CMS - 1
Forward-Looking Statements and Risk Factors.................... CMS - 2
Results of Operations.......................................... CMS - 5
Critical Accounting Policies................................... CMS - 14
Capital Resources and Liquidity................................ CMS - 20
Outlook........................................................ CMS - 22
Implementation of New Accounting Standards..................... CMS - 31
New Accounting Standards Not Yet Effective..................... CMS - 31
Consolidated Financial Statements
Consolidated Statements of Income ............................. CMS - 34
Consolidated Statements of Cash Flows.......................... CMS - 37
Consolidated Balance Sheets.................................... CMS - 38
Consolidated Statements of Common Stockholders' Equity......... CMS - 40
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies................ CMS - 41
2. Asset Impairment Charges and Sales......................... CMS - 43
3. Contingencies.............................................. CMS - 44
4. Financings and Capitalization.............................. CMS - 59
5. Earnings Per Share......................................... CMS - 63
6. Financial and Derivative Instruments....................... CMS - 65
7. Retirement Benefits........................................ CMS - 70
8. Asset Retirements Obligations.............................. CMS - 72
9. Equity Method Investments.................................. CMS - 73
10. Reportable Segments ....................................... CMS - 74
11. Consolidation of Variable Interest Entities................ CMS - 75
12. Implementation of New Accounting Standards................. CMS - 76
2
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 Risk Factors.................... CE - 2
Results of Operations.......................................... CE - 4
Critical Accounting Policies................................... CE - 11
Capital Resources and Liquidity................................ CE - 15
Outlook........................................................ CE - 17
New Accounting Standards Not Yet Effective..................... CE - 24
Consolidated Financial Statements
Consolidated Statements of Income.............................. CE - 26
Consolidated Statements of Cash Flows.......................... CE - 27
Consolidated Balance Sheets.................................... CE - 28
Consolidated Statements of Common Stockholder's Equity......... CE - 30
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies................ CE - 31
2. Asset Impairment Charges................................... CE - 32
3. Contingencies.............................................. CE - 33
4. Financings and Capitalization.............................. CE - 45
5. Financial and Derivative Instruments....................... CE - 48
6. Retirement Benefits........................................ CE - 53
7. Asset Retirement Obligations............................... CE - 55
8. Reportable Segments ....................................... CE - 56
9. Consolidation of Variable Interest Entities................ CE - 57
10. New Accounting Standards Not Yet Effective................. CE - 57
Quantitative and Qualitative Disclosures about Market Risk........... CO - 1
Controls and Procedures.............................................. CO - 1
PART II: OTHER INFORMATION
Item 1. Legal Proceedings......................................... CO - 1
Item 2. Unregistered Sales of Equity Securities and Use of
Proceeds............................................... CO - 5
Item 3. Defaults Upon Senior Securities........................... CO - 5
Item 4. Submission of Matters to a Vote of Security Holders....... CO - 5
Item 5. Other Information......................................... CO - 5
Item 6. Exhibits.................................................. CO - 6
Signatures........................................................ CO - 7
3
GLOSSARY
Certain terms used in the text and financial statements are defined below
ABO........................... Accumulated Benefit Obligation. The liabilities
of a pension plan based on service and pay to
date. This differs from the Projected Benefit
Obligation that is typically disclosed in that
it does not reflect expected future salary
increases.
ALJ........................... Administrative Law Judge
Alliance RTO.................. Alliance Regional Transmission Organization
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
Articles...................... Articles of Incorporation
Attorney General.............. Michigan Attorney General
Bay Harbor.................... a residential/commercial real estate area
located near Petoskey, Michigan. In 2002, CMS
Energy sold its interest in Bay Harbor.
bcf........................... Billion cubic feet
Big Rock...................... Big Rock Point nuclear power plant, owned by
Consumers
Bluewater Pipeline............ Bluewater Pipeline, a 24.9-mile pipeline that
extends from Marysville, Michigan to Armada,
Michigan.
Board of Directors............ Board of Directors of CMS Energy
CEO........................... Chief Executive Officer
CFO........................... Chief Financial Officer
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, 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 Generation................ CMS Generation Co., a subsidiary of Enterprises
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
Common Stock.................. All classes of Common Stock of CMS Energy and
each of its subsidiaries, or any of them
individually, at the time of an award or grant
under the Performance Incentive Stock Plan
4
Consumers..................... Consumers Energy Company, a subsidiary of CMS
Energy
Customer Choice Act........... Customer Choice and Electricity Reliability
Act, a Michigan statute enacted in June 2000
that allows all retail customers choice of
alternative electric suppliers as of January 1,
2002, provides for full recovery of net
stranded costs and implementation costs,
establishes a five percent reduction in
residential rates, establishes rate freeze and
rate cap, and allows for Securitization
Detroit Edison................ The Detroit Edison Company, a non-affiliated
company
DIG........................... Dearborn Industrial Generation, LLC, a wholly
owned subsidiary of CMS Generation
DOE........................... U.S. Department of Energy
DOJ........................... U.S. Department of Justice
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
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
Ernst & Young................. Ernst & Young LLP
Exchange Act.................. Securities Exchange Act of 1934, as amended
FASB.......................... Financial Accounting Standards Board
FASB Interpretation No. 46.... FASB Interpretation No. 46, Consolidation of
Variable Interest Entities
FERC.......................... Federal Energy Regulatory Commission
FMB........................... First Mortgage Bonds
FMLP.......................... First Midland Limited Partnership, a
partnership that holds a lessor interest in the
MCV facility
FSP........................... FASB Staff Position
FTR........................... Financial transmission right
GAAP.......................... Generally Accepted Accounting Principles
GasAtacama.................... An integrated natural gas pipeline and electric
generation project located in Argentina and
Chile, which includes 702 miles of natural gas
pipeline and a 720 MW gross capacity power
plant
GCR........................... Gas cost recovery
Goldfields.................... A pipeline business located in Australia, in
which CMS Energy formerly held a 39.7 percent
ownership interest
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
5
Health Care Plan.............. The medical, dental, and prescription drug
programs offered to eligible employees of
Consumers and CMS Energy
IRS........................... Internal Revenue Service
Jorf Lasfar................... The 1,356 MW coal-fueled power plant in
Morocco, jointly owned by CMS Generation and
ABB Energy Ventures, Inc.
kWh........................... Kilowatt-hour
LORB.......................... Limited Obligation Revenue Bonds
Loy Yang...................... The 2,000 MW brown coal fueled Loy Yang A power
plant and an associated coal mine in Victoria,
Australia, in which CMS Generation held a 50
percent ownership interest
Ludington..................... Ludington pumped storage plant, jointly owned
by Consumers and Detroit Edison
mcf........................... Thousand cubic feet
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
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.
Moody's....................... Moody's Investors Service, Inc.
MPSC.......................... Michigan Public Service Commission
MSBT.......................... Michigan Single Business Tax
MTH........................... Michigan Transco Holdings, Limited Partnership
MW............................ Megawatts
NEIL.......................... Nuclear Electric Insurance Limited, an industry
mutual insurance company owned by member
utility companies
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
NYMEX......................... New York Mercantile Exchange
6
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
Pension Plan.................. The trusteed, non-contributory, defined benefit
pension plan of Panhandle, Consumers and CMS
Energy
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
RRP........................... Renewable Resources Program
RTO........................... Regional Transmission Organization
S&P........................... Standard & Poor's Rating Group, a division of
the McGraw Hill Companies, Inc.
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. 98................... SFAS No. 98, "Accounting for Leases"
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"
7
SFAS No. 123.................. SFAS No. 123, "Accounting for Stock-Based
Compensation"
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"
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
Taweelah...................... Al Taweelah A2, a power and desalination plant
of Emirates CMS Power Company, in which CMS
Generation holds a 40 percent interest
8
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9
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 for the year ended December
31, 2004.
EXECUTIVE OVERVIEW
CMS Energy is an integrated energy company with a business strategy focused
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. We 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, gas transmission,
storage, and processing. Our businesses are affected primarily by:
- weather, especially during the traditional heating and cooling
seasons,
- economic conditions, primarily in Michigan,
- regulation and regulatory issues that affect our gas and electric
utility operations,
- energy commodity prices,
- interest rates, and
- our debt credit rating.
During the past two 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 non-strategic assets, and to improve earnings and cash flow from the
businesses we retain.
Going forward, our business plan of "building on the basics" will focus on
reducing parent company debt substantially, improving our credit ratings,
growing earnings, restoring a common stock dividend, and positioning us to make
new investments consistent with our strengths. In the near term, our new
investments will concentrate on the utility.
Although we are looking ahead to business opportunities, the future holds
important challenges for us. The MCV Partnership reevaluated the economics of
operating the MCV Facility and determined that an impairment charge of $1.159
billion was required in September 2005. After accounting for minority interest
and income tax impacts, our third quarter 2005 net income was reduced by $369
million. We further reduced our third quarter 2005 net income by $16 million by
impairing certain other assets on our Consolidated Balance Sheets related to the
MCV Partnership. We are evaluating various alternatives in order to develop a
new long-term strategy with respect to the MCV Facility. For additional details
regarding the impairment, see Note 2, Asset Impairment Charges and Sales.
We continue to be challenged by the substantial increase in natural gas prices.
Prior to Hurricane Katrina in August 2005, NYMEX forward natural gas prices
through 2010 were approximately $2 per mcf higher than they were at year-end
2004. The effects of this summer's hurricanes, combined with tight natural gas
supplies, have caused natural gas prices to increase even further. Although our
natural gas purchases are recoverable from our utility customers, as gas prices
increase, the amount we pay for natural gas stored as
CMS-1
Cms Energy Corporation
inventory will require additional liquidity due to the timing of the cost
recoveries from our customers. We have requested authority from the MPSC to
recover the gas cost increases experienced by the gas utility. As of October
2005, our gas storage facilities are full and approximately 83 percent of our
gas purchase requirements for the 2005-2006 heating season are under fixed price
contracts.
Our electric utility customer base includes a mix of residential, commercial,
and diversified industrial customers. A sluggish Michigan economy has been
hurting our industrial sales. Recent negative developments in Michigan's
automotive industry, our largest industrial segment, could have long-term
impacts on our commercial and industrial customer base.
Additionally, Michigan's Customer Choice Act allows our electric customers to
buy electric generation service from an alternative electric supplier. As of
October 2005, alternative electric suppliers are providing 754 MW of generation
service to ROA customers. This is, however, down from 877 MW in October 2004, a
decrease of 14 percent. We expect this trend down to continue through year end,
but cannot predict future load loss.
Our business plan is targeted at predictable earnings growth and debt reduction.
Between 2001 and 2003, we reduced parent debt (ie: excluding Consumers' and
other subsidiaries' debt) by 50 percent. We are now in the second year of a
five-year plan to reduce parent debt further, by about half. In 2005, we retired
higher-interest rate consolidated debt through the use of proceeds from the
issuance of $150 million of CMS Energy senior notes and $875 million of
Consumers' FMB. We also issued 23 million shares of common stock and infused
$550 million into Consumers in 2005. By the end of the first quarter of 2006,
Consumers will extinguish through a defeasance $129 million of 9 percent notes.
These efforts, and others, are designed to lead us to be a strong, reliable
energy company that will be poised to take advantage of opportunities for
further growth.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
This Form 10-Q and other written and oral statements that we make contain
forward-looking statements as defined in Rule 3b-6 of the Securities Exchange
Act of 1934, as amended, Rule 175 of the Securities Exchange 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:
- capital and financial market conditions, including the price of CMS
Energy Common Stock and the effect of such market conditions on the
Pension Plan, interest rates, and access to the capital markets as
well as 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,
CMS-2
Cms Energy Corporation
- 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 future Stranded Costs incurred due to customers
choosing alternative energy suppliers,
- recovery of Clean Air Act costs and other environmental and
safety-related expenditures,
- power supply and natural gas supply costs when oil prices
and other fuel prices are rapidly increasing,
- timely recognition in rates of additional equity investments
in Consumers, and
- adequate and timely recovery of additional electric and gas
rate-based investments,
- the impact of adverse natural gas prices on the MCV Partnership and
FMLP investments, regulatory decisions that limit recovery of capacity
and fixed energy payments, and our ability to develop a new long-term
strategy with respect to the MCV Facility,
- 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 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 gas customers due
to high natural gas prices,
- potential adverse impacts of the new Midwest Energy Market upon power
supply and transmission costs,
- potential for the Midwest Energy Market to develop into an active
energy market in the state of Michigan, which may lead us to account
for certain electric energy contracts at CMS ERM 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,
CMS-3
Cms Energy Corporation
- 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,
- nuclear power plant performance, 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 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
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 efficient 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, and many of which
are beyond our control.
For additional information regarding these and other uncertainties, see Note 3,
Contingencies.
CMS-4
Cms Energy Corporation
RESULTS OF OPERATIONS
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for
per share amounts)
------------------------
Three months ended September 30 2005 2004 Change
- ------------------------------- ------ ----- -------
Net Income (Loss) Available to Common Stockholders $ (265) $ 56 $ (321)
Basic Earnings (Loss) Per Share $(1.21) $0.35 $(1.56)
Diluted Earnings (Loss) Per Share $(1.21) $0.34 $(1.55)
------ ----- ------
Electric Utility $ 62 $ 49 $ 13
Gas Utility (16) (11) (5)
Enterprises (260) 59 (319)
Corporate Interest and Other (51) (49) (2)
Discontinued Operations - 8 (8)
------ ----- ------
CMS Energy Net Income (Loss) Available to Common Stockholders $ (265) $ 56 $ (321)
====== ===== ======
For the three months ended September 30, 2005, our net loss available to common
stockholders was $265 million, compared to $56 million of net income available
to common stockholders for the three months ended September 30, 2004. The
decrease is primarily due to an 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 values. The decrease also reflects the
absence in 2005 of gains associated with the sale of our interest in Goldfields
and a reduction in net income from our gas utility, as higher operating and
maintenance costs exceeded the benefits derived from increased deliveries and
the increase in revenue resulting from the gas rates surcharge authorized by the
MPSC in October 2004. Partially offsetting these losses are higher earnings at
our electric utility primarily due to weather-driven higher than normal
residential electric utility sales and the collection of an electric surcharge
related to the recovery of costs incurred in the transition to customer choice.
The reduction was also partially offset by increases in the fair value of
certain long-term gas contracts and financial hedges at the MCV Partnership and
interest rate swaps at Taweelah.
Specific changes to net income (loss) available to common stockholders for the
three months ended September 30, 2005 versus the same period in 2004 are:
In Millions
-----------
- - decrease in earnings from our ownership interest in the MCV Partnership
primarily due to a $385 million impairment charge to property, plant, and
equipment to reflect the excess of the carrying value over the estimated
fair values of these assets, offset partially by an increase of $67 million
from operations, primarily due to an increase in fair value of certain
long-term gas contracts and financial hedges, $(318)
- - the absence in 2005 of the gain on the sale of our interest in Goldfields, (29)
- - the absence in 2005 of net gains associated with discontinued operations, (8)
CMS-5
Cms Energy Corporation
- - decrease in net income from our gas utility primarily due to increases in
benefit costs and safety, reliability and customer service expenses offset
partially by increased deliveries and increased revenue associated with the
gas rate surcharge authorized by the MPSC in October of 2004, (5)
- - increase in corporate interest and other expenses primarily due to premiums
paid on the early retirement of a portion of our 9.75 percent senior notes
offset by reduced interest expense, (2)
- - increase in income at our electric utility primarily due to weather-driven
higher than normal residential electric utility sales and the collection of
electric surcharges related to the recovery of MPSC approved costs, offset
partially by increased operating expenses and power supply costs, 13
- - increase in the fair value of interest rate swaps associated with our
investment in Taweelah as we recorded gains in 2005 versus losses in 2004, 13
- - income tax benefit recorded at Enterprises resulting from the American Jobs
Creation Act of 2004, and 10
- - increase in income from CMS ERM primarily due to mark-to-market
adjustments. 5
-----
Total Change $(321)
=====
In Millions (except for
per share amounts)
-----------------------
Nine months ended September 30 2005 2004 Change
- ------------------------------ ------ ----- ------
Net Income (Loss) Available to Common Stockholders $ (88) $ 63 $ (151)
Basic Earnings (Loss) Per Share $(0.42) $0.39 $(0.81)
Diluted Earnings (Loss) Per Share $(0.42) $0.38 $(0.80)
------ ----- ------
Electric Utility $ 141 $ 124 $ 17
Gas Utility 39 46 (7)
Enterprises (126) 36 (162)
Corporate Interest and Other (142) (147) 5
Discontinued Operations - 6 (6)
Accounting Changes - (2) 2
------ ----- ------
CMS Energy Net Income (Loss) Available to Common Stockholders $ (88) $ 63 $ (151)
====== ===== ======
For the nine months ended September 30, 2005, our net loss available to common
stockholders was $88 million, compared to $63 million of net income available to
common stockholders for the nine months ended September 30, 2004. The decrease
is primarily due to an asset 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 values. The decrease also reflects the absence
in 2005 of the gain on the sale of our interest in Goldfields and a decrease in
net income at our gas utility due to higher operating costs and depreciation
expense. Partially offsetting these decreases is an increase in the fair value
of certain long-term gas contracts and financial hedges at the MCV Partnership
and the positive impact at our electric utility due to an increase in the
collection of an electric surcharge related to the recovery of costs incurred
in the transition to customer choice, increased regulatory return on capital
expenditures, and weather-driven higher than normal residential electric
utility sales. The reduction was also partially offset by the absence in 2005
of a 2004 Loy Yang investment impairment and tax benefits recorded in 2005
resulting from the American Jobs Creation Act of 2004.
CMS-6
CMS Energy Corporation
Specific changes to net income (loss) available to common stockholders for the
nine months ended September 30, 2005 versus the same period in 2004 are:
In Millions
-----------
- - decrease in earnings from our ownership interest in the MCV
Partnership primarily due to a $385 million impairment charge
to property, plant, and equipment to reflect the excess of
the carrying value over the estimated fair values of these
assets, offset partially by an increase of $120 million from
operations, primarily due to an increase in fair value of
certain long-term gas contracts and financial hedges, $(265)
- - the absence in 2005 of the gain on the sale of our interest
in Goldfields, (29)
- - the absence in 2005 of the settlement agreement that DIG and
CMS MST entered into with the purchasers of electric power
and steam from DIG, (8)
- - decrease in net income from our gas utility primarily due to
increases in benefit costs and safety, reliability and
customer service expenses offset partially by increased
deliveries and increased revenue associated with the gas rate
surcharge authorized by the MPSC in October 2004, (7)
- - the absence in 2005 of net gains associated with discontinued
operations, (6)
- - the absence in 2005 of an impairment charge related to the
sale of our Loy Yang investment that was recorded in 2004, 81
- - income tax benefit recorded at Enterprises resulting from the
American Jobs Creation Act of 2004, 33
- - increase in other Enterprises income primarily due to an
increase in earnings from our overseas investments, increased
interest income, and the favorable resolution of a contingent
liability at our Leonard Field storage facility, 21
- - increase in income from our electric utility primarily due to
weather-driven higher than normal electric utility sales, the
return on capital expenditures, and the collection of
electric surcharges related to the recovery of MPSC approved
costs, offset partially by increased operating expenses and
power supply purchase costs, and customers choosing
alternative suppliers, 17
- - increase in income from CMS ERM primarily due to
mark-to-market adjustments, 5
- - reduction in corporate interest and other expenses partially
offset by premiums paid on the early retirement of a portion
of our 9.75 percent senior notes, and 5
- - the absence in 2005 of a loss recorded in 2004 for the
cumulative effect of a change in accounting principle. 2
-----
TOTAL CHANGE $(151)
=====
CMS-7
CMS Energy Corporation
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2005 2004 Change
- ------------ ---- ---- ------
Three months ended $ 62 $ 49 $13
Nine months ended $141 $124 $17
Three Months Ended Nine Months Ended
September 30, 2005 September 30, 2005
Reasons for the change: vs. 2004 vs. 2004
- ----------------------- ------------------ ------------------
Electric deliveries $ 49 $ 87
Power supply costs and related revenue (31) (42)
Other operating expenses, other income, and
non-commodity revenue (14) (45)
Regulatory return on capital expenditures 7 20
General taxes 3 (1)
Fixed charges 5 7
Income taxes (6) (9)
---- ----
Total change $ 13 $ 17
==== ====
ELECTRIC DELIVERIES: For the three months ended September 30, 2005, electric
deliveries increased 1.7 billion kWh or 16.0 percent versus the same period in
2004. For the nine months ended September 30, 2005, electric deliveries
increased 1.7 billion kWh or 5.8 percent versus the same period in 2004. The
corresponding increases in electric delivery revenue for both periods were due
to increased sales to residential customers due to warmer weather and increased
surcharge revenue, offset partially by reduced electric delivery revenue from
customers choosing alternative electric suppliers.
On July 1, 2004, Consumers started collecting a surcharge related to the
recovery of costs incurred in the transition to customer choice. This surcharge
increased electric delivery revenue by $2 million for the three months ended
September 30, 2005 and $12 million for the nine months ended September 30, 2005
versus the same periods in 2004. Surcharge revenue related to the recovery of
security costs and stranded costs increased electric delivery revenue by an
additional $3 million for the three months ended September 30, 2005 and $9
million for the nine months ended September 30, 2005.
POWER SUPPLY COSTS AND RELATED REVENUE: Our recovery of power supply costs is
capped for our residential customers until January 1, 2006. For the three months
ended September 30, 2005, our underrecovery of power costs allocated to these
capped customers increased by $32 million versus the same period in 2004. For
the nine months ended September 30, 2005, our underrecovery of power costs
allocated to these capped customers increased by $53 million versus the same
period in 2004. Power supply-related costs increased in 2005 primarily due to
higher coal costs and higher priced purchased power to replace the generation
loss from outages at our Palisades and Campbell 3 generating plants.
Partially offsetting these underrecoveries are transmission and nitrogen oxide
allowance expenditures related to our capped customers. To the extent these
costs are not fully recoverable due to the application of rate caps, we have
deferred these costs and are requesting recovery under Public Act 141. For the
three months ended September 30, 2005, deferrals of these costs increased by $1
million versus the same period in 2004. For the nine months ended September 30,
2005, deferrals of these costs increased by $11 million versus the same period
in 2004.
CMS-8
CMS Energy Corporation
OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For the three
months ended September 30, 2005, other operating expenses increased $16 million,
other income increased $3 million, and non-commodity revenue decreased $1
million versus the same period in 2004. For the nine months ended September 30,
2005, other operating expenses increased $55 million, other income increased $7
million, and non-commodity revenue increased $3 million versus the same period
in 2004.
The increase in other operating expenses reflects higher depreciation and
amortization expense, and higher pension and benefit expense. Depreciation and
amortization expense increased due to higher plant in service and greater
amortization of certain regulatory assets. Pension and benefit expense increased
primarily due to changes in actuarial assumptions and the remeasurement of our
pension and OPEB plans to reflect the new collective bargaining agreement
between the Utility Workers Union of America and Consumers. Benefit expense also
reflects the reinstatement of the employer matching contribution to our 401(k)
plan.
In addition, the increase in other operating expenses reflects increased
underrecovery expense related to the MCV PPA, offset partially by our direct
savings from the RCP. In 1992, a liability was established for estimated future
underrecoveries of power supply costs under the MCV PPA. In 2004, a portion of
the cash underrecoveries continued to reduce this liability until its depletion
in December. In 2005, all cash underrecoveries are expensed directly to income.
Partially offsetting this increased operating expense were the savings from the
RCP approved by the MPSC in January 2005.
The RCP allows us to dispatch the MCV Facility on the basis of natural gas
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas. The MCV
Facility's fuel cost savings are first used to offset the cost of replacement
power and fund a renewable energy program. Remaining savings are split between
us and the MCV Partnership. Our direct savings are shared 50 percent with
customers in 2005 and 70 percent thereafter.
The cost associated with the MCV PPA cash underrecoveries, net of our direct
savings from the RCP, increased operating expense $4 million for the nine months
ended September 30, 2005 versus the same period in 2004.
For the three months ended September 30, 2005, the increase in other income is
primarily due to higher interest income on short-term cash investments versus
the same period in 2004. For the nine months ended September 30, 2005, the
increase in other income is primarily due to higher interest income on
short-term cash investments, offset partially by expenses associated with the
early retirement of debt, versus the same period in 2004.
For the three months ended September 30, 2005, the decrease in non-commodity
revenue is primarily due to lower transmission services revenue. For the nine
months ended September 30, 2005, the increase in non-commodity revenue is
primarily due to higher transmission services revenue.
REGULATORY RETURN ON CAPITAL EXPENDITURES: The return on capital expenditures in
excess of our depreciation base as allowed by the Customer Choice Act increased
income by $7 million for the three months ended September 30, 2005 and $20
million for the nine months ended September 30, 2005 versus the same periods in
2004.
GENERAL TAXES: For the three months ended September 30, 2005, general taxes
decreased versus the same period in 2004 primarily due to lower property tax
expense. For the nine months ended September 30, 2005, general taxes increased
versus the same period in 2004 primarily due to higher MSBT expense, offset
partially by lower property tax expense.
CMS-9
CMS Energy Corporation
FIXED CHARGES: For the three months ended September 30, 2005, fixed charges
reflect a 46 basis point reduction in the average rate of interest on our debt
and lower average debt levels versus the same period in 2004. For the nine
months ended September 30, 2005, fixed charges reflect a 37 basis point
reduction in the average rate of interest on our debt and higher average debt
levels versus the same period in 2004.
INCOME TAXES: For the three and nine months ended September 30, 2005, income
taxes increased versus the same periods in 2004 primarily due to higher earnings
by the electric utility.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2005 2004 Change
- ------------ ---- ---- ------
Three months ended $(16) $(11) $(5)
Nine months ended $ 39 $ 46 $(7)
Three Months Ended Nine Months Ended
September 30, 2005 September 30, 2005
Reasons for the change: vs. 2004 vs. 2004
- ----------------------- ------------------ ------------------
Gas deliveries $ 1 $ -
Gas rate increase 3 24
Gas wholesale and retail services, other gas
revenues and other income 3 2
Operation and maintenance (14) (31)
General taxes and depreciation (1) (4)
Fixed charges - (2)
Income taxes 3 4
---- ----
Total change $ (5) $ (7)
==== ====
GAS DELIVERIES: For the three months ended September 30, 2005, higher gas
delivery revenues reflect increased deliveries to our customers versus the same
period in 2004. Gas deliveries, including miscellaneous transportation to
end-use customers, increased 1.4 bcf or 5.5 percent.
For the nine months ended September 30, 2005, gas delivery revenues reflect
slightly lower deliveries to our customers versus the same period in 2004. Gas
deliveries, including miscellaneous transportation to end-use customers,
decreased 0.6 bcf or 0.3 percent.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. In October 2004,
the MPSC issued a final order authorizing an annual increase of $58 million
through a two-year surcharge. As a result of these orders, gas revenues
increased $3 million for the three months ended September 30, 2005 and $24
million for the nine months ended September 30, 2005 versus the same periods in
2004.
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES AND OTHER INCOME: For the
three months ended September 30, 2005, other income increased primarily due to
higher interest income on short-term cash investments versus the same period in
2004. For the nine months ended September 30, 2005, other income increased
primarily due to higher interest income on short-term cash investments, offset
partially by expenses associated with the early retirement of debt, versus the
same period in 2004.
CMS-10
CMS Energy Corporation
OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2005, operation and maintenance expenses increased primarily due to increases in
benefit costs and additional safety, reliability, and customer service expenses.
Pension and benefit expense increased primarily due to changes in actuarial
assumptions and the remeasurement of our pension and OPEB plans to reflect the
new collective bargaining agreement between the Utility Workers Union of America
and Consumers. Benefit expense also reflects the reinstatement of the employer
matching contribution to our 401(k) plan.
GENERAL TAXES AND DEPRECIATION: For the three and nine months ended September
30, 2005, depreciation expense increased due to higher plant in service.
FIXED CHARGES: For the nine months ended September 30, 2005, fixed charges
reflect a 37 basis point reduction in the average rate of interest on our debt
and higher average debt levels versus the same period in 2004.
INCOME TAXES: For the three and nine months ended September 30, 2005, income
taxes decreased primarily due to lower earnings by the gas utility.
ENTERPRISES RESULTS OF OPERATIONS
In Millions
---------------------
September 30 2005 2004 Change
- ------------ ----- ---- ------
Three months ended $(260) $59 $(319)
Nine months ended $(126) $36 $(162)
Three Months Ended Nine Months Ended
September 30, 2005 September 30, 2005
Reasons for the change: vs. 2004 vs. 2004
- ----------------------- ------------------ ------------------
Operating revenues $ 123 $ 155
Cost of gas and purchased power (110) (154)
Fuel costs mark-to-market at MCV 197 361
Earnings from equity method investees 22 15
Gain on sale of assets (44) (40)
Operation and maintenance (3) (6)
General taxes, depreciation, and other income 8 11
Asset impairment charges (1,184) (1,048)
Fixed charges 2 14
Minority interest 484 397
Income taxes 186 133
------- -------
Total change $ (319) $ (162)
======= =======
OPERATING REVENUES AND COST OF GAS AND PURCHASED POWER: For three months ended
September 30, 2005, net operating revenues increased $123 million versus the
same period in 2004 and the related cost of gas and purchased power cost
increased $110 million versus the same period in 2004. These increases were
primarily due to the impact of increased customer demand on deliveries, fuel
costs and purchased power primarily at South American subsidiaries and increased
wholesale power sales and related costs at our Michigan generating plants. Also
contributing to the increase in operating revenue were mark-to-market gains on
gas contracts at CMS ERM.
CMS-11
CMS Energy Corporation
For the nine months ended September 30, 2005, operating revenues increased $155
million versus the same period in 2004 due to increased demand at our South
American subsidiaries, increased wholesale power sales at our Michigan
generating assets and mark to market gains on gas contracts at CMS ERM. Related
cost of gas and purchased power cost increased $154 million versus the same
period in 2004 primarily due to increased fuel costs and increased purchased
power associated with higher demand at our South American subsidiaries and our
Michigan generating plants.
FUEL COSTS MARK-TO-MARKET AT MCV: For the three and nine months ended September
30, 2005, the fuel costs mark-to-market adjustments at the MCV Partnership of
certain long-term gas contracts and financial hedges increased operating
earnings primarily due to increased gas prices.
EARNINGS FROM EQUITY METHOD INVESTEES: Equity earnings increased $22 million for
the three months ended September 30, 2005 versus the same period in 2004. The
increase was primarily due to a $13 million increase in the fair value of
interest rate swaps associated with our investment in Taweelah as gains in the
current period replaced the losses recorded on these instruments in the same
period of 2004. Also contributing to the increase was an $11 million increase in
earnings from our investment in Neyveli primarily due to the settlement of a
revenue dispute. These increases were offset partially by the absence of $2
million of earnings from Goldfields, which we sold in August of 2004.
Equity earnings increased $15 million for the nine months ended September 30,
2005 versus the same period in 2004. The increase was primarily due to $7
million in earnings from Shuweihat, which achieved commercial operations in the
fourth quarter of 2004, and a $7 million increase in earnings from GasAtacama,
as it is able to import more natural gas from Argentina than in 2004. Also
contributing to the increase were $6 million in higher earnings at Neyveli,
primarily due to the settlement of a revenue dispute, and $3 million of other
increases in earnings. These increases were offset partially by the absence of
$8 million in earnings from Goldfields, which we sold in August of 2004.
GAIN ON SALE OF ASSETS: For the three months ended September 30, 2005, gains on
asset sales decreased $44 million due to a $43 million gain on the sale of
Goldfields and a $1 million gain on the sale of the Bluewater Pipeline in 2004.
There were no significant gains or losses on asset sales during this period in
2005.
For the nine months ended September 30, 2005, gains on asset sales decreased $40
million versus the same period in 2004. This is due to a $3 million gain on the
sale of GVK and a $2 million gain on the sale of SLAP in 2005 versus a $43
million gain on the sale of Goldfields and a $1 million gain on the sale of the
Bluewater Pipeline in 2004.
OPERATION AND MAINTENANCE: For the three months ended September 30, 2005,
operation and maintenance expenses increased $3 million versus the same period
in 2004. The increase was primarily due to higher legal fees related to
litigation at DIG and increased costs due to higher electrical production.
For the nine months ended September 30, 2005, operation and maintenance expenses
increased $6 million versus the same period of 2004. The increase in 2005 was
primarily due to higher legal fees related to litigation at DIG, increased costs
due to higher electrical production and increased professional fees at South
American subsidiaries, offset partially by lower legal fees in connection with
arbitration in Argentina.
GENERAL TAXES, DEPRECIATION AND OTHER INCOME, NET: For the three months ended
September 30, 2005, the net of general tax expense, depreciation and other
income increased operating income $8 million primarily due to increased interest
income.
CMS-12
CMS Energy Corporation
For the nine months ended September 30, 2005, the net of general tax expense,
depreciation and other income increased operating income $11 million primarily
due to increased interest income, net positive foreign exchange activity, and
the reversal of a contingent liability at Leonard Field.
ASSET IMPAIRMENT CHARGES: For the three months ended September 30, 2005, asset
impairment charges increased by $1.184 billion versus the same period in 2004.
The increase relates to the impairment of property, plant, and equipment at the
MCV Partnership to reflect the excess of the carrying value of these assets
over their estimated fair values.
For the nine months ended September 30, 2005, asset impairment charges increased
by $1.048 billion versus the same period in 2004. The increase relates to the
impairment of property, plant, and equipment at the MCV Partnership to reflect
the excess of the carrying value of these assets over their estimated fair
values, offset partially by the absence, in 2005, of the Loy Yang impairment
recorded in 2004.
FIXED CHARGES: For the three and nine months ended September 30, 2005, fixed
charges decreased versus the same periods in 2004 due to lower expense at the
MCV Partnership.
MINORITY INTEREST: For the three and nine months ended September 30, 2005, net
losses attributed to minority interest owners in our subsidiaries replaced net
gains attributed to minority interest owners for the same periods in 2004. The
losses relate to the asset impairment charge to property, plant, and equipment
at the MCV Partnership, partially offset by mark-to-market gains at the MCV
Partnership.
INCOME TAXES: For the three months ended September 30, 2005, income tax expense
decreased versus the same period in 2004. The decrease reflects lower earnings
in 2005 due to the impairment of property, plant, and equipment at the MCV
Partnership. Also contributing to the decrease were income tax benefits related
to the American Jobs Creation Act.
For the nine months ended September 30, 2005, income tax expense decreased
versus the same period in 2004. The decrease reflects lower earnings in 2005 due
to the impairment of property, plant, and equipment at the MCV Partnership. Also
contributing to the decrease were income tax benefits related to the American
Jobs Creation Act. The decrease was partially offset by the absence of tax
benefits related to the 2004 Loy Yang investment impairment.
CORPORATE INTEREST AND OTHER RESULTS OF OPERATIONS
In Millions
----------------------
September 30 2005 2004 Change
- ------------ ----- ----- ------
Three months ended $ (51) $ (49) $(2)
Nine months ended $(142) $(147) $ 5
For the three months ended September 30, 2005 corporate interest and other net
expenses were $51 million, an increase of $2 million versus the same period in
2004. The increase reflects premiums paid on the early retirement of a portion
of our CMS Energy 9.75 percent senior notes partially offset by a reduction of
corporate interest as well as a reduction in other interest expenses allocated
from the utilities.
For the nine months ended September 30, 2005, corporate interest and other net
expenses were $142 million, a decrease of $5 million versus the same period in
2004. The decrease reflects a reduction in corporate interest as well as a
reduction in other interest expenses allocated from the utilities. The decrease
in interest expense was offset partially by a premium paid on the early
retirement of a portion of our CMS Energy 9.75 percent senior notes and the
absence in 2005 of a benefit from the reversal of a currency translation
adjustment related to the sale of Loy Yang that was recorded in 2004.
CMS-13
CMS Energy Corporation
DISCONTINUED OPERATIONS: For the three and nine months ended September 30, 2005,
we had no activity from operations accounted for as discontinued. Our net gain
from Discontinued Operations was $8 million for the three months ended September
30, 2004, and $6 million for the nine months ended September 30, 2004.
ACCOUNTING CHANGES: In 2004, we recorded a $2 million loss for the cumulative
effect of a change in accounting principle. The loss was the result of a change
in the measurement date of our benefit plans.
CRITICAL ACCOUNTING POLICIES
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.
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 the occurrence of 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 most significant of these contingencies are our pending class
actions arising out of round-trip trading and gas price reporting, our electric
and gas environmental liabilities, our indemnity and environmental remediation
obligations at Bay Harbor, and the potential underrecoveries from our power
purchase contract with the MCV Partnership.
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.
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 $16.115
billion at September 30, 2005, 52 percent represent long-lived assets and equity
method investments that are subject to this type of analysis. We base our
evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- domestic and foreign regulatory and political environments,
- state and federal regulatory and political environments,
- historical and future cash flow and profitability measurements, and
- other external market conditions or factors.
CMS-14
CMS Energy Corporation
If an event occurs or circumstances change in a manner that indicates the
recoverability of a long-lived asset should be assessed, we evaluate the asset
for impairment. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. An asset considered
held-for-sale is recorded at the lower of its carrying amount or fair value,
less cost to sell.
We also assess our ability to recover the carrying amounts of our equity method
investments. 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.
Our assessments of fair value using these valuation methodologies represent our
best estimates at the time of the reviews and are consistent with our internal
planning. The estimates we use can change over time, which could have a material
impact on our financial statements.
For additional details on asset impairments, see Note 2, Asset Impairment
Charges and Sales.
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. There have been no material changes to the accounting for
financial instruments since the year ended December 31, 2004. For details on
financial instruments, see Note 6, Financial and Derivative Instruments.
DERIVATIVE INSTRUMENTS: We use SFAS No. 133 to account for derivative
instruments. Except as noted within this section, there have been no material
changes to the accounting for derivatives since the year ended December 31,
2004.
To determine the fair value of our derivatives, we use quoted market prices and
third-party valuations (i.e., from brokers and banks), if available. For certain
contracts, market prices and third-party valuations are not available, and we
must determine fair values by using mathematical valuation models. These
valuation models require various inputs and assumptions, including commodity
forward prices, strike 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 these contracts. The following
table summarizes the interest rate and volatility rate assumptions we used to
value these contracts as of September 30, 2005:
Interest Rates (%) Volatility Rates (%)
------------------ --------------------
Long-term gas contracts associated with the MCV
Partnership 3.86 - 4.67 32 - 63
Gas-related option contracts 3.95 38 - 69
Electricity-related option contracts 3.95 59 - 74
CMS-15
CMS Energy Corporation
Commencement of the Midwest Energy Market: The MISO began operating the Midwest
Energy Market on April 1, 2005. Through operation of the Midwest Energy Market,
the MISO centrally dispatches electricity and transmission service throughout
the Midwest and provides day-ahead and real-time energy market information. At
this time, we believe that the commencement of this market does not constitute
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 the potential for an active energy market in
Michigan. If an active market develops in the future, some of our electric
purchases and sales contracts may qualify as derivatives. However, we believe
that we will 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, will not be required to mark these contracts to market.
Implementation of the RCP: The MCV Partnership uses long-term gas contracts to
purchase natural gas as fuel for generation, and to manage gas fuel costs. The
MCV Partnership believes that certain of these contracts qualify as normal
purchases under SFAS No. 133. Accordingly, these contracts are not recognized at
fair value on our Consolidated Balance Sheets. However, as a result of
implementing the RCP in January 2005, a significant portion of long-term gas
contracts no longer qualify as normal purchases, because the gas will not be
consumed as fuel for electric production. Accordingly, these contracts are
accounted for as derivatives, with changes in fair value recorded in earnings
each quarter. For the nine months ended September 30, 2005, we recorded a $242
million gain associated with the increase in fair value of these long-term gas
contracts. This gain is included in the total Fuel costs mark-to-market at MCV
on our Consolidated Statements of Income. As a result of mark-to-market gains,
we have recorded derivative assets totaling $298 million associated with the
fair value of long-term gas contracts on our Consolidated Balance Sheets. The
majority of these assets are expected to reverse through earnings during 2005
and 2006 as the gas is purchased, with the remainder reversing between 2007 and
2011.
The MCV Partnership holds natural gas futures and swap contracts to manage price
risk by fixing the price to be paid for natural gas on some of its long-term gas
contracts. Prior to the implementation of the RCP, these futures and swap
contracts were accounted for as cash flow hedges. Since the RCP was implemented
in January 2005, these instruments no longer qualify for cash flow hedge
accounting and any changes in their fair value have been recorded in earnings
each quarter. For the nine months ended September 30, 2005, we recorded a $125
million gain associated with the increase in fair value of these instruments.
This gain is also included in the total Fuel costs mark-to-market at MCV on our
Consolidated Statements of Income. As a result of mark-to-market gains, we have
recorded derivative assets totaling $125 million associated with the fair value
of these instruments on our Consolidated Balance Sheets. The majority of these
assets are expected to be realized during 2005 and 2006 as the futures and swap
contracts settle, with the remainder to be realized during 2007. Because of the
volatility of the natural gas market, the MCV Partnership expects future
earnings volatility on both the long-term gas contracts and the futures and swap
contracts, since gains and losses will be recorded each quarter.
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, 2004.
The fair value of the derivative contracts held by CMS ERM is included 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, 2005:
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In Millions
-----------------------------
Non-Trading Trading Total
----------- ------- -----
Fair value of contracts outstanding at December 31, 2004 $(199) $201 $ 2
Fair value of new contracts when entered into during the period (a) - (1) (1)
Changes in fair value attributable to changes in valuation techniques
and assumptions - - -
Contracts realized or otherwise settled during the period 39 (46) (7)
Other changes in fair value (b) (250) 274 24
----- ---- ---
Fair value of contracts outstanding at September 30, 2005 $(410) $428 $18
===== ==== ===
(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) 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, 2005
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 (410) (149) (185) (68) (8)
----- ----- ----- ---- ---
Total $(410) $(149) $(185) $(68) $(8)
===== ===== ===== ==== ===
Fair Value of Trading Contracts at September 30, 2005
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 $(55) $ (7) $(39) $(9) $ -
Prices obtained from external
sources or based on models and
other valuation methods 483 178 223 75 7
---- ---- ---- --- ---
Total $428 $171 $184 $66 $ 7
==== ==== ==== === ===
MARKET RISK INFORMATION: The following is an update of our risk sensitivities
since the year ended December 31, 2004. These risk sensitivities indicate the
potential loss in fair value, cash flows, or future earnings from our derivative
contracts and other financial instruments based upon a hypothetical 10 percent
adverse change in market rates or prices. Changes in excess of the amounts shown
in the sensitivity analyses could occur if market rates or prices exceed the 10
percent shift used for the analyses.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in
market interest rates):
In Millions
September 30, 2005 December 31, 2004
------------------ -----------------
Variable-rate financing -
before-tax annual earnings exposure $ 2 $ 2
Fixed-rate financing - potential
loss in fair value (a) 214 216
(a) Fair value exposure 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
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to be included in the sensitivity analysis, but can have an impact on financial
results.
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change
in market prices):
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Potential REDUCTION in fair value:
Gas supply option contracts $ 3 $ 1
FTRs - -
CMS ERM electric and gas forward contracts 19 10
Derivative contracts associated with the
MCV Partnership:
Long-term gas contracts (a) (b) 49 17
Gas futures and swaps (b) 59 41
(a) The increased potential reduction in fair value for the MCV Partnership's
long-term gas contracts is due to the increased number of contracts
accounted for as derivatives as a result of the RCP.
(b) The increased potential reduction in fair value for the MCV Partnership's
long-term gas contracts and gas futures and swaps is due to the significant
increase in natural gas prices from December 31, 2004.
Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10
percent adverse change in market prices):
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Potential REDUCTION in fair value:
Electricity-related option contracts $ 2 $ -
Gas-related option contracts 1 3
Gas-related swaps and futures (a) 23 7
(a) The increased potential reduction in fair value for the gas-related swaps
and futures is due to the significant increase in natural gas prices from
December 31, 2004.
Investment Securities Price Risk Sensitivity Analysis (assuming a 10 percent
adverse change in market prices):
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
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, which may only be used
to fund certain costs of nuclear plant decommissioning. These funds are 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. Those 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 earnings or
cash flows.
For additional details on market risk and derivative activities, see Note 6,
Financial and Derivative Instruments.
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INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
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 with the International Centre for the
Settlement of Investment Disputes (ICSID) in mid-2001, citing breaches by
Argentina under the Argentine-U.S. Bilateral Investment Treaty. In May 2005, an
ICSID tribunal concluded, among other things, that Argentina's economic
emergency did not excuse Argentina from liability. The ICSID tribunal found in
favor of CMS Gas Transmission, and awarded damages of U.S. $133 million, plus
interest.
Under the Rules of the ICSID Convention, Either Party May Seek an Annulment of
the Award From a Newly Constituted Tribunal. Argentina's Application for
Annulment was Formally Registered by ICSID On September 27, 2005
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension
benefits to our employees under a non-contributory, defined benefit Pension
Plan. We implemented a cash balance plan for certain employees hired after June
30, 2003. On September 1, 2005, we implemented the Defined Company Contribution
Plan.
The Defined Company Contribution Plan provides an employer cash contribution of
5 percent of base pay to the existing Employees' Savings Plan. No employee
contribution is required to receive the plan's employer contribution. All
employees hired on and after September 1, 2005 participate in this plan as part
of their retirement benefit program. Cash balance pension plan participants also
participate in the Defined Company Contribution Plan on September 1, 2005.
Additional pay credits under the cash balance pension plan were discontinued as
of that date. We use SFAS No. 87 to account for pension costs.
401(k): We resumed the employer's match in CMS Energy Stock on our 401(k)
Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled in the
company's 401(k) Savings Plan had their employer match increased from 50 percent
to 60 percent on eligible contributions up to the first six percent of an
employee's wages.
OPEB: We provide postretirement health and life benefits under our OPEB plan to
substantially all our retired employees. We use SFAS No. 106 to account for
other postretirement benefit costs.
Liabilities for both pension and OPEB are recorded on the balance sheet at the
present value of their future obligations, net of any plan assets. The
calculation of the liabilities and associated expenses requires the expertise of
actuaries. Many assumptions are made including:
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
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Any change in these assumptions can change significantly the liability and
associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost, and
cash contributions for the next three years:
In Millions
- ---------------------------------------------------------
Expected Costs Pension Cost OPEB Cost Contributions
- -------------- ------------ --------- -------------
2006 $ 95 $38 $ 82
2007 104 34 184
2008 99 30 112
Actual future pension cost and contributions will depend on future investment
performance, changes in future discount rates, and various other factors related
to the populations participating in the Pension Plan.
For additional details on postretirement benefits, see Note 7, Retirement
Benefits.
OTHER
Other accounting policies that are important to an understanding of our results
of operations and financial condition include:
- accounting for the effects of industry regulation,
- accounting for asset retirement obligations, and
- accounting for nuclear decommissioning costs.
There have been no material changes to these accounting policies since the year
ended December 31, 2004.
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
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. The market price for natural gas has increased. Although our 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 as gas prices increase. In addition, a few of our commodity suppliers
have requested nonstandard payment terms or other forms of assurances, including
margin calls, in connection with maintenance of ongoing deliveries of gas and
electricity.
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
September 2005, Consumers' ability to issue FMB as primary obligations or as
collateral for financing is expected to be limited to $298 million for 12
months, ending September 30, 2006. Beyond 12 months, Consumers' ability to issue
FMB in excess of $298 million is based on achieving a two-times FMB interest
coverage rate. Nonetheless, we believe our current level of cash and revolving
credit facilities, and our ability to access junior secured and unsecured
borrowing capacity in the capital markets, along with anticipated cash flows
from operating and investing activities, will be sufficient to meet our
liquidity needs. 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
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CMS Energy Corporation
conditions, including our results of operations, financial condition, and
capital requirements, as well as other relevant factors.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2005, $989 million consolidated cash was on hand, which
includes $196 million of restricted cash and $423 million from the entities
consolidated pursuant to FASB Interpretation No. 46. For additional details, see
Note 11, Consolidation of Variable Interest Entities.
Our primary ongoing source of cash is dividends and other distributions from our
subsidiaries. For the nine months ended September 30, 2005, Consumers paid $207
million in common stock dividends to CMS Energy.
SUMMARY OF CASH FLOWS:
In Millions
-------------
Nine months ended September 30 2005 2004
- ------------------------------ ----- -----
Net cash provided by (used in):
Operating activities $ 604 $ 200
Investing activities (399) (388)
----- -----
Net cash provided by (used in) operating and investing activities 205 (188)
Financing activities (82) (219)
Effect of exchange rates on cash 1 -
----- -----
Net Increase (Decrease) in Cash and Cash Equivalents $ 124 $(407)
===== =====
OPERATING ACTIVITIES: For the nine months ended September 30, 2005, net cash
provided by operating activities increased $404 million versus the same period
in 2004 due to increases in MCV gas supplier funds on deposit and accounts
payable. The increase in MCV gas supplier funds on deposit and accounts payable
is due to the effect of rising gas prices.
INVESTING ACTIVITIES: For the nine months ended September 30, 2005, net cash
used in investing activities increased $11 million versus the same period in
2004 primarily due to an increase in restricted cash of $267 million combined
with a decrease in proceeds from asset sales of $156 million. These changes were
offset by a net increase in short-term investment proceeds of $370 million. The
increase in restricted cash was due to an irrevocable deposit made with a
trustee to permit a defeasance of Consumers' 9 percent notes by the end of the
first quarter of 2006.
FINANCING ACTIVITIES: For the nine months ended September 30, 2005, net cash
used in financing activities decreased $137 million versus the same period in
2004 primarily due to net proceeds from the issuance of common stock of $289
million, offset by a decrease of $168 million in net proceeds from borrowings.
For additional details on long-term debt activity, see Note 4, Financings and
Capitalization.
OBLIGATIONS AND COMMITMENTS
REVOLVING CREDIT FACILITIES: For details on revolving credit facilities, see
Note 4, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: There have been no material changes in
off-balance sheet arrangements since the year ended December 31, 2004. For
details on guarantee arrangements, see Note 4,
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CMS Energy Corporation
Financings and Capitalization, "FASB Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others."
DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4,
Financings and Capitalization.
DEBT CREDIT RATING: On November 1, 2005, S&P placed CMS Energy's and Consumers'
debt credit ratings on CreditWatch with negative implications. S&P indicated
that they expect resolution of the CreditWatch before year end 2005.
OTHER: CMS ERM is a party to a certain gas supply contract whose performance is
backed by a bond issued by American Home Assurance Co. (AHA), a subsidiary of
American International Group, Inc. (AIG), as a jointly liable surety. AHA
currently has a surety obligation of approximately $119 million pursuant to this
contract. This amount amortizes monthly. The gas supply contract requires that
the surety maintain minimum credit ratings of AA- or better from S&P and Aa3 or
better from Moody's. S&P has downgraded the credit ratings of AIG and AHA to AA
and AA+, respectively, with a negative outlook for AIG. Moody's has lowered its
long-term senior debt ratings on AIG and AHA to Aa2 with a stable outlook for
AIG. We cannot predict whether these ratings will decline further; however, we
have several alternatives in the event that AHA no longer meets the minimum
rating requirements. These alternatives include obtaining a letter of credit
under our existing revolving credit agreement, seeking an alternative letter of
credit arrangement or posting available cash as collateral. These alternatives
may have a negative impact on our liquidity.
OUTLOOK
CORPORATE OUTLOOK
During 2005, we will continue to implement a business strategy that involves
improving our balance sheet and providing superior utility operations and
service. This strategy is designed to generate cash to pay down debt and provide
for more predictable future operating revenues and earnings.
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 non-strategic assets, and to improve earnings and cash flow from
businesses we retain. The percentage of our future earnings relating to our
larger equity method investments may increase and our total future earnings may
depend more significantly upon the performance of those investments. For
additional details, see Note 9, Equity Method Investments.
Over the next few years, our business plan of "building on the basics" will
focus on reducing parent company debt substantially, improving our credit
ratings, growing earnings, restoring a common stock dividend, and positioning us
to make new investments consistent with our strengths. In the near term, our new
investments will concentrate on the utility.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: We expect the growth in electric deliveries for 2005 to be approximately
four percent. Summer 2005 temperatures were higher than historical averages,
leading to increased demand from electric customers. Over the next five years,
we expect electric deliveries to grow at an average rate of approximately two
percent per year. However, such growth is dependent on a modestly growing
customer base and recovery of the 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.
CMS-22
CMS Energy Corporation
INDUSTRIAL REVENUE OUTLOOK: Our electric utility customer base includes a mix of
residential, commercial, and diversified industrial customers, the largest
segment of which is the automotive industry. In October 2005, Delphi Corporation
(Delphi) filed for Chapter 11 bankruptcy protection. Delphi is the nation's
largest automotive supplier headquartered in Troy, Michigan, and is a large
industrial customer of Consumers. Our electric utility operations are not
dependent upon a single customer, and we do not believe that this event will
have a material adverse effect on our financial condition. We cannot, however,
predict the impact of the Delphi bankruptcy filing on other automotive-related
manufacturing customers or the Michigan industrial base. Continued degradation
of the industrial customer base would have a negative impact on electric utility
revenues.
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 establish a reserve margin target to address various scenarios and
contingencies so that the probability of interrupting service to retail
customers because of a supply shortage is no greater than an industry-recognized
standard. However, even with the reserve margin target, additional spot
purchases during periods when electric prices are high may be required.
We are currently planning for a reserve margin of approximately 11 percent for
summer 2006, or supply resources equal to 111 percent of projected summer peak
load. Of the 2006 supply resources target of 111 percent, we expect to meet
approximately 98 percent from our electric generating plants and long-term power
purchase contracts, and approximately 13 percent from short-term contracts,
options for physical deliveries, and other agreements. We have purchased
capacity and energy contracts covering partially the estimated reserve margin
requirements for 2006 through 2007. As a result, we have recognized an asset of
$6 million for unexpired capacity and energy contracts at September 30, 2005.
COAL DELIVERY DISRUPTIONS: In May 2005, western coal rail carriers experienced
derailments and significant service disruptions due to heavy snow and rain
conditions. These disruptions affected all shippers of western coal from Wyoming
mines as well as coal producers from May 2005 through June 2005. We received
notification that, under contractual Force Majeure provisions, the coal tonnage
not delivered during this period will not be made up. According to recent
announcements, rail repairs will extend through November 2005. Although we
expect some impact on coal shipments during the repair period, we expect our
inventories will remain within historical levels, at least during the upcoming
winter period, though at lower levels than planned before the disruptions
occurred. Based on our present delivery experience, projections, and inventory,
we believe we will have adequate coal supply to allow for normal dispatch of our
coal-fired generating units.
ENERGY MARKET DEVELOPMENT: The MISO began operating the Midwest Energy Market on
April 1, 2005. The Midwest Energy Market includes a day-ahead and real-time
energy market and centralized generation dispatch for market participants. We
are a participant in this energy market. The intention of this market is to meet
load requirements in the region reliably and efficiently, to improve management
of congestion on the grid, and to centralize dispatch of generation throughout
the region. The MISO is now responsible for the reliability and economic
dispatch in the entire MISO area, which covers parts of 15 states and Manitoba,
including our service territory. We are presently evaluating what financial
impact, if any, these changes are having on our operations.
The settlement of charges for each operating day of the Midwest Energy Market
invokes the issuance of multiple settlement statements over a 155-day period.
This extended settlement period is designed to allow for adjustments associated
with the receipt of complete billing information and other adjustments. When
adjustments are necessary, the MISO bills market participants on a retroactive
basis, covering several months. We record adjustments as appropriate when the
MISO notifies us of the revised amounts. The revised amounts may result in
either a positive or a negative expense adjustment. We cannot predict
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CMS Energy Corporation
the amount or timing of any MISO billing adjustments.
RENEWABLE RESOURCES PROGRAM: In January 2005, in collaboration with the MPSC, we
established a renewable resources program. Under the RRP, we purchase energy
from approved renewable sources, which include solar, wind, geothermal, biomass,
and hydroelectric suppliers. Customers are able to participate in the RRP in
accordance with tariffs approved by the MPSC. The MPSC has authorized recovery
of above-market costs for the RRP by establishing a fund that consists of an
annual contribution from savings generated by the RCP, a surcharge imposed by
the MPSC on all customers, and contributions from customers that choose to
participate in the RRP. In February 2005, the Attorney General filed appeals of
the MPSC orders providing funding for the RRP in the Michigan Court of Appeals.
In August 2005, we secured long-term renewable energy supply contracts. In
October 2005, the MPSC issued an order approving these new supply contracts.
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to
increase our retail electric base rates. The electric rate case filing requests
an annual increase in revenues of approximately $320 million. The primary
reasons for the request are load migration to alternative electric suppliers,
increased system maintenance and improvement costs, Clean Air Act-related
expenditures, and employee pension costs. In April 2005, we filed updated debt
and equity information in this case.
In June 2005, the MPSC Staff filed its position in this case, recommending a
base rate increase of $98 million. The MPSC Staff also recommended an 11.25
percent return on equity to establish rates and recognized all of our projected
equity investment (infusions and retained earnings) in 2006. In August 2005, we
revised our request for an annual increase in revenues to approximately $197
million, and the MPSC Staff revised its recommendation to $100 million. In
October 2005, the ALJ issued a proposal for decision recommending a base rate
increase of $112 million and an 11.25 percent authorized return on equity. We
expect a final order from the MPSC in late 2005. If approved as requested, the
rate increase would go into effect in January 2006 and would apply to all retail
electric customers. We cannot predict the amount or timing of the rate increase,
if any, which the MPSC will approve.
BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of Appeals
upheld a lower court decision that requires Detroit Edison to obey a municipal
ordinance enacted by the City of Taylor, Michigan. The ordinance requires
Detroit Edison to bury a section of its overhead power lines at its own expense.
Detroit Edison filed an appeal with the Michigan Supreme Court. Unless
overturned by the Michigan Supreme Court, the decision could encourage other
municipalities to adopt similar ordinances, as has occurred or is under
discussion in a few municipalities in our service territory. If incurred, we
would seek recovery of these costs from our customers located in the
municipality affected, subject to MPSC approval. This case has potentially broad
ramifications for the electric utility industry in Michigan. In a similar
matter, in May 2005, we filed a request with the MPSC that asks the MPSC to rule
that the City of East Grand Rapids, Michigan must pay for the relocation of
electric utility facilities required by an ordinance adopted by the city. In
September 2005, we reached a settlement of this particular dispute with the City
of East Grand Rapids, which is in the process of finalization. In October 2005,
the Michigan Supreme Court issued an order in which it agreed to review the
lower court's decision in the City of Taylor matter. The Court also established
a briefing schedule. At this time, we cannot predict the outcome of the broader
issues addressed in the City of Taylor matter.
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.
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CMS Energy Corporation
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: 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 $815 million. 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
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.3 percent. As of September 2005, we have
incurred $589 million in capital expenditures to comply with these regulations
and anticipate that the remaining $226 million of capital expenditures will be
made in 2005 through 2011. These expenditures include installing selective
catalytic reduction technology at four of our coal-fired electric plants. In
addition to modifying the coal-fired electric plants, we expect to utilize
nitrogen oxide emissions allowances for years 2006 through 2008, of which 90
percent have been obtained. The cost of the allowances is estimated to average
$5 million per year for 2006 through 2008. The estimated costs are based on the
average cost of the purchased, allocated, and exchanged allowances. The need for
allowances will decrease after 2006 with the installation of selective catalytic
control technology. The cost of the allowances is accounted for as inventory.
The allowance inventory is expensed as the coal-fired electric generating units
emit nitrogen oxide.
The EPA recently adopted a Clean Air Interstate Rule that requires additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. The rule involves a two-phase program to reduce emissions of sulfur
dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule
will require that we run our Selective Catalytic Reduction 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 State Implementation
Plan, 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 a cost near that of
the Nitrogen Oxide State Implementation Plan.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial
reductions of mercury emissions from coal-fired electric power plants by 2010
and further reductions by 2018. While the industry has not reached a consensus
on the technical methods for curtailing mercury emissions, our capital and
operating costs for mercury emissions reductions are expected to be
significantly less than what is required for nitrogen oxide compliance.
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. The MDEQ has not indicated the direction that it will pursue to meet
or exceed the EPA requirements through a state rulemaking. We are actively
participating in dialog with the MDEQ regarding potential paths for controlling
mercury emissions and meeting the EPA requirements. In October 2005, the EPA
announced it would reconsider certain aspects of the Clean Air Mercury Rule. We
cannot predict the outcome of this proceeding.
Several legislative proposals have been introduced in the United States Congress
that would require reductions in emissions of greenhouse gases, however, none
have yet been enacted. We cannot predict
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CMS Energy Corporation
whether any federal mandatory greenhouse gas emission reduction rules ultimately
will be enacted, or the specific requirements of any such rules.
To the extent that greenhouse gas emission reduction rules come into effect,
such 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 and
engage in the 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 generating plant cooling
water intake systems. The new rules require significant reduction in fish killed
by operating equipment. Some of our facilities will be required to comply with
the new rules by 2007. We are currently performing the required studies to
determine the most cost-effective solutions for compliance.
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. As of October 2005, alternative electric
suppliers are providing 754 MW of generation service to ROA customers. This
amount represents a decrease of 14 percent compared to October 2004, and 10
percent of our total distribution load. Current trends indicate a continued
reduction in ROA load loss. However, it is difficult to predict future ROA
customer trends.
Implementation Costs: In June 2005, the MPSC issued an order that authorizes us
to recover implementation costs incurred during 2002 and 2003 totaling $6
million, plus the cost of money through the period of collection.
We are also pursuing authorization at the FERC for the MISO to reimburse us for
Alliance RTO development costs. Included in this amount is $2 million that the
MPSC did not approve as part of our 2002 implementation costs application. The
FERC denied our request for reimbursement, and we are appealing the FERC ruling
at the United States Court of Appeals for the District of Columbia. We cannot
predict the amount, if any, the FERC will approve as recoverable.
Section 10d(4) Regulatory Assets: In October 2004, we filed an application with
the MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets
for the period June 2000 through December 2005. Of the $628 million, $152
million relates to the cost of money. In March 2005, the MPSC Staff filed
testimony recommending the MPSC approve recovery of approximately $323 million
in Section 10d(4) costs, which includes the cost of money through the period of
collection. In June 2005, the ALJ issued a proposal for decision recommending
the MPSC approve recovery of the same Section 10d(4) costs recommended by the
MPSC Staff. However, we may have the opportunity to recover certain costs
included in our application alternatively in other cases pending before the
MPSC. We cannot predict the amount, if any, the MPSC will approve as
recoverable.
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."
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CMS Energy Corporation
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.
The cost that we incur under the MCV PPA exceeds the recovery amount allowed by
the MPSC. As a result, we estimate that cash underrecoveries of capacity and
fixed energy payments will aggregate $150 million from 2005 through 2007. 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 clause after September 15, 2007. We believe that the clause
is valid and fully effective, but cannot assure that it will prevail in the
event of a dispute. The MPSC's future actions on the capacity and fixed energy
payments recoverable from customers subsequent to September 15, 2007 may affect
negatively the financial performance of the MCV Partnership.
Further, 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. Natural gas prices have
increased substantially in recent years and throughout 2005. In the third
quarter of 2005, the MCV Partnership reevaluated the economics of operating the
MCV Facility and determined that an impairment was required. 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 financial obligations under the sale and leaseback transactions and
other contracts. We are currently evaluating various alternatives in order to
develop a new long-term strategy with respect to the MCV Facility. For
additional details on the impairment of the MCV Facility, see Note 2, Asset
Impairment Charges and Sales.
For additional details on the MCV Partnership, see Note 3, Contingencies, "Other
Consumers' Electric Utility Contingencies - The Midland Cogeneration Venture."
NUCLEAR MATTERS: Big Rock: Dismantlement of plant systems is essentially
complete and demolition of the remaining plant structures has begun. The
restoration project is on schedule to return approximately 530 acres of the
site, including the area formerly occupied by the nuclear plant, to a natural
setting for unrestricted use by early 2007. We expect a 30-acre area containing
eight casks loaded with spent nuclear fuel and other high-level radioactive
waste material to be returned to a natural state within two years from the date
the DOE begins removing the spent nuclear fuel from Big Rock.
Palisades: In August 2005, the NRC completed its performance review of the
Palisades Nuclear Plant for the first half of the calendar year 2005. The NRC
determined that Palisades was operated in a manner that preserved public health
and safety and met all of the NRC's specific "cornerstone objectives." As of
August 2005, all inspection findings were classified as having very low safety
significance and all performance indicators show performance at a level
requiring no additional oversight. Based on the plant's performance, only
regularly scheduled inspections are planned through March 31, 2007.
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 2005,
we have loaded 22 dry casks with spent nuclear fuel.
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CMS Energy Corporation
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. Certain parties are seeking to intervene and
have requested a hearing on the application. The NRC has stated that it expects
to take 22-30 months to review a license renewal application. We expect a
decision from the NRC in 2007.
Palisades, like other nuclear plants, has experienced cracking in reactor head
nozzle penetrations. Repairs to two nozzles were made in 2004. We have
authorized the purchase of a replacement reactor vessel closure head. The
replacement head is being manufactured and is scheduled to be installed in 2007.
For additional information on nuclear plant decommissioning at Big Rock and
Palisades, see Note 3, Contingencies, "Other Consumers' Electric Utility
Contingencies - Nuclear Plant Decommissioning."
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council,
the Public Interest Research Group in Michigan, and the Michigan Consumer
Federation filed a complaint with the MPSC, which was served on us by the MPSC
in April 2003. The complaint asks the MPSC to initiate a generic investigation
and contested case to review all facts and issues concerning costs associated
with spent nuclear fuel storage and disposal. The complaint seeks a variety of
relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric
Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear fuel storage and disposal should be placed in an independent
trust. The complaint also asks the MPSC to take additional actions. In May 2003,
Consumers and other named utilities each filed motions to dismiss the complaint.
In September 2005, the MPSC dismissed the complaint.
GAS UTILITY BUSINESS OUTLOOK
GROWTH: 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 the gas commodity prices,
- Michigan economic conditions,
- the price of competing energy sources or fuels, and
- gas consumption per customer.
In February 2004, we filed an application with the MPSC for a Certificate of
Public Convenience and Necessity to construct a 25-mile gas transmission
pipeline in northern Oakland County. The project is necessary to meet estimated
peak load beginning in the winter of 2005-2006. We started construction of Phase
I of the pipeline in June 2005 and expect Phase I to be completed and in service
by November 2005. We anticipate completion of Phase II of the project in 2008.
In October 2004, we filed an application with the MPSC for a Certificate of
Public Convenience and Necessity to construct a 10.8-mile gas transmission
pipeline in northwestern Wayne County. The project is necessary to meet the
projected capacity demands beginning in the winter of 2007. In August 2005, the
MPSC issued an order approving the application. Construction of the pipeline is
expected to begin in spring of 2006.
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CMS Energy Corporation
GAS UTILITY BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial results
and conditions. 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 for prudency in an annual
reconciliation proceeding. 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. The
October 2004 order also required us to undertake a study to determine why our
removal costs are in excess of those of other regulated Michigan natural gas
utilities and file a report with the MPSC Staff on or before December 31, 2005.
The MPSC has directed us to file our next gas depreciation case within 90 days
after the latter of:
- the removal cost study filing, or
- the MPSC issuance of a final order in the pending case related to ARO
accounting.
The MPSC order on the pending case related to ARO accounting is expected in the
first quarter of 2006. We proposed to incorporate the results of the gas
depreciation case into gas general rates using a surcharge mechanism if the
depreciation case order was not issued concurrently with a gas general rate case
order.
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. The primary reasons for
the request are recovery of new investments, carrying costs on natural gas
inventory related to higher gas prices, system maintenance, employee benefits,
and low-income assistance. If approved, the request would add approximately 5
percent to the typical residential customer's average monthly bill. The increase
would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony on October
31, 2005. In its testimony, the MPSC Staff recommended granting interim rate
relief of $38 million.
EMERGENCY RULES REGARDING BILLING PRACTICES: On October 18, 2005, the MPSC
issued an order adopting emergency rules, effective November 1, 2005 through
March 31, 2006, regarding billing practices for retail customers of electric and
gas utilities subject to the MPSC's jurisdiction. The emergency rules are to
address the expected substantial increase in heating costs this winter. The
emergency rules address billing cycles, fees, deposits, shutoffs and collection
of unpaid bills. We are analyzing the potential impact of these emergency rules.
OTHER CONSUMERS' OUTLOOK
COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of Consumers'
employees are represented by the Utility Workers Union of America. The Union
represents operating, maintenance, and construction employees and call center
employees. The collective bargaining agreement with the Union for operating,
maintenance, and construction employees expired on June 1, 2005 and the
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CMS Energy Corporation
collective bargaining agreement with the Union for call center employees expired
on August l, 2005. In both cases, new 5-year agreements were reached with the
Union and ratified by their membership.
ENTERPRISES OUTLOOK
We plan to continue restructuring our Enterprises business with the objective of
narrowing the focus of our operations to primarily North America, South America,
and the Middle East/North Africa. We will continue to sell designated assets and
investments that are not consistent with this focus.
SENECA operates an electric utility on Margarita Island, Venezuela under a
Concession Agreement with the Venezuelan Ministry of Energy and Mines, now the
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. It
was less than the amount required by the Concession Agreement and no tariff
increases have been granted since then. In July 2003, the MEP approved a fuel
subsidy for SENECA to offset partially the effects of its lower tariff revenues.
The fuel subsidy expired on December 31, 2004. SENECA has sent several letters
to the MEP indicating that the economic circumstances that required the
implementation of the fuel subsidy persist. In the letters, SENECA has informed
the MEP that, unless it objects, 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. SENECA has not received any
response to the letters from the MEP; therefore, SENECA is taking the fuel
subsidy as a credit against billings from Deltaven. Deltaven has continued to
deliver fuel without interruption. We are informed that the government is
considering whether to grant financial relief to SENECA pursuant to its
Concession Agreement obligations. The outcome is uncertain since all
alternatives are still being explored. If timely financial relief is not
approved, the liquidity of SENECA and the value of our investment in SENECA
would be impacted adversely.
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 restrict natural gas exports to our GasAtacama generating
plant, and
- impact of indemnity and environmental remediation obligations at Bay
Harbor.
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CMS Energy Corporation
OTHER OUTLOOK
MCV IMPAIRMENT: As a result of the impairment of the MCV Facility, Consumers
may be required to reduce the amount of equity investment included in its
electric and gas rate cases. This could impact Consumers' requested annual
revenue requirements. However, we cannot predict the amount, if any, of such
reduction. For additional information on the impairment of the MCV Facility,
see Note 2, Asset Impairment Charges and Sales.
LITIGATION AND REGULATORY INVESTIGATION: We are the subject of an investigation
by the DOJ regarding round-trip trading transactions by CMS MST. Additionally,
we are named as a party in various litigation matters including, but not limited
to, a shareholder derivative lawsuit, a securities class action lawsuit, a class
action lawsuit alleging ERISA violations, and several lawsuits regarding alleged
false natural gas price reporting and price manipulation. For additional details
regarding these investigations and litigation, see Note 3, Contingencies.
IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FSP 109-2, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE FOREIGN EARNINGS
REPATRIATION PROVISION WITHIN THE AMERICAN JOBS CREATION ACT OF 2004: The
American Jobs Creation Act of 2004 creates a one-year opportunity to receive a
tax benefit for U.S. corporations that reinvest dividends from controlled
foreign corporations in the U.S. in a 12-month period (calendar year 2005 for
CMS Energy). In September 2005, we decided on a plan to repatriate $33 million
of foreign earnings during the remainder of 2005. Historically, we recorded
deferred taxes on these earnings. Since this planned repatriation is expected to
qualify for the tax benefit, we reversed $10 million of our deferred tax
liability. This adjustment was recorded as a component of income from continuing
operations in the third quarter of 2005.
We may repatriate additional amounts that may qualify for the repatriation tax
benefit during the remainder of 2005. If successful, our current estimate is
that additional amounts could range between $30 million and $180 million. The
amount of additional repatriation remains uncertain because it is based on
future foreign subsidiary operations, cash flows, financings, and repatriation
limitations. This potential additional repatriation could reduce our recorded
deferred tax liability by $9 million to $23 million. We expect to be in a
position to finalize our assessment regarding any potential repatriation, which
may be higher or lower, in the fourth quarter of 2005.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: This Statement 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 amount over the vesting period of
the awards. This Statement also clarifies and expands SFAS No. 123's guidance in
several areas, including measuring fair value, classifying an award as equity or
as a liability, and attributing compensation cost to reporting periods.
This Statement amends SFAS No. 95, Statement of Cash Flows, to require that
excess tax benefits related to the excess of the tax-deductible amount over the
compensation cost recognized be classified as cash inflows from financing
activities rather than as a reduction of taxes paid in operating activities.
Excess tax benefits are recorded as adjustments to additional paid-in capital.
This Statement is effective for us as of the beginning of 2006. We adopted the
fair value method of accounting for share-based awards effective December 2002.
Therefore, we do not expect this statement to have a significant impact on our
results of operations when it becomes effective.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarifies 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 that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the
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CMS Energy Corporation
timing and (or) method of settlement. Accordingly, an entity is required to
recognize a liability for the fair value of a conditional asset retirement
obligation if the fair value of the liability can be reasonably estimated. The
fair value of a liability for the conditional asset retirement obligation should
be recognized when incurred. This Interpretation also clarifies when an entity
would have sufficient information to estimate reasonably the fair value of an
asset retirement obligation. For us, this Interpretation is effective no later
than December 31, 2005. We are in the process of determining the impact this
Interpretation will have on our financial statements upon adoption.
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CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30 2005 2004 2005 2004
- ------------ ------ ------ ------ ------
In Millions, Except Per Share Amounts
OPERATING REVENUE $1,335 $1,063 $4,421 $3,910
EARNINGS FROM EQUITY METHOD INVESTEES 40 18 92 78
OPERATING EXPENSES
Fuel for electric generation 215 215 570 577
Fuel costs mark-to-market at MCV (197) - (367) (6)
Purchased and interchange power 231 100 439 257
Cost of gas sold 242 142 1,415 1,166
Other operating expenses 262 225 753 667
Maintenance 62 63 178 185
Depreciation, depletion and amortization 121 114 399 366
General taxes 59 64 200 200
Asset impairment charges 1,184 - 1,184 125
------ ------ ------ ------
2,179 923 4,771 3,537
------ ------ ------ ------
OPERATING INCOME (LOSS) (804) 158 (258) 451
OTHER INCOME (DEDUCTIONS)
Accretion expense (4) (6) (14) (18)
Gain on asset sales, net - 46 5 49
Interest and dividends 14 8 39 22
Regulatory return on capital expenditures 17 10 48 28
Foreign currency losses, net - (1) (4) (7)
Other income 10 5 28 14
Other expense (13) (1) (25) (5)
------ ------ ------ ------
24 61 77 83
------ ------ ------ ------
FIXED CHARGES
Interest on long-term debt 117 124 360 380
Interest on long-term debt - related parties 7 15 23 44
Other interest 3 6 13 18
Capitalized interest (1) (2) (3) (5)
Preferred dividends of subsidiaries 1 2 3 4
------ ------ ------ ------
127 145 396 441
------ ------ ------ ------
INCOME (LOSS) BEFORE MINORITY INTERESTS (907) 74 (577) 93
MINORITY INTERESTS (479) 5 (380) 17
------ ------ ------ ------
INCOME (LOSS) BEFORE INCOME TAXES (428) 69 (197) 76
INCOME TAX (BENEFIT) EXPENSE (165) 18 (116) 8
------ ------ ------ ------
INCOME (LOSS) FROM CONTINUING OPERATIONS (263) 51 (81) 68
GAIN FROM DISCONTINUED OPERATIONS, NET OF
$4 AND $3 TAX EXPENSE IN 2004 - 8 - 6
------ ------ ------ ------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING (263) 59 (81) 74
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR
RETIREMENT BENEFITS, NET OF $1 TAX BENEFIT IN 2004 - - - (2)
------ ------ ------ ------
NET INCOME (LOSS) (263) 59 (81) 72
PREFERRED DIVIDENDS 2 3 7 9
------ ------ ------ ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDERS $ (265) $ 56 $ (88) $ 63
====== ====== ====== ======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-34
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30 2005 2004 2005 2004
- ------------ ------ ------ ------ ------
In Millions, Except Per Share Amounts
CMS ENERGY
NET INCOME (LOSS)
Net Income (Loss) Available to Common Stockholders $ (265) $ 56 $ (88) $ 63
====== ===== ====== ======
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $(1.21) $0.30 $(0.42) $ 0.36
Gain from Discontinued Operations - 0.05 - 0.04
Loss from Changes in Accounting - - - (0.01)
------ ----- ------ ------
Net Income (Loss) Attributable to Common Stock $(1.21) $0.35 $(0.42) $ 0.39
====== ===== ====== ======
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $(1.21) $0.29 $(0.42) $ 0.36
Gain from Discontinued Operations - 0.05 - 0.03
Loss from Changes in Accounting - - - (0.01)
------ ----- ------ ------
Net Income (Loss) Attributable to Common Stock $(1.21) $0.34 $(0.42) $ 0.38
====== ===== ====== ======
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 2005 2004
- ------------ ------- -----------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (81) $ 72
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $4 per period) 399 366
Regulatory return on capital expenditures (48) (28)
Minority interest (380) 17
Fuel costs mark-to-market at MCV (367) (6)
Asset impairment charges 1,184 125
Property tax, capital lease and other amortization 143 130
Accretion expense 14 18
Distributions from related parties less than earnings (21) (57)
Gain on the sale of assets (5) (49)
Cumulative effect of accounting changes - 2
Changes in other assets and liabilities:
Decrease (increase) in accounts receivable and accrued
revenues (18) 16
Increase in inventories (351) (273)
Increase in accounts payable 147 18
Decrease in accrued expenses (182) (82)
Increase in MCV gas supplier funds on deposit 275 16
Deferred income taxes and investment tax credit (114) 61
Decrease (increase) in other current and non-current
assets - (134)
Increase (decrease) in other current and non-current
liabilities 9 (12)
------- -------
Net cash provided by operating activities $ 604 $ 200
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $ (435) $ (377)
Investments in partnerships and unconsolidated subsidiaries - (70)
Cost to retire property (57) (53)
Restricted cash (149) 118
Investments in nuclear decommissioning trust funds (5) (4)
Proceeds from nuclear decommissioning trust funds 31 35
Proceeds from short-term investments 295 1,683
Purchase of short-term investments (186) (1,944)
Maturity of MCV restricted investment securities held-to-maturity 316 592
Purchase of MCV restricted investment securities held-to-maturity (267) (592)
Proceeds from sale of assets 59 215
Other investing (1) 9
------- -------
Net cash used in investing activities $ (399) $ (388)
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds, and other long-term debt $ 1,086 $ 839
Issuance of common stock 289 -
Retirement of bonds and other long-term debt (1,381) (987)
Payment of preferred stock dividends (8) (9)
Payment of capital lease obligations (26) (41)
Debt issuance costs and financing fees (42) (21)
------- -------
Net cash used in financing activities $ (82) $ (219)
EFFECT OF EXCHANGE RATES ON CASH 1 -
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS $ 124 $ (407)
CASH AND CASH EQUIVALENTS FROM EFFECT OF REVISED FASB
INTERPRETATION NO. 46 CONSOLIDATION - 174
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD 669 532
------- -------
CASH AND CASH EQUIVALENTS, END OF PERIOD $ 793 $ 299
======= =======
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CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30
2005 DECEMBER 31
(UNAUDITED) 2004
------------ -----------
In Millions
ASSETS
PLANT AND PROPERTY (AT COST)
Electric utility $ 8,129 $ 7,967
Gas utility 3,066 2,995
Enterprises 1,069 3,517
Other 31 28
------- -------
12,295 14,507
Less accumulated depreciation, depletion and amortization 5,077 6,135
------- -------
7,218 8,372
Construction work-in-progress 501 370
------- -------
7,719 8,742
------- -------
INVESTMENTS
Enterprises 677 729
Other 13 23
------- -------
690 752
------- -------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 793 669
Restricted cash 196 56
Short-term investments at cost, which approximates market - 109
Accounts receivable, notes receivable and accrued revenue, less
allowances of $33 and $38, respectively 560 528
Accounts receivable and notes receivable - related parties 82 53
Inventories at average cost
Gas in underground storage 1,173 856
Materials and supplies 89 90
Generating plant fuel stock 118 84
Price risk management assets 260 91
Regulatory assets - postretirement benefits 19 19
Derivative instruments 380 96
Deferred property taxes 116 167
Prepayments and other 154 181
------- -------
3,940 2,999
------- -------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 571 604
Additional minimum pension 466 372
Postretirement benefits 122 139
Capital expenditures return 201 141
Abandoned Midland Project 9 10
Other 461 411
Price risk management assets 358 214
Nuclear decommissioning trust funds 555 575
Goodwill 30 23
Notes receivable - related parties 199 217
Notes receivable 173 178
Other 621 495
------- -------
3,766 3,379
------- -------
TOTAL ASSETS $16,115 $15,872
======= =======
CMS-38
STOCKHOLDERS' INVESTMENT AND LIABILITIES
SEPTEMBER 30
2005 DECEMBER 31
(UNAUDITED) 2004
------------ -----------
In Millions
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 350.0 shares; outstanding 220.0
shares and 195.0 shares, respectively $ 2 $ 2
Other paid-in capital 4,428 4,140
Accumulated other comprehensive loss (297) (336)
Retained deficit (1,822) (1,734)
------- -------
2,311 2,072
Preferred stock of subsidiary 44 44
Preferred stock 261 261
Long-term debt 6,521 6,444
Long-term debt - related parties 178 504
Non-current portion of capital and finance lease obligations 299 315
------- -------
9,614 9,640
------- -------
MINORITY INTERESTS 396 733
------- -------
CURRENT LIABILITIES
Current portion of long-term debt, capital and finance leases 312 296
Current portion of long-term debt - related parties 129 180
Accounts payable 530 391
Accounts payable - related parties 1 1
Accrued interest 115 145
Accrued taxes 167 312
Price risk management liabilities 237 90
Current portion of gas supply contract obligations 35 32
Deferred income taxes 48 19
MCV gas supplier funds on deposit 295 20
Other 299 269
------- -------
2,168 1,755
------- -------
NON-CURRENT LIABILITIES
Regulatory Liabilities
Regulatory liabilities for cost of removal 1,097 1,044
Income taxes, net 369 357
Other regulatory liabilities 174 173
Postretirement benefits 455 275
Deferred income taxes 538 671
Deferred investment tax credit 75 79
Asset retirement obligation 436 439
Price risk management liabilities 363 213
Gas supply contract obligations 151 176
Other 279 317
------- -------
3,937 3,744
------- -------
COMMITMENTS AND CONTINGENCIES (Notes 3, 4 and 6)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $16,115 $15,872
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-39
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ ------------------
SEPTEMBER 30 2005 2004 2005 2004
- ------------ ------- ------- ------- --------
In In
Millions Millions
COMMON STOCK
At beginning and end of period $ 2 $ 2 $ 2 $ 2
OTHER PAID-IN CAPITAL
At beginning of period 4,422 3,848 4,140 3,846
Common stock repurchased (1) - (1) -
Common stock reacquired - (4) - (5)
Common stock issued 7 6 288 9
Common stock reissued - - 1 -
------- ------- ------- -------
At end of period 4,428 3,850 4,428 3,850
------- ------- ------- -------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period (26) - (17) -
Minimum pension liability adjustments (a) - (1) (9) (1)
------- ------- ------- -------
At end of period (26) (1) (26) (1)
------- ------- ------- -------
Investments
At beginning of period 8 8 9 8
Unrealized gain (loss) on investments (a) 1 (1) - (1)
------- ------- ------- -------
At end of period 9 7 9 7
------- ------- ------- -------
Derivative Instruments
At beginning of period (3) 6 (9) (8)
Unrealized gain on derivative instruments (a) 31 5 43 24
Reclassification adjustments included in net income
(loss) (a) (1) (1) (7) (6)
------- ------- ------- -------
At end of period 27 10 27 10
------- ------- ------- -------
Foreign Currency Translation
At beginning of period (312) (327) (319) (419)
Loy Yang sale - - - 110
Other foreign currency translations (a) 5 2 12 (16)
------- ------- ------- -------
At end of period (307) (325) (307) (325)
------- ------- ------- -------
At end of period (297) (309) (297) (309)
------- ------- ------- -------
RETAINED DEFICIT
At beginning of period (1,557) (1,837) (1,734) (1,844)
Net income (loss) (a) (263) 59 (81) 72
Preferred stock dividends declared (2) (3) (7) (9)
------- ------- ------- -------
At end of period (1,822) (1,781) (1,822) (1,781)
------- ------- ------- -------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 2,311 $ 1,762 $ 2,311 $ 1,762
======= ======= ======= =======
(a) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum Pension Liability
Minimum pension liability adjustments, net of tax
benefit of $-, $(1), $(5) and $(1), respectively $ - $ (1) $ (9) $ (1)
Investments
Unrealized gain (loss) on investments, net of tax of
$-, $-, $- and $-, respectively 1 (1) - (1)
Derivative Instruments
Unrealized gain on derivative instruments, net of tax
of $15, $7, $28 and $14, respectively 31 5 43 24
Reclassification adjustments included in net income,
net of tax benefit of $(1), $-, $(7) and $(3),
respectively (1) (1) (7) (6)
Foreign currency translation, net 5 2 12 94
Net income (loss) (263) 59 (81) 72
------- ------- ------- -------
Total Other Comprehensive Income (Loss) $ (227) $ 63 $ (42) $ 182
======= ======= ======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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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 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 Notes to Consolidated Financial Statements
contained in CMS Energy's Form 10-K for the year ended December 31, 2004. 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 integrated energy company with a business
strategy focused 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 Revised FASB Interpretation No. 46. 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. generally accepted accounting principles. 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.
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. The gains or losses that result from this process are shown
in the stockholders' equity section on our Consolidated Balance Sheets. Gains
and losses that arise from exchange rate fluctuations on transactions
denominated in
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CMS Energy Corporation
a currency other than the functional currency, except those that are hedged, are
included in determining net income.
Argentina: At September 30, 2005, the net foreign currency loss due to the
unfavorable exchange rate of the Argentine peso recorded in the Foreign Currency
Translation component of stockholders' equity using an exchange rate of 2.920
pesos per U.S. dollar was $263 million. This amount also reflects the effect of
recording, at December 31, 2002, U.S. income taxes on temporary differences
between the book and tax bases of foreign investments, including the foreign
currency translation associated with our Argentine investments.
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 2005 2004 2005 2004
- ------------ ---- ---- ---- ----
Other income
Interest and dividends - related parties $ 2 $ 2 $ 7 $ 4
Electric restructuring return 1 2 5 5
Return on stranded and security
costs 1 - 4 1
Nitrogen oxide allowance sales 1 - 2 -
Investment sale gain - 1 - 2
Reversal of contingent liability - - 3 -
All other 5 - 7 2
--- --- --- ---
Total other income $10 $ 5 $28 $14
=== === === ===
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2005 2004 2005 2004
- ------------ ---- ---- ---- ----
Other expense
Investment write-down $ - $ - $ (1) $ -
Loss on reacquired and extinguished debt (10) - (16) -
Plant maintenance shut-down - - (2) -
Civic and political expenditures (1) (1) (2) (2)
Loss on SERP investment - (1) (1) (2)
All other (2) 1 (3) (1)
---- --- ---- ---
Total other expense $(13) $(1) $(25) $(5)
==== === ==== ===
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
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CMS Energy Corporation
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. In the third quarter of 2005, we recorded
Asset impairment charges of $1.184 billion on our Consolidated Statements of
Income. These charges reduced our third quarter 2005 net income by $385 million.
The MCV Partnership's costs of producing electricity are tied to the price of
natural gas, but its revenues do not vary with changes in the price of natural
gas. While the average forward price of natural gas has increased steadily from
2002 through the second quarter of 2005, it remained at a level that suggested
the MCV Partnership's operating cash flow would be sufficient to provide for the
recovery of its assets. However, unforeseen natural and economic events in the
third quarter of 2005 caused a substantial upward spike in NYMEX forward natural
gas prices for the years 2005 through 2010. Additionally, other independent
natural gas long-term forward price forecasting organizations indicated their
intention to raise their forecasts for the price of natural gas generally over
the entire long-term forecast horizon beyond 2010. Our analysis and assessment
of this new information suggests that forward natural gas prices for the period
from 2006 through 2010 will average approximately $9 per mcf. This compares to
the second quarter 2005 NYMEX-quoted average prices for the same forward period
of approximately $7.50 per mcf. Further, this new information indicates that
natural gas prices will average approximately $6.50 per mcf over the long term
beyond 2010. As a result, the MCV Partnership reevaluated the economics of
operating the MCV Facility and determined that an impairment analysis,
considering revised forward natural gas price assumptions, was required. In its
impairment analysis, the MCV Partnership determined the fair value of its fixed
assets by discounting a set of probability-weighted streams of future operating
cash flows at a 4.3 percent risk free interest rate. The carrying value of the
MCV Partnership's fixed assets exceeded the estimated fair value by $1.159
billion. In the third quarter of 2005, the MCV Partnership recorded an
impairment charge of $1.159 billion to recognize the reduction in fair value of
the MCV Facility's fixed assets. As a result, our net income was reduced by $369
million after considering tax effects and minority interest. The MCV
Partnership's fixed assets, which are included on our Consolidated Balance
Sheets and reported under the Enterprises business segment, after reflecting the
impairment charge, are valued at $219 million at September 30, 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 financial obligations under the sale and
leaseback transactions and other contracts.
Our 49 percent interest in the MCV Partnership is held through Consumers'
wholly-owned subsidiary, CMS Midland. The severe adverse change in the
anticipated economics of the MCV Partnership operations discussed within this
Note also led to our decision to impair certain assets carried on the balance
sheet of CMS Midland. These assets represented interest capitalized during the
construction of the MCV Facility, which were being amortized over the life of
the MCV Facility. In the third quarter of 2005, we recorded an impairment charge
of $25 million ($16 million, net of tax) to reduce the carrying amount of these
assets to zero.
In the first quarter of 2004, an impairment charge of $125 million ($81 million,
net of tax) was recorded to recognize the reduction in fair value as a result of
the sale of Loy Yang. The impairment included a cumulative net foreign currency
translation loss of approximately $110 million. The sale of Loy Yang was
completed in April 2004.
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CMS Energy Corporation
ASSET SALES
Gross cash proceeds received from the sale of assets totaled $59 million for the
nine months ended September 30, 2005 and $215 million for the nine months ended
September 30, 2004. The impacts of these sales are included in Gain on assets
sales, net on our Consolidated Statements of Income.
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
=== ===
For the nine months ended September 30, 2004, we sold the following assets:
In Millions
------------------
Pretax After-tax
Date sold Business/Project Gain Gain
- --------- ---------------- ------ ---------
February Bluewater Pipeline $ 1 $ 1
April Loy Yang - -
May American Gas Index fund 1 1
August Goldfields 45 29
Various Other 2 1
--- ---
Total gain on asset sales $49 $32
=== ===
Although much of our asset sales program is complete, we still may sell certain
remaining businesses that are not strategic to us.
3: CONTINGENCIES
SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading transactions by
CMS MST, CMS Energy's Board of Directors established a Special Committee to
investigate matters surrounding the transactions and retained outside counsel to
assist in the investigation. The Special Committee completed its investigation
and reported its findings to the Board of Directors in October 2002. The Special
Committee concluded, based on an extensive investigation, that the round-trip
trades were undertaken to raise CMS MST's profile as an energy marketer with the
goal of enhancing its ability to promote its services to new customers. The
Special Committee found no effort to manipulate the price of CMS Energy Common
Stock or affect energy prices. The Special Committee also made recommendations
designed to prevent any recurrence of this practice. Previously, CMS Energy
terminated its speculative trading business and revised its risk management
policy. The Board of Directors adopted, and CMS Energy implemented, the
recommendations of the Special Committee.
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 nor
denied the order's findings. The settlement resolved the SEC
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CMS Energy Corporation
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 by
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.
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, including but not limited to
Consumers which, while established, operated and regulated as a separate legal
entity and publicly traded company, shares a parallel Board of Directors with
CMS Energy. The complaints were filed as purported class actions in the United
States District Court for the Eastern District of Michigan, by shareholders who
allege that they purchased CMS Energy's securities during a purported class
period running from May 2000 through March 2003. The cases were consolidated
into a single lawsuit. The consolidated lawsuit 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, a motion was granted dismissing Consumers
and three of the individual defendants, but the court denied the motions to
dismiss for CMS Energy and the 13 remaining individual defendants. Plaintiffs
filed a motion for class certification on April 15, 2005 and an amended motion
for class certification on June 20, 2005. CMS Energy and the individual
defendants will defend themselves vigorously in this litigation but cannot
predict its outcome.
SETTLEMENT OF DEMAND FOR ACTION AGAINST OFFICERS AND DIRECTORS: In May 2002, the
Board of Directors of CMS Energy received a demand, on behalf of a shareholder
of CMS Energy Common Stock, that it commence civil actions (i) to remedy alleged
breaches of fiduciary duties by certain CMS Energy officers and directors in
connection with round-trip trading by CMS MST, and (ii) to recover damages
sustained by CMS Energy as a result of alleged insider trades alleged to have
been made by certain current and former officers of CMS Energy and its
subsidiaries. In December 2002, two new directors were appointed to the Board.
The Board formed a special litigation committee in January 2003 to determine
whether it was in CMS Energy's best interest to bring the action demanded by the
shareholder. The disinterested members of the Board appointed the two new
directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed by the
shareholder on behalf of CMS Energy in the Circuit Court of Jackson County,
Michigan in furtherance of his demands.
On July 7, 2005, CMS Energy filed with the court a Stipulation of Settlement
that was signed by all parties as well as the special litigation committee. The
judge entered the Final Order and Judgment on August 26, 2005. Pursuant to the
terms of the settlement, on September 5, 2005, CMS Energy received $12 million
from its insurance carriers under its directors and officers liability insurance
program, $7 million of which will be used to pay any reasonable settlement,
judgment or other costs associated with the securities class action lawsuits.
CMS Energy may use the remaining $5 million to pay attorneys' fees and expenses
arising out of the derivative proceeding.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST,
and certain named and unnamed officers and directors, in two lawsuits brought as
purported class actions on behalf of participants and beneficiaries of the CMS
Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July
2002 in United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek 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. Plaintiffs also seek other equitable
relief and legal fees. In March 2004, the judge granted in part, but denied in
part, CMS Energy's motion to dismiss
CMS-45
CMS Energy Corporation
the complaint. The judge has conditionally granted plaintiffs' motion for class
certification. A trial date has not been set, but is expected to be no earlier
than mid-2006. CMS Energy and Consumers will defend themselves vigorously in
this litigation but cannot predict its outcome.
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 Commodity Futures Trading Commission 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 the action seeks to enjoin
such acts, compel compliance with the Commodities Exchange Act, and impose
monetary penalties.
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, a third party
constructed a golf course over several abandoned cement kiln dust (CKD) piles,
leftover from the former cement plant operation on the Bay Harbor site. Pursuant
to the agreement with the MDEQ, CMS Energy constructed a water collection system
to recover seep water from one of the CKD piles. 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, the MDEQ issued a notice of noncompliance (NON), 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, a
subsidiary of Enterprises and CMS Capital, LLC, a subsidiary of CMS Energy.
Under the AOC, CMS Energy is generally obligated, among other things, to: (i)
engage in measures to restrict access to seep areas, install methods to
interrupt the flow of seep water to Lake Michigan, and take other measures as
may be required by the EPA under an approved "removal action work plan"; (ii)
investigate and study the extent of hazardous substances at the site, evaluate
alternatives to address a long-term remedy, and issue a report of the
investigation and study; and (iii) within 120 days after EPA approval of the
investigation report, enter into an enforceable agreement with the MDEQ to
address a long-term remedy under certain criteria set forth in the AOC. The EPA
approved a final removal action work plan in September 2005.
The EPA-approved removal action work plan provides for fencing of affected
beach-front areas and the installation of an underground leachate collection
system, among other elements. The EPA's approvals also specify that a backup
"containment and isolation system," involving dams or barriers in the lake,
could be required in certain areas, if the collection system is ineffective.
Several parties have issued demand letters to CMS Energy claiming breach of the
indemnification provisions, making requests for payment of their expenses
related to the NON, and/or claiming damages to property or personal injury with
regard to the matter. Several landowners have threatened litigation in the event
their demands are not met and owners of one parcel have filed a lawsuit in Emmet
County Circuit Court against CMS Energy and several of its subsidiaries, as well
as Bay Harbor Company LLC and David Johnson, one of the developers at Bay
Harbor. CMS Energy responded to the indemnification claims by stating that it
had not breached its indemnity obligations, it will comply with the indemnities,
it has restarted the seep water collection facility and it has responded to the
NON. CMS Energy has entered into
CMS-46
CMS Energy Corporation
negotiations with several landowners at Bay Harbor for access as necessary to
implement remediation measures, and will defend vigorously any property damage
and personal injury claims or lawsuits.
CMS Energy recorded a liability for its obligations associated with this matter
in the amount of $45 million in the fourth quarter of 2004. 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: 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 $815 million. 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
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.3 percent. As of September 2005, we have
incurred $589 million in capital expenditures to comply with these regulations
and anticipate that the remaining $226 million of capital expenditures will be
made in 2005 through 2011. These expenditures include installing selective
catalytic reduction technology at four of our coal-fired electric plants. In
addition to modifying the coal-fired electric plants, we expect to utilize
nitrogen oxide emissions allowances for years 2006 through 2008, of which 90
percent have been obtained. The cost of the allowances is estimated to average
$5 million per year for 2006 through 2008. The estimated costs are based on the
average cost of the purchased, allocated, and exchanged allowances. The need for
allowances will decrease after 2006 with the installation of selective catalytic
control technology. The cost of the allowances is accounted for as inventory.
The allowance inventory is expensed as the coal-fired electric generating units
emit nitrogen oxide.
The EPA recently adopted a Clean Air Interstate Rule that requires additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. The rule involves a two-phase program to reduce emissions of sulfur
dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule
will require that we run our Selective Catalytic Reduction 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 State Implementation
Plan, 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 a cost near that of
the Nitrogen Oxide State Implementation Plan.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial
reductions of mercury emissions from coal-fired electric power plants by 2010
and further reductions by 2018. While the industry has not reached a consensus
on the technical methods for curtailing mercury emissions, our capital and
CMS-47
CMS Energy Corporation
operating costs for mercury emissions reductions are expected to be
significantly less than what is required for nitrogen oxide compliance.
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. The MDEQ has not indicated the direction that it will pursue to meet
or exceed the EPA requirements through a state rulemaking. We are actively
participating in dialog with the MDEQ regarding potential paths for controlling
mercury emissions and meeting the EPA requirements. In October 2005, the EPA
announced it would reconsider certain aspects of the Clean Air Mercury Rule. We
cannot predict the outcome of this proceeding.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seeking modification permits
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 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 past experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $9 million. At September 30, 2005, we have
recorded a liability for the minimum amount of our estimated Superfund
liability.
In October 1998, during routine maintenance activities, we identified PCB as a
component in certain paint, grout, and sealant materials at the Ludington Pumped
Storage facility. 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: On July 12, 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 GTG duct burner and failing to maintain certain
records in the required format. The MCV Partnership has declared five of the six
duct burners in the MCV Facility as unavailable for operational use (which
reduces the generation capability of the MCV Facility by approximately 100 MW)
and is assessing the duct burner issue and has begun other corrective action to
address the MDEQ's assertions. The one available duct burner was tested in April
2005 and its emissions met permitted levels due to the unique configuration of
that particular unit. The MCV Partnership disagrees with certain of the MDEQ's
assertions. The MCV Partnership filed a response to address this MDEQ letter in
July 2004. On December 13, 2004, the MDEQ informed the MCV Partnership that it
was pursuing an escalated enforcement action against the MCV Partnership
regarding the alleged violations of the MCV Facility's PTI. The MDEQ also stated
that the alleged violations are deemed federally significant and, as such,
placed the MCV Partnership on the EPA's High Priority Violators List (HPVL). The
MDEQ and the MCV Partnership are pursuing voluntary settlement of this matter,
which will satisfy state and federal requirements and remove the MCV Partnership
from the HPVL. Any such settlement is likely to involve a fine, but at this
time, the MDEQ has not stated what, if any, fine they will seek to impose. At
this time, the MCV Partnership management cannot predict the financial impact or
outcome of this issue.
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CMS Energy Corporation
On July 13, 2004, the MDEQ, Water Division, issued the MCV Facility a Notice
Letter asserting the MCV Facility violated its National Pollutant Discharge
Elimination System (NPDES) Permit by discharging heated process wastewater into
the storm water system, failure to document inspections, and other minor
infractions (alleged NPDES violations). In August 2004, the MCV Partnership
filed a response to the MDEQ letter covering the remediation for each of the
MDEQ's alleged violations. On October 17, 2005, the MDEQ, Water Bureau, issued
the MCV Partnership a Compliance Inspection report, which listed several minor
violations and concerns that needed to be addressed by the MCV Facility. This
report was the result of an inspection of the MCV Facility in September 2005,
which was conducted for compliance and review of the Storm Water Pollution
Prevention Plans (SWPPP). All items have been addressed or corrected and the MCV
Partnership has committed to updating its SWPPP by December 1, 2005. The MCV
Partnership management believes that once it files its updated SWPPP it will
have resolved all issues associated with the Notice Letter and Compliance
Inspection and does not expect any further MDEQ action on these matters.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities, which
sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges 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. 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 eight plaintiff qualifying facilities have appealed the dismissal of the
circuit court case to the Michigan Court of Appeals. The qualifying facilities
have also appealed the February 2005 MPSC order in the 2004 PSCR plan case to
the Michigan Court of Appeals, and have initiated separate legal actions in
federal district court and at the FERC concerning the energy charge calculation
issue. In June 2005, the FERC issued a notice of intent not to act on this
issue. In October 2005, the federal district court dismissed the case. We cannot
predict the outcome of the remaining appeals.
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC ROA: We cannot predict the total amount of electric supply load that
may be lost to alternative electric suppliers. As of October 2005, alternative
electric suppliers are providing 754 MW of generation service to ROA customers.
This amount represents a decrease of 14 percent compared to October 2004, and 10
percent of our total distribution load.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings.
The following chart summarizes our electric restructuring filings with the MPSC:
Year(s) Years Requested
Proceeding Filed Covered Amount Status
- ---------- ------- ------- --------- ------
Stranded Costs 2002-2004 2000-2003 $137 million(a) The MPSC ruled that we experienced zero
Stranded Costs for 2000 through 2001. The
MPSC approved recovery of $63 million in
Stranded Costs for 2002 through 2003, plus
the cost of money through the period of
collection.
Implementation 1999-2004 1997-2003 $91 million(b) The MPSC allowed $68 million for the years
Costs 1997-2001, plus the cost of money through
the period of collection. The MPSC allowed
$6 million for the years 2002-2003, plus
the cost of money through the period of
collection.
Section 10d(4) 2004 2000-2005 $628 million Application filed with the MPSC in October
Regulatory 2004.
Assets
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(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes recovery of Clean Air Act costs
through the Section 10d(4) Regulatory Asset case.
(b) Amount includes the cost of money through the year prior to the year filed.
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act
allows us to recover certain regulatory assets through deferred recovery of
annual capital expenditures in excess of depreciation levels and certain other
expenses incurred prior to and throughout the rate freeze and rate cap periods,
including the cost of money. The section also allows deferred recovery of
expenses incurred during the rate freeze and rate cap periods that result from
changes in taxes, laws, or other state or federal governmental actions. In
October 2004, we filed an application with the MPSC seeking recovery of $628
million of Section 10d(4) Regulatory Assets for the period June 2000 through
December 2005 consisting of:
- capital expenditures in excess of depreciation,
- Clean Air Act costs,
- other expenses related to changes in law or governmental action
incurred during the rate freeze and rate cap periods, and
- the associated cost of money through the period of collection.
Of the $628 million, $152 million relates to the cost of money.
As allowed by the Customer Choice Act, we accrue and defer for recovery a
portion of our Section 10d(4) Regulatory Assets. In March 2005, the MPSC Staff
filed testimony recommending the MPSC approve recovery of approximately $323
million in Section 10d(4) costs, which includes the cost of money through the
period of collection. In June 2005, the ALJ issued a proposal for decision
recommending that the MPSC approve recovery of the same Section 10d(4) costs
recommended by the MPSC Staff. However, we may have the opportunity to recover
certain costs included in our application alternatively in other cases pending
before the MPSC. We cannot predict the amount, if any, the MPSC will approve as
recoverable. At September 30, 2005, total recorded Section 10d(4) Regulatory
Assets were $201 million.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system to MTH,
a non-affiliated limited partnership whose general partner is a subsidiary of
Trans-Elect, Inc. We are in arbitration with MTH regarding property tax items
used in establishing the selling price of our electric transmission system. An
unfavorable outcome could result in a reduction of sale proceeds previously
recognized of approximately $2 million to $3 million.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to
increase our retail electric base rates. The electric rate case filing requests
an annual increase in revenues of approximately $320 million. The primary
reasons for the request are load migration to alternative electric suppliers,
increased system maintenance and improvement costs, Clean Air Act-related
expenditures, and employee pension costs. In April 2005, we filed updated debt
and equity information in this case.
In June 2005, the MPSC Staff filed its position in this case, recommending a
base rate increase of $98 million. The MPSC Staff also recommended an 11.25
percent return on equity to establish rates and recognized all of our projected
equity investment (infusions and retained earnings) in 2006. In August 2005, we
revised our request for an annual increase in revenues to approximately $197
million, and the MPSC Staff revised its recommendation to $100 million. In
October 2005, the ALJ issued a proposal for decision recommending a base rate
increase of $112 million and an 11.25 percent authorized return on equity. We
expect a final order from the MPSC in late 2005. If approved as requested, the
rate increase
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would go into effect in January 2006 and would apply to all retail electric
customers. We cannot predict the amount or timing of the rate increase, if any,
which the MPSC will approve.
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 2006 through 2007. As a result, we
have recognized an asset of $6 million for unexpired capacity and energy
contracts at September 30, 2005. As of October 2005, we expect the total premium
cost of electric capacity and energy contracts for 2005 to be approximately $8
million.
PSCR: The PSCR process is designed to allow recovery of all reasonable and
prudent power supply costs that we actually incur. In June 2005, the MPSC issued
an order that approves our 2005 PSCR plan. The 2005 PSCR charge allows us to
recover a portion of our power supply costs from commercial and industrial
customers and, subject to the overall rate caps, from other customers. The
revenues from the PSCR charges are subject to reconciliation after review of
actual costs for reasonableness and prudence. In March 2005, we submitted our
2004 PSCR reconciliation filing to the MPSC. In September 2005, we submitted our
2006 PSCR plan filing to the MPSC. Unless we receive an order from the MPSC, we
expect to self-implement this proposed 2006 PSCR charge in January 2006. We
cannot predict the outcome of these PSCR proceedings.
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 Revised FASB Interpretation No. 46. For
additional details, see Note 9, Consolidation of Variable Interest Entities.
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
cash underrecoveries of capacity and fixed energy payments as follows:
In Millions
------------------
2005 2006 2007
---- ---- ----
Estimated cash underrecoveries $56 $55 $39
Of the 2005 estimate, we expensed $43 million during the nine months ended
September 30, 2005.
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 amount that we collect from our
customers. The MCV Partnership has indicated that it may take issue with our
exercise of the regulatory out clause after September 15, 2007. We believe that
the clause is valid and fully effective, but cannot assure that it will prevail
in the event of a dispute. The MPSC's future actions on the capacity and fixed
energy payments recoverable from customers subsequent to September 15, 2007 may
affect negatively the financial performance of the MCV Partnership.
Further, 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. Natural gas prices have
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increased substantially in recent years and throughout 2005. In the third
quarter of 2005, the MCV Partnership reevaluated the economics of operating the
MCV Facility and determined that an impairment was required. We are evaluating
various alternatives in order to develop a new long-term strategy with respect
to the MCV Facility. For additional details on the impairment of the MCV
Facility, see Note 2, Asset Impairment Charges and Sales.
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 will benefit our ownership interest in the MCV Partnership.
The substantial MCV Facility fuel cost savings are first used to offset fully
the cost of replacement power. Second, $5 million annually, funded jointly by
Consumers and the MCV Partnership, are contributed to our RRP. Remaining savings
are split between the MCV Partnership and Consumers. Consumers' direct savings
are shared 50 percent with its customers in 2005 and 70 percent in 2006 and
beyond. Consumers' direct savings from the RCP, after allocating a portion to
customers, are used to offset our capacity and fixed energy underrecoveries
expense. Since the MPSC has excluded these underrecoveries from the rate making
process, we anticipate that our savings from the RCP will not affect our return
on equity used in our base rate filings.
In January 2005, Consumers and the MCV Partnership's general partners accepted
the terms of the order and 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. 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 2005. The
MCV Partnership estimates that the 1997 through 2005 tax year cases will result
in a refund to the MCV Partnership of approximately $83 million, inclusive of
interest, if the decision of the Michigan Tax Tribunal is upheld. The MCV
Partnership cannot predict the outcome of these proceedings; therefore, this
anticipated refund has not been recognized in earnings.
NUCLEAR PLANT DECOMMISSIONING: 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 on March 31, 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. Recently updated cost projections for Big Rock indicate an anticipated
decommissioning cost of $394 million in 2005 dollars.
Big Rock: In December 2000, funding of the Big Rock trust fund stopped because
the MPSC-authorized decommissioning surcharge collection period expired.
Excluding the additional nuclear fuel storage costs
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due to the DOE's failure to accept spent fuel on schedule, we are currently
projecting that the level of funds provided by the trust for Big Rock will fall
short of the amount needed to complete the decommissioning by $57 million. At
this time, we plan to provide the additional amounts needed from our corporate
funds and, subsequent to the completion in 2007 of radiological decommissioning
work, seek recovery of such expenditures at the MPSC. We cannot predict how the
MPSC will rule on our request.
Palisades: Excluding additional nuclear fuel storage costs due to the DOE's
failure to accept spent fuel on schedule, we concluded, based on the costs
estimates filed in March 2004, that the existing surcharge for Palisades needed
to be increased to $25 million annually, beginning January 1, 2006, and
continuing through 2011, our current license expiration date. In June 2004, we
filed an application with the MPSC seeking approval to increase the surcharge
for recovery of decommissioning costs related to Palisades beginning in 2006. In
September 2004, we announced that we would seek a 20-year license renewal for
Palisades. In January 2005, we filed a settlement agreement with the MPSC that
was agreed to by four of the six parties involved in the proceeding. The
settlement agreement provides for the continuation of the existing $6 million
annual decommissioning surcharge through 2011 and for the next periodic review
to be filed in March 2007. In September 2005, the MPSC approved the contested
settlement. Amounts collected from electric retail customers and deposited in
trusts, including trust earnings, are credited to a regulatory liability and
asset retirement obligation.
In March 2005, the NMC, which operates the Palisades plant, applied for a
20-year license renewal for the plant on behalf of Consumers. Certain parties
are seeking to intervene and have requested a hearing on the application. The
NRC has stated that it expects to take 22-30 months to review a license renewal
application. We expect a decision from the NRC in 2007. At this time, we cannot
determine what impact this will have on decommissioning costs or the adequacy of
funding.
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, 2005, we have recorded a
liability to the DOE of $144 million, including interest, which is payable prior
to 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.
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. On April 29, 2005, the court ruled on various cross-motions for
summary judgment previously filed by the DOE and us. The court denied the DOE's
motions to dismiss Counts I and II of the complaint and its motion seeking
recovery of a one-time fee that is due to be paid by us prior to delivery of the
spent nuclear fuel. The court, however, granted the DOE's motion to recoup the
one-time fee against any award of damages to us. The court further granted our
motion for summary judgment on liability and our motion to dismiss the DOE's
affirmative defense alleging our failure to satisfy a condition precedent. We
filed a motion for reconsideration of the portion of the Court's order dealing
with recoupment, which the Court denied. 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.
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In July 2002, Congress approved and the President signed a bill designating the
site at Yucca Mountain, Nevada, 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 $28 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. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. 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 by a combination of insurance and
a NRC indemnity totaling $544 million, and 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.
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 2003, we estimated our remaining
costs to be between $37 million and $90 million, based on 2003 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 insurance proceeds and
MPSC-approved rates. Since 2003, we have spent $14 million on remediation
activities related to the 23 sites. At September 30, 2005, we have a liability
of $34 million, net of $48 million of expenditures incurred to date, and a
regulatory asset of $62 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.
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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 for prudency in an annual
reconciliation proceeding.
The following table summarizes our GCR reconciliation filings with the MPSC.
Additional details related to the proceedings follow the table.
Gas Cost Recovery Reconciliation
Net Over-
GCR Year Date Filed Order Date recovery (a) Status
- --------- ---------- ------------- ------------ ------------------------
2003-2004 June 2004 February 2005 $31 million The net overrecovery
includes $1 million and
$5 million GCR net
overrecoveries from
prior GCR years and
interest accrued through
March 2004.
2004-2005 June 2005 Pending $2 million
(a) Net overrecoveries include refunds that we received from our suppliers,
which are required to be refunded to our customers.
GCR plan for year 2005-2006: In December 2004, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2005
through March 2006. Our request proposed using a GCR factor consisting of:
- a base GCR factor of $6.98 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future
events.
The GCR factor can be adjusted monthly, provided it remains at or below the
current ceiling price. The quarterly adjustment mechanism allows an increase in
the GCR ceiling price 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 current ceiling price for 2005 is $8.73 per mcf. Actual gas
costs and revenues will be subject to an annual reconciliation proceeding.
In June 2005, four of the five parties filed a settlement agreement; the fifth
party filed a statement of non-objection. The settlement agreement includes a
GCR ceiling price adjustment contingent upon future events.
In September 2005, we filed a motion with the MPSC seeking to reopen our GCR
plan for year 2005-2006. Since the settlement agreement entered into in June
2005, there have been substantial, unanticipated increases in the market price
for natural gas. These increases have been so large that the maximum adjustments
possible under the GCR ceiling price adjustment mechanisms included in the
settlement agreement are not adequate. Unless the maximum allowable GCR factor
is increased, we will experience a substantial GCR underrecovery for the
2005-2006 GCR year. In our filing, we have requested the MPSC to:
- increase the base GCR factor from $6.98 to $9.11 per mcf, and
- revise the GCR ceiling price adjustment mechanism increasing the
maximum GCR factor from $8.73 per mcf to $11.21 per mcf.
We are requesting the increase in the maximum allowable GCR factor be effective
as soon as possible but not later than January 1, 2006.
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On October 6, 2005, the MPSC issued an order reopening evidentiary proceedings.
The MPSC established an expedited contested case proceeding. The MPSC Staff and
intervenors filed testimony and exhibits on October 17, 2005; rebuttal testimony
occurred October 24, 2005. The case is scheduled to be submitted directly to the
Commission without the necessity of the preparation of the ALJ's proposal for
decision on November 21, 2005.
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. The
October 2004 order also required us to undertake a study to determine why our
removal costs are in excess of those of other regulated Michigan natural gas
utilities and file a report with the MPSC Staff on or before December 31, 2005.
The MPSC has directed us to file our next gas depreciation case within 90 days
after the latter of:
- the removal cost study filing, or
- the MPSC issuance of a final order in the pending case related to ARO
accounting.
The MPSC order on the pending case related to ARO accounting is expected in the
first quarter of 2006. We proposed to incorporate the results of the gas
depreciation case into gas general rates using a surcharge mechanism if the
depreciation case order was not issued concurrently with a gas general rate case
order.
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. The primary reasons for
the request are recovery of new investments, carrying costs on natural gas
inventory related to higher gas prices, system maintenance, employee benefits,
and low-income assistance. If approved, the request would add approximately 5
percent to the typical residential customer's average monthly bill. The increase
would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony on October
31, 2005. In its testimony, the MPSC Staff recommended granting interim rate
relief of $38 million.
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 and Tennessee.
CMS Energy and the other CMS Energy defendants will defend themselves vigorously
against these matters but cannot predict their outcome.
DEARBORN INDUSTRIAL GENERATION: In October 2001, Duke/Fluor Daniel (DFD)
presented DIG with a change order to their construction contract and filed an
action in Michigan state court claiming damages in
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the amount of $110 million, plus interest and costs, which DFD states represents
the cumulative amount owed by DIG for delays DFD believes DIG caused and for
prior change orders that DIG previously rejected. DFD also filed a construction
lien for the $110 million. DIG, in addition to drawing down on three letters of
credit totaling $30 million that it obtained from DFD, 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 began October 10, 2005 and is scheduled to
continue through mid-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 drill wells
it had committed to drill. A jury then awarded the plaintiffs a $7.6 million
award. Terra appealed this matter to the Michigan Court of Appeals. The Michigan
Court of Appeals reversed the trial court judgment with respect to the
appropriate measure of damages and remanded the case for a new trial on damages.
The trial judge reinstated the judgment against Terra and awarded Terra title to
the minerals. Terra appealed this judgment. The court of appeals heard arguments
on May 19, 2005 and issued an opinion on May 26, 2005 remanding the case to the
trial court for a new trial on damages. The plaintiffs filed an application for
leave to appeal with the Michigan Supreme Court. 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 will remain in effect until
completion of arbitration on the matter, to be administered by the International
Chamber of Commerce. The arbitration hearing was held in July 2005 and a
decision from the arbitration panel is expected by year-end.
IRS RULING: On August 2, 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 use this tax accounting method,
generally allowed by the IRS under section 263A of the Internal Revenue Code,
with respect to the allocation of certain corporate overheads to the tax basis
of self-constructed utility assets. Under the IRS guidance, significant issues
with respect to the application of this method remain unresolved. Accordingly,
we cannot predict the impact of this ruling on future earnings, cash flows, or
our present NOL carryforwards.
OTHER: CMS Generation does not currently expect to incur material capital costs
at its power facilities for compliance with current U.S. environmental
regulatory standards.
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.
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CMS Energy Corporation
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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4: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
CMS ENERGY CORPORATION
Senior notes $2,222 $2,175
Other long-term debt 3 225
------ ------
Total - CMS Energy Corporation 2,225 2,400
------ ------
CONSUMERS ENERGY COMPANY
First mortgage bonds 3,175 2,300
Senior notes, bank debt and other 850 1,436
Securitization bonds 378 398
------ ------
Total - Consumers Energy Company 4,403 4,134
------ ------
OTHER SUBSIDIARIES 199 208
------ ------
TOTAL PRINCIPAL AMOUNTS OUTSTANDING 6,827 6,742
Current amounts (286) (267)
Net unamortized discount (20) (31)
------ ------
Total Long-term debt $6,521 $6,444
====== ======
FINANCINGS: The following is a summary of significant long-term debt issuances
and retirements during the nine months ended September 30, 2005:
Principal Interest Rate Issue/Retirement
(In millions) (%) Date Maturity Date
------------- ------------- ---------------- --------------
DEBT ISSUANCES:
CMS ENERGY
Senior notes $ 150 6.30 January 2005 February 2012
CONSUMERS
FMB 250 5.15 January 2005 February 2017
FMB 300 5.65 March 2005 April 2020
FMB insured quarterly notes 150 5.65 April 2005 April 2035
LORB 35 Variable April 2005 April 2035
FMB 175 5.80 August 2005 September 2035
------
TOTAL $1,060
======
DEBT RETIREMENTS:
CMS ENERGY
General term notes $ 220 Various January and Various
February 2005
Senior notes 103 9.875 July through October 2007
September 2005
CONSUMERS
Long-term bank debt 60 Variable January 2005 November 2006
Long-term debt - related parties 180 9.25 January 2005 December 2029
Long-term debt - related parties 73 8.36 February 2005 December 2015
Long-term debt - related parties 124 8.20 February 2005 September 2027
Senior notes 332 6.25 April and May 2005 September 2006
Senior insured quarterly notes 141 6.50 May 2005 October 2028
------
TOTAL $1,233
======
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By the end of the first quarter of 2006, Consumers will extinguish through a
defeasance $129 million of 9 percent notes. These notes are classified on the
balance sheet as Current portion of long-term debt - related parties.
CAPITALIZATION: In April 2005, we issued 23 million shares of our common stock
at a price of $12.25 per share. We realized net proceeds of $272 million.
REGULATORY AUTHORIZATION FOR FINANCINGS: In April 2005, the FERC issued an
authorization to permit Consumers to issue up to an additional $1.0 billion
($2.0 billion in total) of long-term securities for refinancing or refunding
purposes, and up to an additional $1.0 billion ($2.5 billion in total) of
long-term securities for general corporate purposes during the period ending
June 30, 2006.
Combined with remaining availability from previously issued FERC authorizations,
Consumers can now issue up to:
- $876 million of long-term securities for refinancing or refunding
purposes,
- $1.159 billion of long-term securities for general corporate purposes,
and
- $1.935 billion of long-term FMB to be issued solely as collateral for
other long-term securities.
FMB Indenture Limitations: Irrespective of Consumers' existing FERC
authorization, their ability to issue FMB as primary obligations or as
collateral for financing is governed by certain provisions of their indenture
dated September 1, 1945 and its subsequent supplements. Due to the adverse
impact of the MCV Partnership asset impairment charge recorded in September 2005
on the net earnings coverage test in one of the governing bond-issuance
provisions of the indenture, Consumers expects their ability to issue additional
FMB will be limited to $298 million for 12 months, ending September 30, 2006.
Beyond 12 months, Consumers' ability to issue FMB in excess of $298 million is
based on achieving a two-times FMB interest coverage rate.
REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities
with banks are available at September 30, 2005:
In Millions
-----------------------------------------------------------------------------------------------------------
Outstanding
Company Expiration Date Amount of Facility Amount Borrowed Letters-of-Credit Amount Available
------- --------------- ------------------ --------------- ----------------- ----------------
CMS ENERGY May 18, 2010 $300 $ - $98 $202
CONSUMERS May 18, 2010 500 - 31 469
MCV PARTNERSHIP August 26, 2006 50 - 3 47
CMS Energy and Consumers amended their credit facilities in May 2005. The
amendments extended the terms of the agreements to 2010, reduced certain fees
and interest margins, and reduced CMS Energy's restriction on payment of common
stock dividends.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly
of leased service vehicles and office furniture. At September 30, 2005, capital
lease obligations totaled $52 million. In order to obtain permanent financing
for the MCV Facility, the MCV Partnership entered into a sale and lease back
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, 2005, finance lease obligations totaled $273 million, which
represents the third-party portion of the MCV Partnership's finance lease
obligation.
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CMS Energy Corporation
SALE OF ACCOUNTS RECEIVABLE: Under a revolving accounts receivable sales
program, we currently 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 $100 million of receivables as of
September 30, 2005 and $304 million of receivables as of December 31, 2004.
Consumers continues 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. Consumers has 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 2005 2004
- ------------------------------ ------ ------
Net cash flow as a result of accounts receivable financing $ (204) $ (247)
Collections from customers $3,782 $3,542
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, 2005,
Consumers had $163 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. For the nine months ended
September 30, 2005, we received $207 million of common stock dividends from
Consumers.
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 initial recognition and measurement provision of this
Interpretation does not apply to some guarantee contracts, such as product
warranties, derivatives, or guarantees between corporations under common
control, although disclosure of these guarantees is required.
The following table describes our guarantees at September 30, 2005:
In Millions
------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee description Date Date Obligation Amount provision(b)
- --------------------- -------- ---------- ---------- -------- ------------
Indemnifications from asset sales and
other agreements(a) Various Various $1,147 $ 1 $ -
Standby letters of credit Various Various 64 - -
Surety bonds and other indemnifications Various Various 25 - -
Other guarantees Various Various 258 - -
Subsidiary guarantee of parent debt May 2005 May 2010 99 - -
Nuclear insurance retrospective premiums Various Various 135 - -
(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 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.
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CMS Energy Corporation
(b) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
The following table provides additional information regarding our guarantees:
Guarantee Description How Guarantee Arose Events That Would Require Performance
- ------------------------------- -------------------------------- -----------------------------------------------
Indemnifications from asset Stock and asset sales agreements Findings of misrepresentation, breach of
sales and other agreements warranties, and other specific events or
circumstances
Standby letters of credit Normal operations of coal power Noncompliance with environmental regulations
plants and inadequate response to demands for
corrective action
Natural gas transportation Nonperformance
Self-insurance requirement Nonperformance
Nuclear plant closure Nonperformance
Surety bonds and other Normal operating activity, Nonperformance
indemnifications permits and license
Other guarantees Normal operating activity Nonperformance or non-payment by a subsidiary
under a related contract
Subsidiary guarantee of parent Loan agreement Non-payment by CMS Energy and CMS Enterprises
debt of obligations under the loan agreement
Nuclear insurance retrospective Normal operations of nuclear Call by NEIL and Price-Anderson Act for nuclear
premiums plants incident
In the ordinary course of business, we enter into agreements containing tax and
other indemnification provisions in connection with a variety of transactions
including transactions for the sale of subsidiaries and assets, equipment
leasing, and financing agreements. While we cannot estimate our maximum exposure
under these indemnities, we consider the probability of liability remote.
We have guaranteed payment of obligations through indemnities, surety bonds and
other guarantees of unconsolidated affiliates and related parties of $446
million at September 30, 2005. Expiration dates vary from December 2005 to
September 2027 or terminate upon payment or cancellation of the obligation. We
monitor these obligations and believe it is unlikely that we would be required
to perform or otherwise incur any material losses associated with the above
obligations.
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.
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CONTINGENTLY CONVERTIBLE SECURITIES: In September 2005, the $11.87 per share
trigger price contingency was met for our $250 million 4.50 percent contingently
convertible preferred stock and the $12.81 per share trigger price contingency
was met for our $150 million 3.375 percent contingently convertible senior
notes. The contingency was met since the price of our common stock remained at
or above the applicable trigger price for 20 of 30 consecutive trading days
ended on the last trading day of the calendar quarter. As a result, these
securities are convertible at the option of the security holders, with the
principal or par amount payable in cash, for the three months ended December 31,
2005. Once the 3.375 percent contingently convertible senior notes became
convertible, which occurred first in June 2005, they held the characteristics of
a current liability. Therefore, in June 2005, we reclassified the 3.375 percent
contingently convertible senior notes from Long-term debt to Current portion of
long-term debt, where they will remain during the period that they are
outstanding and convertible. As of October 2005, none of the security holders
have notified us of their intention to convert these securities.
5: EARNINGS PER SHARE
The following tables present the basic and diluted earnings per share
computations:
In Millions, Except Per Share Amounts
-------------------------------------
Three Months Ended September 30 2005 2004
- ------------------------------- ------ ------
EARNINGS AVAILABLE TO COMMON STOCK
Income (Loss) From Continuing Operations $ (263) $ 51
Less Preferred Dividends (2) (3)
------ ------
Income (Loss) From Continuing Operations
Available to Common Stock - Basic and Diluted $ (265) $ 48
====== ======
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
Average Shares - Basic 219.6 161.5
Add Dilutive Impact of Contingently
Convertible Securities - 3.0
Add Dilutive Stock Options and Warrants - 0.5
------ ------
Average Shares - Diluted 219.6 165.0
====== ======
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
AVAILABLE TO COMMON STOCK
Basic $(1.21) $ 0.30
Diluted $(1.21) $ 0.29
====== ======
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CMS Energy Corporation
In Millions, Except Per Share Amounts
-------------------------------------
Nine Months Ended September 30 2005 2004
- ------------------------------ ------ ------
EARNINGS AVAILABLE TO COMMON STOCK
Income (Loss) From Continuing Operations $ (81) $ 68
Less Preferred Dividends (7) (9)
------ ------
Income (Loss) From Continuing Operations
Available to Common Stock - Basic and Diluted $ (88) $ 59
====== ======
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
Average Shares - Basic 211.0 161.3
Add Dilutive Impact of Contingently
Convertible Securities - 3.0
Add Dilutive Stock Options and Warrants - 0.5
------ ------
Average Shares - Diluted 211.0 164.8
====== ======
EARNINGS (LOSS) PER AVERAGE COMMON SHARE
AVAILABLE TO COMMON STOCK
Basic $(0.42) $ 0.36
Diluted $(0.42) $ 0.36
====== ======
Contingently Convertible Securities: Due to antidilution, there was no impact to
diluted EPS from our contingently convertible securities for the three and nine
months ended September 30, 2005. 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.
Stock Options and Warrants: 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. For the three and nine
months ended September 30, 2004, since the exercise price was greater than the
average market price of our common stock, there was no impact to diluted EPS for
options and warrants to purchase 4.7 million shares of common stock.
Convertible Debentures: Due to antidilution, the following impacts from our 7.75
percent convertible subordinated debentures were not reflected in diluted EPS:
- an additional 4.2 million shares of common stock for the three and
nine months ended September 30, 2005 and the three and nine months
ended September 30, 2004,
- a $2 million reduction of interest expense, net of tax, for the three
months ended September 30, 2005 and the three months ended September
30, 2004, and
- a $7 million reduction of interest expense, net of tax, for the nine
months ended September 30, 2005 and the nine months ended September
30, 2004.
We can revoke the conversion rights if certain conditions are met.
In April 2005, we issued 23 million shares of our common stock. For additional
details, see Note 4, Financings and Capitalization.
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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.
The cost and fair value of our long-term financial instruments are as follows:
In Millions
-------------------------------------------------------------
September 30, 2005 December 31, 2004
----------------------------- -----------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain (Loss) Cost Value Gain (Loss)
------ ------ ----------- ------ ------ -----------
Long-term debt,
including current amounts $6,807 $7,183 $(376) $6,711 $7,052 $(341)
Long-term debt - related parties,
including current amounts 307 284 23 684 653 31
Available-for-sale securities:
SERP:
Equity securities 34 48 14 33 47 14
Debt securities 18 18 - 20 20 -
Nuclear decommissioning investments:
Equity securities 135 252 117 136 262 126
Debt securities 288 293 5 291 302 11
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, currency exchange
rates, and equity security prices. We may use various contracts to manage these
risks, including swaps, options, futures, and forward contracts. We enter into
these risk management contracts using established policies and procedures, under
the direction of both 1) an executive oversight committee consisting of senior
management representatives, and 2) a risk committee consisting of business-unit
managers. Our intention is that any gains or losses on these contracts will be
offset by an opposite movement in the value of the item at risk. These contracts
are classified as either non-trading or trading.
These contracts contain credit risk if the counterparties, including financial
institutions and energy marketers, fail to perform under the agreements. We
reduce this risk through established credit policies, which include performing
financial credit reviews of our counterparties. Determination of our
counterparties' credit quality is based upon a number of factors, including
credit ratings, disclosed financial condition, and collateral requirements.
Where contractual terms permit, we use standard agreements that allow us to net
positive and negative exposures associated with the same counterparty. Based on
these policies, our current exposures, and our credit reserves, we do not expect
a material adverse effect on our financial position or earnings as a result of
counterparty nonperformance.
Contracts used 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 accounted for as a derivative instrument, it is recorded on the balance sheet
as an asset or a liability, at its fair value. The value recorded is then
adjusted quarterly to reflect any change in the market value of the contract, a
practice known as marking the contract to market. If a derivative qualifies for
cash flow hedge accounting treatment, the changes in fair value (gains or
losses) are reported in Other Comprehensive Income; otherwise, the changes are
reported in earnings.
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CMS Energy Corporation
For a derivative instrument to qualify for hedge accounting:
- the relationship between the derivative instrument and the item being
hedged must be formally documented at inception,
- the derivative instrument must be highly effective in offsetting the
hedged item's cash flows or changes in fair value, and
- if hedging a forecasted transaction, the forecasted transaction must
be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or
losses are recorded in Other Comprehensive Income, those gains and 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 as of such date recorded in Accumulated Other Comprehensive
Income 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 recorded when the forecasted transaction affects earnings. The
ineffective portion, if any, of all hedges is recognized in earnings.
We use quoted market prices, prices obtained from external sources (i.e.,
brokers and banks), and mathematical valuation models to determine the fair
value of our derivatives. For some derivatives, the time period of the contracts
may extend longer than the time periods for which market quotations for such
contracts are available. Thus, in order to calculate fair value, mathematical
models are developed to determine various inputs into the calculation, including
price and other variables. Cash returns actually realized from these commitments
may vary, either positively or negatively, from the results estimated by
applying mathematical models. As part of determining the fair value of our
derivatives, we maintain reserves, if necessary, for credit risks based on the
financial condition of counterparties.
The majority of our commodity purchase or sale contracts are not subject to
derivative accounting under SFAS No. 133 because 1) they do not have a notional
amount identified in the contract, 2) they qualify for the normal purchases and
sales exception, or 3) 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 that 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 and the significant transportation costs that would be incurred to
deliver the power to the closest active energy market (the Cinergy hub in Ohio).
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 to our financial
statements. For our electric capacity and energy contracts, we believe that we
will be able to apply the normal purchases and sales exception to the majority
of these contracts (including the MCV PPA), and, therefore, will not be required
to mark these contracts to market.
The MISO began operating the Midwest Energy Market on April 1, 2005. Through
operation of the Midwest Energy Market, the MISO centrally dispatches
electricity and transmission service throughout the Midwest and provides
day-ahead and real-time energy market information. At this time, we believe that
the commencement of this market does not constitute 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 the potential for an active energy market in Michigan.
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CMS Energy Corporation
Derivative accounting is required for certain contracts used to limit our
exposure to interest rate risk, commodity price risk, and foreign exchange risk.
The following table summarizes our derivative instruments:
In Millions
-------------------------------------------------------
September 30, 2005 December 31, 2004
-------------------------- --------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- ---------------------- ---- ----- ----------- ---- ----- -----------
Non-trading:
Interest rate risk contracts $ - $ - $ - $ - $ (1) $ (1)
Gas supply option contracts 2 6 4 2 - (2)
FTRs - 1 1 - - -
Derivative contracts associated with
the MCV Partnership:
Long-term gas contracts - 298 298 - 56 56
Gas futures and swaps - 297 297 - 64 64
CMS ERM contracts:
Non-trading electric / gas contracts - (410) (410) - (199) (199)
Trading electric / gas contracts (3) 428 431 (4) 201 205
Derivative contracts associated with
equity investments in:
Shuweihat - (25) (25) - (25) (25)
Taweelah (35) (21) 14 (35) (24) 11
Jorf Lasfar - (10) (10) - (11) (11)
The fair value of our interest rate risk contracts, gas supply option contracts,
FTRs, and the derivative contracts associated with the MCV Partnership is
included in Derivative instruments, Other assets, or Other liabilities on our
Consolidated Balance Sheets. The fair value of the derivative contracts held by
CMS ERM is included 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.
INTEREST RATE RISK CONTRACTS: We use interest rate contracts, such as swaps and
collars, to hedge the risk associated with forecasted interest payments on
variable-rate debt and to reduce the impact of interest rate fluctuations. As of
September 30, 2005, we held a floating-to-fixed interest rate swap and an
interest rate collar, effectively hedging long-term variable-rate debt with a
notional amount of $24 million. The notional amount reflects the principal
amount of variable-rate debt being fixed.
For those interest rate contracts that do not qualify for hedge accounting
treatment, we record changes in fair value in earnings as part of Other income.
For interest rate contracts designated as cash flow hedges, we record changes in
the fair value of these contracts in Other Comprehensive Income. There was no
ineffectiveness associated with any of the interest rate contracts that
qualified for cash flow hedge accounting treatment. At September 30, 2005, we
have recorded an unrealized loss of less than $1 million, net of tax, in
Accumulated other comprehensive loss related to these cash flow hedges. We
expect to reclassify this amount as a decrease to earnings during the next 12
months, primarily to offset the variable-rate interest expense on hedged debt.
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. 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
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CMS Energy Corporation
earnings and recorded on the balance sheet as a regulatory asset or liability as
part of the GCR process. At September 30, 2005, we had purchased fixed-priced
weather-based gas supply call options and had sold fixed-priced gas supply put
options. We had not purchased any fixed-priced gas supply call options.
FTRS: As part 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.
DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: Long-term gas
contracts: The MCV Partnership uses long-term gas contracts to purchase natural
gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership
believes that certain of these contracts qualify as normal purchases under SFAS
No. 133. Accordingly, these contracts are not recognized at fair value on our
Consolidated Balance Sheets at September 30, 2005.
The MCV Partnership also held certain long-term gas contracts that did not
qualify as normal purchases at September 30, 2005, because these contracts
contained volume optionality. In addition, as a result of implementing the RCP
in January 2005, a significant portion of long-term gas contracts no longer
qualify as normal purchases, because the gas will not be consumed as fuel for
electric production. 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, 2005, we recorded a $242 million gain
associated with the increase in fair value of these long-term gas contracts.
This gain is included in the total Fuel costs mark-to-market at MCV on our
Consolidated Statements of Income. As a result of mark-to-market gains, we have
recorded derivative assets totaling $298 million associated with the fair value
of long-term gas contracts on our Consolidated Balance Sheets. 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. The majority of these derivative assets are expected to reverse
through earnings during 2005 and 2006 as the gas is purchased, with the
remainder reversing between 2007 and 2011. For further details on the RCP, see
Note 3, Contingencies, "Other Consumers' Electric Utility Contingencies - The
Midland Cogeneration Venture."
Gas Futures and Swaps: The MCV Partnership enters into natural gas futures
contracts, option contracts, and over-the-counter swap transactions in order to
hedge against unfavorable changes in the market price of natural gas in future
months when gas is expected to be needed. These financial instruments are used
principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements. At September 30, 2005, the MCV
Partnership only held natural gas futures and swaps.
The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. There was no ineffectiveness associated with any of these
cash flow hedges. At September 30, 2005, we have recorded a cumulative net gain
of $57 million, net of tax, in Accumulated other comprehensive loss relating to
our proportionate share of the cash flow hedges held by the MCV Partnership.
This balance represents natural gas futures, options, and swaps with maturities
ranging from October 2005 to December 2009, of which $15 million of this gain,
net of tax, is expected to be reclassified as an increase to earnings during the
next 12 months as the contracts settle, offsetting the costs of gas purchases.
The MCV Partnership also holds natural gas futures and swap contracts to manage
price risk by fixing the price to be paid for natural gas on some of its
long-term gas contracts. Prior to the implementation of the RCP, these futures
and swap contracts were accounted for as cash flow hedges. Since the RCP was
implemented in January 2005, these instruments no longer qualify for cash flow
hedge accounting and any
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changes in their fair value have been recorded in earnings each quarter. For the
nine months ended September 30, 2005, we recorded a $125 million gain associated
with the increase in fair value of these instruments. This gain is included in
the total Fuel costs mark-to-market at MCV on our Consolidated Statements of
Income. As a result of mark-to-market gains, we have recorded derivative assets
totaling $125 million associated with the fair value of these instruments on our
Consolidated Balance Sheets, which is included in the Gas futures and swaps
amount in the Derivative Instruments table above. 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. The
majority of these derivative assets are expected to be realized during 2005 and
2006 as the futures and swap contracts settle, with the remainder to be realized
during 2007. For further details on the RCP, see Note 3, Contingencies, "Other
Consumers' Electric Utility Contingencies - The Midland Cogeneration Venture."
The MCV Partnership also engages in cost mitigation activities to offset fixed
charges incurred in operating the MCV Facility. These cost mitigation activities
may include the use of futures and options contracts to purchase and/or sell
natural gas to maximize the use of the transportation and storage contracts when
it is determined that they will not be needed for the MCV Facility operation.
Although these cost mitigation activities do serve to offset the fixed monthly
charges, these activities are not considered a normal course of business for the
MCV Partnership and do not qualify as hedges. Therefore, the mark-to-market
gains and losses from these cost mitigation activities are recorded in earnings
each quarter. For the nine months ended September 30, 2005, we recorded a $4
million loss associated with the decrease in fair value of futures used in these
cost mitigation activities.
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 forward contracts for the purchase and sale of electricity
and natural gas that result in physical delivery of the commodity at contractual
prices. These contracts are generally long-term in nature and are classified as
non-trading. CMS ERM also uses various financial instruments, such as swaps,
options, and futures, to manage the commodity price risks associated with its
forward purchase and sales contracts as well as generation assets owned by CMS
Energy or its subsidiaries. These financial contracts are classified as trading
activities.
Non-trading and trading contracts that meet the definition of a derivative under
SFAS No. 133 are recorded as assets or liabilities in the financial statements
at the fair value of the contracts. Gains or losses arising from changes in fair
value of these contracts are recognized in earnings as a component of Operating
Revenue in the period in which the changes occur. Gains and losses on trading
contracts 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 (i.e., on an accrual basis).
DERIVATIVE CONTRACTS ASSOCIATED WITH EQUITY INVESTMENTS: At September 30, 2005,
some of our equity method investees held 1) interest rate contracts that hedged
the risk associated with variable-rate debt and 2) foreign exchange contracts
that hedged the foreign currency risk associated with payments to be made under
operating and maintenance service agreements. The accounting for these
instruments depends on whether they qualify for cash flow hedge accounting
treatment. For the contracts that qualify as cash flow hedges, we record our
proportionate share of the change in fair value of these contracts in Other
Comprehensive Income. For those contracts that do not qualify as cash flow
hedges, we record our proportionate share of the change in fair value of these
contracts in Earnings from Equity Method Investees.
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CMS Energy Corporation
FOREIGN EXCHANGE DERIVATIVES: In the past, we have used forward exchange and
option contracts to hedge the equity value relating to investments in foreign
operations. These contracts limited 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, 2005, 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, 2005, our total
foreign currency translation adjustment was a net loss of $307 million, which
included a net hedging loss of $26 million, net of tax, related to settled
contracts.
7: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after June 30,
2003,
- a defined company contribution plan for employees hired on or after
September 1, 2005,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) plan,
- benefits to a select group of management under 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.
On September 1, 2005, we implemented the Defined Company Contribution Plan. The
Defined Company Contribution Plan provides an employer contribution of 5 percent
of base pay to the existing Employees' Savings Plan. No employee contribution is
required to receive the plan's employer contribution. All employees hired on and
after September 1, 2005 participate in this plan as part of their retirement
benefit program. Cash balance pension plan participants also participate in the
Defined Company Contribution Plan on September 1, 2005. Additional pay credits
under the cash balance pension plan were discontinued as of that date. The
Defined Company Contribution Plan cost for the nine months ended September 30,
2005 was less than $1 million.
On January 1, 2005, we resumed the employer's match in CMS Energy Stock on our
401(k) Savings Plan. On September 1, 2005, employees enrolled in the company's
401(k) Savings Plan had their employer match increased from 50 percent to 60
percent on eligible contributions up to the first six percent of an employee's
wages. The total 401(k) Savings Plan cost for the nine months ended September
30, 2005 was $9 million.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was
signed into law in December 2003. The Act establishes a prescription drug
benefit under Medicare (Medicare Part D), and a federal subsidy, which is
tax-exempt, to sponsors of retiree health care benefit plans that provide a
benefit that is actuarially equivalent to Medicare Part D. We believe our plan
is actuarially equivalent to Medicare Part D.
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CMS Energy Corporation
Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
--------------------------------------
Pension
--------------------------------------
September 30 Three Months Ended Nine Months Ended
- ------------ ------------------ -----------------
2005 2004 2005 2004
---- ---- ---- ----
Service cost $ 9 $ 10 $ 34 $ 29
Interest expense 15 17 64 53
Expected return on plan assets (17) (26) (80) (80)
Amortization of:
Net loss 11 3 25 10
Prior service cost 1 1 5 4
---- ---- ---- ----
Net periodic pension cost $ 19 $ 5 $ 48 $ 16
==== ==== ==== ====
In Millions
--------------------------------------
OPEB
--------------------------------------
September 30 Three Months Ended Nine Months Ended
- ------------ ------------------ -----------------
2005 2004 2005 2004
---- ---- ---- ----
Service cost $ 6 $ 5 $ 17 $ 15
Interest expense 15 14 47 43
Expected return on plan assets (14) (12) (42) (36)
Amortization of:
Net loss 6 3 15 8
Prior service cost (3) (2) (7) (7)
---- ---- ---- ----
Net periodic postretirement
benefit cost $ 10 $ 8 $ 30 $ 23
==== ==== ==== ====
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 nine
months ended September 30, 2005 was less than $1 million.
We remeasured our Pension and OPEB obligations as of April 30, 2005 to
incorporate the effects of the collective bargaining agreement reached between
the Utility Workers Union of America and Consumers. The Pension plan
remeasurement increased our ABO by $127 million. Net periodic pension cost is
expected to increase $14 million for 2005.
The Pension plan remeasurement resulted in an unfunded ABO of $208 million. The
unfunded ABO is the amount by which the ABO exceeds the fair value of the plan
assets. SFAS No. 87 states that the pension liability shown on the balance sheet
must be at least equal to the unfunded ABO. As such, we increased our additional
minimum liability by $145 million to $564 million at June 30, 2005. Consistent
with MPSC guidance, Consumers recognized the cost of its minimum pension
liability adjustment as a regulatory asset. This adjustment increased our
regulatory assets by $94 million and intangible assets by $38 million and
reduced Accumulated other comprehensive loss by $9 million (net of income
taxes).
The OPEB plan remeasurement increased our accumulated postretirement benefit
obligation by $50 million, with an expected total increase in benefit costs of
$3 million for 2005.
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CMS Energy Corporation
8: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: 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. For our
regulated utility, as required by SFAS No. 71, we account for the implementation
of this standard by recording regulatory assets and liabilities instead of a
cumulative effect of a change in accounting principle.
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 $22 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. 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.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
September 30, 2005 In Millions
- -----------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- --------------- ---------- ----------------- -----
Palisades-decommission plant site 1972 Palisades nuclear plant $537
Big Rock-decommission plant site 1962 Big Rock nuclear plant 18
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 --
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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CMS Energy Corporation
In Millions
------------------------------------------------------------------
ARO ARO
Liability Cash flow Liability
ARO Description 12/31/04 Incurred Settled Accretion Revisions 9/30/05
- --------------- --------- -------- ------- --------- --------- ---------
Palisades-decommission $350 $ - $ - $19 $ - $369
Big Rock-decommission 30 - (33) 11 - 8
JHCampbell intake line - - - - - -
Coal ash disposal areas 54 - (3) 4 - 55
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 2 - (1) - - 1
---- --- ---- --- --- ----
Total $439 $ - $(37) $34 $ - $436
==== === ==== === === ====
On October 14, 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. Utilities
filed responses to the Order in March 2005; the MPSC Staff and intervenors filed
responses in May 2005; a proposal for decision is expected in December 2005. We
consider the proceeding as involving a clarification of accounting and reporting
issues that relate to all Michigan utilities. We cannot predict the outcome of
the proceeding.
9: 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. Net income
from these investments included undistributed earnings of $5 million for the
three months ended September 30, 2005 and $13 million for the three months ended
September 30, 2004 and $21 million for the nine months ended September 30, 2005
and $57 million for the nine months ended September 30, 2004.
The most significant of these investments are:
- our 50 percent interest in Jorf Lasfar, and
- our 40 percent interest in Taweelah.
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CMS Energy Corporation
Summarized financial information for these equity method investments is as
follows:
Income Statement Data
In Millions
--------------------------------------
JORF LASFAR Three Months Ended Nine Months Ended
- ----------- ------------------ -----------------
September 30 2005 2004 2005 2004
- ------------ ---- ---- ----- -----
Operating revenue $123 $120 $ 382 $ 332
Operating expenses (82) (82) (255) (203)
---- ---- ----- -----
Operating income 41 38 127 129
Other expense, net (16) (13) (44) (42)
---- ---- ----- -----
Net income $ 25 $ 25 $ 83 $ 87
==== ==== ===== =====
Income Statement Data
In Millions
--------------------------------------
TAWEELAH Three Months Ended Nine Months Ended
- ----------- ------------------ -----------------
September 30 2005 2004 2005 2004
- ------------ ---- ---- ---- ----
Operating revenue $ 27 $ 26 $ 77 $ 74
Operating expenses (9) (8) (28) (30)
---- ---- ---- ----
Operating income 18 18 49 44
Other income (expense), net 4 (28) (20) (20)
---- ---- ---- ----
Net income (loss) $ 22 $(10) $ 29 $ 24
==== ==== ==== ====
10: 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 three
reportable segments: electric utility, gas utility, and enterprises.
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CMS Energy Corporation
The "Other" segment includes corporate interest and other, discontinued
operations, and the cumulative effect of accounting changes. The following table
shows our financial information by reportable segment:
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2005 2004 2005 2004
- ------------ ------ ------ ------ ------
Operating Revenue
Electric utility $ 793 $ 704 $2,065 $1,945
Gas utility 219 171 1,566 1,376
Enterprises 323 188 790 589
------ ------ ------ ------
Total Operating Revenue $1,335 $1,063 $4,421 $3,910
====== ====== ====== ======
Net Income (Loss)
Available to Common
Stockholders
Electric utility $ 62 $ 49 $ 141 $ 124
Gas utility (16) (11) 39 46
Enterprises (260) 59 (126) 36
Other (51) (41) (142) (143)
------ ------ ------ ------
Total Net Income (Loss)
Available to Common
Stockholders $ (265) $ 56 $ (88) $ 63
====== ====== ====== ======
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Assets
Electric utility (a) $ 7,584 $ 7,289
Gas utility (a) 3,650 3,187
Enterprises 4,536 4,980
Other 345 416
------- -------
Total Assets $16,115 $15,872
======= =======
(a) Amounts include a portion of our other common assets attributable to both
the electric and gas utility businesses.
11: CONSOLIDATION OF VARIABLE INTEREST ENTITIES
We are the primary beneficiary of both the MCV Partnership and the FMLP. We have
a 49 percent partnership interest in the MCV Partnership and a 46.4 percent
partnership interest in the FMLP. Consumers is the primary purchaser of power
from the MCV Partnership through a long-term power purchase agreement. The FMLP
holds a 75.5 percent lessor interest in the MCV Facility, which results in
Consumers holding a 35 percent lessor interest in the MCV Facility.
Collectively, these interests make us the primary beneficiary of these entities.
Therefore, we consolidated these partnerships into our consolidated financial
statements for all periods presented. These partnerships have third-party
obligations totaling $480 million at September 30, 2005. Property, plant, and
equipment serving as collateral for these obligations has a carrying value of
$219 million at September 30, 2005. The creditors of these partnerships do not
have recourse to the general credit of CMS Energy.
We are the primary beneficiary of three other variable interest entities. We
have 50 percent partnership interests each in the T.E.S. Filer City Station
Limited Partnership, the Grayling Generating Station Limited
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CMS Energy Corporation
Partnership, and the Genesee Power Station Limited Partnership. Additionally, we
have operating and management contracts and are the primary purchaser of power
from each partnership through long-term power purchase agreements. Collectively,
these interests make us the primary beneficiary as defined by the
Interpretation. Therefore, we consolidated these partnerships into our
consolidated financial statements for all periods presented. These partnerships
have third-party obligations totaling $109 million at September 30, 2005.
Property, plant, and equipment serving as collateral for these obligations has a
carrying value of $164 million at September 30, 2005. Other than outstanding
letters of credit and guarantees of $5 million, the creditors of these
partnerships do not have recourse to the general credit of CMS Energy.
Additionally, we hold interests in variable interest entities in which we are
not the primary beneficiary. The following chart details our involvement in
these entities at September 30, 2005:
Name Investment Operating Total
(Ownership Nature of the Involvement Balance Agreement with Generating
Interest) Entity Country Date (In Millions) CMS Energy Capacity
- --------- ------------- ------------ ----------- ------------- -------------- ----------
Taweelah United Arab
(40%) Generator Emirates 1999 $ 76 Yes 777 MW
Jubail (25%) Generator Saudi Arabia 2001 $ 1 Yes 250 MW
Shuweihat United Arab
(20%) Generator Emirates 2001 $ 39 Yes 1,500 MW
---- --------
Total $116 2,527 MW
==== ========
Our maximum exposure to loss through our interests in these variable interest
entities is limited to our investment balance of $116 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$47 million.
12: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FSP 109-2, ACCOUNTING AND DISCLOSURE GUIDANCE FOR THE FOREIGN EARNINGS
REPATRIATION PROVISION WITHIN THE AMERICAN JOBS CREATION ACT OF 2004: The
American Jobs Creation Act of 2004 creates a one-year opportunity to receive a
tax benefit for U.S. corporations that reinvest dividends from controlled
foreign corporations in the U.S. in a 12-month period (calendar year 2005 for
CMS Energy). In September 2005, we decided on a plan to repatriate $33 million
of foreign earnings during the remainder of 2005. Historically, we recorded
deferred taxes on these earnings. Since this planned repatriation is expected to
qualify for the tax benefit, we reversed $10 million of our deferred tax
liability. This adjustment was recorded as a component of income from continuing
operations in the third quarter of 2005.
We may repatriate additional amounts that may qualify for the repatriation tax
benefit during the remainder of 2005. If successful, our current estimate is
that additional amounts could range between $30 million and $180 million. The
amount of additional repatriation remains uncertain because it is based on
future foreign subsidiary operations, cash flows, financings, and repatriation
limitations. This potential additional repatriation could reduce our recorded
deferred tax liability by $9 million to $23 million. We expect to be in a
position to finalize our assessment regarding any potential repatriation, which
may be higher or lower, in the fourth quarter of 2005.
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CMS Energy Corporation
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: This Statement 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 amount over the vesting period of
the awards. This Statement also clarifies and expands SFAS No. 123's guidance in
several areas, including measuring fair value, classifying an award as equity or
as a liability, and attributing compensation cost to reporting periods.
This Statement amends SFAS No. 95, Statement of Cash Flows, to require that
excess tax benefits related to the excess of the tax-deductible amount over the
compensation cost recognized be classified as cash inflows from financing
activities rather than as a reduction of taxes paid in operating activities.
Excess tax benefits are recorded as adjustments to additional paid-in capital.
This Statement is effective for us as of the beginning of 2006. We adopted the
fair value method of accounting for share-based awards effective December 2002.
Therefore, we do not expect this statement to have a significant impact on our
results of operations when it becomes effective.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarifies 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 that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and
(or) method of settlement. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. The fair value of a
liability for the conditional asset retirement obligation should be recognized
when incurred. This Interpretation also clarifies when an entity would have
sufficient information to estimate reasonably the fair value of an asset
retirement obligation. For us, this Interpretation is effective no later than
December 31, 2005. We are in the process of determining the impact this
Interpretation will have on our financial statements upon adoption.
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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, 2004.
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, the largest segment of which is the automotive industry.
We manage our business by the nature of services each provides. We 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 transmission and
storage, and other energy related services. Our businesses are affected
primarily by:
- weather, especially during the traditional heating and cooling
seasons,
- economic conditions,
- regulation and regulatory issues,
- energy commodity prices,
- interest rates, and
- our debt credit rating.
During the past two years, our business strategy has involved improving our
balance sheet and maintaining focus on our core strength: utility operations and
service. Going forward, our business plan of "building on the basics" will focus
on improving our credit ratings, growing earnings, and positioning us to make
new investments consistent with our strengths.
Although we are looking ahead to business opportunities, the future holds
important challenges for us. The MCV Partnership reevaluated the economics of
operating the MCV Facility and determined that an impairment charge of $1.159
billion was required in September 2005. After accounting for minority interest
and income tax impacts, our third quarter 2005 net income was reduced by $369
million. We further reduced our third quarter 2005 net income by $16 million by
impairing certain other assets on our Consolidated Balance Sheets related to the
MCV Partnership. We are evaluating various alternatives in order to develop a
new long-term strategy with respect to the MCV Facility. For additional details
regarding the impairment, see Note 2, Asset Impairment Charges.
We continue to be challenged by the substantial increase in natural gas prices.
Prior to Hurricane Katrina in August 2005, NYMEX forward natural gas prices
through 2010 were approximately $2 per mcf higher than they were at year-end
2004. The effects of this summer's hurricanes, combined with tight natural gas
supplies, have caused natural gas prices to increase even further. Although our
natural gas purchases are recoverable from our customers, as gas prices
increase, the amount we pay for natural gas stored as inventory will require
additional liquidity due to the timing of the cost recoveries from our
customers. We have requested authority from the MPSC to recover the gas cost
increases experienced by the gas
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Consumers Energy Company
utility. As of October 2005, our gas storage facilities are full and
approximately 83 percent of our gas purchase requirements for the 2005-2006
heating season are under fixed price contracts.
Our electric utility customer base includes a mix of residential, commercial,
and diversified industrial customers. A sluggish Michigan economy has been
hurting our industrial sales. Recent negative developments in Michigan's
automotive industry, our largest industrial segment, could have long-term
impacts on our commercial and industrial customer base.
Additionally, Michigan's Customer Choice Act allows our electric customers to
buy electric generation service from an alternative electric supplier. As of
October 2005, alternative electric suppliers are providing 754 MW of generation
service to ROA customers. This is, however, down from 877 MW in October 2004, a
decrease of 14 percent. We expect this trend down to continue through year end,
but cannot predict future load loss.
We are focused on growing the equity base of our company and refinancing our
debt to reduce interest rate costs. In 2005, we retired higher-interest rate
debt through the use of proceeds from the issuance of $875 million of FMB. We
also received cash contributions from CMS Energy of $550 million in 2005. By the
end of the first quarter of 2006, we will extinguish through a defeasance $129
million of 9 percent notes. These efforts, and others, are designed to lead us
to be a strong, reliable utility company that will be poised to take advantage
of opportunities for further growth.
FORWARD-LOOKING STATEMENTS AND RISK FACTORS
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 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:
- capital and financial market conditions, including the price of CMS
Energy Common Stock and the effect of such market conditions on the
Pension Plan, interest rates, and access to the capital markets as
well as 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,
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Consumers Energy Company
- 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 future Stranded Costs incurred due to customers
choosing alternative energy suppliers,
- recovery of Clean Air Act costs and other environmental and
safety-related expenditures,
- power supply and natural gas supply costs when oil prices
and other fuel prices are rapidly increasing,
- timely recognition in rates of additional equity investments
in Consumers, and
- adequate and timely recovery of additional electric and gas
rate-based investments,
- the impact of adverse natural gas prices on the MCV Partnership and
FMLP investments, regulatory decisions that limit recovery of capacity
and fixed energy payments, and our ability to develop a new long-term
strategy with respect to the MCV Facility,
- 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 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 gas customers due
to high natural gas prices,
- potential adverse impacts of the new Midwest Energy Market upon power
supply and transmission costs,
- 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, 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,
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Consumers Energy Company
- changes in financial or regulatory accounting principles or policies,
- changes in tax laws or new IRS interpretations of existing tax laws,
- outcome, cost, and other effects of legal and administrative
proceedings, settlements, investigations and claims,
- 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,
- 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, and many of which
are beyond our control.
For additional information regarding these and other uncertainties, see Note 3,
Contingencies.
RESULTS OF OPERATIONS
NET INCOME AVAILABLE TO COMMON STOCKHOLDER
In Millions
---------------------
THREE MONTHS ENDED SEPTEMBER 30 2005 2004 CHANGE
- ------------------------------- ----- ---- ------
Electric $ 62 $ 49 $ 13
Gas (16) (11) (5)
Other (Includes MCV Partnership interest) (322) (4) (318)
----- ---- -----
Net income (loss) available to common stockholder $(276) $ 34 $(310)
===== ==== =====
For the three months ended September 30, 2005, our net loss available to our
common stockholder was $276 million, compared to $34 million of net income
available to our common stockholder for the three months ended September 30,
2004. The decrease is primarily due to an 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 decrease also reflects a
reduction in net income from our gas utility, as higher operating and
maintenance costs exceeded the benefits derived from increased deliveries and
the increase in revenue resulting from the gas rates surcharge authorized by the
MPSC in October of 2004. Partially offsetting these losses is an increase in the
fair value of certain long-term gas contracts and financial hedges at the MCV
Partnership, and higher earnings at our electric utility primarily due to
weather-driven higher than normal residential electric utility sales and the
collection of an electric surcharge related to the recovery of costs incurred in
the transition to customer choice.
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Consumers Energy Company
Specific changes to net income (loss) available to our common stockholder for
the three months ended September 30, 2005 versus the same period in 2004 are:
In Millions
-----------
- - decrease in earnings related to our ownership interest in the
MCV partnership due to an impairment charge to property,
plant, and equipment to reflect the excess of the carrying
value over the estimated fair values of the assets, $(385)
- - decrease in earnings due to increased operating expenses
primarily due to higher depreciation and amortization
expense, higher pension and benefit expense, and higher
underrecovery expense related to the MCV PPA, offset
partially by our direct savings from the RCP, (21)
- - decrease in earnings due to an underrecovery of power supply
revenue primarily due to non-recoverable power supply costs
related to capped customers, (20)
- - increase in earnings from our ownership interest in the MCV
Partnership primarily due to the increase in fair value of
certain long-term gas contracts and financial hedges (the
MPSC's approval of the RCP resulted in the MCV Partnership
recognizing the increase in fair value of additional gas
contracts beginning January 2005), 67
- - increase in electric delivery revenue due to warmer weather
and increased surcharge revenue, 32
- - increase in earnings due to lower fixed charges, 5
- - increase in electric utility earnings due to the return on
capital expenditures in excess of our depreciation base as
allowed by the Customer Choice Act, 5
- - increase in earnings due to lower general taxes and other
income, and 4
- - increase in gas delivery revenue due to higher deliveries and
the MPSC's October 2004 final gas rate order. 3
-----
Total Change $(310)
=====
In Millions
----------------------
Nine months ended September 30 2005 2004 Change
- ------------------------------ ------ ---- ------
Electric $ 141 $124 $ 17
Gas 39 46 (7)
Other (Includes MCV Partnership interest) (267) (9) (258)
----- ---- -----
Net income (loss) available to common stockholder $ (87) $161 $(248)
===== ==== =====
For the nine months ended September 30, 2005, our net loss available to our
common stockholder was $87 million, compared to $161 million of net income
available to our common stockholder for the nine months ended September 30,
2004. The decrease is primarily due to an 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 decrease also
reflects a reduction in net income at our gas utility due to higher operating
costs and depreciation expenses. Partially offsetting these losses is an
increase in the fair value of certain long-term gas contracts and financial
hedges at the MCV Partnership, and the positive impact at our electric utility
due to an increase in the collection of an electric surcharge related to the
recovery of costs incurred in the transition to customer choice, increased
regulatory return on capital expenditures,
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Consumers Energy Company
and weather driven higher than normal residential electric sales.
Specific changes to net income (loss) available to our common stockholder for
the nine months ended September 30, 2005 versus the same period in 2004 are:
In Millions
-----------
- - decrease in earnings related to our ownership interest in the
MCV partnership due to an impairment charge to property,
plant, and equipment to reflect the excess of the carrying
value over the estimated fair values of these assets, $(385)
- - decrease in earnings due to increased operating expenses
primarily due to higher depreciation and amortization
expense, higher pension and benefit expense, and higher
underrecovery expense related to the MCV PPA, offset
partially by our direct savings from the RCP, (51)
- - decrease in earnings due to an underrecovery of power supply
revenue primarily due to non-recoverable power supply costs
related to capped customers, (27)
- - increase in earnings from our ownership interest in the MCV
Partnership primarily due to the increase in fair value of
certain long-term gas contracts and financial hedges (the
MPSC's approval of the RCP resulted in the MCV Partnership
recognizing the increase in fair value of additional gas
contracts beginning January 2005), 120
- - increase in electric delivery revenue due to warmer weather
and increased surcharge revenue, 57
- - increase in gas delivery revenue due to the MPSC's October
2004 final gas rate order, 16
- - increase in electric utility earnings due to the return on
capital expenditures in excess of our depreciation base as
allowed by the Customer Choice Act, and 13
- - increase in earnings due to lower fixed charges. 9
-----
Total Change $(248)
=====
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ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2005 2004 Change
- ------------ ---- ---- ------
Three months ended $ 62 $ 49 $13
Nine months ended $141 $124 $17
Three Months Ended Nine Months Ended
September 30, 2005 September 30, 2005
Reasons for the change: vs. 2004 vs. 2004
- ----------------------- ------------------ ------------------
Electric deliveries $ 49 $ 87
Power supply costs and related revenue (31) (42)
Other operating expenses, other income, and
non-commodity revenue (14) (45)
Regulatory return on capital expenditures 7 20
General taxes 3 (1)
Fixed charges 5 7
Income taxes (6) (9)
---- ----
Total change $ 13 $ 17
==== ====
ELECTRIC DELIVERIES: For the three months ended September 30, 2005, electric
deliveries increased 1.7 billion kWh or 16.0 percent versus the same period in
2004. For the nine months ended September 30, 2005, electric deliveries
increased 1.7 billion kWh or 5.8 percent versus the same period in 2004. The
corresponding increases in electric delivery revenue for both periods were due
to increased sales to residential customers due to warmer weather and increased
surcharge revenue, offset partially by reduced electric delivery revenue from
customers choosing alternative electric suppliers.
On July 1, 2004, Consumers started collecting a surcharge related to the
recovery of costs incurred in the transition to customer choice. This surcharge
increased electric delivery revenue by $2 million for the three months ended
September 30, 2005 and $12 million for the nine months ended September 30, 2005
versus the same periods in 2004. Surcharge revenue related to the recovery of
security costs and stranded costs increased electric delivery revenue by an
additional $3 million for the three months ended September 30, 2005 and $9
million for the nine months ended September 30, 2005.
POWER SUPPLY COSTS AND RELATED REVENUE: Our recovery of power supply costs is
capped for our residential customers until January 1, 2006. For the three months
ended September 30, 2005, our underrecovery of power costs allocated to these
capped customers increased by $32 million versus the same period in 2004. For
the nine months ended September 30, 2005, our underrecovery of power costs
allocated to these capped customers increased by $53 million versus the same
period in 2004. Power supply-related costs increased in 2005 primarily due to
higher coal costs and higher priced purchased power to replace the generation
loss from outages at our Palisades and Campbell 3 generating plants.
Partially offsetting these underrecoveries are transmission and nitrogen oxide
allowance expenditures related to our capped customers. To the extent these
costs are not fully recoverable due to the application of rate caps, we have
deferred these costs and are requesting recovery under Public Act 141. For the
three months ended September 30, 2005, deferrals of these costs increased by $1
million versus the same period in 2004.
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Consumers Energy Company
For the nine months ended September 30, 2005, deferrals of these costs
increased by $11 million versus the same period in 2004.
OTHER OPERATING EXPENSES, OTHER INCOME, AND NON-COMMODITY REVENUE: For the three
months ended September 30, 2005, other operating expenses increased $16 million,
other income increased $3 million, and non-commodity revenue decreased $1
million versus the same period in 2004. For the nine months ended September 30,
2005, other operating expenses increased $55 million, other income increased $7
million, and non-commodity revenue increased $3 million versus the same period
in 2004.
The increase in other operating expenses reflects higher depreciation and
amortization expense, and higher pension and benefit expense. Depreciation and
amortization expense increased due to higher plant in service and greater
amortization of certain regulatory assets. Pension and benefit expense increased
primarily due to changes in actuarial assumptions and the remeasurement of our
pension and OPEB plans to reflect the new collective bargaining agreement
between the Utility Workers Union of America and Consumers. Benefit expense also
reflects the reinstatement of the employer matching contribution to our 401(k)
plan.
In addition, the increase in other operating expenses reflects increased
underrecovery expense related to the MCV PPA, offset partially by our direct
savings from the RCP. In 1992, a liability was established for estimated future
underrecoveries of power supply costs under the MCV PPA. In 2004, a portion of
the cash underrecoveries continued to reduce this liability until its depletion
in December. In 2005, all cash underrecoveries are expensed directly to income.
Partially offsetting this increased operating expense were the savings from the
RCP approved by the MPSC in January 2005.
The RCP allows us to dispatch the MCV Facility on the basis of natural gas
prices, which will reduce the MCV Facility's annual production of electricity
and, as a result, reduce the MCV Facility's consumption of natural gas. The MCV
Facility's fuel cost savings are first used to offset the cost of replacement
power and fund a renewable energy program. Remaining savings are split between
us and the MCV Partnership. Our direct savings are shared 50 percent with
customers in 2005 and 70 percent thereafter.
The cost associated with the MCV PPA cash underrecoveries, net of our direct
savings from the RCP, increased operating expense $4 million for the nine months
ended September 30, 2005 versus the same period in 2004.
For the three months ended September 30, 2005, the increase in other income is
primarily due to higher interest income on short-term cash investments versus
the same period in 2004. For the nine months ended September 30, 2005, the
increase in other income is primarily due to higher interest income on
short-term cash investments, offset partially by expenses associated with the
early retirement of debt, versus the same period in 2004.
For the three months ended September 30, 2005, the decrease in non-commodity
revenue is primarily due to lower transmission services revenue. For the nine
months ended September 30, 2005, the increase in non-commodity revenue is
primarily due to higher transmission services revenue.
REGULATORY RETURN ON CAPITAL EXPENDITURES: The return on capital expenditures in
excess of our depreciation base as allowed by the Customer Choice Act increased
income by $7 million for the three months ended September 30, 2005 and $20
million for the nine months ended September 30, 2005 versus the same periods in
2004.
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Consumers Energy Company
GENERAL TAXES: For the three months ended September 30, 2005, general taxes
decreased versus the same period in 2004 primarily due to lower property tax
expense. For the nine months ended September 30, 2005, general taxes increased
versus the same period in 2004 primarily due to higher MSBT expense, offset
partially by lower property tax expense.
FIXED CHARGES: For the three months ended September 30, 2005, fixed charges
reflect a 46 basis point reduction in the average rate of interest on our debt
and lower average debt levels versus the same period in 2004. For the nine
months ended September 30, 2005, fixed charges reflect a 37 basis point
reduction in the average rate of interest on our debt and higher average debt
levels versus the same period in 2004.
INCOME TAXES: For the three and nine months ended September 30, 2005, income
taxes increased versus the same periods in 2004 primarily due to higher earnings
by the electric utility.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
--------------------
September 30 2005 2004 Change
- ------------ ---- ---- ------
Three months ended $(16) $(11) $(5)
Nine months ended $ 39 $ 46 $(7)
==== ==== ===
Three Months Ended Nine Months Ended
September 30, 2005 September 30, 2005
Reasons for the Change: Vs. 2004 Vs. 2004
- ----------------------- ------------------ ------------------
Gas deliveries $ 1 $ -
Gas rate increase 3 24
Gas wholesale and retail services, other gas
revenues and other income 3 2
Operation and maintenance (14) (31)
General taxes and depreciation (1) (4)
Fixed charges - (2)
Income taxes 3 4
---- ----
Total change $ (5) $ (7)
==== ====
GAS DELIVERIES: For the three months ended September 30, 2005, higher gas
delivery revenues reflect increased deliveries to our customers versus the same
period in 2004. Gas deliveries, including miscellaneous transportation to
end-use customers, increased 1.4 bcf or 5.5 percent.
For the nine months ended September 30, 2005, gas delivery revenues
reflect slightly lower deliveries to our customers versus the same period in
2004. Gas deliveries, including miscellaneous transportation to end-use
customers, decreased 0.6 bcf or 0.3 percent.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. In October 2004,
the MPSC issued a final order authorizing an annual increase of $58 million
through a two-year surcharge. As a result of these orders, gas revenues
increased $3 million for the three months ended September 30, 2005 and $24
million for the nine months ended September 30, 2005 versus the same periods in
2004.
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Consumers Energy Company
GAS WHOLESALE AND RETAIL SERVICES, OTHER GAS REVENUES AND OTHER INCOME: For the
three months ended September 30, 2005, other income increased primarily due to
higher interest income on short-term cash investments versus the same period in
2004. For the nine months ended September 30, 2005, other income increased
primarily due to higher interest income on short-term cash investments, offset
partially by expenses associated with the early retirement of debt, versus the
same period in 2004.
OPERATION AND MAINTENANCE: For the three and nine months ended September 30,
2005, operation and maintenance expenses increased primarily due to increases in
benefit costs and additional safety, reliability, and customer service expenses.
Pension and benefit expense increased primarily due to changes in actuarial
assumptions and the remeasurement of our pension and OPEB plans to reflect the
new collective bargaining agreement between the Utility Workers Union of America
and Consumers. Benefit expense also reflects the reinstatement of the employer
matching contribution to our 401(k) plan.
GENERAL TAXES AND DEPRECIATION: For the three and nine months ended September
30, 2005, depreciation expense increased due to higher plant in service.
FIXED CHARGES: For the nine months ended September 30, 2005, fixed charges
reflect a 37 basis point reduction in the average rate of interest on our debt
and higher average debt levels versus the same period in 2004.
INCOME TAXES: For the three and nine months ended September 30, 2005, income
taxes decreased primarily due to lower earnings by the gas utility.
OTHER RESULTS OF OPERATIONS
In Millions
---------------------
September 30 2005 2004 Change
- ------------ ----- ---- ------
Three months ended $(322) $(4) $(318)
Nine months ended $(267) $(9) $(258)
===== === =====
For the three months ended September 30, 2005, other operations decreased net
income by $322 million, a decrease of $318 million in income versus the same
period in 2004. The change is primarily due to a $318 million decrease in
earnings related to our ownership interest in the MCV Partnership due to an
impairment charge to property, plant, and equipment to reflect the excess of the
carrying value of these assets over their estimated fair value. Partially
offsetting the impairment charge is an increase in the fair value of certain
long term gas contracts and related financial hedges at the MCV Partnership.
For the nine months ended September 30, 2005, other operations decreased net
income by $267 million, a decrease of $258 million in income versus the same
period in 2004. The change is primarily due to a $265 million decrease in
earnings related to our ownership interest in the MCV Partnership due to an
impairment charge to property, plant, and equipment to reflect the excess of the
carrying value of these assets over their estimated fair value. Partially
offsetting the impairment charge is an increase in the fair value of certain
long term gas contracts and related financial hedges at the MCV Partnership.
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Consumers Energy Company
CRITICAL ACCOUNTING POLICIES
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.
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 the occurrence of 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 most significant of these contingencies are our electric and gas
environmental liabilities, and the potential underrecoveries from our power
purchase contract with the MCV Partnership, all of which are discussed in the
"Outlook" section included in this MD&A.
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 $13.061
billion at September 30, 2005, 55 percent represent long-lived assets and equity
method investments that are subject to this type of analysis. We base our
evaluations of impairment on such indicators as:
- the nature of the assets,
- projected future economic benefits,
- regulatory and political environments,
- state and federal regulatory and political environments,
- historical and future cash flow and profitability measurements, and
- other external market conditions or factors.
If an event occurs or circumstances change in a manner that indicates the
recoverability of a long-lived asset should be assessed, we evaluate the asset
for impairment. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. An asset considered
held-for-sale is recorded at the lower of its carrying amount or fair value,
less cost to sell.
We also assess our ability to recover the carrying amounts of our equity method
investments. 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
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Consumers Energy Company
appropriate write-down is recorded.
Our assessments of fair value using these valuation methodologies represent our
best estimates at the time of the reviews and are consistent with our internal
planning. The estimates we use can change over time, which could have a material
impact on our financial statements.
For additional details on asset impairments, see Note 2, Asset Impairment
Charges.
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. There have been no material changes to the accounting for
financial instruments since the year ended December 31, 2004. For details on
financial instruments, see Note 5, Financial and Derivative Instruments.
DERIVATIVE INSTRUMENTS: We use SFAS No. 133 to account for derivative
instruments. Except as noted within this section, there have been no material
changes to the accounting for derivatives since the year ended December 31,
2004.
To determine the fair value of our derivatives, we use quoted market prices and
third-party valuations (i.e., from brokers and banks), if available. For certain
contracts, market prices and third-party valuations are not available, and we
must determine fair values by using mathematical valuation models. These
valuation models require various inputs and assumptions, including commodity
forward prices, strike 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 these contracts. The following
table summarizes the interest rate and volatility rate assumptions we used to
value these contracts as of September 30, 2005:
Interest Rates (%) Volatility Rates (%)
------------------ --------------------
Long-term gas contracts associated with the MCV
Partnership 3.86 - 4.67 32 - 63
Gas supply option contracts 3.95 67 - 69
Commencement of the Midwest Energy Market: The MISO began operating the Midwest
Energy Market on April 1, 2005. Through operation of the Midwest Energy Market,
the MISO centrally dispatches electricity and transmission service throughout
the Midwest and provides day-ahead and real-time energy market information. At
this time, we believe that the commencement of this market does not constitute
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 the potential for an active energy market in
Michigan. If an active market develops in the future, some of our electric
purchases and sales contracts may qualify as derivatives. However, we believe
that we will be able to apply the normal purchases and sales exception of SFAS
No. 133 to these contracts and, therefore, will not be required to mark these
contracts to market.
Implementation of the RCP: The MCV Partnership uses long-term gas contracts to
purchase natural gas as fuel for generation, and to manage gas fuel costs. The
MCV Partnership believes that certain of these contracts qualify as normal
purchases under SFAS No. 133. Accordingly, these contracts are not recognized at
fair value on our Consolidated Balance Sheets. However, as a result of
implementing the RCP in January 2005, a significant portion of long-term gas
contracts no longer qualify as normal
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purchases, because the gas will not be consumed as fuel for electric production.
Accordingly, these contracts are accounted for as derivatives, with changes in
fair value recorded in earnings each quarter. For the nine months ended
September 30, 2005, we recorded a $242 million gain associated with the increase
in fair value of these long-term gas contracts. This gain is included in the
total Fuel costs mark-to-market at MCV on our Consolidated Statements of Income.
As a result of mark-to-market gains, we have recorded derivative assets totaling
$298 million associated with the fair value of long-term gas contracts on our
Consolidated Balance Sheets. The majority of these assets are expected to
reverse through earnings during 2005 and 2006 as the gas is purchased, with the
remainder reversing between 2007 and 2011.
The MCV Partnership holds natural gas futures and swap contracts to manage price
risk by fixing the price to be paid for natural gas on some of its long-term gas
contracts. Prior to the implementation of the RCP, these futures and swap
contracts were accounted for as cash flow hedges. Since the RCP was implemented
in January 2005, these instruments no longer qualify for cash flow hedge
accounting and any changes in their fair value have been recorded in earnings
each quarter. For the nine months ended September 30, 2005, we recorded a $125
million gain associated with the increase in fair value of these instruments.
This gain is also included in the total Fuel costs mark-to-market at MCV on our
Consolidated Statements of Income. As a result of mark-to-market gains, we have
recorded derivative assets totaling $125 million associated with the fair value
of these instruments on our Consolidated Balance Sheets. The majority of these
assets are expected to be realized during 2005 and 2006 as the futures and swap
contracts settle, with the remainder to be realized during 2007. Because of the
volatility of the natural gas market, the MCV Partnership expects future
earnings volatility on both the long-term gas contracts and the futures and swap
contracts, since gains and losses will be recorded each quarter.
MARKET RISK INFORMATION: The following is an update of our risk sensitivities
since the year ended December 31, 2004. These risk sensitivities indicate the
potential loss in fair value, cash flows, or future earnings from our derivative
contracts and other financial instruments based upon a hypothetical 10 percent
adverse change in market rates or prices. Changes in excess of the amounts shown
in the sensitivity analyses could occur if market rates or prices exceed the 10
percent shift used for the analyses.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in
market interest rates):
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Variable-rate financing - before
tax annual earnings exposure $ 2 $ 2
Fixed-rate financing - potential
loss in fair value (a) 149 138
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change
in market prices):
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Potential REDUCTION in fair value:
Gas supply option contracts $ 3 $ 1
FTRs - -
Derivative contracts associated with
the MCV Partnership:
Long-term gas contracts (a) (b) 49 17
Gas futures and swaps (b) 59 41
(a) The increased potential reduction in fair value for the MCV Partnership's
long-term gas contracts is
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Consumers Energy Company
due to the increased number of contracts accounted for as derivatives as a
result of the RCP.
(b) The increased potential reduction in fair value for the MCV Partnership's
long-term gas contracts and gas futures and swaps is due to the significant
increase in natural gas prices from December 31, 2004.
Investment Securities Price Risk Sensitivity Analysis (assuming a 10 percent
adverse change in market prices):
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Potential REDUCTION in fair value of
available-for-sale equity securities
(SERP investments and investments in
CMS Energy common stock) $6 $5
We maintain trust funds, as required by the NRC, which may only be used to fund
certain costs of nuclear plant decommissioning. These funds are 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. Those 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 consolidated
earnings or cash flows.
For additional details on market risk and derivative activities, see Note 5,
Financial and Derivative Instruments.
ACCOUNTING FOR PENSION AND OPEB
Pension: We have established external trust funds to provide retirement pension
benefits to our employees under a non-contributory, defined benefit Pension
Plan. We implemented a cash balance plan for certain employees hired after June
30, 2003. On September 1, 2005, we implemented the Defined Company Contribution
Plan.
The Defined Company Contribution Plan provides an employer contribution of 5
percent of base pay to the existing Employees' Savings Plan. No employee
contribution is required to receive the plan's employer cash contribution. All
employees hired on and after September 1, 2005 participate in this plan as part
of their retirement benefit program. Cash balance pension plan participants also
participate in the Defined Company Contribution Plan on September 1, 2005.
Additional pay credits under the cash balance pension plan were discontinued as
of that date. We use SFAS No. 87 to account for pension costs.
401(k): We resumed the employer's match in CMS Energy Stock on our 401(k)
Savings Plan on January 1, 2005. On September 1, 2005, employees enrolled in the
company's 401(k) Savings Plan had their employer match increased from 50 percent
to 60 percent on eligible contributions up to the first six percent of an
employee's wages.
OPEB: We provide postretirement health and life benefits under our OPEB plan to
substantially all our retired employees. We use SFAS No. 106 to account for
other postretirement benefit costs.
Liabilities for both pension and OPEB are recorded on the balance sheet at the
present value of their future obligations, net of any plan assets. The
calculation of the liabilities and associated expenses requires the expertise of
actuaries. Many assumptions are made including:
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Consumers Energy Company
- life expectancies,
- present-value discount rates,
- expected long-term rate of return on plan assets,
- rate of compensation increases, and
- anticipated health care costs.
Any change in these assumptions can change significantly the liability and
associated expenses recognized in any given year.
The following table provides an estimate of our pension cost, OPEB cost, and
cash contributions for the next three years:
In Millions
----------------------------------------
Expected Costs Pension Cost OPEB Cost Contributions
- -------------- ------------ --------- -------------
2006 $89 $38 $ 81
2007 98 34 176
2008 93 30 109
Actual future pension cost and contributions will depend on future investment
performance, changes in future discount rates, and various other factors related
to the populations participating in the Pension Plan.
For additional details on postretirement benefits, see Note 6, Retirement
Benefits.
OTHER
Other accounting policies that are important to an understanding of our results
of operations and financial condition include:
- accounting for the effects of industry regulation,
- accounting for asset retirement obligations,
- accounting for nuclear decommissioning costs, and
- accounting for related party transactions.
There have been no material changes to these accounting policies since the year
ended December 31, 2004.
CAPITAL RESOURCES AND LIQUIDITY
Our liquidity and capital requirements are a function of our results of
operations, capital expenditures, contractual obligations, debt maturities,
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. The market price for natural gas has increased. Although our 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 as gas prices increase. In addition, a few of our commodity suppliers
have requested nonstandard payment terms or other forms of assurances, including
margin calls, in connection with maintenance of ongoing deliveries of gas and
electricity.
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
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Partnership asset impairment charge recorded in September 2005, our ability to
issue FMB as primary obligations or as collateral for financing is expected to
be limited to $298 million for 12 months, ending September 30, 2006. Beyond 12
months, our ability to issue FMB in excess of $298 million is based on achieving
a two-times FMB interest coverage rate. Nonetheless, we believe our current
level of cash and revolving credit facilities, and our ability to access junior
secured and unsecured borrowing capacity in the capital markets, along with
anticipated cash flows from operating and investing activities, will be
sufficient to meet our liquidity needs.
CASH POSITION, INVESTING, AND FINANCING
Our operating, investing, and financing activities meet consolidated cash needs.
At September 30, 2005, $662 million consolidated cash was on hand, which
includes $184 million of restricted cash and $416 million from the entities
consolidated pursuant to FASB Interpretation No. 46. For additional details, see
Note 9, Consolidation of Variable Interest Entities.
SUMMARY OF CASH FLOWS:
In Millions
-------------
Nine Months Ended September 30 2005 2004
- ------------------------------ ----- -----
Net cash provided by (used in):
Operating activities $ 677 $ 325
Investing activities (547) (431)
----- -----
Net cash provided by (used in)
Operating and investing activities 130 (106)
Financing activities 177 10
----- -----
Net Increase (Decrease) in Cash and
Cash Equivalents $ 307 $ (96)
===== =====
OPERATING ACTIVITIES: For the nine months ended September 30, 2005, net cash
provided by operating activities increased $352 million versus the same period
in 2004 due to increases in MCV gas supplier funds on deposit and accounts
payable, partially offset by an increase in inventories. The increase in MCV gas
supplier funds on deposit, accounts payable, and inventories is due to the
effect of rising gas prices.
INVESTING ACTIVITIES: For the nine months ended September 30, 2005, net cash
used in investing activities increased $116 million versus the same period in
2004 primarily due to an increase in restricted cash on hand of $129 million.
The increase in restricted cash was due to an irrevocable deposit made with a
trustee to permit a defeasance of our 9 percent notes by the end of the first
quarter of 2006.
FINANCING ACTIVITIES: For the nine months ended September 30, 2005, net cash
provided by financing activities increased $167 million versus the same period
in 2004 due to an increase of $400 million in stockholder's contributions from
the parent, offset by a decrease in net proceeds from borrowings of $229
million.
For additional details on long-term debt activity, see Note 4, Financings and
Capitalization.
OBLIGATIONS AND COMMITMENTS
REVOLVING CREDIT FACILITIES: For details on revolving credit facilities, see
Note 4, Financings and Capitalization.
OFF-BALANCE SHEET ARRANGEMENTS: There have been no material changes in
off-balance sheet arrangements since the year ended December 31, 2004. For
details on guarantee arrangements, see Note
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4, Financings and Capitalization, "FASB Interpretation No. 45, Guarantor's
Accounting and Disclosure Requirements for Guarantees, Including Indirect
Guarantees of Indebtedness of Others."
DIVIDEND RESTRICTIONS: For details on dividend restrictions, see Note 4,
Financings and Capitalization.
DEBT CREDIT RATING: On November 1, 2005, S&P placed CMS Energy's and Consumers'
debt credit ratings on CreditWatch with negative implications. S&P indicated
that they expect resolution of the CreditWatch before year end 2005.
OUTLOOK
ELECTRIC BUSINESS OUTLOOK
GROWTH: We expect the growth in electric deliveries for 2005 to be approximately
four percent. Summer 2005 temperatures were higher than historical averages,
leading to increased demand from electric customers. Over the next five years,
we expect electric deliveries to grow at an average rate of approximately two
percent per year. However, such growth is dependent on a modestly growing
customer base and recovery of the 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.
INDUSTRIAL REVENUE OUTLOOK: Our electric utility customer base includes a mix of
residential, commercial, and diversified industrial customers, the largest
segment of which is the automotive industry. In October 2005, Delphi Corporation
(Delphi) filed for Chapter 11 bankruptcy protection. Delphi is the nation's
largest automotive supplier headquartered in Troy, Michigan, and is a large
industrial customer of Consumers. Our electric utility operations are not
dependent upon a single customer, and we do not believe that this event will
have a material adverse effect on our financial condition. We cannot, however,
predict the impact of the Delphi bankruptcy filing on other automotive-related
manufacturing customers or the Michigan industrial base. Continued degradation
of the industrial customer base would have a negative impact on electric utility
revenues.
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 establish a reserve margin target to address various scenarios and
contingencies so that the probability of interrupting service to retail
customers because of a supply shortage is no greater than an industry-recognized
standard. However, even with the reserve margin target, additional spot
purchases during periods when electric prices are high may be required.
We are currently planning for a reserve margin of approximately 11 percent for
summer 2006, or supply resources equal to 111 percent of projected summer peak
load. Of the 2006 supply resources target of 111 percent, we expect to meet
approximately 98 percent from our electric generating plants and long-term power
purchase contracts, and approximately 13 percent from short-term contracts,
options for physical deliveries, and other agreements. We have purchased
capacity and energy contracts covering partially the estimated reserve margin
requirements for 2006 through 2007. As a result, we have recognized an asset of
$6 million for unexpired capacity and energy contracts at September 30, 2005.
COAL DELIVERY DISRUPTIONS: In May 2005, western coal rail carriers experienced
derailments and significant service disruptions due to heavy snow and rain
conditions. These disruptions affected all shippers of western coal from Wyoming
mines as well as coal producers from May 2005 through June 2005. We received
notification that, under contractual Force Majeure provisions, the coal tonnage
not
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delivered during this period will not be made up. According to recent
announcements, rail repairs will extend through November 2005. Although we
expect some impact on coal shipments during the repair period, we expect our
inventories will remain within historical levels, at least during the upcoming
winter period, though at lower levels than planned before the disruptions
occurred. Based on our present delivery experience, projections, and inventory,
we believe we will have adequate coal supply to allow for normal dispatch of our
coal-fired generating units.
ENERGY MARKET DEVELOPMENT: The MISO began operating the Midwest Energy Market on
April 1, 2005. The Midwest Energy Market includes a day-ahead and real-time
energy market and centralized generation dispatch for market participants. We
are a participant in this energy market. The intention of this market is to meet
load requirements in the region reliably and efficiently, to improve management
of congestion on the grid, and to centralize dispatch of generation throughout
the region. The MISO is now responsible for the reliability and economic
dispatch in the entire MISO area, which covers parts of 15 states and Manitoba,
including our service territory. We are presently evaluating what financial
impact, if any, these changes are having on our operations.
The settlement of charges for each operating day of the Midwest Energy Market
invokes the issuance of multiple settlement statements over a 155-day period.
This extended settlement period is designed to allow for adjustments associated
with the receipt of complete billing information and other adjustments. When
adjustments are necessary, the MISO bills market participants on a retroactive
basis, covering several months. We record adjustments as appropriate when the
MISO notifies us of the revised amounts. The revised amounts may result in
either a positive or a negative expense adjustment. We cannot predict the amount
or timing of any MISO billing adjustments.
RENEWABLE RESOURCES PROGRAM: In January 2005, in collaboration with the MPSC, we
established a renewable resources program. Under the RRP, we purchase energy
from approved renewable sources, which include solar, wind, geothermal, biomass,
and hydroelectric suppliers. Customers are able to participate in the RRP in
accordance with tariffs approved by the MPSC. The MPSC has authorized recovery
of above-market costs for the RRP by establishing a fund that consists of an
annual contribution from savings generated by the RCP, a surcharge imposed by
the MPSC on all customers, and contributions from customers that choose to
participate in the RRP. In February 2005, the Attorney General filed appeals of
the MPSC orders providing funding for the RRP in the Michigan Court of Appeals.
In August 2005, we secured long-term renewable energy supply contracts. In
October 2005, the MPSC issued an order approving these new supply contracts.
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to
increase our retail electric base rates. The electric rate case filing requests
an annual increase in revenues of approximately $320 million. The primary
reasons for the request are load migration to alternative electric suppliers,
increased system maintenance and improvement costs, Clean Air Act-related
expenditures, and employee pension costs. In April 2005, we filed updated debt
and equity information in this case.
In June 2005, the MPSC Staff filed its position in this case, recommending a
base rate increase of $98 million. The MPSC Staff also recommended an 11.25
percent return on equity to establish rates and recognized all of our projected
equity investment (infusions and retained earnings) in 2006. In August 2005, we
revised our request for an annual increase in revenues to approximately $197
million, and the MPSC Staff revised its recommendation to $100 million. In
October 2005, the ALJ issued a proposal for decision recommending a base rate
increase of $112 million and an 11.25 percent authorized return on equity. We
expect a final order from the MPSC in late 2005. If approved as requested, the
rate increase would go into effect in January 2006 and would apply to all retail
electric customers. We cannot predict
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the amount or timing of the rate increase, if any, which the MPSC will approve.
BURIAL OF OVERHEAD POWER LINES: In September 2004, the Michigan Court of Appeals
upheld a lower court decision that requires Detroit Edison to obey a municipal
ordinance enacted by the City of Taylor, Michigan. The ordinance requires
Detroit Edison to bury a section of its overhead power lines at its own expense.
Detroit Edison filed an appeal with the Michigan Supreme Court. Unless
overturned by the Michigan Supreme Court, the decision could encourage other
municipalities to adopt similar ordinances, as has occurred or is under
discussion in a few municipalities in our service territory. If incurred, we
would seek recovery of these costs from our customers located in the
municipality affected, subject to MPSC approval. This case has potentially broad
ramifications for the electric utility industry in Michigan. In a similar
matter, in May 2005, we filed a request with the MPSC that asks the MPSC to rule
that the City of East Grand Rapids, Michigan must pay for the relocation of
electric utility facilities required by an ordinance adopted by the city. In
September 2005, we reached a settlement of this particular dispute with the City
of East Grand Rapids, which is in the process of finalization. In October 2005,
the Michigan Supreme Court issued an order in which it agreed to review the
lower court's decision in the City of Taylor matter. The Court also established
a briefing schedule. At this time, we cannot predict the outcome of the broader
issues addressed in the City of Taylor matter.
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.
Clean Air: 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 $815 million. 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
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.3 percent. As of September 2005, we have
incurred $589 million in capital expenditures to comply with these regulations
and anticipate that the remaining $226 million of capital expenditures will be
made in 2005 through 2011. These expenditures include installing selective
catalytic reduction technology at four of our coal-fired electric plants. In
addition to modifying the coal-fired electric plants, we expect to utilize
nitrogen oxide emissions allowances for years 2006 through 2008, of which 90
percent have been obtained. The cost of the allowances is estimated to average
$5 million per year for 2006 through 2008. The estimated costs are based on the
average cost of the purchased, allocated, and exchanged allowances. The need for
allowances will decrease after 2006 with the installation of selective catalytic
control technology. The cost of the allowances is accounted for as inventory.
The allowance inventory is expensed as the coal-fired electric generating units
emit nitrogen oxide.
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The EPA recently adopted a Clean Air Interstate Rule that requires additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. The rule involves a two-phase program to reduce emissions of sulfur
dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule
will require that we run our Selective Catalytic Reduction 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 State Implementation
Plan, 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 a cost near that of
the Nitrogen Oxide State Implementation Plan.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial
reductions of mercury emissions from coal-fired electric power plants by 2010
and further reductions by 2018. While the industry has not reached a consensus
on the technical methods for curtailing mercury emissions, our capital and
operating costs for mercury emissions reductions are expected to be
significantly less than what is required for nitrogen oxide compliance.
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. The MDEQ has not indicated the direction that it will pursue to meet
or exceed the EPA requirements through a state rulemaking. We are actively
participating in dialog with the MDEQ regarding potential paths for controlling
mercury emissions and meeting the EPA requirements. In October 2005, the EPA
announced it would reconsider certain aspects of the Clean Air Mercury Rule. We
cannot predict the outcome of this proceeding.
Several legislative proposals have been introduced in the United States Congress
that would require reductions in emissions of greenhouse gases, however, none
have yet been enacted. We cannot predict whether any federal mandatory
greenhouse gas emission reduction rules ultimately will be enacted, or the
specific requirements of any such rules.
To the extent that greenhouse gas emission reduction rules come into effect,
such 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 and
engage in the 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 generating plant cooling
water intake systems. The new rules require significant reduction in fish killed
by operating equipment. Some of our facilities will be required to comply with
the new rules by 2007. We are currently performing the required studies to
determine the most cost-effective solutions for compliance.
For additional details on electric environmental matters, see Note 3,
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. As of October 2005, alternative electric
suppliers are providing 754 MW of generation service to ROA customers. This
amount represents a decrease of 14 percent compared to October 2004, and 10
percent of our total distribution load. Current trends indicate a continued
reduction in ROA load loss. However, it is difficult to predict future ROA
customer trends.
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Implementation Costs: In June 2005, the MPSC issued an order that authorizes us
to recover implementation costs incurred during 2002 and 2003 totaling $6
million, plus the cost of money through the period of collection.
We are also pursuing authorization at the FERC for the MISO to reimburse us for
Alliance RTO development costs. Included in this amount is $2 million that the
MPSC did not approve as part of our 2002 implementation costs application. The
FERC denied our request for reimbursement, and we are appealing the FERC ruling
at the United States Court of Appeals for the District of Columbia. We cannot
predict the amount, if any, the FERC will approve as recoverable.
Section 10d(4) Regulatory Assets: In October 2004, we filed an application with
the MPSC seeking recovery of $628 million of Section 10d(4) Regulatory Assets
for the period June 2000 through December 2005. Of the $628 million, $152
million relates to the cost of money. In March 2005, the MPSC Staff filed
testimony recommending the MPSC approve recovery of approximately $323 million
in Section 10d(4) costs, which includes the cost of money through the period of
collection. In June 2005, the ALJ issued a proposal for decision recommending
the MPSC approve recovery of the same Section 10d(4) costs recommended by the
MPSC Staff. However, we may have the opportunity to recover certain costs
included in our application alternatively in other cases pending before the
MPSC. We cannot predict the amount, if any, the MPSC will approve as
recoverable.
For additional details and material changes relating to the restructuring of the
electric utility industry and electric rate matters, see Note 3, Contingencies,
"Electric Restructuring Matters," and "Electric Rate Matters."
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.
The cost that we incur under the MCV PPA exceeds the recovery amount allowed by
the MPSC. As a result, we estimate that cash underrecoveries of capacity and
fixed energy payments will aggregate $150 million from 2005 through 2007. 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 clause after September 15, 2007. We believe that the clause
is valid and fully effective, but cannot assure that it will prevail in the
event of a dispute. The MPSC's future actions on the capacity and fixed energy
payments recoverable from customers subsequent to September 15, 2007 may affect
negatively the financial performance of the MCV Partnership.
Further, 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. Natural gas prices have
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increased substantially in recent years and throughout 2005. In the third
quarter of 2005, the MCV Partnership reevaluated the economics of operating the
MCV Facility and determined that an impairment was required. 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 financial obligations under the sale and leaseback transactions and
other contracts. We are evaluating various alternatives in order to develop a
new long-term strategy with respect to the MCV Facility. For additional details
on the impairment of the MCV Facility, see Note 2, Asset Impairment Charges.
For additional details on the MCV Partnership, see Note 3, Contingencies, "Other
Electric Contingencies - The Midland Cogeneration Venture."
NUCLEAR MATTERS: Big Rock: Dismantlement of plant systems is essentially
complete and demolition of the remaining plant structures has begun. The
restoration project is on schedule to return approximately 530 acres of the
site, including the area formerly occupied by the nuclear plant, to a natural
setting for unrestricted use by early 2007. We expect a 30-acre area containing
eight casks loaded with spent nuclear fuel and other high-level radioactive
waste material to be returned to a natural state within two years from the date
the DOE begins removing the spent nuclear fuel from Big Rock.
Palisades: In August 2005, the NRC completed its performance review of the
Palisades Nuclear Plant for the first half of the calendar year 2005. The NRC
determined that Palisades was operated in a manner that preserved public health
and safety and met all of the NRC's specific "cornerstone objectives." As of
August 2005, all inspection findings were classified as having very low safety
significance and all performance indicators show performance at a level
requiring no additional oversight. Based on the plant's performance, only
regularly scheduled inspections are planned through March 31, 2007.
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 2005,
we have loaded 22 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. Certain parties are seeking to intervene and
have requested a hearing on the application. The NRC has stated that it expects
to take 22-30 months to review a license renewal application. We expect a
decision from the NRC in 2007.
Palisades, like other nuclear plants, has experienced cracking in reactor head
nozzle penetrations. Repairs to two nozzles were made in 2004. We have
authorized the purchase of a replacement reactor vessel closure head. The
replacement head is being manufactured and is scheduled to be installed in 2007.
For additional information on nuclear plant decommissioning at Big Rock and
Palisades, see Note 3, Contingencies, "Other Electric Contingencies - Nuclear
Plant Decommissioning."
Spent nuclear fuel complaint: In March 2003, the Michigan Environmental Council,
the Public Interest Research Group in Michigan, and the Michigan Consumer
Federation filed a complaint with the MPSC, which was served on us by the MPSC
in April 2003. The complaint asks the MPSC to initiate a generic investigation
and contested case to review all facts and issues concerning costs associated
with spent nuclear fuel storage and disposal. The complaint seeks a variety of
relief with respect to Consumers, Detroit Edison, Indiana & Michigan Electric
Company, Wisconsin Electric Power Company, and Wisconsin Public Service
Corporation. The complaint states that amounts collected from customers for
spent nuclear fuel storage and disposal should be placed in an independent
trust. The complaint also asks the MPSC to take additional actions. In May 2003,
Consumers and other named utilities each filed motions to dismiss the complaint.
In September 2005, the MPSC dismissed the complaint.
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GAS BUSINESS OUTLOOK
GROWTH: 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.
In February 2004, we filed an application with the MPSC for a Certificate of
Public Convenience and Necessity to construct a 25-mile gas transmission
pipeline in northern Oakland County. The project is necessary to meet estimated
peak load beginning in the winter of 2005-2006. We started construction of Phase
I of the pipeline in June 2005 and expect Phase I to be completed and in service
by November 2005. We anticipate completion of Phase II of the project in 2008.
In October 2004, we filed an application with the MPSC for a Certificate of
Public Convenience and Necessity to construct a 10.8-mile gas transmission
pipeline in northwestern Wayne County. The project is necessary to meet the
projected capacity demands beginning in the winter of 2007. In August 2005, the
MPSC issued an order approving the application. Construction of the pipeline is
expected to begin in spring of 2006.
GAS BUSINESS UNCERTAINTIES
Several gas business trends or uncertainties may affect our financial results
and conditions. 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, "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 for prudency in an annual
reconciliation proceeding. For additional details on gas cost recovery, see Note
3, 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. The
October 2004 order also required us to undertake a study to determine why our
removal costs are in excess of those of other regulated Michigan natural gas
utilities and file a report with the MPSC Staff on or before December 31, 2005.
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The MPSC has directed us to file our next gas depreciation case within 90 days
after the latter of:
- the removal cost study filing, or
- the MPSC issuance of a final order in the pending case related to ARO
accounting.
The MPSC order on the pending case related to ARO accounting is expected in the
first quarter of 2006. We proposed to incorporate the results of the gas
depreciation case into gas general rates using a surcharge mechanism if the
depreciation case order was not issued concurrently with a gas general rate case
order.
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. The primary reasons for
the request are recovery of new investments, carrying costs on natural gas
inventory related to higher gas prices, system maintenance, employee benefits,
and low-income assistance. If approved, the request would add approximately 5
percent to the typical residential customer's average monthly bill. The increase
would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony on October
31, 2005. In its testimony, the MPSC Staff recommended granting interim rate
relief of $38 million.
EMERGENCY RULES REGARDING BILLING PRACTICES: On October 18, 2005, the MPSC
issued an order adopting emergency rules, effective November 1, 2005 through
March 31, 2006, regarding billing practices for retail customers of electric and
gas utilities subject to the MPSC's jurisdiction. The emergency rules are to
address the expected substantial increase in heating costs this winter. The
emergency rules address billing cycles, fees, deposits, shutoffs and collection
of unpaid bills. We are analyzing the potential impact of these emergency rules.
OTHER OUTLOOK
COLLECTIVE BARGAINING AGREEMENTS: Approximately 46 percent of our employees are
represented by the Utility Workers Union of America. The Union represents
operating, maintenance, and construction employees and call center employees.
The collective bargaining agreement with the Union for operating, maintenance,
and construction employees expired on June 1, 2005 and the collective bargaining
agreement with the Union for call center employees expired on August l, 2005. In
both cases, new 5-year agreements were reached with the Union and ratified by
their membership.
MCV IMPAIRMENT: As a result of the impairment of the MCV Facility, we may be
required to reduce the amount of equity investment included in our electric and
gas rate cases. This could impact our requested annual revenue requirements.
However, we cannot predict the amount, if any, of such reduction. For additional
information on the impairment of the MCV Facility, see Note 2, Asset Impairment
Charges.
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. Additionally, CMS Energy and Consumers
are named as parties in a class action lawsuit alleging ERISA violations. For
additional details regarding these investigations and litigation, see Note 3,
Contingencies.
NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: This Statement 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 amount over the vesting period of
the awards. This Statement also clarifies and expands SFAS No. 123's guidance in
several areas, including measuring fair value, classifying an award as equity or
as a liability, and attributing compensation cost to reporting periods.
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This Statement amends SFAS No. 95, Statement of Cash Flows, to require that
excess tax benefits related to the excess of the tax-deductible amount over the
compensation cost recognized be classified as cash inflows from financing
activities rather than as a reduction of taxes paid in operating activities.
Excess tax benefits are recorded as adjustments to additional paid-in capital.
This Statement is effective for us as of the beginning of 2006. We adopted the
fair value method of accounting for share-based awards effective December 2002.
Therefore, we do not expect this statement to have a significant impact on our
results of operations when it becomes effective.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarifies 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 that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and
(or) method of settlement. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can be reasonably estimated. The fair value of a
liability for the conditional asset retirement obligation should be recognized
when incurred. This Interpretation also clarifies when an entity would have
sufficient information to estimate reasonably the fair value of an asset
retirement obligation. For us, this Interpretation is effective no later than
December 31, 2005. We are in the process of determining the impact this
Interpretation will have on our financial statements upon adoption.
CE-25
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ -----------------
SEPTEMBER 30 2005 2004 2005 2004
- ------------ ------ ---- ------ -------
In Millions
OPERATING REVENUE $1,025 $885 $3,673 $3,355
EARNINGS FROM EQUITY METHOD INVESTEES 1 1 1 1
OPERATING EXPENSES
Fuel for electric generation 183 194 494 524
Fuel costs mark-to-market at MCV (197) - (367) (6)
Purchased and interchange power 145 71 272 171
Purchased power - related parties 19 18 50 49
Cost of gas sold 133 89 1,115 947
Cost of gas sold - related parties - - - 1
Other operating expenses 212 181 601 529
Maintenance 53 56 155 163
Depreciation, depletion and amortization 113 104 369 335
General taxes 46 51 164 163
Asset impairment charges 1,184 - 1,184 -
------ ---- ------ ------
1,891 764 4,037 2,876
------ ---- ------ ------
OPERATING INCOME (LOSS) (865) 122 (363) 480
OTHER INCOME (DEDUCTIONS)
Accretion expense - (1) (1) (3)
Interest and dividends 9 4 24 11
Gain on asset sales, net - 1 - 1
Regulatory return on capital expenditures 17 10 48 28
Other income 6 3 16 7
Other expense (2) (2) (10) (4)
------ ---- ------ ------
30 15 77 40
------ ---- ------ ------
INTEREST CHARGES
Interest on long-term debt 70 70 217 215
Interest on long-term debt - related parties 3 11 12 33
Other interest - 4 4 11
Capitalized interest (1) (2) (3) (5)
------ ---- ------ ------
72 83 230 254
------ ---- ------ ------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS (907) 54 (516) 266
MINORITY INTERESTS (483) 1 (386) 12
------ ---- ------ ------
INCOME (LOSS) BEFORE INCOME TAXES (424) 53 (130) 254
INCOME TAX (BENEFIT) EXPENSE (148) 19 (44) 91
------ ---- ------ ------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE (276) 34 (86) 163
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING FOR RETIREMENT BENEFITS,
NET OF $- TAX BENEFIT IN 2004 - - - (1)
------ ---- ------ ------
NET INCOME (LOSS) (276) 34 (86) 162
PREFERRED STOCK DIVIDENDS - - 1 1
------ ---- ------ ------
NET INCOME (LOSS) AVAILABLE TO COMMON STOCKHOLDER $ (276) $ 34 $ (87) $ 161
====== ==== ====== ======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-26
\ CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
NINE MONTHS ENDED
-----------------
SEPTEMBER 30 2005 2004
- ------------ ------- ------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (86) $ 162
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $4 per period) 369 335
Gain on sale of assets - (1)
Regulatory return on capital expenditures (48) (28)
Minority interest (386) 12
Fuel costs mark-to-market at MCV (367) (6)
Asset impairment charges 1,184 -
Property tax, capital lease and other amortization 138 132
Cumulative effect of change in accounting - 1
Changes in assets and liabilities:
Increase in accounts receivable and accrued revenue (44) (13)
Increase in inventories (351) (273)
Increase in accounts payable 140 27
Decrease in accrued expenses (153) (130)
Increase in MCV gas supplier funds on deposit 275 16
Deferred income taxes and investment tax credit (97) 91
Decrease (increase) in other current and non-current assets 66 (17)
Increase in other current and non-current liabilities 37 17
------- -----
Net cash provided by operating activities $ 677 $ 325
------- -----
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $ (419) $(368)
Cost to retire property (57) (53)
Restricted cash on hand (163) (34)
Investments in nuclear decommissioning trust funds (5) (4)
Proceeds from nuclear decommissioning trust funds 31 35
Proceeds from short-term investments 145 717
Purchase of short-term investments (141) (726)
Maturity of MCV restricted investment securities held-to-maturity 316 592
Purchase of MCV restricted investment securities held-to-maturity (267) (592)
Cash proceeds from sale of assets 1 2
Other investing 12 -
------- -----
Net cash used in investing activities $ (547) $(431)
------- -----
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long-term debt $ 910 $ 828
Retirement of long-term debt (1,020) (717)
Payment of common stock dividends (207) (187)
Payment of preferred stock dividends (1) (2)
Payment of capital and finance lease obligations (26) (41)
Stockholder's contribution 550 150
Debt issuance costs and financing fees (29) (21)
------- -----
Net cash provided by financing activities $ 177 $ 10
------- -----
Net Increase (Decrease) in Cash and Cash Equivalents $ 307 $ (96)
Cash and Cash Equivalents from Effect of Revised FASB
Interpretation No. 46 Consolidation - 174
Cash and Cash Equivalents, Beginning of Period 171 46
------- -----
Cash and Cash Equivalents, End of Period $ 478 $ 124
======= =====
CE-27
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
SEPTEMBER 30
2005 DECEMBER 31
(UNAUDITED) 2004
------------ -----------
In Millions
ASSETS
PLANT AND PROPERTY (AT COST)
Electric $ 8,129 $ 7,967
Gas 3,066 2,995
Other 222 2,523
------- -------
11,417 13,485
Less accumulated depreciation, depletion and amortization 4,756 5,665
------- -------
6,661 7,820
Construction work-in-progress 489 353
------- -------
7,150 8,173
------- -------
INVESTMENTS
Stock of affiliates 37 25
Other 8 19
------- -------
45 44
------- -------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 478 171
Short-term investments at cost, which approximates market - 4
Restricted cash 184 21
Accounts receivable, notes receivable and accrued revenue,
less allowances of $10 and $10, respectively 413 374
Accounts receivable - related parties 10 18
Inventories at average cost
Gas in underground storage 1,172 855
Materials and supplies 70 67
Generating plant fuel stock 97 66
Deferred property taxes 115 165
Regulatory assets - postretirement benefits 19 19
Derivative instruments 380 96
Other 50 95
------- -------
2,988 1,951
------- -------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 571 604
Additional minimum pension 466 372
Postretirement benefits 122 139
Capital expenditures return 201 141
Abandoned Midland Project 9 10
Other 461 411
Nuclear decommissioning trust funds 555 575
Other 493 391
------- -------
2,878 2,643
------- -------
TOTAL ASSETS $13,061 $12,811
======= =======
CE-28
STOCKHOLDER'S EQUITY AND LIABILITIES
SEPTEMBER 30
2005 DECEMBER 31
(UNAUDITED) 2004
------------ -----------
In Millions
CAPITALIZATION
Common stockholder's equity
Common stock, authorized 125.0 shares; outstanding
84.1 shares for all periods $ 841 $ 841
Paid-in capital 1,482 932
Accumulated other comprehensive income 76 31
Retained earnings since December 31, 1992 314 608
------- -------
2,713 2,412
Preferred stock 44 44
Long-term debt 4,310 4,000
Long-term debt - related parties - 326
Non-current portion of capital leases and finance lease
obligations 299 315
------- -------
7,366 7,097
------- -------
MINORITY INTERESTS 322 657
------- -------
CURRENT LIABILITIES
Current portion of long-term debt, capital leases and
finance leases 111 147
Current portion of long-term debt - related parties 129 180
Accounts payable 410 267
Accounts payable - related parties 11 14
Accrued interest 59 83
Accrued taxes 133 254
Deferred income taxes 48 20
MCV gas supplier funds on deposit 295 20
Other 233 218
------- -------
1,429 1,203
------- -------
NON-CURRENT LIABILITIES
Deferred income taxes 1,240 1,350
Regulatory Liabilities
Regulatory liabilities for cost of removal 1,097 1,044
Income taxes, net 369 357
Other 174 173
Postretirement benefits 367 207
Asset retirement obligations 434 436
Deferred investment tax credit 75 79
Other 188 208
------- -------
3,944 3,854
------- -------
COMMITMENTS AND CONTINGENCIES (Notes 3, 4, and 5)
TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES $13,061 $12,811
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-29
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(UNAUDITED)
THREE MONTHS ENDED NINE MONTHS ENDED
------------------ --------------------
SEPTEMBER 30 2005 2004 2005 2004
- ------------ ------ ------ ------ -----------
In Millions
COMMON STOCK
At beginning and end of period (a) $ 841 $ 841 $ 841 $ 841
------ ------ ------ ------
OTHER PAID-IN CAPITAL
At beginning of period 1,482 682 932 682
Stockholder's contribution - 150 550 150
------ ------ ------ ------
At end of period 1,482 832 1,482 832
------ ------ ------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period (2) - (1) -
Minimum pension liability adjustment (b) - (1) (1) (1)
------ ------ ------ ------
At end of period (2) (1) (2) (1)
------ ------ ------ ------
Investments
At beginning of period 18 10 12 9
Unrealized gain on investments (b) 3 - 9 1
------ ------ ------ ------
At end of period 21 10 21 10
------ ------ ------ ------
Derivative Instruments
At beginning of period 32 16 20 8
Unrealized gain on derivative instruments (b) 27 14 50 27
Reclassification adjustments included in net income (loss) (b) (2) (1) (13) (6)
------ ------ ------ ------
At end of period 57 29 57 29
------ ------ ------ ------
Total Accumulated Other Comprehensive Income 76 38 76 38
------ ------ ------ ------
RETAINED EARNINGS
At beginning of period 630 543 608 521
Net income (loss) (276) 34 (86) 162
Cash dividends declared - Common Stock (40) (82) (207) (187)
Cash dividends declared - Preferred Stock - - (1) (1)
------ ------ ------ ------
At end of period 314 495 314 495
------ ------ ------ ------
TOTAL COMMON STOCKHOLDER'S EQUITY $2,713 $2,206 $2,713 $2,206
====== ====== ====== ======
(a) Number of shares of common stock outstanding was 84,108,789 for all periods
presented.
(b) Disclosure of Other Comprehensive Income (Loss):
Minimum Pension Liabilityr
Minimum pension liability adjustment, net of tax of
$-, $(1), $-, and $(1), respectively $ - $(1) $ (1) $ (1)
Investments
Unrealized gain on investments, net of tax of
$2, $-, $5, and $1, respectively 3 - 9 1
Derivative Instruments
Unrealized gain on derivative instruments, net of tax of
$15, $7, $27, and $14, respectively 27 14 50 27
Reclassification adjustments included in net income, net of tax of
$(1), $(1), $(7), and $(3), respectively (2) (1) (13) (6)
Net income (loss) (276) 34 (86) 162
----- --- ---- ----
Total Other Comprehensive Income (Loss) $(248) $46 $(41) $183
===== === ==== ====
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-30
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 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 Notes to Consolidated Financial Statements
contained in the Consumers' Form 10-K for the year ended December 31, 2004. 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, the largest segment of which is the automotive
industry. 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 Revised FASB
Interpretation No. 46. 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. generally accepted accounting principles. 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 3, Contingencies.
CE-31
Consumers Energy Company
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 2005 2004 2005 2004
- ------------ ---- ---- ---- ----
Other income
Electric restructuring return $ 1 $ 2 $ 5 $ 5
Return on stranded and security costs 1 - 4 1
Nitrogen oxide allowance sales 1 - 2 -
Gain on stock - - 1 -
All other 3 1 4 1
--- --- --- ---
Total other income $ 6 $ 3 $16 $ 7
=== === === ===
In Millions
--------------------------------------
Three Months Ended Nine Months Ended
------------------ -----------------
September 30 2005 2004 2005 2004
- ------------ ---- ---- ---- ----
Other expense
Loss on reacquired debt $ - $ - $ (6) $ -
Civic and political expenditures (1) (1) (2) (2)
Loss on SERP investment (1) (1) (1) (1)
Other - - (1) (1)
--- --- ---- ---
Total other expense $(2) $(2) $(10) $(4)
=== === ==== ===
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
2: 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. In the third quarter of 2005, we recorded
Asset Impairment charges of $1.184 billion on our Consolidated Statements of
Income. These charges reduced our third quarter 2005 net income by $385 million.
The MCV Partnership's costs of producing electricity are tied to the price of
natural gas, but its revenues do not vary with changes in the price of natural
gas. While the average forward price of natural gas has increased steadily from
2002 through the second quarter of 2005, it remained at a level that suggested
the MCV Partnership's operating cash flow would be sufficient to provide for the
recovery of its assets. However, unforeseen natural and economic events in the
third quarter of 2005 caused a substantial upward spike in NYMEX forward natural
gas prices for the years 2005 through 2010. Additionally, other independent
natural gas long-term forward price forecasting organizations indicated their
CE-32
Consumers Energy Company
intention to raise their forecasts for the price of natural gas generally over
the entire long-term forecast horizon beyond 2010. Our analysis and assessment
of this new information suggests that forward natural gas prices for the period
from 2006 through 2010 will average approximately $9 per mcf. This compares to
the second quarter 2005 NYMEX-quoted average prices for the same forward period
of approximately $7.50 per mcf. Further, this new information indicates that
natural gas prices will average approximately $6.50 per mcf over the long term
beyond 2010. As a result, the MCV Partnership reevaluated the economics of
operating the MCV Facility and determined that an impairment analysis,
considering revised forward natural gas price assumptions, was required. In its
impairment analysis, the MCV Partnership determined the fair value of its fixed
assets by discounting a set of probability-weighted streams of future operating
cash flows at a 4.3 percent risk free interest rate. The carrying value of the
MCV Partnership's fixed assets exceeded the estimated fair value by $1.159
billion. In the third quarter of 2005, the MCV Partnership recorded an
impairment charge of $1.159 billion to recognize the reduction in fair value of
the MCV Facility's fixed assets. As a result, our net income was reduced by $369
million after considering tax effects and minority interest. The MCV
Partnership's fixed assets, which are included on our Consolidated Balance
Sheets, after reflecting the impairment charge, are valued at $219 million at
September 30, 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 financial obligations under the sale and
leaseback transactions and other contracts.
Our 49 percent interest in the MCV Partnership is held through our wholly-owned
subsidiary, CMS Midland. The severe adverse change in the anticipated economics
of the MCV Partnership operations discussed within this Note also led to our
decision to impair certain assets carried on the balance sheet of CMS Midland.
These assets represented interest capitalized during the construction of the MCV
Facility, which were being amortized over the life of the MCV Facility. In the
third quarter of 2005, we recorded an impairment charge of $25 million ($16
million, net of tax) to reduce the carrying amount of these assets to zero.
3: CONTINGENCIES
SEC AND OTHER INVESTIGATIONS: As a result of round-trip trading transactions by
CMS MST, CMS Energy's Board of Directors established a Special Committee to
investigate matters surrounding the transactions and retained outside counsel to
assist in the investigation. The Special Committee completed its investigation
and reported its findings to the Board of Directors in October 2002. The Special
Committee concluded, based on an extensive investigation, that the round-trip
trades were undertaken to raise CMS MST's profile as an energy marketer with the
goal of enhancing its ability to promote its services to new customers. The
Special Committee found no effort to manipulate the price of CMS Energy Common
Stock or affect energy prices. The Special Committee also made recommendations
designed to prevent any recurrence of this practice. Previously, CMS Energy
terminated its speculative trading business and revised its risk management
policy. The Board of Directors adopted, and CMS Energy implemented, the
recommendations of the Special Committee.
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 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 by 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.
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, including but not limited to
Consumers which, while established, operated and regulated as a separate legal
entity and publicly traded company, shares a parallel Board of Directors with
CMS Energy. The
CE-33
Consumers Energy Company
complaints were filed as purported class actions in the United States District
Court for the Eastern District of Michigan, by shareholders who allege that they
purchased CMS Energy's securities during a purported class period running from
May 2000 through March 2003. The cases were consolidated into a single lawsuit.
The consolidated lawsuit 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, a motion was granted dismissing Consumers and three of the
individual defendants, but the court denied the motions to dismiss for CMS
Energy and the 13 remaining individual defendants. Plaintiffs filed a motion for
class certification on April 15, 2005 and an amended motion for class
certification on June 20, 2005. CMS Energy and the individual defendants will
defend themselves vigorously in this litigation but cannot predict its outcome.
ERISA LAWSUITS: CMS Energy is a named defendant, along with Consumers, CMS MST,
and certain named and unnamed officers and directors, in two lawsuits brought as
purported class actions on behalf of participants and beneficiaries of the CMS
Employees' Savings and Incentive Plan (the Plan). The two cases, filed in July
2002 in United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek 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. Plaintiffs also seek other equitable
relief and legal fees. In March 2004, the judge granted in part, but denied in
part, CMS Energy's motion to dismiss the complaint. The judge has conditionally
granted plaintiffs' motion for class certification. A trial date has not been
set, but is expected to be no earlier than mid-2006. CMS Energy and Consumers
will defend themselves vigorously in this litigation but cannot predict its
outcome.
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: 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 $815 million. 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
- allowance for funds used during construction (AFUDC) rate.
Our current capital cost estimates include an escalation rate of 2.6 percent and
an AFUDC capitalization rate of 8.3 percent. As of September 2005, we have
incurred $589 million in capital expenditures to comply with these regulations
and anticipate that the remaining $226 million of capital expenditures will be
made in 2005 through 2011. These expenditures include installing selective
catalytic reduction technology at four of our coal-fired electric plants. In
addition to modifying the coal-fired electric plants, we expect to utilize
nitrogen oxide emissions allowances for years 2006 through 2008, of which 90
percent have been obtained. The cost of the allowances is estimated to average
$5 million per year
CE-34
Consumers Energy Company
for 2006 through 2008. The estimated costs are based on the average cost of the
purchased, allocated, and exchanged allowances. The need for allowances will
decrease after 2006 with the installation of selective catalytic control
technology. The cost of the allowances is accounted for as inventory. The
allowance inventory is expensed as the coal-fired electric generating units emit
nitrogen oxide.
The EPA recently adopted a Clean Air Interstate Rule that requires additional
coal-fired electric plant emission controls for nitrogen oxides and sulfur
dioxide. The rule involves a two-phase program to reduce emissions of sulfur
dioxide by 71 percent and nitrogen oxides by 63 percent by 2015. The final rule
will require that we run our Selective Catalytic Reduction 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 State Implementation
Plan, 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 a cost near that of
the Nitrogen Oxide State Implementation Plan.
In May 2005, the EPA issued the Clean Air Mercury Rule, which requires initial
reductions of mercury emissions from coal-fired electric power plants by 2010
and further reductions by 2018. While the industry has not reached a consensus
on the technical methods for curtailing mercury emissions, our capital and
operating costs for mercury emissions reductions are expected to be
significantly less than what is required for nitrogen oxide compliance.
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. The MDEQ has not indicated the direction that it will pursue to meet
or exceed the EPA requirements through a state rulemaking. We are actively
participating in dialog with the MDEQ regarding potential paths for controlling
mercury emissions and meeting the EPA requirements. In October 2005, the EPA
announced it would reconsider certain aspects of the Clean Air Mercury Rule. We
cannot predict the outcome of this proceeding.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seeking modification permits
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 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 past experience, we
estimate that our share of the total liability for the known Superfund sites
will be between $1 million and $9 million. At September 30, 2005, we have
recorded a liability for the minimum amount of our estimated Superfund
liability.
In October 1998, during routine maintenance activities, we identified PCB as a
component in certain paint, grout, and sealant materials at the Ludington Pumped
Storage facility. 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.
CE-35
Consumers Energy Company
MCV Environmental Issue: On July 12, 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 GTG duct burner and failing to maintain certain
records in the required format. The MCV Partnership has declared five of the six
duct burners in the MCV Facility as unavailable for operational use (which
reduces the generation capability of the MCV Facility by approximately 100 MW)
and is assessing the duct burner issue and has begun other corrective action to
address the MDEQ's assertions. The one available duct burner was tested in April
2005 and its emissions met permitted levels due to the unique configuration of
that particular unit. The MCV Partnership disagrees with certain of the MDEQ's
assertions. The MCV Partnership filed a response to address this MDEQ letter in
July 2004. On December 13, 2004, the MDEQ informed the MCV Partnership that it
was pursuing an escalated enforcement action against the MCV Partnership
regarding the alleged violations of the MCV Facility's PTI. The MDEQ also stated
that the alleged violations are deemed federally significant and, as such,
placed the MCV Partnership on the EPA's High Priority Violators List (HPVL). The
MDEQ and the MCV Partnership are pursuing voluntary settlement of this matter,
which will satisfy state and federal requirements and remove the MCV Partnership
from the HPVL. Any such settlement is likely to involve a fine, but at this
time, the MDEQ has not stated what, if any, fine they will seek to impose. At
this time, the MCV Partnership management cannot predict the financial impact or
outcome of this issue.
On July 13, 2004, the MDEQ, Water Division, issued the MCV Facility a Notice
Letter asserting the MCV Facility violated its National Pollutant Discharge
Elimination System (NPDES) Permit by discharging heated process wastewater into
the storm water system, failure to document inspections, and other minor
infractions (alleged NPDES violations). In August 2004, the MCV Partnership
filed a response to the MDEQ letter covering the remediation for each of the
MDEQ's alleged violations. On October 17, 2005, the MDEQ, Water Bureau, issued
the MCV Partnership a Compliance Inspection report, which listed several minor
violations and concerns that needed to be addressed by the MCV Facility. This
report was the result of an inspection of the MCV Facility in September 2005,
which was conducted for compliance and review of the Storm Water Pollution
Prevention Plans (SWPPP). All items have been addressed or corrected and the MCV
Partnership has committed to updating its SWPPP by December 1, 2005. The MCV
Partnership management believes that once it files its updated SWPPP it will
have resolved all issues associated with the Notice Letter and Compliance
Inspection and does not expect any further MDEQ actions on these matters.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities, which
sell power to us, filed a lawsuit in Ingham County Circuit Court. The lawsuit
alleges 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. 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 eight plaintiff qualifying facilities have appealed the dismissal of the
circuit court case to the Michigan Court of Appeals. The qualifying facilities
have also appealed the February 2005 MPSC order in the 2004 PSCR plan case to
the Michigan Court of Appeals, and have initiated separate legal actions in
federal district court and at the FERC concerning the energy charge calculation
issue. In June 2005, the FERC issued a notice of intent not to act on this
issue. In October 2005, the federal district court dismissed the case. We cannot
predict the outcome of the remaining appeals.
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC ROA: We cannot predict the total amount of electric supply load that
may be lost to alternative electric suppliers. As of October 2005, alternative
electric suppliers are providing 754 MW of generation service to ROA customers.
This amount represents a decrease of 14 percent compared to October 2004, and 10
percent of our total distribution load.
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Consumers Energy Company
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings.
The following chart summarizes our electric restructuring filings with the MPSC:
Year(s) Years Requested
Proceeding Filed Covered Amount Status
- ---------- ----- ------ --------- ------
Stranded Costs 2002-2004 2000-2003 $137 million (a) The MPSC ruled that we experienced zero Stranded Costs
for 2000 through 2001. The MPSC approved recovery of
$63 million in Stranded Costs for 2002 through 2003,
plus the cost of money through the period of
collection.
Implementation Costs 1999-2004 1997-2003 $91 million (b) The MPSC allowed $68 million for the years 1997-2001,
plus the cost of money through the period of
collection. The MPSC allowed $6 million for the years
2002-2003, plus the cost of money through the period
of collection.
Section 10d(4) Regulatory Assets 2004 2000-2005 $628 million Application filed with the MPSC in October 2004.
(a) Amount includes the cost of money through the year in which we expected to
receive recovery from the MPSC and assumes recovery of Clean Air Act costs
through the Section 10d(4) Regulatory Asset case.
(b) Amount includes the cost of money through the year prior to the year filed.
Section 10d(4) Regulatory Assets: Section 10d(4) of the Customer Choice Act
allows us to recover certain regulatory assets through deferred recovery of
annual capital expenditures in excess of depreciation levels and certain other
expenses incurred prior to and throughout the rate freeze and rate cap periods,
including the cost of money. The section also allows deferred recovery of
expenses incurred during the rate freeze and rate cap periods that result from
changes in taxes, laws, or other state or federal governmental actions. In
October 2004, we filed an application with the MPSC seeking recovery of $628
million of Section 10d(4) Regulatory Assets for the period June 2000 through
December 2005 consisting of:
- capital expenditures in excess of depreciation,
- Clean Air Act costs,
- other expenses related to changes in law or governmental action
incurred during the rate freeze and rate cap periods, and
- the associated cost of money through the period of collection.
Of the $628 million, $152 million relates to the cost of money.
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As allowed by the Customer Choice Act, we accrue and defer for recovery a
portion of our Section 10d(4) Regulatory Assets. In March 2005, the MPSC Staff
filed testimony recommending the MPSC approve recovery of approximately $323
million in Section 10d(4) costs, which includes the cost of money through the
period of collection. In June 2005, the ALJ issued a proposal for decision
recommending that the MPSC approve recovery of the same Section 10d(4) costs
recommended by the MPSC Staff. However, we may have the opportunity to recover
certain costs included in our application alternatively in other cases pending
before the MPSC. We cannot predict the amount, if any, the MPSC will approve as
recoverable. At September 30, 2005, total recorded Section 10d(4) Regulatory
Assets were $201 million.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system to MTH,
a non-affiliated limited partnership whose general partner is a subsidiary of
Trans-Elect, Inc. We are in arbitration with MTH regarding property tax items
used in establishing the selling price of our electric transmission system. An
unfavorable outcome could result in a reduction of sale proceeds previously
recognized of approximately $2 million to $3 million.
ELECTRIC RATE MATTERS
ELECTRIC RATE CASE: In December 2004, we filed an application with the MPSC to
increase our retail electric base rates. The electric rate case filing requests
an annual increase in revenues of approximately $320 million. The primary
reasons for the request are load migration to alternative electric suppliers,
increased system maintenance and improvement costs, Clean Air Act-related
expenditures, and employee pension costs. In April 2005, we filed updated debt
and equity information in this case.
In June 2005, the MPSC Staff filed its position in this case, recommending a
base rate increase of $98 million. The MPSC Staff also recommended an 11.25
percent return on equity to establish rates and recognized all of our projected
equity investment (infusions and retained earnings) in 2006. In August 2005, we
revised our request for an annual increase in revenues to approximately $197
million, and the MPSC Staff revised its recommendation to $100 million. In
October 2005, the ALJ issued a proposal for decision recommending a base rate
increase of $112 million and an 11.25 percent authorized return on equity. We
expect a final order from the MPSC in late 2005. If approved as requested, the
rate increase would go into effect in January 2006 and would apply to all retail
electric customers. We cannot predict the amount or timing of the rate increase,
if any, which the MPSC will approve.
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 2006 through 2007. As a result, we
have recognized an asset of $6 million for unexpired capacity and energy
contracts at September 30, 2005. As of October 2005, we expect the total premium
cost of electric capacity and energy contracts for 2005 to be approximately $8
million.
PSCR: The PSCR process is designed to allow recovery of all reasonable and
prudent power supply costs that we actually incur. In June 2005, the MPSC issued
an order that approves our 2005 PSCR plan. The 2005 PSCR charge allows us to
recover a portion of our power supply costs from commercial and industrial
customers and, subject to the overall rate caps, from other customers. The
revenues from the PSCR charges are subject to reconciliation after review of
actual costs for
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reasonableness and prudence. In March 2005, we submitted our 2004 PSCR
reconciliation filing to the MPSC. In September 2005, we submitted our 2006 PSCR
plan filing to the MPSC. Unless we receive an order from the MPSC, we expect to
self-implement this proposed 2006 PSCR charge in January 2006. We cannot predict
the outcome of these PSCR proceedings.
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 Revised FASB Interpretation No. 46. For
additional details, see Note 9, Consolidation of Variable Interest Entities.
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
cash underrecoveries of capacity and fixed energy payments as follows:
In Millions
------------------
2005 2006 2007
---- ---- ----
Estimated cash underrecoveries $56 $55 $39
Of the 2005 estimate, we expensed $43 million during the nine months ended
September 30, 2005.
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 amount that we collect from our
customers. The MCV Partnership has indicated that it may take issue with our
exercise of the regulatory out clause after September 15, 2007. We believe that
the clause is valid and fully effective, but cannot assure that it will prevail
in the event of a dispute. The MPSC's future actions on the capacity and fixed
energy payments recoverable from customers subsequent to September 15, 2007 may
affect negatively the financial performance of the MCV Partnership.
Further, 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. Natural gas prices have
increased substantially in recent years and throughout 2005. In the third
quarter of 2005, the MCV Partnership reevaluated the economics of operating the
MCV Facility and determined that an impairment was required. We are evaluating
various alternatives in order to develop a new long-term strategy with respect
to the MCV Facility. For additional details on the impairment of the MCV
Facility, see Note 2, Asset Impairment Charges.
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 will benefit our ownership interest in the MCV Partnership.
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Consumers Energy Company
The substantial MCV Facility fuel cost savings are first used to offset fully
the cost of replacement power. Second, $5 million annually, funded jointly by
Consumers and the MCV Partnership, are contributed to our RRP. Remaining savings
are split between the MCV Partnership and Consumers. Consumers' direct savings
are shared 50 percent with its customers in 2005 and 70 percent in 2006 and
beyond. Consumers' direct savings from the RCP, after allocating a portion to
customers, are used to offset our capacity and fixed energy underrecoveries
expense. Since the MPSC has excluded these underrecoveries from the rate making
process, we anticipate that our savings from the RCP will not affect our return
on equity used in our base rate filings.
In January 2005, Consumers and the MCV Partnership's general partners accepted
the terms of the order and 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. 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 2005. The
MCV Partnership estimates that the 1997 through 2005 tax year cases will result
in a refund to the MCV Partnership of approximately $83 million, inclusive of
interest, if the decision of the Michigan Tax Tribunal is upheld. The MCV
Partnership cannot predict the outcome of these proceedings; therefore, this
anticipated refund has not been recognized in earnings.
NUCLEAR PLANT DECOMMISSIONING: 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 on March 31, 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. Recently updated cost projections for Big Rock indicate an anticipated
decommissioning cost of $394 million in 2005 dollars.
Big Rock: In December 2000, funding of the Big Rock trust fund stopped because
the MPSC-authorized decommissioning surcharge collection period expired.
Excluding the additional nuclear fuel storage costs due to the DOE's failure to
accept spent fuel on schedule, we are currently projecting that the level of
funds provided by the trust for Big Rock will fall short of the amount needed to
complete the decommissioning by $57 million. At this time, we plan to provide
the additional amounts needed from our corporate funds and, subsequent to the
completion in 2007 of radiological decommissioning work, seek recovery of such
expenditures at the MPSC. We cannot predict how the MPSC will rule on our
request.
Palisades: Excluding additional nuclear fuel storage costs due to the DOE's
failure to accept spent fuel on schedule, we concluded, based on the costs
estimates filed in March 2004, that the existing surcharge for Palisades needed
to be increased to $25 million annually, beginning January 1, 2006, and
continuing through 2011, our current license expiration date. In June 2004, we
filed an application with the MPSC seeking approval to increase the surcharge
for recovery of decommissioning costs related to
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Consumers Energy Company
Palisades beginning in 2006. In September 2004, we announced that we would seek
a 20-year license renewal for Palisades. In January 2005, we filed a settlement
agreement with the MPSC that was agreed to by four of the six parties involved
in the proceeding. The settlement agreement provides for the continuation of the
existing $6 million annual decommissioning surcharge through 2011 and for the
next periodic review to be filed in March 2007. In September 2005, the MPSC
approved the contested settlement. Amounts collected from electric retail
customers and deposited in trusts, including trust earnings, are credited to a
regulatory liability and asset retirement obligation.
In March 2005, the NMC, which operates the Palisades plant, applied for a
20-year license renewal for the plant on behalf of Consumers. Certain parties
are seeking to intervene and have requested a hearing on the application. The
NRC has stated that it expects to take 22-30 months to review a license renewal
application. We expect a decision from the NRC in 2007. At this time, we cannot
determine what impact this will have on decommissioning costs or the adequacy of
funding.
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, 2005, we have recorded a
liability to the DOE of $144 million, including interest, which is payable prior
to 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.
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. On April 29, 2005, the court ruled on various cross-motions for
summary judgment previously filed by the DOE and us. The court denied the DOE's
motions to dismiss Counts I and II of the complaint and its motion seeking
recovery of a one-time fee that is due to be paid by us prior to delivery of the
spent nuclear fuel. The court, however, granted the DOE's motion to recoup the
one-time fee against any award of damages to us. The court further granted our
motion for summary judgment on liability and our motion to dismiss the DOE's
affirmative defense alleging our failure to satisfy a condition precedent. We
filed a motion for reconsideration of the portion of the Court's order dealing
with recoupment, which the Court denied. 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 July 2002, Congress approved and the President signed a bill designating the
site at Yucca Mountain, Nevada, 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.
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Consumers Energy Company
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 $28 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. The United States Congress enacted the
Price-Anderson Act to provide financial liability protection for those parties
who may be liable for a nuclear accident or incident. 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 by a combination of insurance and
a NRC indemnity totaling $544 million, and 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.
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 2003, we estimated our remaining
costs to be between $37 million and $90 million, based on 2003 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 insurance proceeds and
MPSC-approved rates. Since 2003, we have spent $14 million on remediation
activities related to the 23 sites. At September 30, 2005, we have a liability
of $34 million, net of $48 million of expenditures incurred to date, and a
regulatory asset of $62 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.
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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 for prudency in an annual
reconciliation proceeding.
The following table summarizes our GCR reconciliation filings with the MPSC.
Additional details related to the proceedings follow the table.
Gas Cost Recovery Reconciliation
Net Over-
GCR Year Date Filed Order Date recovery (a) Status
- --------- ---------- ------------- ------------ ------------------------
2003-2004 June 2004 February 2005 $31 million The net overrecovery
includes $1 million and
$5 million GCR net
overrecoveries from
prior GCR years and
interest accrued through
March 2004.
2004-2005 June 2005 Pending $2 million
(a) Net overrecoveries include refunds that we received from our suppliers,
which are required to be refunded to our customers.
GCR plan for year 2005-2006: In December 2004, we filed an application with the
MPSC seeking approval of a GCR plan for the 12-month period of April 2005
through March 2006. Our request proposed using a GCR factor consisting of:
- a base GCR factor of $6.98 per mcf, plus
- a quarterly GCR ceiling price adjustment contingent upon future
events.
The GCR factor can be adjusted monthly, provided it remains at or below the
current ceiling price. The quarterly adjustment mechanism allows an increase in
the GCR ceiling price 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 current ceiling price for 2005 is $8.73 per mcf. Actual gas
costs and revenues will be subject to an annual reconciliation proceeding.
In June 2005, four of the five parties filed a settlement agreement; the fifth
party filed a statement of non-objection. The settlement agreement includes a
GCR ceiling price adjustment contingent upon future events.
In September 2005, we filed a motion with the MPSC seeking to reopen our GCR
plan for year 2005-2006. Since the settlement agreement entered into in June
2005, there have been substantial, unanticipated increases in the market price
for natural gas. These increases have been so large that the maximum adjustments
possible under the GCR ceiling price adjustment mechanisms included in the
settlement agreement are not adequate. Unless the maximum allowable GCR factor
is increased, we will experience a substantial GCR underrecovery for the
2005-2006 GCR year. In our filing, we have requested the MPSC to:
- increase the base GCR factor from $6.98 to $9.11 per mcf, and
- revise the GCR ceiling price adjustment mechanism increasing the
maximum GCR factor from $8.73 per mcf to $11.21 per mcf.
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Consumers Energy Company
We are requesting the increase in the maximum allowable GCR factor be effective
as soon as possible but not later than January 1, 2006.
On October 6, 2005, the MPSC issued an order reopening evidentiary proceedings.
The MPSC established an expedited contested case proceeding. The MPSC Staff and
intervenors filed testimony and exhibits on October 17, 2005; rebuttal testimony
occurred October 24, 2005. The case is scheduled to be submitted directly to the
Commission without the necessity of the preparation of the ALJ's proposal for
decision on November 21, 2005.
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. The
October 2004 order also required us to undertake a study to determine why our
removal costs are in excess of those of other regulated Michigan natural gas
utilities and file a report with the MPSC Staff on or before December 31, 2005.
The MPSC has directed us to file our next gas depreciation case within 90 days
after the latter of:
- the removal cost study filing, or
- the MPSC issuance of a final order in the pending case related to ARO
accounting.
The MPSC order on the pending case related to ARO accounting is expected in the
first quarter of 2006. We proposed to incorporate the results of the gas
depreciation case into gas general rates using a surcharge mechanism if the
depreciation case order was not issued concurrently with a gas general rate case
order.
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. The primary reasons for
the request are recovery of new investments, carrying costs on natural gas
inventory related to higher gas prices, system maintenance, employee benefits,
and low-income assistance. If approved, the request would add approximately 5
percent to the typical residential customer's average monthly bill. The increase
would also affect commercial and industrial customers.
As part of this filing, we also requested interim rate relief of $75 million.
The MPSC Staff and intervenors filed interim rate relief testimony on October
31, 2005. In its testimony, the MPSC Staff recommended granting interim rate
relief of $38 million.
OTHER CONTINGENCIES
IRS RULING: On August 2, 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 use this tax accounting method,
generally allowed by the IRS under section 263A of the Internal Revenue Code,
with respect to the allocation of certain corporate overheads to the tax basis
of self-constructed utility assets. Under the IRS guidance, significant issues
with respect to the application of this method remain unresolved. Accordingly,
we cannot predict the impact of this ruling on future earnings, cash flows, or
our present NOL carryforwards.
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.
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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.
4: FINANCINGS AND CAPITALIZATION
Long-term debt is summarized as follows:
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
First mortgage bonds $3,175 $2,300
Senior notes, bank debt and other 850 1,436
Securitization bonds 378 398
------ ------
Principal amounts outstanding 4,403 4,134
Current amounts (85) (118)
Net unamortized discount (8) (16)
------ ------
Total Long-term debt $4,310 $4,000
====== ======
FINANCINGS: The following is a summary of significant long-term debt issuances
and retirements during the nine months ended September 30, 2005:
Principal Interest Rate Issue/Retirement
(In millions) (%) Date Maturity Date
------------- ------------- ------------------ --------------
DEBT ISSUANCES
FMB $250 5.15 January 2005 February 2017
FMB 300 5.65 March 2005 April 2020
FMB insured quarterly notes 150 5.65 April 2005 April 2035
LORB 35 Variable April 2005 April 2035
FMB 175 5.80 August 2005 September 2035
----
TOTAL $910
====
DEBT RETIREMENTS
Long-term bank debt $ 60 Variable January 2005 November 2006
Long-term debt - related parties 180 9.25 January 2005 December 2029
Long-term debt - related parties 73 8.36 February 2005 December 2015
Long-term debt - related parties 124 8.20 February 2005 September 2027
Senior notes 332 6.25 April and May 2005 September 2006
Senior insured quarterly notes 141 6.50 May 2005 October 2028
----
TOTAL $910
====
By the end of the first quarter of 2006, we will extinguish through a defeasance
$129 million of 9 percent notes. We classified the notes on the balance sheet as
Current portion of long-term debt - related parties.
REGULATORY AUTHORIZATION FOR FINANCINGS: In April 2005, the FERC issued an
authorization to permit us to issue up to an additional $1.0 billion ($2.0
billion in total) of long-term securities for refinancing or refunding purposes,
and up to an additional $1.0 billion ($2.5 billion in total) of long-term
securities for general corporate purposes during the period ending June 30,
2006.
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Consumers Energy Company
Combined with remaining availability from previously issued FERC authorizations,
we can now issue up to:
- $876 million of long-term securities for refinancing or refunding
purposes,
- $1.159 billion of long-term securities for general corporate purposes,
and
- $1.935 billion of long-term FMB to be issued solely as collateral for
other long-term securities.
FMB Indenture Limitations: Irrespective of our existing FERC authorization, our
ability to issue FMB as primary obligations or as collateral for financing is
governed by certain provisions of our indenture dated September 1, 1945 and its
subsequent supplements. Due to the adverse impact of the MCV Partnership asset
impairment charge recorded in September 2005 on the net earnings coverage test
in one of the governing bond-issuance provisions of the indenture, we expect our
ability to issue additional FMB will be limited to $298 million for 12 months,
ending September 30, 2006. Beyond 12 months, our ability to issue FMB in excess
of $298 million is based on achieving a two-times FMB interest coverage rate.
REVOLVING CREDIT FACILITIES: The following secured revolving credit facilities
with banks are available at September 30, 2005:
In Millions
-----------
Amount of Amount Outstanding Amount
Company Expiration Date Facility Borrowed Letters-of-Credit Available
- --------------- --------------- --------- -------- ----------------- ---------
Consumers May 18, 2010 $500 $ - $31 $469
MCV Partnership August 26, 2006 50 - 3 47
We amended our credit facility in May 2005. The amendment extended the term of
the agreement to 2010 and reduced certain fees and interest margins.
CAPITAL AND FINANCE LEASE OBLIGATIONS: Our capital leases are comprised mainly
of leased service vehicles and office furniture. At September 30, 2005, capital
lease obligations totaled $52 million. In order to obtain permanent financing
for the MCV Facility, the MCV Partnership entered into a sale and lease back
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, 2005, finance lease obligations totaled $273 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 currently 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 $100 million of receivables as of
September 30, 2005 and $304 million of receivables as of December 31, 2004. 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 not recorded a gain or loss on the receivables sold or retained interest in
the receivables sold.
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Consumers Energy Company
Certain cash flows under our accounts receivable sales program are shown in the
following table:
In Millions
---------------
Nine months ended September 30 2005 2004
- ------------------------------ ------ ------
Net cash flow as a result of accounts receivable financing $ (204) $ (247)
Collections from customers $3,782 $3,542
====== ======
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
September 30, 2005, we had $163 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. For the nine
months ended September 30, 2005, we paid $207 million in common stock dividends
to CMS Energy.
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 initial recognition and measurement provision of this
Interpretation does not apply to some guarantee contracts, such as product
warranties, derivatives, or guarantees between corporations under common
control, although disclosure of these guarantees is required.
The following table describes our guarantees at September 30, 2005:
In Millions
-------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount Provision (a)
- --------------------- -------- ---------- ---------- -------- -------------
Standby letters of credit Various Various $ 31 $ - $ -
Surety bonds Various Various 6 - -
Performance guarantee Jan 1987 Mar 2015 85 - -
Nuclear insurance retrospective premiums Various Various 135 - -
======= ======= ==== === ===
(a) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
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Consumers Energy Company
The following table provides additional information regarding our guarantees:
Guarantee Description How Guarantee Arose Events That Would Require Performance
- ------------------------------- -------------------------------------- ----------------------------------------------------
Standby letters of credit Normal operations of coal power plants Noncompliance with environmental regulations and
inadequate response to demands for corrective action
Natural gas transportation Nonperformance
Self-insurance requirement Nonperformance
Nuclear plant closure Nonperformance
Surety bonds Normal operating activity, permits and Nonperformance
license
Performance guarantee Agreement to provide power and steam Termination of the Steam and Electric Power
to Dow Agreement by Dow due to MCV's nonperformance
Nuclear insurance retrospective Normal operations of nuclear plants Call by NEIL and Price-Anderson Act for nuclear
premiums incident
In the ordinary course of business, we enter into agreements containing
indemnification provisions in connection with a variety of transactions
including financing agreements. While we cannot estimate our maximum exposure
under these indemnities, we consider the probability of liability remote.
5: 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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Consumers Energy Company
The cost and fair value of our long-term financial instruments are as follows:
In Millions
-------------------------------------------------------------
September 30, 2005 December 31, 2004
----------------------------- -----------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain (Loss) Cost Value Gain (Loss)
------ ------ ----------- ------ ------ -----------
Long-term debt, $4,395 $4,455 $(60) $4,118 $4,232 $(114)
including current amounts
Long-term debt - related parties,
including current amounts 129 132 (3) 506 518 (12)
Available-for-sale securities:
Common stock of CMS Energy 10 37 27 10 25 15
SERP:
Equity securities 16 22 6 15 21 6
Debt securities 8 8 - 9 9 -
Nuclear decommissioning investments:
Equity securities 135 252 117 136 262 126
Debt securities 288 293 5 291 302 11
====== ====== ==== ====== ====== =====
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in commodity prices, interest rates, and equity security
prices. We may use various contracts to manage these risks, including options,
futures, swaps, and forward contracts. We enter into these risk management
contracts using established policies and procedures, under the direction of both
1) an executive oversight committee consisting of senior management
representatives, and 2) a risk committee consisting of business-unit managers.
Our intention is that any gains or losses on these contracts will be offset by
an opposite movement in the value of the item at risk. We enter into all of
these contracts for purposes other than trading.
These contracts contain credit risk if the counterparties, including financial
institutions and energy marketers, fail to perform under the agreements. We
reduce this risk through established credit policies, which include performing
financial credit reviews of our counterparties. Determination of our
counterparties' credit quality is based upon a number of factors, including
credit ratings, disclosed financial condition, and collateral requirements.
Where contractual terms permit, we use standard agreements that allow us to net
positive and negative exposures associated with the same counterparty. Based on
these policies and our current exposures, we do not expect a material adverse
effect on our financial position or earnings as a result of counterparty
nonperformance.
Contracts used 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 accounted for as a derivative instrument, it is recorded on the balance sheet
as an asset or a liability, at its fair value. The value recorded is then
adjusted quarterly to reflect any change in the market value of the contract, a
practice known as marking the contract to market. If a derivative qualifies for
cash flow hedge accounting treatment, the changes in fair value (gains or
losses) are reported in Other Comprehensive Income; otherwise, the changes are
reported in earnings.
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Consumers Energy Company
For a derivative instrument to qualify for hedge accounting:
- the relationship between the derivative instrument and the item being
hedged must be formally documented at inception,
- the derivative instrument must be highly effective in offsetting the
hedged item's cash flows or changes in fair value, and
- if hedging a forecasted transaction, the forecasted transaction must
be probable.
If a derivative qualifies for cash flow hedge accounting treatment and gains or
losses are recorded in Other Comprehensive Income, those gains and 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 as of such date recorded in Accumulated other comprehensive
income 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 recorded when the forecasted transaction affects earnings. The
ineffective portion, if any, of all hedges is recognized in earnings.
We use quoted market prices, prices obtained from external sources (i.e.,
brokers and banks), and mathematical valuation models to determine the fair
value of our derivatives. For some derivatives, the time period of the contracts
may extend longer than the time periods for which market quotations for such
contracts are available. Thus, in order to calculate fair value, mathematical
models are developed to determine various inputs into the calculation, including
price and other variables. Cash returns actually realized from these commitments
may vary, either positively or negatively, from the results estimated by
applying mathematical models. As part of determining the fair value of our
derivatives, we maintain reserves, if necessary, for credit risks based on the
financial condition of counterparties.
The majority of our commodity purchase or sale contracts are not subject to
derivative accounting under SFAS No. 133 because 1) they do not have a notional
amount identified in the contract, 2) they qualify for the normal purchases and
sales exception, or 3) 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 that we purchase. Similarly, our electric capacity and energy contracts
are not derivatives due to the lack of an active energy market in Michigan and
the significant transportation costs that would be incurred to deliver the power
to the closest active energy market (the Cinergy hub in Ohio). 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 to our financial statements. For our
electric capacity and energy contracts, we believe that we will be able to apply
the normal purchases and sales exception, and, therefore, will not be required
to mark these contracts to market.
The MISO began operating the Midwest Energy Market on April 1, 2005. Through
operation of the Midwest Energy Market, the MISO centrally dispatches
electricity and transmission service throughout the Midwest and provides
day-ahead and real-time energy market information. At this time, we believe that
the commencement of this market does not constitute 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 the potential for an active energy market in Michigan.
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Consumers Energy Company
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, 2005 December 31, 2004
------------------------- --------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain Cost Value Gain (Loss)
- ---------------------- ---- ----- ---------- ---- ----- -----------
Gas supply option contracts $2 $ 6 $ 4 $2 $- $ (2)
FTRs - 1 1 - - -
Derivative contracts
associated with the MCV
Partnership:
Long-term gas contracts - 298 298 - 56 56
Gas futures and swaps - 297 297 - 64 64
The fair value of our derivative contracts is included 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. 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 as part of the GCR process. At September 30, 2005,
we had purchased fixed-priced weather-based gas supply call options and had sold
fixed-priced gas supply put options. We had not purchased any fixed-priced gas
supply call options.
FTRS: As part 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.
DERIVATIVE CONTRACTS ASSOCIATED WITH THE MCV PARTNERSHIP: Long-term gas
contracts: The MCV Partnership uses long-term gas contracts to purchase natural
gas as fuel for generation, and to manage gas fuel costs. The MCV Partnership
believes that certain of these contracts qualify as normal purchases under SFAS
No. 133. Accordingly, these contracts are not recognized at fair value on our
Consolidated Balance Sheets at September 30, 2005.
The MCV Partnership also held certain long-term gas contracts that did not
qualify as normal purchases at September 30, 2005, because these contracts
contained volume optionality. In addition, as a result of implementing the RCP
in January 2005, a significant portion of long-term gas contracts no longer
qualify as normal purchases, because the gas will not be consumed as fuel for
electric production. 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, 2005, we recorded a $242 million gain
associated with the increase in fair value of these long-term gas contracts.
This gain is included in the total Fuel costs mark-to-market at MCV on our
Consolidated Statements of Income. As a result of mark-to-market gains, we have
recorded derivative assets totaling $298 million associated with the fair value
of long-term gas contracts on our Consolidated Balance Sheets. 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. The majority of these derivative assets are expected to reverse
through earnings during 2005 and 2006 as the gas is purchased, with the
remainder reversing
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Consumers Energy Company
between 2007 and 2011. For further details on the RCP, see Note 3,
Contingencies, "Other Electric Contingencies - The Midland Cogeneration
Venture."
Gas Futures and Swaps: The MCV Partnership enters into natural gas futures
contracts, option contracts, and over-the-counter swap transactions in order to
hedge against unfavorable changes in the market price of natural gas in future
months when gas is expected to be needed. These financial instruments are used
principally to secure anticipated natural gas requirements necessary for
projected electric and steam sales, and to lock in sales prices of natural gas
previously obtained in order to optimize the MCV Partnership's existing gas
supply, storage, and transportation arrangements. At September 30, 2005, the MCV
Partnership only held natural gas futures and swaps.
The contracts that are used to secure anticipated natural gas requirements
necessary for projected electric and steam sales qualify as cash flow hedges
under SFAS No. 133. There was no ineffectiveness associated with any of these
cash flow hedges. At September 30, 2005, we have recorded a cumulative net gain
of $57 million, net of tax, in Accumulated other comprehensive income relating
to our proportionate share of the cash flow hedges held by the MCV Partnership.
This balance represents natural gas futures, options, and swaps with maturities
ranging from October 2005 to December 2009, of which $15 million of this gain,
net of tax, is expected to be reclassified as an increase to earnings during the
next 12 months as the contracts settle, offsetting the costs of gas purchases.
The MCV Partnership also holds natural gas futures and swap contracts to manage
price risk by fixing the price to be paid for natural gas on some of its
long-term gas contracts. Prior to the implementation of the RCP, these futures
and swap contracts were accounted for as cash flow hedges. Since the RCP was
implemented in January 2005, these instruments no longer qualify for cash flow
hedge accounting and any changes in their fair value have been recorded in
earnings each quarter. For the nine months ended September 30, 2005, we recorded
a $125 million gain associated with the increase in fair value of these
instruments. This gain is included in the total Fuel costs mark-to-market at MCV
on our Consolidated Statements of Income. As a result of mark-to-market gains,
we have recorded derivative assets totaling $125 million associated with the
fair value of these instruments on our Consolidated Balance Sheets, which is
included in the Gas futures and swaps amount in the Derivative Instruments table
above. 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. The majority of these derivative assets are
expected to be realized during 2005 and 2006 as the futures and swap contracts
settle, with the remainder to be realized during 2007. For further details on
the RCP, see Note 3, Contingencies, "Other Electric Contingencies - The Midland
Cogeneration Venture."
The MCV Partnership also engages in cost mitigation activities to offset fixed
charges incurred in operating the MCV Facility. These cost mitigation activities
may include the use of futures and options contracts to purchase and/or sell
natural gas to maximize the use of the transportation and storage contracts when
it is determined that they will not be needed for the MCV Facility operation.
Although these cost mitigation activities do serve to offset the fixed monthly
charges, these activities are not considered a normal course of business for the
MCV Partnership and do not qualify as hedges. Therefore, the mark-to-market
gains and losses from these cost mitigation activities are recorded in earnings
each quarter. For the nine months ended September 30, 2005, we recorded a $4
million loss associated with the decrease in fair value of futures used in these
cost mitigation activities.
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6: RETIREMENT BENEFITS
We provide retirement benefits to our employees under a number of different
plans, including:
- non-contributory, defined benefit Pension Plan,
- a cash balance pension plan for certain employees hired after June 30,
2003,
- a defined company contribution plan for employees hired on or after
September 1, 2005,
- benefits to certain management employees under SERP,
- a defined contribution 401(k) plan,
- benefits to a select group of management under 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.
On September 1, 2005, we implemented the Defined Company Contribution Plan. The
Defined Company Contribution Plan provides an employer cash contribution of 5
percent of base pay to the existing Employees' Savings Plan. No employee
contribution is required to receive the plan's employer contribution. All
employees hired on and after September 1, 2005 participate in this plan as part
of their retirement benefit program. Cash balance pension plan participants also
participate in the Defined Company Contribution Plan on September 1, 2005.
Additional pay credits under the cash balance pension plan were discontinued as
of that date. The Defined Company Contribution Plan cost for the nine months
ended September 30, 2005 was less than $1 million.
On January 1, 2005, we resumed the employer's match in CMS Energy Stock on our
401(k) Savings Plan. On September 1, 2005, employees enrolled in the company's
401(k) Savings Plan had their employer match increased from 50 percent to 60
percent on eligible contributions up to the first six percent of an employee's
wages. The total 401(k) Savings Plan cost for the nine months ended September
30, 2005 was $9 million.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003 was
signed into law in December 2003. The Act establishes a prescription drug
benefit under Medicare (Medicare Part D), and a federal subsidy, which is
tax-exempt, to sponsors of retiree health care benefit plans that provide a
benefit that is actuarially equivalent to Medicare Part D. We believe our plan
is actuarially equivalent to Medicare Part D.
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Consumers Energy Company
Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
--------------------------------------
Pension
--------------------------------------
SEPTEMBER 30 Three Months Ended Nine Months Ended
- ------------ ------------------ -----------------
2005 2004 2005 2004
---- ---- ---- ----
Service cost $ 9 $ 10 $ 32 $ 29
Interest expense 15 17 60 53
Expected return on plan assets (17) (26) (75) (80)
Amortization of:
Net loss 11 3 25 10
Prior service cost 1 1 4 4
---- ---- ---- ----
Net periodic pension cost $ 19 $ 5 $ 46 $ 16
==== ==== ==== ====
In Millions
--------------------------------------
OPEB
--------------------------------------
SEPTEMBER 30 Three Months Ended Nine Months Ended
- ------------ ------------------ -----------------
2005 2004 2005 2004
---- ---- ---- ----
Service cost $ 7 $ 4 $ 17 $ 13
Interest expense 15 14 45 41
Expected return on plan assets (14) (11) (40) (34)
Amortization of:
Net loss 5 3 15 9
Prior service cost (3) (2) (7) (6)
---- ---- ---- ----
Net periodic postretirement
benefit cost $ 10 $ 8 $ 30 $ 23
==== ==== ==== ====
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 nine
months ended September 30, 2005 was less than $1 million.
We remeasured our Pension and OPEB obligations as of April 30, 2005 to
incorporate the effects of the collective bargaining agreement reached between
the Utility Workers Union of America and Consumers. The Pension plan
remeasurement increased our ABO by $127 million. Net periodic pension cost is
expected to increase $12 million for 2005.
The Pension plan remeasurement resulted in an unfunded ABO of $208 million. The
unfunded ABO is the amount by which the ABO exceeds the fair value of the plan
assets. SFAS No. 87 states that the pension liability shown on the balance sheet
must be at least equal to the unfunded ABO. As such, we increased our additional
minimum liability by $129 million to $521 million at June 30, 2005. Consistent
with MPSC guidance, we recognized the cost of our minimum pension liability
adjustment as a regulatory asset. This adjustment increased our regulatory
assets by $94 million and intangible assets by $35 million.
The OPEB plan remeasurement increased our accumulated postretirement benefit
obligation by $41 million, with an expected total increase in benefit costs of
$2 million for 2005.
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Consumers Energy Company
7: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143: 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. As
required by SFAS No. 71, we accounted for the implementation of this standard by
recording regulatory assets and liabilities instead of a cumulative effect of a
change in accounting principle.
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 $22 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. 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.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life:
September 30, 2005 In Millions
-----------
In Service Trust
ARO Description Date Long Lived Assets Fund
- --------------- ---------- ----------------- -----
Palisades - decommission plant site 1972 Palisades nuclear plant $537
Big Rock - decommission plant site 1962 Big Rock nuclear plant 18
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 -
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In Millions
-----------
ARO ARO
Liability Cash flow Liability
ARO Description 12/31/04 Incurred Settled Accretion Revisions 9/30/05
- --------------- --------- -------- ------- --------- --------- ---------
Palisades - decommission $350 $ - $ - $19 $ - $369
Big Rock - decommission 30 - (33) 11 - 8
JHCampbell intake line - - - - - -
Coal ash disposal areas 54 - (3) 4 - 55
Wells at gas storage fields 1 - - - - 1
Indoor gas services relocations 1 - - - - 1
---- --- ---- --- --- ----
Total $436 $ - $(36) $34 $ - $434
==== === ==== === === ====
On October 14, 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. Utilities
filed responses to the Order in March 2005; the MPSC Staff and intervenors filed
responses in May 2005; a proposal for decision is expected in December 2005. We
consider the proceeding as involving a clarification of accounting and reporting
issues that relate to all Michigan utilities. We cannot predict the outcome of
the proceeding.
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 2005 2004 2005 2004
- ------------ ------ ---- ----- -------
Operating revenue
Electric $ 794 $704 $2,071 $1,947
Gas 219 171 1,566 1,376
Other 12 10 36 32
------ ---- ------ ------
Total Operating Revenue $1,025 $885 $3,673 $3,355
====== ==== ====== ======
Net income (loss) available to
common stockholder
Electric $ 62 $ 49 $ 141 $ 124
Gas (16) (11) 39 46
Other (322) (4) (267) (9)
------ ---- ------ ------
Total Net (Loss) Income Available to
Common Stockholder $ (276) $ 34 $ (87) $ 161
====== ==== ====== ======
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Consumers Energy Company
In Millions
--------------------------------------
September 30, 2005 December 31, 2004
------------------ -----------------
Assets
Electric (a) $ 7,584 $ 7,289
Gas (a) 3,650 3,187
Other 1,827 2,335
------- -------
Total Assets $13,061 $12,811
======= =======
(a) Amounts include a portion of our other common assets attributable to both
the electric and gas utility businesses.
9: CONSOLIDATION OF VARIABLE INTEREST ENTITIES
We are the primary beneficiary of both the MCV Partnership and the FMLP. We have
a 49 percent partnership interest in the MCV Partnership and a 46.4 percent
partnership interest in the FMLP. Consumers is the primary purchaser of power
from the MCV Partnership through a long-term power purchase agreement. The FMLP
holds a 75.5 percent lessor interest in the MCV Facility, which results in
Consumers holding a 35 percent lessor interest in the MCV Facility.
Collectively, these interests make us the primary beneficiary of these entities.
Therefore, we consolidated these partnerships into our consolidated financial
statements for all periods presented. These partnerships have third-party
obligations totaling $480 million at September 30, 2005. Property, plant, and
equipment serving as collateral for these obligations has a carrying value of
$219 million at September 30, 2005. The creditors of these partnerships do not
have recourse to the general credit of Consumers.
10: NEW ACCOUNTING STANDARDS NOT YET EFFECTIVE
SFAS NO. 123R, SHARE-BASED PAYMENT: This Statement 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 amount over the vesting period of
the awards. This Statement also clarifies and expands SFAS No. 123's guidance in
several areas, including measuring fair value, classifying an award as equity or
as a liability, and attributing compensation cost to reporting periods.
This Statement amends SFAS No. 95, Statement of Cash Flows, to require that
excess tax benefits related to the excess of the tax-deductible amount over the
compensation cost recognized be classified as cash inflows from financing
activities rather than as a reduction of taxes paid in operating activities.
Excess tax benefits are recorded as adjustments to additional paid-in capital.
This Statement is effective for us as of the beginning of 2006. We adopted the
fair value method of accounting for share-based awards effective December 2002.
Therefore, we do not expect this statement to have a significant impact on our
results of operations when it becomes effective.
FASB INTERPRETATION NO. 47, ACCOUNTING FOR CONDITIONAL ASSET RETIREMENT
OBLIGATIONS: This Interpretation clarifies 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 that may or may not be
within the control of the entity. The obligation to perform the asset retirement
activity is unconditional even though uncertainty exists about the timing and
(or) method of settlement. Accordingly, an entity is required to recognize a
liability for the fair value of a conditional asset retirement obligation if the
fair value of the liability can
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Consumers Energy Company
be reasonably estimated. The fair value of a liability for the conditional asset
retirement obligation should be recognized when incurred. This Interpretation
also clarifies when an entity would have sufficient information to estimate
reasonably the fair value of an asset retirement obligation. For us, this
Interpretation is effective no later than December 31, 2005. We are in the
process of determining the impact this Interpretation will have on our financial
statements upon adoption.
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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, as of the end of such period, its disclosure controls and procedures are
effective.
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.
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 and Consumers' Forms 10-K for the year ended December
31, 2004. Reference is also made to the Condensed Notes to the Consolidated
Financial Statements, in particular, Note 3, Contingencies, for CMS Energy and
Note 3, Contingencies, for Consumers, included herein for additional information
regarding various pending administrative and judicial proceedings involving
rate, operating, regulatory and environmental matters.
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CMS ENERGY
SEC REQUEST
On August 5, 2004, CMS Energy received a request from the SEC that CMS Energy
voluntarily produce all documents and data relating to the SEC's inquiry into
payments made to 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. 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 has been and will continue to produce documents responsive to
the subpoena.
SETTLEMENT OF DEMAND FOR ACTION AGAINST OFFICERS AND DIRECTORS
In May 2002, the Board of Directors of CMS Energy received a demand, on behalf
of a shareholder of CMS Energy Common Stock, that it commence civil actions (i)
to remedy alleged breaches of fiduciary duties by certain CMS Energy officers
and directors in connection with round-trip trading by CMS MST, and (ii) to
recover damages sustained by CMS Energy as a result of alleged insider trades
alleged to have been made by certain current and former officers of CMS Energy
and its subsidiaries. In December 2002, two new directors were appointed to the
Board. The Board formed a special litigation committee in January 2003 to
determine whether it was in CMS Energy's best interest to bring the action
demanded by the shareholder. The disinterested members of the Board appointed
the two new directors to serve on the special litigation committee.
In December 2003, during the continuing review by the special litigation
committee, CMS Energy was served with a derivative complaint filed by the
shareholder on behalf of CMS Energy in the Circuit Court of Jackson County,
Michigan in furtherance of his demands.
On July 7, 2005, CMS Energy filed with the court a Stipulation of Settlement
that was signed by all parties as well as the special litigation committee. The
judge entered the Final Order and Judgment on August 26, 2005. Pursuant to the
terms of the settlement, on September 5, 2005, CMS Energy received $12 million
from its insurance carriers under its directors and officers liability insurance
program, $7 million of which will be used to pay any reasonable settlement,
judgment or other costs associated with the securities class action lawsuits.
CMS Energy may use the remaining $5 million to pay attorneys' fees and expenses
arising out of the derivative proceeding.
GAS INDEX PRICE REPORTING LITIGATION
In August 2003, Cornerstone Propane Partners, L.P. (Cornerstone) filed a
putative class action complaint in the United States District Court for the
Southern District of New York against CMS Energy and dozens of other energy
companies. The Cornerstone complaint was subsequently consolidated with two
similar complaints filed by other plaintiffs. The plaintiffs filed a
consolidated complaint on January 20, 2004. The consolidated complaint alleges
that false natural gas price reporting by the defendants manipulated the prices
of NYMEX natural gas futures and options. The complaint contains two counts
under the Commodity Exchange Act, one for manipulation and one for aiding and
abetting violations. On September 30, 2005, the court entered an order granting
plaintiffs' motion for class certification.
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Plaintiffs are seeking to have the class recover actual damages and costs,
including attorneys fees. CMS Energy is no longer a defendant, however, CMS MST
and CMS Field Services are named as defendants. (CMS Energy sold CMS Field
Services to Cantera Natural Gas, LLC, which changed the name of CMS Field
Services to Cantera Gas Company. CMS Energy is required to indemnify Cantera
Natural Gas, LLC with respect to this action.)
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.
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.
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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 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. On April 8, 2005, defendants filed a demurrer to
the master class action complaint and the individual complaints and on May 13,
2005, plaintiffs filed a memorandum of points and authorities in opposition to
defendants' federal preemption demurrer and motion to strike. Pursuant to a
ruling dated June 29, 2005, the demurrer was overruled and the motion to strike
was denied.
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 March 7, 2005, defendants removed the case to the United
States District Court for the Western District of Tennessee, Western Division,
and they filed a motion on May 20, 2005 to transfer the case to the MDL
proceeding in Nevada. On April 6, 2005, plaintiffs filed a motion to remand the
case back to the Chancery Court in Tennessee. Defendants filed a motion to stay
proceedings pending resolution of the motion to remand and plaintiffs have filed
a response, objecting to defendants' motion. The parties are considering further
extending the time to answer or otherwise respond to the complaint until after
the motion to remand is decided.
CMS Energy and the other CMS defendants will defend themselves vigorously
against 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,
including but not limited to Consumers which, while established, operated and
regulated as a separate legal entity and publicly traded company, shares a
parallel Board of Directors with CMS Energy. The complaints were filed as
purported class actions in the United States District Court for the Eastern
District of Michigan, by shareholders who allege that they purchased CMS
Energy's securities during a purported class period running from May 2000
through March 2003. The cases were consolidated into a single lawsuit. The
consolidated lawsuit 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, a motion was
granted dismissing Consumers and three of the individual defendants, but the
court denied the motions to dismiss for CMS Energy and the 13 remaining
individual defendants. Plaintiffs filed a motion for class certification on
April 15, 2005 and an amended motion for class certification on June 20, 2005.
CMS Energy and the individual defendants will defend themselves vigorously in
this litigation but cannot predict its outcome.
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ERISA LAWSUITS
CMS Energy is a named defendant, along with Consumers, CMS MST, and certain
named and unnamed officers and directors, in two lawsuits brought as purported
class actions on behalf of participants and beneficiaries of the CMS Employees'
Savings and Incentive Plan (the Plan). The two cases, filed in July 2002 in
United States District Court for the Eastern District of Michigan, were
consolidated by the trial judge and an amended consolidated complaint was filed.
Plaintiffs allege breaches of fiduciary duties under ERISA and seek 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. Plaintiffs also seek other equitable
relief and legal fees. In March 2004, the judge granted in part, but denied in
part, CMS Energy's motion to dismiss the complaint. The judge has conditionally
granted plaintiffs' motion for class certification. A trial date has not been
set, but is expected to be no earlier than mid-2006. CMS Energy and Consumers
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 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None.
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 2006 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 19,
2005. In any event if CMS Energy has not received written notice of any matter
to be proposed at that meeting by March 4, 2006, 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.
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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 1, 2005 By: /s/ Thomas J. Webb
------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
CONSUMERS ENERGY COMPANY
(Registrant)
Dated: November 1, 2005 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