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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 MARCH 31, 2004
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.
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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]
Number of shares outstanding of each of the issuer's classes of common stock at
April 30, 2004:
CMS ENERGY CORPORATION:
CMS Energy Common Stock, $.01 par value 163,544,282
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 MARCH 31, 2004
This combined Form 10-Q is separately filed by CMS Energy Corporation and
Consumers Energy Company. Information contained herein relating to each
individual registrant is filed by such registrant on its own behalf.
Accordingly, except for its subsidiaries, Consumers Energy Company makes no
representation as to information relating to any other companies affiliated with
CMS Energy Corporation.
TABLE OF CONTENTS
Page
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Glossary........................................................................................... 4
PART I: FINANCIAL INFORMATION
CMS Energy Corporation
Management's Discussion and Analysis
Executive Overview...................................................................... CMS - 1
Restatement of 2003 Financial Statements................................................ CMS - 2
Consolidation of the MCV Partnership and the FMLP....................................... CMS - 2
Forward-Looking Statements and Risk Factors............................................. CMS - 2
Results of Operations................................................................... CMS - 4
Critical Accounting Policies............................................................ CMS - 7
Capital Resources and Liquidity......................................................... CMS - 19
Outlook................................................................................. CMS - 23
New Accounting Standards................................................................ CMS - 34
Consolidated Financial Statements
Consolidated Statements of Income (Loss)................................................ CMS - 38
Consolidated Statements of Cash Flows................................................... CMS - 40
Consolidated Balance Sheets............................................................. CMS - 42
Consolidated Statements of Common Stockholders' Equity.................................. CMS - 44
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies........................................ CMS - 45
2. Discontinued Operations, Other Asset Sales, Impairments, and Restructuring......... CMS - 47
3. Uncertainties...................................................................... CMS - 51
4. Financings and Capitalization...................................................... CMS - 72
5. Earnings Per Share and Dividends................................................... CMS - 76
6. Financial and Derivative Instruments............................................... CMS - 77
7. Retirement Benefits................................................................ CMS - 82
8. Equity Method Investments.......................................................... CMS - 83
9. Reportable Segments................................................................ CMS - 84
10. Asset Retirement Obligations........................................................ CMS - 85
11. Implementation of New Accounting Standards.......................................... CMS - 86
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TABLE OF CONTENTS
(CONTINUED)
Page
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Consumers Energy Company
Management's Discussion and Analysis
Executive Overview...................................................................... CE - 1
Consolidation of the MCV Partnership and the FMLP....................................... CE - 2
Forward-Looking Statements and Risk Factors............................................. CE - 2
Results of Operations................................................................... CE - 3
Critical Accounting Policies............................................................ CE - 7
Capital Resources and Liquidity......................................................... CE - 15
Outlook................................................................................. CE - 19
New Accounting Standards................................................................ CE - 29
Consolidated Financial Statements
Consolidated Statements of Income....................................................... CE - 31
Consolidated Statements of Cash Flows................................................... CE - 32
Consolidated Balance Sheets............................................................. CE - 34
Consolidated Statements of Common Stockholder's Equity.................................. CE - 36
Condensed Notes to Consolidated Financial Statements:
1. Corporate Structure and Accounting Policies......................................... CE - 38
2. Uncertainties....................................................................... CE - 41
3. Financings and Capitalization....................................................... CE - 57
4. Financial and Derivative Instruments................................................ CE - 59
5. Retirement Benefits................................................................. CE - 64
6. Asset Retirement Obligations........................................................ CE - 65
7. Implementation of New Accounting Standards.......................................... CE - 66
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 5. Other Information........................................................................ CO - 5
Item 6. Exhibits and Reports on Form 8-K......................................................... CO - 5
Signatures....................................................................................... CO - 7
3
GLOSSARY
Certain terms used in the text and financial statements are defined below
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.
AEP..................................... American Electric Power, a non-affiliated company
ALJ..................................... Administrative Law Judge
Alliance RTO............................ Alliance Regional Transmission Organization
Alstom.................................. Alstom Power Company
APB..................................... Accounting Principles Board
APB Opinion No. 18...................... APB Opinion No. 18, "The Equity Method of Accounting for Investments in Common Stock"
APT..................................... Australian Pipeline Trust
ARO..................................... Asset retirement obligation
Articles................................ Articles of Incorporation
Attorney General........................ Michigan Attorney General
bcf..................................... Billion cubic feet
Big Rock................................ Big Rock Point nuclear power plant, owned by Consumers
Board of Directors...................... Board of Directors of CMS Energy
Btu..................................... British thermal unit
CEO..................................... Chief Executive Officer
CFO..................................... Chief Financial Officer
Clean Air Act........................... Federal Clean Air Act, as amended
CMS Electric and Gas.................... CMS Electric and Gas Company, a subsidiary of Enterprises
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 Holdings............................ CMS Midland Holdings Company, a subsidiary of Consumers
CMS Midland............................. CMS Midland Inc., a subsidiary of Consumers
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
CMS Pipeline Assets..................... CMS Enterprises pipeline assets in Michigan and Australia
4
CMS Viron............................... CMS Viron Energy Services, formerly a wholly owned subsidiary of CMS MST. The sale
of this subsidiary closed in June 2003.
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
Consumers............................... Consumers Energy Company, a subsidiary of CMS Energy
Consumers Funding....................... Consumers Funding LLC, a wholly-owned special purpose subsidiary of Consumers for
the issuance of securitization bonds dated November 8, 2001
Consumers Receivables Funding II........ Consumers Receivables Funding II LLC, a wholly-owned subsidiary of Consumers
Court of Appeals........................ Michigan Court of Appeals
CPEE.................................... Companhia Paulista de Energia Eletrica, a subsidiary of Enterprises
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
Dow..................................... The Dow Chemical Company, a non-affiliated company
EISP.................................... Executive Incentive Separation Plan
EITF.................................... Emerging Issues Task Force
EITF Issue No. 02-03.................... Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities
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
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
Ford.................................... Ford Motor Company
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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
GEII.................................... General Electric International Inc.
Guardian................................ Guardian Pipeline, LLC, in which CMS Gas Transmission owned a one-third interest
Health Care Plan........................ The medical, dental, and prescription drug programs offered to eligible employees of
Consumers and CMS Energy
HL Power................................ H.L. Power Company, a California Limited Partnership, owner of the Honey Lake
generation project in Wendel, California
Integrum................................ Integrum Energy Ventures, LLC
IPP..................................... Independent Power Production
JOATT................................... Joint Open Access Transmission Tariff
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
LIBOR................................... London Inter-Bank Offered Rate
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 holds a 50 percent ownership interest
LNG..................................... Liquefied natural gas
Ludington............................... Ludington pumped storage plant, jointly owned by Consumers and Detroit Edison
Marysville.............................. CMS Marysville Gas Liquids Company, a Michigan corporation and a subsidiary of CMS
Gas Transmission that held a 100 percent interest in Marysville Fractionation
Partnership and a 51 percent interest in St. Clair Underground Storage Partnership
mcf..................................... Thousand cubic feet
MCV Expansion, LLC...................... An agreement entered into with General Electric Company to expand the MCV Facility
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
MD&A.................................... Management's Discussion and Analysis
METC.................................... Michigan Electric Transmission Company, formerly a subsidiary of Consumers Energy
and now an indirect subsidiary of Trans-Elect
6
Michigan Power.......................... CMS Generation Michigan Power, LLC, owner of the Kalamazoo River Generating Station
and the Livingston Generating Station
MISO.................................... Midwest Independent System Operator
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
NERC.................................... North American Electric Reliability Council
NRC..................................... Nuclear Regulatory Commission
NYMEX................................... New York Mercantile Exchange
OATT.................................... Open Access Transmission Tariff
OPEB.................................... Postretirement benefit plans other than pensions for retired employees
Palisades............................... Palisades nuclear power plant, which is owned by Consumers
Panhandle Eastern Pipe Line
or 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.
Parmelia................................ A business located in Australia comprised of a pipeline, processing facilities, and
a gas storage facility, a subsidiary of CMS Gas Transmission
PCB..................................... Polychlorinated biphenyl
Pension Plan............................ The trusteed, non-contributory, defined benefit pension plan of Panhandle, Consumers
and CMS Energy
PJM RTO................................. Pennsylvania-Jersey-Maryland Regional Transmission Organization
Powder River............................ CMS Oil & Gas previously owned a significant interest in coalbed methane fields or
projects developed within the Powder River Basin which spans the border between
Wyoming and Montana. The Powder River properties have been sold.
PPA..................................... The Power Purchase Agreement between Consumers and the MCV Partnership with a
35-year term commencing in March 1990
7
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
PUHCA................................... Public Utility Holding Company Act of 1935
PURPA................................... Public Utility Regulatory Policies Act of 1978
ROA..................................... Retail Open Access
RTO..................................... Regional Transmission Organization
Rouge................................... Rouge Steel Industries
SCP..................................... Southern Cross Pipeline in Australia, in which CMS Gas Transmission holds a 45
percent ownership interest
SEC..................................... U.S. Securities and Exchange Commission
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.A., 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. 52............................. SFAS No. 52, "Foreign Currency Translation"
SFAS No. 71............................. SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
SFAS No. 87............................. SFAS No. 87, "Employers' Accounting for Pensions"
SFAS No. 88............................. SFAS No. 88, "Employers' Accounting for Settlements and Curtailments of Defined
Benefit Pension Plans and for Termination Benefits"
SFAS No. 106............................ SFAS No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
SFAS No. 107............................ Disclosures about Fair Value of Financial Instruments
SFAS No. 115............................ SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities"
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"
SFAS No. 144............................ SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets"
SFAS No. 148............................ SFAS No. 148, "Accounting for Stock-Based Compensation - Transition and Disclosure"
SFAS No. 149............................ SFAS No. 149, "Amendment of Statement No. 133 on Derivative Instruments and Hedging
Activities"
8
SFAS No. 150............................ SFAS No. 150, "Accounting for Certain Financial Instruments with Characteristics of
Both Liabilities and Equity"
Southern Union.......................... Southern Union Company, a non-affiliated company
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 forty percent interest
TEPPCO.................................. Texas Eastern Products Pipeline Company, LLC
Toledo Power............................ Toledo Power Company, the 135 MW coal and fuel oil power plant located on Cebu
Island, Phillipines, in which CMS Generation held a 47.5 percent interest.
Transition Costs........................ Stranded Costs, as defined, plus the costs incurred in the transition to competition
Trunkline............................... Trunkline Gas Company, LLC, formerly a subsidiary of CMS Panhandle Holdings, LLC
Trunkline LNG........................... Trunkline LNG Company, LLC, formerly a subsidiary of LNG Holdings, LLC
Trust Preferred Securities.............. Securities representing an undivided beneficial interest in the assets of statutory
business trusts, the interests of which have a preference with respect to certain
trust distributions over the interests of either CMS Energy or Consumers, as
applicable, as owner of the common beneficial interests of the trusts
VEBA Trusts............................. VEBA (voluntary employees' beneficiary association) Trusts accounts established to
specifically set aside employer contributed assets to pay for future expenses of the
OPEB plan
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CMS ENERGY CORPORATION
CMS ENERGY CORPORATION
MANAGEMENT'S DISCUSSION AND ANALYSIS
This MD&A is a combined 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
combined entity, except where it is made clear that such term means only CMS
Energy.
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 subsidiaries, is engaged in
domestic and international diversified energy businesses including: independent
power production; natural gas transmission, storage and processing; and energy
services. We manage our businesses by the nature of services each provides and
operate principally in three business segments: electric utility, gas utility,
and enterprises.
We earn our revenue and generate cash from operations by providing electric and
natural gas utility services, electric power generation, gas transmission,
storage, and processing, and other energy services. Our businesses are affected
by weather, especially during the key heating and cooling seasons, economic
conditions, particularly in Michigan, regulation and regulatory issues that
primarily affect our gas and electric utility operations, interest rates, our
debt credit rating, and energy commodity prices.
Our strategy involves rebuilding our balance sheet and refocusing on our core
strength: superior utility operation. Over the next few years, we expect this
strategy to reduce our parent company debt substantially, improve our debt
ratings, grow earnings at a mid-single digit rate, restore a meaningful
dividend, and position the company to make new investments consistent with our
strengths. In the near term, our new investments will focus on the utility.
We face important challenges in the future. We continue to lose industrial and
commercial customers to other electric suppliers without receiving compensation
for stranded costs caused by the lost sales. As of April 2004, we lost 823 MW or
10 percent of our electric business to these alternative electric suppliers. We
expect the loss to grow to over 1,100 MW in 2004. Existing state legislation
encourages competition and provides for recovery of stranded costs, but the MPSC
has not yet authorized stranded cost recovery. We continue to work cooperatively
with the MPSC to resolve this issue.
Further, higher natural gas prices have harmed the economics of the MCV and we
are seeking approval from the MPSC to change the way in which the facility is
used. Our proposal would reduce gas consumption by an estimated 30 to 40 bcf per
year while improving the MCV's financial performance with no change to customer
rates. A portion of the benefits from the proposal will support additional
renewable resource development in Michigan. Resolving the issue is critical for
our shareowners and customers.
We also are focused on further reducing our business risk and leverage, while
growing the equity base of our company. Much of our asset sales program is
complete; we are focused on selling the remaining businesses that are not
strategic to us. This creates volatility in earnings as we recognize foreign
currency translation account losses at the time of sale, but it is the right
strategic direction for our company. In April 2004, we and our partners sold the
2,000-megawatt Loy Yang power plant and adjacent coal mine in Victoria,
Australia for about A$3.5 billion ($2.6 billion in U.S. dollars), including
A$145 million for the
CMS-1
CMS ENERGY CORPORATION
project equity. Our gross proceeds were about $54 million and are subject to
closing adjustments and transaction costs.
Finally, we are working to resolve outstanding litigation that stemmed from
energy trading and gas index price reporting activities in 2001 and earlier.
Doing so will permit us to devote more attention to improving business growth.
In March 2004, the SEC imposed a cease-and-desist order settling an
administrative action against CMS Energy related to round-trip trading. The
settlement resolved the SEC investigation involving CMS Energy and CMS MST.
Our business plan is targeted at predictable earnings growth and debt reduction.
We are now over a year into our plan to reduce by about half the debt of CMS
Energy over a five-year period. The result of these efforts will be a strong,
reliable energy company that will be poised to take advantage of opportunities
for further growth.
RESTATEMENT OF 2003 FINANCIAL STATEMENTS
Our financial statements as of and for the quarter ended March 31, 2003, as
presented in this Form 10-Q, have been restated for the following matters that
were previously disclosed in Note 19, Quarterly Financial and Common Stock
Information (Unaudited), in our 2003 Form 10-K:
- International Energy Distribution, which includes SENECA and CPEE,
is no longer considered "discontinued operations," due to a change
in our expectations as to the timing of the sales, and
- certain derivative accounting corrections at our equity affiliates,
which were reflected in our 2003 Form 10-K.
CONSOLIDATION OF THE MCV PARTNERSHIP AND THE FMLP
Under revised FASB Interpretation No. 46, we are the primary beneficiary of the
MCV Partnership and the FMLP. As a result, we have consolidated their assets,
liabilities, and activities into our financial statements for the first time as
of and for the quarter ended March 31, 2004. The MCV Partnership and the FMLP
were previously reported as equity method investments. Therefore, the
consolidation of these entities had no impact on our consolidated net loss. For
additional details, see Note 11, Implementation of New Accounting Standards.
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 Exchange Act, as
amended, Rule 175 of the Securities Act of 1933, as amended, and relevant legal
decisions. Our intention with the use of such words as "may," "could,"
"anticipates," "believes," "estimates," "expects," "intends," "plans," and other
similar words is to identify forward-looking statements that involve risk and
uncertainty. We designed this discussion of potential risks and uncertainties to
highlight important factors that may impact our business and financial outlook.
We have no obligation to update or revise forward-looking statements regardless
of whether new information, future events or any other factors affect the
information contained in the statements. These forward-looking statements are
subject to various factors that could cause our actual results to differ
materially from the results anticipated in these statements. Such factors
include our inability to predict and/or control:
- the efficient sale of non-strategic or under-performing domestic or
international assets and discontinuation of certain operations,
CMS-2
CMS ENERGY CORPORATION
- capital and financial market conditions, including the current price
of CMS Energy Common Stock and the effect on the Pension Plan,
interest rates and 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,
- security ratings of CMS Energy, Consumers, or any of their
affiliates,
- currency fluctuations, transfer restrictions, and exchange controls,
- factors affecting utility and diversified energy operations such as
unusual weather conditions, catastrophic weather-related damage,
unscheduled generation outages, maintenance or repairs,
environmental incidents, or electric transmission or gas pipeline
system constraints,
- ability to access the capital markets successfully,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including environmental laws
and regulations,
- federal regulation of electric sales and transmission of electricity
including re-examination by federal regulators of the market-based
sales authorizations by which our subsidiaries participate in
wholesale power markets without price restrictions, and proposals by
the FERC to change the way it currently lets our subsidiaries and
other public utilities and natural gas companies interact with each
other,
- energy markets, including the timing and extent of unanticipated
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,
- 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,
- 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,
CMS-3
CMS ENERGY CORPORATION
- 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 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.
RESULTS OF OPERATIONS
CMS Energy's business plan focuses on strengthening CMS Energy's balance sheet
and improving financial liquidity through debt reduction and aggressive cost
management. The on-going asset sales program's objectives are to generate cash
to reduce debt, reduce business risk and provide for more predictable future
earnings. This program encompasses the sale of non-strategic and
under-performing assets, the proceeds of which are being used primarily to
reduce debt.
CMS ENERGY CONSOLIDATED RESULTS OF OPERATIONS
In Millions (except for per share amounts)
- ------------------------------------------------------------------------------
Restated
Three months ended March 31 2004 2003 Change
- --------------------------- ------ ------ ------
Net Income (Loss) $ (11) $ 82 $ (93)
Basic Earnings (Loss) Per Share $(0.07) $ 0.57 $(0.64)
Diluted Earnings (Loss) Per Share $(0.07) $ 0.52 $(0.59)
------ ------ ------
Electric Utility $ 45 $ 51 $ (6)
Gas Utility 55 54 1
Enterprises (61) 21 (82)
Corporate Interest and Other (48) (51) 3
Discontinued Operations (2) 31 (33)
Accounting Changes - (24) 24
------ ------ ------
CMS Energy Net Income (Loss) $ (11) $ 82 $ (93)
====== ====== ======
For the three months ended March 31, 2004, CMS Energy's net loss was $11
million, compared to $82 million of net income for the three months ended March
31, 2003. The $93 million change reflects:
- $81 million after-tax impairment charge on our Loy Yang investment.
The impairment charge was recorded in connection with the sale of
Loy Yang which was completed in April 2004,
- the absence of earnings in discontinued operations from Panhandle
and other businesses sold in prior periods, and
- the reduction in electricity revenue resulting primarily from the
continuing switch by industrial customers to alternative suppliers
as allowed by the Customer Choice Act. For additional details, see
"Electric Utility Results of Operations" within this section.
These losses were partially offset by:
CMS-4
CMS ENERGY CORPORATION
- the exclusion in 2004 of a $24 million charge in 2003 that resulted
from a cumulative effect of changes in accounting, and
- income of $8 million (net of tax) in 2004 reflecting a settlement
agreement that DIG and CMS MST entered into with Ford and Rouge.
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
- ---------------------------------------------------------------------------
March 31 2004 2003 Change
- -------- ---- ---- ------
Three months ended $ 45 $ 51 $ (6)
==== ==== ====
Reasons for the change:
Electric deliveries $(10)
Power supply costs and related revenue (6)
Other operating expenses and non-commodity revenue 10
General taxes 4
Fixed charges (6)
Income taxes 2
----
Total change $ (6)
====
ELECTRIC DELIVERIES: Electric deliveries, including transactions with other
wholesale marketers, other electric utilities, and customers choosing
alternative suppliers increased 0.3 billion kWh or 3.6 percent in the first
quarter of 2004 compared to 2003. Despite increased electric deliveries,
electric delivery revenue decreased in the first quarter of 2004 versus 2003.
This revenue decrease primarily reflects tariff revenue reductions that began
January 1, 2004. The tariff revenue reductions were equivalent to the Big Rock
nuclear decommissioning surcharge in effect when our electric retail rates were
frozen from June 2000 through December 31, 2003. The tariff revenue reduction
decreased electric delivery revenue by $9 million in the first quarter of 2004
versus 2003, and is expected to decrease electric delivery revenues $35 million
in 2004 versus 2003.
The reduction in electric delivery revenue for the first quarter 2004 versus
2003 also reflects the impact of customers switching to alternative electric
suppliers as allowed by the Customer Choice Act. Although deliveries to the
sector of customers choosing an alternative supplier has grown significantly
from the same period in 2003, the margin on these sales is substantially less
than if we had supplied the generation.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost rate of
recovery was a fixed amount per kWh, as required under the Customer Choice Act.
Therefore, power supply-related revenue in excess of actual power supply costs
increased operating income. By contrast, if power supply-related revenues had
been less than actual power supply costs, the impact would have decreased
operating income. In 2004, our recovery of power supply costs is no longer
fixed, but is instead restricted to a pre-defined limit for certain customer
classes. The customer classes that have a pre-defined limit, or cap, on the
level of power supply costs they can be charged are primarily the residential
and small commercial customer classes. In 2004, to the extent our power
supply-related revenues are in excess of actual power supply costs, this former
benefit is reserved for possible future refund. This change in the treatment of
excess
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CMS ENERGY CORPORATION
power supply revenues over power supply costs decreased 2004 versus 2003 first
quarter operating income.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In the first quarter of
2004, other operating expenses decreased $2 million and non-commodity revenue
increased $8 million versus 2003. The increase in non-commodity revenue relates
primarily to interest income recognized in relation to capital expenditures in
excess of depreciation as allowed by the Customer Choice Act. The decrease in
operating expenses reflects a reduction in nuclear operating and maintenance
expense in 2004 compared to the same period in 2003 that included a scheduled
refueling outage at the Palisades nuclear facility.
GENERAL TAXES: In the first quarter of 2004, general taxes decreased from the
same period in 2003 due primarily to reductions in MSBT expense.
FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004
versus the same period in 2003 due to higher average debt levels, partially
offset by a 41 basis point reduction in the average interest rate.
INCOME TAXES: In the first quarter of 2004, income taxes decreased versus the
same period in 2003 due primarily to lower earnings by the electric utility.
GAS UTILITY RESULTS OF OPERATIONS
In Millions
- -----------------------------------------------------------------------------
March 31 2004 2003 Change
- -------- ---- ---- ------
Three months ended $ 55 $ 54 $ 1
==== ==== ======
Reasons for the change:
Gas deliveries $ (14)
Gas rate increase 9
Gas wholesale and retail services and other gas revenues 2
Operation and maintenance (4)
General taxes, depreciation, and other income 6
Fixed charges (3)
Income taxes 5
------
Total change $ 1
======
GAS DELIVERIES: For the first quarter 2004 versus the same period in 2003, gas
deliveries, including miscellaneous transportation, decreased 7 bcf or 4 percent
versus 2003. Deliveries decreased during the first quarter of 2004 due primarily
to milder weather.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. As a result of
this order, first quarter 2004 gas revenues increased compared to the same
period in 2003.
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CMS ENERGY CORPORATION
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: Gas wholesale and
retail services and other gas revenues increased for the period ended March 31,
2004 versus the same period in 2003. This increase relates primarily to
increases in gas transportation and storage revenues and late payment fees.
In 2003, we reserved $11 million for a settlement agreement associated with the
2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003
through February 2004, at Consumers' authorized rate of return, increased the
cost of the settlement by $1 million. In March 2004, the MPSC approved this
settlement agreement in the amount we had reserved. Neither the prior year
reservation, nor the current year final MPSC settlement had any effect on
earnings in the first quarter of 2004 versus the same period in 2003.
OPERATION AND MAINTENANCE: In the first quarter 2004 versus 2003, operation and
maintenance expenses increased due to increases in health care costs and
additional expenditures on safety, reliability, and customer service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In the first quarter 2004 versus
2003, the net change in general tax expense, depreciation expense, and other
income increased operating income primarily because of decreases in depreciation
rates authorized by the MPSC's December 2003 interim rate order.
FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004
versus the same period in 2003 due to higher average debt levels, partially
offset by a 41 basis point reduction in the average interest rate.
INCOME TAXES: Income tax expense decreased in the period ended March 31, 2004
versus the same period in 2003. This reduction was attributable primarily to the
income tax treatment of items related to plant, property and equipment as
required by past MPSC rulings.
ENTERPRISES RESULTS OF OPERATIONS
For the three months ended March 31, 2004, Enterprises' net loss was $61
million, compared to $21 million of net income for the comparable period in
2003. The $82 million change reflects primarily an asset impairment charge
related to the sale of Loy Yang, which was completed in April 2004. For
additional details, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
OTHER RESULTS OF OPERATIONS
For the three months ended March 31, 2004, corporate interest and other net
expenses were $48 million compared to $51 million for the comparable period in
2003. The reduction was primarily the result of an $8 million benefit from the
reversal of a currency translation adjustment associated with Loy Yang,
partially offset by an increase in interest expense.
OTHER: In 2003, we sold Panhandle and other businesses as we continued to
implement our utility-plus strategy. The decreased earnings of $33 million in
discontinued operations are a result of the sale of income producing assets. For
more information, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results and financial condition and should be considered an integral part of our
MD&A:
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CMS ENERGY CORPORATION
- use of estimates in accounting for long-lived assets, equity method
investments, and contingencies,
- accounting for financial and derivative instruments,
- accounting for international operations and foreign currency,
- accounting for the effects of industry regulation,
- accounting for pension and postretirement benefits,
- accounting for asset retirement obligations, and
- accounting for nuclear decommissioning costs.
For additional accounting policies, see Note 1, Corporate Structure and
Accounting Policies.
USE OF ESTIMATES
In preparing our financial statements, we use estimates and assumptions that may
affect reported amounts and disclosures. Accounting estimates are used 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.
LONG-LIVED ASSETS AND EQUITY METHOD INVESTMENTS: Our assessment of the
recoverability of long-lived assets and equity method investments involves
critical accounting estimates. Tests of impairment are performed periodically 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 $15.117
billion at March 31, 2004, 61 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.
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. We also
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CMS ENERGY CORPORATION
consider the existence of CMS Energy guarantees on obligations of the investee
or other commitments to provide further financial support. 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. If fair values were
estimated differently, they could have a material impact on the financial
statements.
In March 2004, we reduced the carrying amount of our investment in Loy Yang to
reflect its fair value. For additional details on asset sales, see Note 2,
Discontinued Operations, Other Asset Sales, Impairments, and Restructuring. We
are still pursuing the sale of our remaining non-strategic and under-performing
assets, including some assets that were not determined to be impaired. Upon the
sale of these assets, the proceeds realized may be materially different from the
remaining carrying values. Even though these assets have been identified for
sale, we cannot predict when, or make any assurances that, these asset sales
will occur. Further, we cannot predict the amount of cash or the value of
consideration that may be received.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that
arise in the ordinary course of our business. We record accruals for such
contingencies based upon our assessment that the occurrence is probable and an
estimate of the liability amount. 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 history and the specifics of each
matter. The most significant of these contingencies are our electric and gas
environmental estimates, which are discussed in the "Outlook" section included
in this MD&A, and the potential underrecoveries from our power purchase contract
with the MCV Partnership.
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 and to supply electricity and steam to Dow. We hold a 49
percent partnership interest in the MCV Partnership, and a 35 percent lessor
interest in the MCV Facility.
Under our power purchase agreement with the MCV Partnership, we pay a capacity
charge based on the availability of the MCV Facility whether or not electricity
is actually delivered to us; a variable energy charge for kWh delivered to us;
and a fixed energy charge based on availability up to 915 MW and based on
delivery for the remaining 325 MW of contract capacity. The cost that we incur
under the MCV Partnership power purchase agreement exceeds the recovery amount
allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity
and fixed energy payments will aggregate $206 million from 2004 through 2007.
For capacity and fixed energy payments billed by the MCV Partnership after
September 15, 2007, and not recovered from customers, we expect to claim relief
under a regulatory out provision under the MCV Partnership power purchase
agreement. This provision obligates Consumers to pay the MCV Partnership only
those capacity and energy charges that the MPSC has authorized for recovery from
electric customers. The effect of any such action would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and
- eliminate our underrecoveries for capacity and fixed energy
payments.
Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned in our coal plants and our operations and
maintenance expenses. However, the MCV Partnership's
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CMS ENERGY CORPORATION
costs of producing electricity are tied to the cost of natural gas. Because
natural gas prices have increased substantially in recent years, while the price
the MCV Partnership can charge us for energy has not, the MCV Partnership's
financial performance has been affected adversely.
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be harmed.
In February 2004, we filed a resource conservation plan with the MPSC that is
intended to help conserve natural gas and thereby improve our investment in the
MCV Partnership, without raising the costs paid by our electric customers. The
plan's primary objective is to dispatch the MCV Facility on the basis of natural
gas market prices, which will reduce the MCV Facility's annual natural gas
consumption by an estimated 30 to 40 bcf. This decrease in the quantity of
high-priced natural gas consumed by the MCV Facility will benefit Consumers'
ownership interest in the MCV Partnership. In April 2004, the presiding ALJ at
the MPSC held a pre-hearing conference regarding the resource conservation plan.
The ALJ denied our request to establish a schedule that would have allowed
consideration of the plan on an interim basis and established a review schedule
that calls for a Proposal for Decision in September 2004 after which point the
MPSC would consider the plan. We cannot predict if or when the MPSC will approve
our resource conservation plan.
The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
22 years and the MPSC's decision in 2007 or beyond related to limiting our
recovery of capacity and fixed energy payments. Natural gas prices have been
volatile historically. Presently, there is no consensus in the marketplace on
the price or range of prices of natural gas in the short term or beyond the next
five years. Even with an approved resource conservation plan, if gas prices
continue at present levels or increase, the economics of operating the MCV
Facility may be adverse enough to require us to recognize an impairment of our
investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.
For additional details, see Note 3, Uncertainties, "Other Consumers Electric
Uncertainties - The Midland Cogeneration Venture."
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. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale securities.
Our investments in equity securities are classified as available-for-sale
securities. They are reported at fair value, with any unrealized gains or losses
resulting from changes in fair value reported in equity as part of accumulated
other comprehensive income and are excluded from earnings unless such changes in
fair value are determined to be other than temporary. Unrealized gains or losses
resulting from changes in the fair value of our nuclear decommissioning
investments are reported as regulatory liabilities. The fair value of these
investments is determined from quoted market prices. Our debt securities are
classified as held-to-maturity securities and are reported at cost.
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CMS ENERGY CORPORATION
DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended and
interpreted, to determine if certain contracts must be accounted for as
derivative instruments. The rules for determining whether a contract meets the
criteria for derivative accounting are numerous and complex. Moreover,
significant judgment is required to determine whether a contract requires
derivative accounting, and similar contracts can sometimes be accounted for
differently.
If a contract is accounted for as a derivative instrument, it is recorded in the
financial statements as an asset or a liability, at the fair value of the
contract. The recorded fair value of the contract is then adjusted quarterly to
reflect any change in the market value of the contract, a practice known as
marking the contract to market. The accounting for changes in the fair value of
a derivative (that is, gains or losses) is reported either in earnings or
accumulated other comprehensive income depending on whether the derivative
qualifies for special hedge accounting treatment. For additional details on the
accounting policies for derivative instruments, see Note 6, Financial and
Derivative Instruments.
The types of contracts we typically classify as derivative instruments are
interest rate swaps, foreign currency exchange contracts, electric call options,
gas fuel futures and options, gas fuel contracts containing volume optionality,
fixed priced weather-based gas supply call options, fixed price gas supply call
and put options, gas futures, gas and power swaps, and forward purchases and
sales. We generally do not account for electric capacity and energy contracts,
gas supply contracts, coal and nuclear fuel supply contracts, or purchase orders
for numerous supply items as derivatives.
The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives because there is not an active market for the commodity.
Certain of our electric capacity and energy contracts are not accounted for as
derivatives due to the lack of an active energy market in the state of Michigan
and the significant transportation costs that would be incurred to deliver the
power under the contracts to the closest active energy market at the Cinergy hub
in Ohio. If an active market develops in the future, we may be required to
account for these contracts as derivatives. The mark-to-market impact on
earnings related to these contracts could be material to our financial
statements.
To determine the fair value of contracts that are accounted for as derivative
instruments, we use a combination of quoted market prices and mathematical
valuation models. Valuation models require various inputs, including forward
prices, volatilities, interest rates, and exercise periods. Changes in forward
prices or volatilities could change significantly the calculated fair value of
certain contracts. At March 31, 2004, we assumed a market-based interest rate of
1 percent (a rate that is not significantly different than the LIBOR rate) and
volatility rates ranging between 55 percent and 146 percent to calculate the
fair value of our electric and gas options. At March 31, 2004, we assumed
market-based interest rates ranging between 1.09 percent and 2.7 percent and
volatility rates ranging between 23 percent and 38 percent to calculate the fair
value of the gas fuel derivative contracts held by the MCV Partnership.
TRADING ACTIVITIES: CMS ERM enters into and owns energy trading contracts that
are directly related to activities considered to be an integral part of CMS
Energy's ongoing operations. The intent of holding these energy contracts is to
optimize the performance of CMS Energy-owned generating assets and to fulfill
contractual obligations.
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CMS ENERGY CORPORATION
CMS ERM accounts for power and gas trading contracts using the criteria defined
in SFAS No. 133. Energy trading contracts that meet the definition of a
derivative 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 into earnings in the period in which the
changes occur. Energy trading contracts that do not meet the definition of a
derivative are accounted for as executory contracts (i.e., on an accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. Market prices are adjusted to reflect the impact of liquidating our
position in an orderly manner over a reasonable period of time under present
market conditions.
In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit risks based on the financial condition of
counterparties. We also maintain credit policies that management believes will
minimize its overall credit risk with regard to 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 employ standard agreements that
allow for netting of positive and negative exposures associated with a single
counterparty. Based on these policies, our current exposures, and our credit
reserves, we do not anticipate a material adverse effect on our financial
position or results of operations as a result of counterparty nonperformance.
The following tables provide a summary of the fair value of our energy trading
contracts as of March 31, 2004.
In Millions
-----------
Fair value of contracts outstanding as of December 31, 2003 $ 15
Fair value of new contracts when entered into during the period (a) (3)
Changes in fair value attributable to changes in valuation techniques
and assumptions -
Contracts realized or otherwise settled during the period (7)
Other changes in fair value (b) 10
----
Fair value of contracts outstanding as of March 31, 2004 $ 15
====
(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 mark-to-market and credit reserves.
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Fair Value of Contracts at March 31, 2004 In Millions
- --------------------------------------------------------------------------------------
Total Maturity (in years)
Source of Fair Value Fair Value Less than 1 1 to 3 4 to 5 Greater than 5
-------------------- ---------- ----------- ------ ------ --------------
Prices actively quoted $ (27) $ - $ (10) $ (17) $ -
Prices based on models and
other valuation methods 42 10 17 15 -
------ ------ ------ ------ ----
Total $ 15 $ 10 $ 7 $ (2) $ -
====== ====== ====== ====== ====
MARKET RISK INFORMATION: 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 manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks, including swaps, options, futures, and forward contracts.
Contracts used to manage market risks may be considered derivative instruments
that are subject to derivative and hedge accounting pursuant to SFAS No. 133. We
intend that any gains or losses on these contracts will be offset by an opposite
movement in the value of the item at risk. Risk management contracts are
classified as either trading or other than trading. These contracts contain
credit risk if the counterparties, including financial institutions and energy
marketers, fail to perform under the agreements. We minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
We perform sensitivity analyses to assess the potential loss in fair value, cash
flows, or future earnings based upon a hypothetical 10 percent adverse change in
market rates or prices. We do not believe that sensitivity analyses alone
provide an accurate or reliable method for monitoring and controlling risks.
Therefore, we use our experience and judgment to revise strategies and modify
assessments. Changes in excess of the amounts determined in sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity
Price Risk," "Trading Activity Commodity Price Risk," "Currency Exchange Risk,"
and "Equity Securities Price Risk" within this section.
Interest Rate Risk: We are exposed to interest rate risk resulting from issuing
fixed-rate and variable-rate financing instruments, and from interest rate swap
agreements. We use a combination of these instruments to manage this risk as
deemed appropriate, based upon market conditions. These strategies are designed
to provide and maintain a balance between risk and the lowest cost of capital.
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in
market interest rates):
In Millions
- -------------------------------------------------------------------------------
March 31, 2004 December 31, 2003
-------------- -----------------
Variable-rate financing - before tax annual
earnings exposure $ 1 $ 1
Fixed-rate financing - potential loss in
fair value (a) 241 242
====== =======
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
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As discussed in "Electric Utility Business Uncertainties - Competition and
Regulatory Restructuring - Securitization" within this MD&A, we have filed an
application with the MPSC to securitize certain expenditures. Upon final
approval, we intend to use the proceeds from the Securitization to retire
higher-cost debt, which could include a portion of our current fixed-rate debt.
We do not believe that any adverse change in debt price and interest rates would
have a material adverse effect on either our consolidated financial position,
results of operations, or cash flows.
Certain equity method investees have issued interest rate swaps. These
instruments are not required to be included in the sensitivity analysis, but can
have an impact on financial results.
Commodity Price Risk: For purposes other than trading, we enter into electric
call options, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. Electric call options are used to
protect against the risk of fluctuations in the market price of electricity, and
to ensure a reliable source of capacity to meet our customers' electric needs.
Electric call options give us the right, but not the obligation, to purchase
electricity at predetermined fixed prices. Weather-based gas supply call
options, along with the gas supply call and put options, are used to purchase
reasonably priced gas supply. Gas supply call options give us the right, but not
the obligation, to purchase gas supply at predetermined fixed prices. Gas supply
put options give third-party suppliers the right, but not the obligation, to
sell gas supply to us at predetermined fixed prices. At March 31, 2004, we only
held gas supply call and put options.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. Some of these contracts contain volume
optionality and, thus, are treated as derivative instruments. Also, the MCV
Partnership enters into natural gas futures contracts 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 being 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.
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change
in market prices):
In Millions
- --------------------------------------------------------------------------------
March 31, December 31,
2004 2003
--------- ------------
Potential reduction in fair value:
Gas supply call and put option contracts $ 12 $ 1
Derivative contracts associated with Consumers'
investment in the
MCV Partnership:
Gas fuel contracts 24 N/A
Gas fuel futures 25 N/A
During the first quarter of 2004, we entered into additional gas supply call and
put option contracts. As a result, the potential reduction in the fair value
increased from December 31, 2003 as shown in the table above. We did not perform
a sensitivity analysis for the derivative contracts held by the MCV Partnership
as of December 31, 2003 because the MCV Partnership was not consolidated into
our financial statements until March 31, 2004, as further discussed in Note 11,
Implementation of New Accounting Standards.
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CMS ENERGY CORPORATION
Trading Activity Commodity Price Risk: We are exposed to market fluctuations in
the price of energy commodities. We employ established policies and procedures
to manage these risks and may use various commodity derivatives, including
futures, options, and swap contracts. The prices of these energy commodities can
fluctuate because of, among other things, changes in the supply of and demand
for those commodities.
Trading Activity Commodity Price Risk Sensitivity Analysis (assuming a 10
percent adverse change in market prices):
In Millions
- ------------------------------------------------------------------------------
March 31, 2004 December 31, 2003
-------------- -----------------
Potential reduction in fair value:
Gas-related swaps and forward contracts $ 3 $ 3
Electricity-related forward contracts 2 2
Electricity-related call option contracts 3 1
=== ===
Currency Exchange Risk: We are exposed to currency exchange risk arising from
investments in foreign operations as well as various international projects in
which we have an equity interest and which have debt denominated in U.S.
dollars. We typically use forward exchange contracts and other risk mitigating
instruments to hedge currency exchange rates. The impact of hedges on our
investments in foreign operations is reflected in accumulated other
comprehensive income as a component of the foreign currency translation
adjustment. Gains or losses from the settlement of these hedges are maintained
in the foreign currency translation adjustment until we sell or liquidate the
investments on which the hedges were taken. At March 31, 2004, we had no foreign
exchange hedging contracts outstanding. As of March 31, 2004, the total foreign
currency translation adjustment was a net loss of $313 million that included a
net hedging loss of $25 million related to settled contracts.
Equity Securities Price Risk: We are exposed to price risk associated with
investments in equity securities. As discussed in "Financial Instruments" within
this section, our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reported as regulatory
liabilities. Our debt securities are classified as held-to-maturity securities
and have original maturity dates of approximately one year or less. Because of
the short maturity of these instruments, their carrying amounts approximate
their fair values.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market prices):
In Millions
- ------------------------------------------------------------------------------
March 31, 2004 December 31, 2003
-------------- -----------------
Potential reduction in fair value:
Nuclear decommissioning investments $ 56 $ 57
Other available for sale investments 7 7
=== ===
For additional details on market risk and derivative activities, see Note 6,
Financial and Derivative Instruments.
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CMS ENERGY CORPORATION
INTERNATIONAL OPERATIONS AND FOREIGN CURRENCY
We have investments in energy-related projects throughout the world. As a result
of a change in business strategy, we have been selling certain foreign
investments. For additional details on the divestiture of foreign investments,
see Note 2, Discontinued Operations, Other Asset Sales, Impairments, and
Restructuring.
BALANCE SHEET: Our subsidiaries and affiliates whose functional currency is
other than 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. Gains
or losses that result from this translation and gains or losses on long-term
intercompany foreign currency transactions are reflected as a component of
stockholders' equity in the Consolidated Balance Sheets as "Foreign Currency
Translation." As of March 31, 2004, cumulative foreign currency translation
decreased stockholders' equity by $313 million. We translate the revenue and
expense accounts of these subsidiaries and affiliates into U.S. dollars at the
average exchange rate during the period.
Australia: The Foreign Currency Translation component of stockholders' equity at
December 31, 2003 included an approximate $110 million unrealized net foreign
currency translation loss related to our investment in Loy Yang. In March 2004,
we recognized the foreign currency translation loss in earnings as a component
of the Loy Yang impairment of approximately $81 million, recorded as a result of
the sale of Loy Yang that was completed in April 2004.
At March 31, 2004, the net foreign currency gain due to the exchange rate of the
Australian dollar recorded in the Foreign Currency Translation component of
stockholders' equity using an exchange rate of 1.328 Australian dollars per U.S.
dollar was $8 million. This foreign currency translation gain relates primarily
to our SCP and Parmelia investments.
Argentina: 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 Argentina peso, converted all
dollar-denominated utility tariffs and energy contract obligations into pesos at
the same one-to-one exchange rate, and directed the President of Argentina to
renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had used previously the U.S. dollar
as the functional currency. As a result, we translated the assets and
liabilities of our Argentine entities into U.S. dollars using an exchange rate
of 3.45 pesos per U.S. dollar, and recorded an initial charge to the Foreign
Currency Translation component of stockholders' equity of $400 million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do expect
that these non-cash charges reduce substantially the risk of further material
balance sheet impacts when combined with anticipated proceeds from international
arbitration currently in progress, political risk insurance, and the eventual
sale of these assets. At March 31, 2004, 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
2.86 pesos per U.S. dollar was $262 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 that were
no longer considered permanent.
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CMS ENERGY CORPORATION
INCOME STATEMENT: We use the U.S. dollar as the functional currency of
subsidiaries operating in highly inflationary economies and of subsidiaries that
meet the U.S. dollar functional currency criteria outlined in SFAS No. 52. Gains
and losses that arise from transactions denominated in a currency other than the
U.S. dollar, except those that are hedged, are included in determining net
income.
HEDGING STRATEGY: We may use forward exchange and option contracts to hedge
certain receivables, payables, long-term debt, and equity value relating to
foreign investments. The purpose of our foreign currency hedging activities is
to reduce risk associated with adverse changes in currency exchange rates that
could affect cash flow materially. These contracts would not subject us to risk
from exchange rate movements because gains and losses on such contracts are
inversely correlated with the losses and gains, respectively, on the assets and
liabilities being hedged.
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions affect the
timing and recognition of revenues and expenses. We use SFAS No. 71 to account
for the effects of these regulatory decisions. As a result, we may defer or
recognize revenues and expenses differently than a non-regulated entity.
For example, items that a non-regulated entity normally would expense, we may
record as regulatory assets if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, items that non-regulated
entities may normally recognize as revenues, we may record as regulatory
liabilities if the actions of the regulator indicate they will require such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. As of
March 31, 2004, we had $1.125 billion recorded as regulatory assets and $1.497
billion recorded as regulatory liabilities.
For additional details on industry regulation, see Note 1, Corporate Structure
and Accounting Policies, "Utility Regulation."
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 have implemented a cash balance plan for certain employees hired after
June 30, 2003. We use SFAS No. 87 to account for pension costs.
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.
Any change in these assumptions can change significantly the liability and
associated expenses recognized in any given year.
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The following table provides an estimate of our pension expense, OPEB expense,
and cash contributions for the next three years:
Expected Costs In Millions
- ---------------------------------------------------
Pension Expense OPEB Expense Contributions
--------------- ------------ -------------
2004 $ 21 $ 55 $ 129
2005 55 63 118
2006 75 59 109
==== ==== =====
Actual future pension expense 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. As of March 31, 2004, we
have a prepaid pension asset of $403 million recorded on our consolidated
balance sheets.
Lowering the expected long-term rate of return on the Pension Plan assets by
0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated
pension expense for 2004 by $2 million. Lowering the discount rate by 0.25
percent (from 6.25 percent to 6.00 percent) would increase estimated pension
expense for 2004 by $4 million.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that
was signed into law in December 2003 establishes a prescription drug benefit
under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree
health care benefit plans that provide a benefit that is actuarially equivalent
to Medicare Part D. We are continuing to defer recognizing the effects of the
Act in our 2004 financial statements, as permitted by FASB Staff Position No.
106-b. When accounting guidance is issued, our retiree health benefit obligation
may be adjusted.
For additional details on postretirement benefits, see Note 7, Retirement
Benefits and Note 11, Implementation of New Accounting Standards.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, Accounting for Asset Retirement Obligations, became effective
January 2003. It requires companies to record the fair value of the cost to
remove assets at the end of their useful lives, 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 a
regulatory asset and liability for regulated entities 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 reasonable estimate of fair value cannot be made in the period the asset
retirement obligation is incurred, such as assets with indeterminate lives, the
liability is to be recognized when a reasonable estimate of fair value can be
made. Generally, transmission and distribution assets have indeterminate lives.
Retirement cash flows cannot be determined. There is a low probability of a
retirement date, so no liability has been recorded for these assets. No
liability has been recorded for assets that have insignificant cumulative
disposal costs, such as substation batteries. The measurement of the ARO
liabilities for
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Palisades and Big Rock are based on decommissioning studies that are based
largely on third-party cost estimates. For additional details on ARO, see Note
10, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. We have established external trust funds to
finance the decommissioning of both plants. We record the trust fund balances as
a non-current asset on our balance sheet.
Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent
landscape,
- all contaminated equipment and material will be removed and disposed
of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us develop
decommissioning cost estimates. Various inflation rates for labor, non-labor,
and contaminated equipment disposal costs are used to escalate these cost
estimates to the future decommissioning cost. A portion of future
decommissioning cost will result from the failure of the DOE to remove fuel from
the sites, as required by the Nuclear Waste Policy Act of 1982.
The decommissioning trust funds include equities and fixed income investments.
Equities will be converted to fixed income investments during decommissioning,
and fixed income investments are converted to cash as needed. In December 2000,
funding of the Big Rock trust fund stopped because the MPSC-authorized
decommissioning surcharge collection period expired. The funds provided by the
trusts, additional customer surcharges, and potential funds from the DOE
litigation are all required to cover fully the decommissioning costs. The costs
of decommissioning these sites and the adequacy of the trust funds could be
affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from
customers, and
- changes in decommissioning technology, regulations, estimates, or
assumptions.
Based on current projections, the current level of funds provided by the trusts
is not adequate to fully fund the decommissioning of Big Rock or Palisades. This
is due in part to the DOE's failure to accept the spent nuclear fuel on schedule
and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation. We will also
seek additional relief from the MPSC. For additional details, see Note 3,
Uncertainties, "Other Consumers' Electric Utility Uncertainties - Nuclear Plant
Decommissioning" and "Nuclear Matters."
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. Recently, 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 could require additional liquidity due to the
timing of the cost recoveries. In addition, a few of our commodity suppliers
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CMS ENERGY CORPORATION
have requested advance payment or other forms of assurances, including margin
calls, in connection with maintenance of ongoing deliveries of gas and
electricity.
In 2003, we had debt maturities and capital expenditures that required
substantial amounts of cash. We were also subject to liquidity demands of
various commercial commitments, such as guarantees, indemnities, and letters of
credit. As a result, we executed a financial improvement plan to address these
critical liquidity issues.
In 2003, we suspended payment of the common stock dividend and increased our
efforts to reduce operating expenses and capital expenditures. We continued to
sell non-strategic assets and we used the proceeds to reduce debt. Finally, we
explored financing opportunities, such as refinancing debt, issuing new debt and
preferred equity, and negotiating private placement debt. Together, all of these
steps enabled us to meet our liquidity demands.
In 2004, we are continuing to monitor our operating expenses and capital
expenditures, evaluate market conditions for financing opportunities, and sell
assets that are not consistent with our strategy. Execution of our asset sales
program is expected to generate positive cash flow in 2004, however, it is not
critical to the maintenance of sufficient corporate liquidity. Further, we do
not anticipate paying common stock dividends in the foreseeable future. The
Board of Directors may reconsider or revise its dividend policy based upon
certain conditions, including our results of operations, financial condition,
and capital requirements, as well as other relevant factors. We believe our
current level of cash and borrowing capacity, along with anticipated cash flows
from operating and investing activities, will be sufficient to meet our
liquidity needs through 2005.
CASH POSITION, INVESTING, AND FINANCING
Consolidated cash needs are met by our operating, investing, and financing
activities. At March 31, 2004, $767 million consolidated cash was on hand which
includes $216 million of restricted cash. For additional details on restricted
cash, see Note 1, Corporate Structure and Accounting Policies.
Our primary ongoing source of cash is dividends and other distributions from our
subsidiaries, including proceeds from asset sales. For the first three months of
2004, Consumers paid $78 million in common stock dividends and Enterprises paid
$80 million in common stock dividends and other distributions to CMS Energy.
SUMMARY OF CASH FLOWS:
In Millions
- ----------------------------------------------------
Three months ended March 31 2004 2003
--------------------------- ---- ----
Net cash provided by (used in):
Operating activities $ 235 $ 415
Investing activities (115) (61)
Financing activities (266) (50)
Effect of exchange rates on cash (9) 1
----- -----
Net increase (decrease) in cash and
temporary cash investments $(155) $ 305
===== =====
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CMS ENERGY CORPORATION
OPERATING ACTIVITIES:
For the three months ended March 31, 2004, net cash provided by operating
activities decreased $180 million due to a greater decrease in accounts payable
and accrued expenses of $44 million and a greater increase in accounts
receivable and accrued revenue of $189 million primarily due to lower sales of
accounts receivable resulting from our improved liquidity. This change was
offset by a greater decrease in inventories of $125 million primarily resulting
from gas sales at higher prices combined with lower volumes of gas purchased.
INVESTING ACTIVITIES:
For the three months ended March 31, 2004, net cash used in investing activities
increased $54 million due primarily to a decrease in asset sale proceeds of $92
million, offset by a greater decrease in capital expenditures of $43 million.
FINANCING ACTIVITIES:
For the three months ended March 31, 2004, net cash used in financing activities
increased $216 million due primarily to a decrease of $218 million in net
proceeds from borrowings. For additional details on long-term debt activity, see
Note 4, Financings and Capitalization.
OBLIGATIONS AND COMMITMENTS
Our total contractual obligations as of March 31, 2004 are shown in the
following table.
Contractual Obligations In Millions
- ---------------------------------------------------------------------------
Payments Due
------------------------------------------------------
Total 2004 2005 2006 2007 2008 Beyond
------- ------ ------- ------- ------- ------- -------
On-balance sheet:
Long-term debt $ 6,678 $ 362 $ 785 $ 546 $ 545 $ 1,050 $ 3,390
Long-term debt -
related
parties 684 - - - - - 684
Capital lease
obligations 372 44 31 27 26 26 218
------- ------- ------- ------ ------- ------- -------
Total on-balance
sheet $ 7,734 $ 406 $ 816 $ 573 $ 571 $ 1,076 $ 4,292
------- ------- ------- ------ ------- ------- -------
Off-balance sheet:
Non-recourse
debt $ 2,716 $ 269 $ 77 $ 411 $ 65 $ 67 $ 1,827
Operating leases 77 11 10 10 9 7 30
Long-term service
agreements 219 9 12 19 13 12 154
Unconditional
purchase
obligations 7,637 1,599 1,161 715 517 442 3,203
------- ------- ------- ------ ------- ------- -------
Total off-balance
sheet $10,649 $ 1,888 $ 1,260 $1,155 $ 604 $ 528 $ 5,214
======= ======= ======= ====== ======= ======= =======
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For additional details, see Note 3, Uncertainties, and Note 4, Financings and
Capitalization.
REGULATORY AUTHORIZATION FOR FINANCINGS: Consumers issues short and long-term
securities under the FERC authorization. For additional details of Consumers'
existing authorization, see Note 4, Financings and Capitalization.
LONG-TERM DEBT: Details on long-term debt are presented in Note 4, Financings
and Capitalization.
SHORT-TERM FINANCINGS: At March 31, 2004, CMS Energy has $190 million available,
Consumers has $376 million available, and the MCV Partnership has $50 million
available in short-term credit facilities. The facilities are available for
general corporate purposes, working capital, and letters of credit. For
additional details, see Note 4, Financings and Capitalization.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of the leased
portion of the MCV Partnership facility, leased service vehicles, and leased
office furniture. The full obligation of our leases could become due in the
event of lease payment default.
OFF-BALANCE SHEET ARRANGEMENTS: We use off-balance sheet arrangements in the
normal course of business. Our off-balance sheet arrangements include:
- operating leases,
- non-recourse debt,
- long-term service agreements,
- sale of accounts receivable, and
- unconditional purchase obligations.
Operating Leases: Our leases of railroad cars, certain vehicles, and
miscellaneous office equipment are accounted for as operating leases.
Non-recourse Debt: Our share of unconsolidated debt associated with partnerships
and joint ventures in which we have a minority interest is non-recourse.
Long-term Service Agreements: These obligations of the MCV Partnership represent
the cost of the current MCV Facility maintenance service agreements and cost of
spare parts.
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. For
additional details, see Note 4, Financings and Capitalization.
Unconditional Purchase Obligations: Long-term contracts for purchase of
commodities and services are unconditional purchase obligations. These
obligations represent operating contracts used to assure adequate supply with
generating facilities that meet PURPA requirements. The commodities and services
include:
- natural gas,
- electricity,
- coal purchase contracts and their associated cost of transportation,
and
- electric transmission.
Included in unconditional purchase obligations are long-term power purchase
agreements with various generating plants. These contracts require us to make
monthly capacity payments based on the plants' availability or deliverability.
These payments will approximate $9 million per month during 2004. If a plant is
not available to deliver electricity, we are not obligated to make the capacity
payments to the plant
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CMS ENERGY CORPORATION
for that period of time. For additional details on power supply costs, see
"Electric Utility Results of Operations" within this MD&A and Note 3,
Uncertainties, "Consumers' Electric Utility Rate Matters - Power Supply Costs."
COMMERCIAL COMMITMENTS: Our commercial commitments include indemnities and
letters of credit. Indemnities are agreements to reimburse other companies, such
as an insurance company, if those companies have to complete our contractual
performance in a third-party contract. Banks, on our behalf, issue letters of
credit guaranteeing payment to a third party. Letters of credit substitute the
bank's credit for ours and reduce credit risk for the third-party beneficiary.
We monitor and approve these obligations and believe it is unlikely that we
would be required to perform or otherwise incur any material losses associated
with these guarantees. Our off-balance sheet commitments at March 31, 2004,
expire as follows:
Commercial Commitments In Millions
- --------------------------------------------------------------------------------
Commitment Expiration
----------------------------------------------------------------
Total 2004 2005 2006 2007 2008 Beyond
------- ------- ------- ------- ------- ------- -------
Off-balance
sheet:
Guarantees $ 212 $ 6 $ 36 $ 4 $ - $ - $ 166
Indemnities 27 8 - - - - 19
Letters of
Credit (a) 248 112 108 5 5 5 13
------- ------- ------- ------- ------- ------- -------
Total $ 487 $ 126 $ 144 $ 9 $ 5 $ 5 $ 198
======= ======= ======= ======= ======= ======= =======
(a) At March 31, 2004, we had $173 million of cash collateralized letters of
credit. The cash that collateralizes the letters of credit is included in
Restricted Cash on the Consolidated Balance Sheets.
DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at
March 31, 2004, Consumers had $397 million of unrestricted retained earnings
available to pay common dividends. Covenants in Consumers' debt facilities cap
common stock dividend payments at $300 million in a calendar year. Consumers is
also under an annual dividend cap of $190 million imposed by the MPSC during the
current interim gas rate relief period. As of March 31, 2004, CMS Energy has
received $78 million of common stock dividends from Consumers.
Our $190 million revolving credit facility with banks, which expires in November
2004, contains provisions that prohibit us from paying dividends on our common
stock.
For additional details on the cap on common dividends payable during the current
interim gas rate relief period, see Note 3, Uncertainties, "Consumers' Gas
Utility Rate Matters - 2003 Gas Rate Case."
OUTLOOK
CORPORATE OUTLOOK
During 2004, we are continuing to implement a utility-plus strategy that focuses
on growing a healthy utility and divesting under-performing or other
non-strategic assets. The strategy is designed to generate cash to pay down
debt, reduce business risk, and provide for more predictable future operating
revenues and earnings.
Consistent with our utility-plus strategy, we are pursuing actively the sale of
non-strategic and under-performing assets. Some of these assets are recorded at
estimates of their current fair value. Upon the sale
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CMS ENERGY CORPORATION
of these assets, the proceeds realized may be different from the recorded values
if market conditions have changed. Even though these assets have been identified
for sale, we cannot predict when, nor make any assurance that, these sales will
occur. We anticipate that the cash proceeds from these sales, if any, will be
used to retire existing debt.
As we continue to implement our utility-plus strategy and further reduce our
ownership of non-utility assets, the percentage of our future earnings relating
to our larger equity method investments, including Jorf Lasfar may increase and
our total future earnings may depend more significantly upon the performance of
those investments. For additional details, see Note 8, Equity Method
Investments.
ELECTRIC UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect electric deliveries to grow at an
average rate of approximately two percent per year based primarily on a steadily
growing customer base and 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 abnormal weather conditions and
changes in economic conditions, including utilization and expansion of
manufacturing facilities. We experienced less growth than expected in 2003 as a
result of cooler than normal summer weather and a decline in manufacturing
activity in Michigan. In 2004, we project electric deliveries to grow
approximately two percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
during the remainder of the year.
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. Such trends and uncertainties include:
Environmental
- increasing capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts and Superfund.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- recovery of electric restructuring implementation costs,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer instead of an electric
transmission owner-operator.
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CMS ENERGY CORPORATION
Regulatory
- effects of conclusions about the causes of the August 14, 2003
blackout, including exposure to liability, increased regulatory
requirements, and new legislation,
- successful implementation of initiatives to reduce exposure to
purchased power price increases,
- effects of potential performance standards payments,
- effects of the FERC supply margin assessment requirements for
electric market-based rate authority,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel, and
- recovery of nuclear decommissioning costs. For additional details,
see "Accounting for Nuclear Decommissioning Costs" within this MD&A.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
- pending other litigation, and
- potential rising pension costs due to market losses and lump sum
payments. For additional details, see "Accounting for Pension and
OPEB" within this MD&A.
For additional details about these trends or uncertainties, see Note 3,
Uncertainties.
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.
Compliance with the federal Clean Air Act and resulting regulations has been,
and will continue to be, a significant focus for us. The Title I provisions of
the Clean Air Act require significant reductions in nitrogen oxide emissions. To
comply with the regulations, we expect to incur capital expenditures totaling
$771 million. The key assumptions included 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 8.9 percent. As of March 31, 2004, we have
incurred $469 million in capital expenditures to comply with these regulations
and anticipate that the remaining $302 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology on coal-fired electric plants. In addition to modifying the
coal-fired electric plants, we expect to purchase nitrogen oxide emissions
credits for years 2004 through 2008. The cost of these credits is estimated to
average $8 million per year and is accounted for as inventory.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek 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
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CMS ENERGY CORPORATION
fines.
The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which
requires additional coal-fired electric plant emission controls for nitrogen
oxides and sulfur dioxide. If implemented, this rule would potentially require
expenditures equivalent to those efforts in progress required to reduce nitrogen
oxide emissions under the Title I provisions of the Clean Air Act. The rule
proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent
and nitrogen oxides by 65 percent by 2015, through the installation of flue gas
desulfurization scrubbers and selective catalytic reduction units. Additionally,
the EPA also proposed two alternative sets of rules to reduce emissions of
mercury and nickel from coal-fired and oil-fired electric plants. Until the
proposed environmental rules are finalized, an accurate cost of compliance
cannot be determined.
Several bills have been introduced in the United States Congress that would
require carbon dioxide emissions reduction. We cannot predict whether any
federal mandatory carbon dioxide emissions reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
To the extent that emissions reduction rules come into legal effect, such
mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows or financial position
due to the speculative nature of the policy. 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.
In March 2004, the EPA changed the 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 by
2006. We are studying the rules to determine the most cost-effective solutions
for compliance.
For additional details on electric environmental matters, see Note 3,
Uncertainties, "Consumers' Electric Utility Contingencies - Electric
Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act and
other developments will continue to result in increased competition in the
electric business. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of April 2004, alternative electric suppliers are providing 823 MW of
generation supply to ROA customers. This amount represents 10 percent of our
distribution load and an increase of 50 percent compared to April 2003. We
anticipate this upward trend to continue and expect over 1,100 MW of generation
supply to ROA customers in 2004. We cannot predict the total amount of electric
supply load that may be lost to competitor suppliers.
In February 2004, the MPSC issued an order on Detroit Edison's request for rate
relief for costs associated with customers leaving under electric customer
choice. The MPSC order allows Detroit Edison to implement a transition charge on
ROA customers and eliminates securitization charge offsets. We are seeking
similar recovery of Stranded Costs due to ROA customers leaving our system and
are encouraged by this ruling. We cannot predict if or when the MPSC will
approve implementation of a transition charge on our ROA customers.
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CMS ENERGY CORPORATION
Securitization: In March 2003, we filed an application with the MPSC seeking
approval to issue Securitization bonds. In June 2003, the MPSC issued a
financing order authorizing the issuance of Securitization bonds in the amount
of approximately $554 million. In July 2003, we filed for rehearing and
clarification on a number of features in the financing order.
In December 2003, the MPSC issued its order on rehearing, which rejected our
requests for clarification and modification to the dividend payment restriction,
failed to rule directly on the accounting clarifications requested, and remanded
the proceeding to the ALJ for additional proceedings to address rate design. We
filed testimony regarding the remanded proceeding in February 2004. The ALJ
completed hearings in March 2004 and the MPSC decision is not anticipated before
May 2004, but could be later. The financing order will become effective after
our acceptance of a favorable MPSC order. Bonds will not be issued until
resolution of any appeals.
Stranded Costs: To the extent we experience net Stranded Costs as determined by
the MPSC, the Customer Choice Act allows us to recover such costs by collecting
a transition surcharge from customers who switch to an alternative electric
supplier. We cannot predict whether the Stranded Cost recovery method adopted by
the MPSC will be applied in a manner that will fully offset any associated
margin loss.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero net
Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We
currently are in the process of appealing these orders with the Michigan Court
of Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002, including the cost of
money, are estimated to be $47 million with the issuance of Securitization bonds
that include Clean Air Act investments, or $104 million without the issuance of
Securitization bonds that include Clean Air Act investments. Once the MPSC
issues a final financing order on Securitization, we will know the amount of our
request for net Stranded Cost recovery for 2002.
In April 2004, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2003, including the cost of money, in the amount of
$106 million with the issuance of Securitization bonds that include Clean Air
Act investments, or $165 million without the issuance of Securitization bonds
that include Clean Air Act investments. Similar to the request that was granted
by the MPSC for Detroit Edison, we also requested interim relief for 2002 and
2003 net Stranded Costs. We cannot predict how the MPSC will rule on our
requests for the recoverability of Stranded Costs. Therefore, we have not
recorded regulatory assets to recognize the future recovery of such costs.
Implementation Costs: Since 1997, we have incurred significant costs to
implement the Customer Choice Act. The Customer Choice Act allows electric
utilities to recover the Act's implementation costs. The MPSC reviewed and
granted deferred conditional recovery of certain of the implementation costs
incurred through 2001, but has not yet authorized rates that would allow
recovery.
Our applications for $7 million of implementation costs for 2002 and $1 million
for 2003 are currently pending approval by the MPSC. Included in the 2002
request is $5 million related to our former participation in the development of
the Alliance RTO. As of March 31, 2004, implementation costs totaled $93
million, which includes $23 million associated with the cost of money. We
believe the implementation costs and the associated cost of money are fully
recoverable in accordance with the Customer Choice Act. Cash recovery from
customers is expected to begin after rate cap periods
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expire. For additional information on rate caps, see "Rate Caps" within this
section.
In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision
finding that the recovery of 1999 implementation costs is conditional and
subject to later disallowance is unlawful. The case was remanded to the MPSC.
The MPSC issued an order regarding the remanded proceeding that directed us to
choose whether we prefer to recover our approved implementation costs through
Securitization pursuant to the MPSC's final order in the Securitization
proceeding or whether we would prefer to have recovery controlled by the remand
proceeding. If the latter option was chosen, the MPSC indicated that it intended
to authorize recovery of such implementation costs through the use of surcharges
on all customer classes that coincide with the expiration of the Customer Choice
Act rate caps. We chose recovery of the approved implementation costs through
the use of surcharges and withdrew our request for approved implementation costs
recovery from our Securitization proposal. The implementation costs withdrawn
from the Securitization case were incurred for the years 1998 through 2000. In
the filing we made electing recovery through separate surcharges, we requested
approval of surcharges that would allow recovery of implementation costs
incurred for the years 1998 through 2001. We requested that the Court of Appeals
issue similar remand orders with respect to appeals of the MPSC orders
addressing 2000 and 2001 implementation costs. We cannot predict the amounts the
MPSC will approve as recoverable costs.
Also, we are pursuing authorization at the FERC for the MISO to reimburse us for
approximately $8 million in certain electric utility restructuring
implementation costs related to our former participation in the development of
the Alliance RTO, a portion of which has been expensed. In May 2003, the FERC
issued an order denying the MISO's request for authorization to reimburse us. We
appealed the FERC ruling at the United States Court of Appeals for the District
of Columbia. We also requested that the MISO seek authorization to reimburse the
METC for these development costs. The MISO filed this request but the FERC
denied it. While we appeal the FERC's orders, we are also pursuing other
potential means of recovery, such as recovery of Alliance RTO development costs
at the MPSC. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act allows for recovery of new and enhanced
security costs, as a result of federal and state regulatory security
requirements. All retail customers, except customers of alternative electric
suppliers, would pay these charges. In April 2004, we filed a security cost
recovery case with the MPSC for $25 million of cost that regulatory treatment
has not yet been granted through other means. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. We cannot
predict how the MPSC will rule on our requests for the recoverability of
security costs.
Rate Caps: The Customer Choice Act imposes certain limitations on electric rates
that could result in us being unable to collect our full cost of conducting
business from electric customers. Such limitations include:
- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and
- rate caps effective through December 31, 2005 for residential
customers.
As a result, we may be unable to maintain our profit margins in our electric
utility business during the rate cap periods. In particular, if we need to
purchase power supply from wholesale suppliers while retail rates are capped,
the rate restrictions may make it impossible for us to fully recover purchased
power and associated transmission costs.
PSCR: The PSCR process provides for the reconciliation of actual power supply
costs with power supply revenues. This process assures recovery of all
reasonable and prudent power supply costs actually incurred by us, including the
actual cost for fuel, and purchased and interchange power. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from
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CMS ENERGY CORPORATION
large commercial and industrial customers to be approximately $30 million in
2004. As allowed under current regulation, we self-implemented the proposed PSCR
charge on January 1, 2004. The revenues received from the PSCR charge are also
subject to subsequent reconciliation at the end of the year after actual costs
have been reviewed for reasonableness and prudence. We cannot predict the
outcome of this filing.
Decommissioning Surcharge: When our electric retail rates were frozen in June
2000, a nuclear decommissioning surcharge related to the decommissioning of Big
Rock was included. In December 2000, funding of the Big Rock nuclear
decommissioning trust fund stopped because the MPSC-authorized decommissioning
surcharge collection period expired. However, we continued to collect the
equivalent to the Big Rock nuclear decommissioning surcharge consistent with the
Customer Choice Act rate freeze through December 31, 2003. Collection of the
surcharge stopped, effective January 1, 2004, when the electric rate freeze
expired.
Industrial Contracts: We entered into multi-year electric supply contracts with
certain large industrial customers. The contracts provide electricity at
specially negotiated prices, usually at a discount from tariff prices. The MPSC
approved these special contracts totaling approximately 685 MW of load. Unless
terminated or restructured, the majority of these contracts are in effect
through 2005. As of March 31, 2004, contracts for 201 MW of load have
terminated. Of the contracts that have terminated, 70 MW of load have gone to an
alternative electric supplier and 131 MW of load have returned to bundled tariff
rates. In January 2004, new special contracts for 91 MW, with the State of
Michigan and three universities, were approved by the MPSC. Initial special
contracts with Dow Corning and Hemlock Semi-Conductor were terminated in
December 2003. New special contracts with Dow Corning and Hemlock Semi-Conductor
for 101 MW received interim approval from the MPSC and are awaiting final
approval. As of April 2004, our special contracts total approximately 580 MW of
load. All new special contracts end by January 1, 2006. We cannot predict
whether additional special contracts will be necessary, advisable, or approved.
Transmission Sale: In May 2002, we sold our electric transmission system for
$290 million to MTH. We are currently in arbitration with MTH regarding property
tax items used in establishing the selling price of our electric transmission
system. We cannot predict whether the remaining open items will affect
materially the sale proceeds previously recognized.
There are multiple proceedings and a proposed rulemaking pending before the FERC
regarding transmission pricing mechanisms and standard market design for
electric bulk power markets and transmission. The results of these proceedings
and proposed rulemakings could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
The financial impact of such proceedings, rulemaking, and trends are not
quantifiable currently. In addition, we are evaluating whether or not there may
be impacts on electric reliability associated with the outcomes of these various
transmission related proceedings. For example, in April 2004, Commomwealth
Edison Company received approval from the FERC to join into the PJM RTO
effective May 1, 2004. This integration could create different patterns of flow
and power within the Midwest area and affect adversely our ability to provide
reliable service to our customers.
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CMS ENERGY CORPORATION
August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid
serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
In December 2003, the MPSC issued an order requiring Michigan investor-owned
utilities to file reports by April 1, 2004, on the status of the transmission
and distribution lines used to serve their customers, including details on
vegetation trimming practices in calendar year 2003. We complied with the MPSC's
order.
In February 2004, the Board of Trustees of the NERC approved recommendations to
improve electric transmission reliability. In April 2004, the U.S. and Canadian
Power System Outage Task Force released its final report on the causes and
recommendations surrounding the blackout. The Task Force concluded that
inadequate assessment of voltage instability and vulnerability by First Energy;
inadequate communication between interconnected grid operators; and improper
vegetation management, outside of our operating territory, were the key causes
of the blackout. In addition to the NERC recommendations, the Task Force made 46
recommendations under the following captions:
- institutional issues,
- support for and strengthening of ongoing NERC initiatives,
- physical and cyber security of North American bulk power systems,
and
- Canadian nuclear power sector operating procedures.
Prompted by the Task Force findings, the MPSC issued an order requiring Michigan
utilities and transmission companies to submit a report concerning relay
settings on their systems by May 10, 2004. We intend to comply with the MPSC's
request. Also, the FERC issued a vegetation management order requiring entities
that own, operate, or control designated transmission facilities to report on
their vegetation management practices by June 17, 2004. As defined by this
particular FERC order, we have a limited amount of designated transmission
facilities for reporting purposes pursuant to this order, including a total of
six miles of high voltage lines located on or adjacent to some generating plant
properties.
Few of the recommendations above apply directly to us, since we are not a
transmission operator. However, the above recommendations could result in
increased transmission costs payable by transmission customers in the future and
upgrades to our distribution system. The financial impacts of these
recommendations are not quantifiable currently.
For additional details and material changes relating to the rate matters and
restructuring of the electric utility industry, see Note 3, Uncertainties,
"Consumers' Electric Utility Restructuring Matters," and "Consumers' Electric
Utility Rate Matters."
FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new market
power screens to assess generation market power and modified measures to
mitigate market power where it is found. The screens will apply to all initial
market-based rate applications and reviews on an interim basis, which occur
every three years. The effects of the modifications are not quantifiable
currently.
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after an outage, safety, and customer relations. Financial incentives and
penalties are contained within the performance standards. An incentive is
possible if all of the established performance standards have been exceeded for
a calendar year. However, the performance standards do not contain an approved
incentive mechanism; therefore, the value of such an incentive cannot be
determined at this point. Financial penalties in the form of customer credits
are also possible. These customer credits are based on duration and repetition
of outages. Year-end results for both 2002 and 2003 resulted in compliance with
the acceptable level of performance as established by the approved standards. We
are a member of an industry coalition that has appealed the customer credit
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CMS ENERGY CORPORATION
portion of the performance standards to the Michigan Court of Appeals. We cannot
predict the likely effects of the financial incentive or penalties, if any, on
us, nor can we predict the outcome of the appeal.
For additional details on performance standards, see Note 3, Uncertainties,
"Consumers' Electric Utility Rate Matters-Performance Standards."
GAS UTILITY BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an average
rate of less than one percent per year. Actual gas deliveries in future periods
may be affected by:
- abnormal weather,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the Michigan Public Service
Commission for a Certificate of public convenience and necessity for the
construction of a 25-mile gas transmission pipeline in northern Oakland County.
The project is necessary to meet peak load beginning in the winter of 2005
through 2006. If we are unable to construct the pipeline due to local
opposition, we will need to pursue more costly alternatives or possibly curtail
serving the system's load growth in that area.
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
net sales, revenues, or income from gas operations. The trends and uncertainties
include:
Environmental
- potential environmental remediation costs at a number of sites,
including sites formerly housing manufactured gas plant facilities.
Regulatory
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers,
Other
- potential rising pension costs due to market losses and lump sum
payments as discussed in the "Critical Accounting Policies -
Accounting for Pension and OPEB" section within this MD&A,
- pipeline integrity maintenance and replacement costs, and
- pending other litigation.
We sell gas to retail customers under tariffs approved by the MPSC. These
tariffs measure the gas delivered to customers based on the volume (i.e. mcf) of
gas delivered. However, we purchase gas for resale on a Btu basis. The Btu
content of the gas available for purchase fluctuates and may result in
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CMS ENERGY CORPORATION
customers using less gas for the same heating requirement. We fully recover our
cost to purchase gas through the approved GCR. However, since the customer may
use less gas on a volumetric basis, the revenue from the distribution charge
(the non-gas cost portion of the customer bill) could be reduced. This could
affect adversely our gas utility earnings. The amount of any possible earnings
loss due to fluctuating btu content in future periods cannot be estimated at
this time.
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we offered. In
December 2003, the FERC ruled that no refunds were at issue and we reversed a $4
million reserve related to this matter. In January 2004, three companies filed
with the FERC for clarification or rehearing of the FERC's December 2003 order.
In April 2004, the FERC issued its Order Granting Clarification. In that Order,
the FERC indicated that its December 2003 order that stated no refunds are at
issue was in error. It directed us to file within 30 days a fair and equitable
title-tracking fee and to make refunds to customers with interest based on the
difference between the filed fee and the fee paid. We believe that with respect
to the FERC jurisdictional transportation, we have not charged any customers
title transfer fees, so no refunds will be required. We will make a filing
within the 30 days and cannot predict the outcome of this proceeding.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could change the remedial action costs for the sites. For
additional details, see Note 3, Uncertainties, "Consumers' Gas Utility
Contingencies - Gas Environmental Matters."
GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our gas costs; however, the MPSC reviews these costs
for prudency in an annual reconciliation proceeding. In January 2004, the MPSC
staff and intervenors filed direct testimony in our 2002-2003 GCR case proposing
GCR recovery disallowances. In 2003, we reserved $11 million for a settlement
agreement associated with the 2002-2003 GCR disallowance. Interest on the
disallowed amount from April 1, 2003 through February 2004, at Consumers'
authorized rate of return, increased the cost of the settlement by $1 million.
The interest was recorded as an expense in 2003. In February 2004, the parties
in the case reached a settlement agreement that resulted in a GCR disallowance
of $11 million for the GCR period. The settlement agreement was
approved by the MPSC in March 2004. For additional details, see Note 3,
Uncertainties, "Consumers' Gas Utility Rate Matters - Gas Cost Recovery."
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim rate
order, Consumers agreed to restrict dividend payments to its parent company, CMS
Energy, to a maximum of $190 million annually during the period of the interim
relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending
that the MPSC not rely upon the projected test year data included in our filing
and supported by the MPSC Staff and further recommended that the application be
dismissed. In response to the Proposal for Decision, the parties have filed
exceptions and replies to exceptions. The MPSC is not bound by the ALJ's
recommendation and will
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CMS ENERGY CORPORATION
review the exceptions and replies to exceptions prior to issuing an order on
final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order which reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief. The original filing was based on December 2000 plant
balances and historical data. The December 2003 filing updates the gas
depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, will result in an annual increase of $12
million in depreciation expense based on December 2002 plant balances. The ALJ's
Proposal for Decision is expected in May 2004.
OTHER CONSUMERS' OUTLOOK
CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that
applies to utilities and alternative electric suppliers. The code of conduct
seeks to prevent financial support, information sharing, and preferential
treatment between a utility's regulated and non-regulated services. The new code
of conduct is broadly written and could affect our:
- retail gas business energy related services,
- retail electric business energy related services,
- marketing of non-regulated services and equipment to Michigan
customers, and
- transfer pricing between our departments and affiliates.
We appealed the MPSC orders related to the code of conduct and sought a deferral
of the orders until the appeal was complete. We also sought waivers available
under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business.
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 MCV Partnership estimates that the
decision will result in a refund of approximately $35 million in taxes plus $9
million of interest. The Michigan Tax Tribunal decision has been appealed to the
Michigan Court of Appeals by the City of Midland and the MCV Partnership has
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
2003 and expects to file an appeal contesting property taxes for 2004. The MCV
Partnership cannot predict the outcome of these proceedings; therefore, the
above refund has not been recognized in first quarter 2004 earnings.
ENTERPRISES OUTLOOK
INDEPENDENT POWER PRODUCTION: We plan to complete the restructuring of our IPP
business by narrowing the focus of our operations to North America and the
Middle East/North Africa. We will continue to sell designated assets and
investments that are under-performing or are not synergistic with our other
business units. We will continue to operate and manage our remaining portfolio
of assets in a
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CMS ENERGY CORPORATION
manner that maximizes their contribution to our earnings and that maintains our
reputation for solid performance in the construction and operation of power
plants.
CMS ERM: CMS ERM has continued to streamline its portfolio in order to reduce
business risk and outstanding credit guarantees. Our future activities will be
centered on fuel procurement activities and merchant power marketing in such a
way as to optimize the earnings from our IPP generation assets.
CMS GAS TRANSMISSION: CMS Gas Transmission continues to narrow its scope of
existing operations. We plan to continue to sell international assets and
businesses. Future operations will be mainly in Michigan.
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
Australia,
- changes in foreign 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 substantially project expenses,
- impact of any future rate cases, or FERC actions, or orders on
regulated businesses,
- impact of ratings downgrades on our liquidity, operating costs, and
cost of capital, and
- impact of restrictions by the Argentine government on natural gas
exports to our GasAtacama plant.
OTHER OUTLOOK
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 including a shareholder derivative
lawsuit, a securities class action lawsuit, a class action lawsuit alleging
ERISA violations, several lawsuits regarding alleged false natural gas price
reporting, and a lawsuit surrounding the possible sale of CMS Pipeline Assets.
For additional details regarding these investigations and litigation, see Note
3, Uncertainties.
NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not
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CMS ENERGY CORPORATION
previously adopted FASB Interpretation No. 46, Revised FASB Interpretation No.
46 provided an implementation deferral until the first quarter of 2004. As of
and for the quarter ended March 31, 2004, we adopted Revised FASB Interpretation
No. 46 for all entities.
We determined that 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. In addition, 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. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $718 million at March 31, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of $1.471 billion at
March 31, 2004. The creditors of these partnerships do not have recourse to the
general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of three
other entities that are determined to be variable interest entities. We have
50 percent partnership interest in the T.E.S Filer City Station Limited
Partnership, the Grayling Generating Station Limited 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 the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $120 million at March 31, 2004. Property,
plant, and equipment serving as collateral for these obligations have a carrying
value of $171 million. 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.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected an investment in related parties of $21 million.
We are not required to, and have not, restated prior periods for the impact of
this accounting change.
Additionally, we have variable interest entities in which we are not the primary
beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at March 31, 2004:
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CMS ENERGY CORPORATION
Name Investment Operating Total
(Ownership Nature of the Involvement Balance Agreement with Generating
Interest) Entity Country Date (In Millions) CMS Energy Capacity
- ------------ ------------------ ----------- ----------- -------------- -------------- ----------
Taweelah Power United Arab
(40%) Generator Emirates 1999 $ 75 Yes 777 MW
Generator - Saudi
Jubail (25%) Under Construction Arabia 2001 $ - Yes 250 MW
Generator -
Shuweihat Under United Arab
(20%) Construction Emirates 2001 $(30)(a) Yes 1,500 MW
---- -----
Total $ 45 2,527 MW
==== =====
(a) At March 31, 2004, we carried a negative investment in Shuweihat. The
balance is comprised of our investment of $3 million reduced by our
proportionate share of the negative fair value of derivative instruments of $33
million. We are required to record the negative investment due to our future
commitment to make an equity investment in Shuweihat.
Our maximum exposure to loss through our interests in these variable interest
entities is limited to our investment balance of $45 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$129 million, including a letter of credit relating to our required initial
investment in Shuweihat of $70 million. We plan to contribute our initial
investment when the project becomes commercially operational in 2004.
In April 2004, we sold our investment in Loy Yang. In March 2004, we recorded an
$81 million after-tax impairment charge. For additional information regarding
the Loy Yang sale, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
EITF ISSUE NO. 02-03, RECOGNITION AND REPORTING OF GAINS AND LOSSES ON ENERGY
TRADING CONTRACTS UNDER EITF ISSUES NO. 98-10 AND 00-17: At its October 25, 2002
meeting, the EITF reached a consensus to rescind EITF Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. As a result, only energy contracts that meet the definition of a
derivative in SFAS No. 133 will be carried at fair value. Energy trading
contracts that do not meet the definition of a derivative must be accounted for
as executory contracts. We recognized a loss for the cumulative effect of a
change in accounting principle of $23 million, net of tax, during the
three-month period ended March 31, 2003.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, ACCOUNTING AND DISCLOSURE
REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND
MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (Act), that was signed into law in December 2003,
establishes a prescription drug benefit under Medicare (Medicare Part D), and a
federal subsidy to sponsors of retiree health care benefit plans that provide a
benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003,
we elected a one-time deferral of the accounting for the Act, as permitted by
FASB Staff Position, No. SFAS 106-1.
CMS-36
CMS ENERGY CORPORATION
Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No.
106-1 and provides further guidance for accounting for the Act. Proposed FASB
Staff Position, No. 106-b states that for plans that are actuarially equivalent
to Medicare Part D, employers' measures of accumulated postretirement benefit
obligations (APBO) and postretirement benefit costs should reflect the effects
of the Act.
As of March 31, 2004, we have not determined whether our postretirement benefit
plan is actuarially equivalent to Medicare Part D. Therefore, our measures of
APBO and net periodic postretirement benefit cost do not reflect any amount
associated with the Medicare Prescription Drug, Improvement, and Modernization
Act of 2003. If our prescription drug plan is determined to be actuarially
equivalent to Medicare Part D, we estimate a decrease in OPEB expense of
approximately $23 million for 2004 and a one-time reduction of our benefit
obligation of approximately $150 million, to be amortized over future periods.
This Proposed FASB Staff Position would be effective for the first interim or
annual period beginning after June 15, 2004.
STATEMENT OF POSITION, ACCOUNTING FOR CERTAIN COSTS AND ACTIVITIES RELATED TO
PROPERTY, PLANT, AND EQUIPMENT: At its September 9, 2003 meeting, the Accounting
Standards Executive Committee, of the American Institute of Certified Public
Accountants voted to approve the Statement of Position, Accounting for Certain
Costs and Activities Related to Property, Plant, and Equipment. The Statement of
Position was presented for FASB clearance in April 2004. The FASB elected not to
clear this proposed Statement of Position.
CMS-37
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
(UNAUDITED)
THREE MONTHS ENDED
RESTATED
MARCH 31 2004 2003
- -------- ------- -------
In Millions, Except Per Share Amounts
OPERATING REVENUE $ 1,754 $ 1,968
EARNINGS FROM EQUITY METHOD INVESTEES 19 47
OPERATING EXPENSES
Fuel for electric generation 172 108
Purchased and interchange power 77 239
Purchased power - related parties - 136
Cost of gas sold 761 837
Other operating expenses 222 198
Maintenance 57 58
Depreciation, depletion and amortization 144 128
General taxes 74 69
Asset impairment charges 125 6
------- -------
1,632 1,779
------- -------
OPERATING INCOME 141 236
OTHER INCOME (DEDUCTIONS)
Accretion expense (6) (7)
Gain (loss) on asset sales, net 2 (5)
Interest and dividends 7 4
Other, net 7 7
------- -------
10 (1)
------- -------
FIXED CHARGES
Interest on long-term debt 130 97
Interest on long-term debt - related parties 15 -
Other interest 5 7
Capitalized interest (2) (2)
Preferred dividends 4 -
Preferred securities distributions - 18
------- -------
152 120
------- -------
INCOME (LOSS) BEFORE INCOME TAXES AND MINORITY INTERESTS (1) 115
INCOME TAX EXPENSE (BENEFIT) (3) 39
MINORITY INTERESTS 11 1
------- -------
INCOME (LOSS) FROM CONTINUING OPERATIONS (9) 75
INCOME (LOSS) FROM DISCONTINUED OPERATIONS, NET OF $1
TAX BENEFIT IN 2004 AND $18 TAX EXPENSE IN 2003 (2) 31
------- -------
INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING (11) 106
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING, NET OF $13
TAX BENEFIT IN 2003 :
DERIVATIVES (NOTE 11) - (23)
ASSET RETIREMENT OBLIGATIONS, SFAS NO. 143 (NOTE 10) - (1)
------- -------
- (24)
NET INCOME (LOSS) $ (11) $ 82
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-38
THREE MONTHS ENDED
RESTATED
MARCH 31 2004 2003
-------- -------- --------
In Millions, Except Per Share Amounts
CMS ENERGY
NET INCOME (LOSS)
Net Income (Loss) Available to Common Stock $ (11) $ 82
======== ========
BASIC EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $ (0.06) $ 0.52
Income (Loss) from Discontinued Operations (0.01) 0.21
Loss from Changes in Accounting - (0.16)
-------- --------
Net Income (Loss) Attributable to Common Stock $ (0.07) $ 0.57
======== ========
DILUTED EARNINGS (LOSS) PER AVERAGE COMMON SHARE
Income (Loss) from Continuing Operations $ (0.06) $ 0.47
Income (Loss) from Discontinued Operations (0.01) 0.19
Loss from Changes in Accounting - (0.14)
-------- --------
Net Income (Loss) Attributable to Common Stock $ (0.07) $ 0.52
======== ========
DIVIDENDS DECLARED PER COMMON SHARE $ - $ -
-------- --------
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-39
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
THREE MONTHS ENDED
RESTATED
MARCH 31 2004 2003
- -------- -------- --------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ (11) $ 82
Adjustments to reconcile net income (loss) to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $1 and $2, respectively) 144 128
Loss (gain) on disposal of discontinued operations 1 (6)
Asset impairments (Note 2) 125 6
Capital lease and debt discount amortization 8 2
Accretion expense 6 7
Bad debt expense 2 3
Undistributed earnings from related parties (6) (33)
Loss (gain) on the sale of assets (2) 5
Cumulative effect of accounting changes - 24
Changes in other assets and liabilities:
Increase in accounts receivable and accrued revenue (325) (136)
Decrease in inventories 366 241
Decrease in accounts payable and accrued expenses (84) (40)
Deferred income taxes and investment tax credit 70 27
Changes in other assets and liabilities (59) 105
-------- --------
Net cash provided by operating activities $ 235 $ 415
-------- --------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $ (113) $ (156)
Cost to retire property (18) (17)
Restricted cash (15) (4)
Investment in Electric Restructuring Implementation Plan (2) (2)
Investments in nuclear decommissioning trust funds (1) (2)
Proceeds from nuclear decommissioning trust funds 20 6
Proceeds from sale of assets 5 97
Other investing 9 17
-------- --------
Net cash used in investing activities $ (115) $ (61)
-------- --------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from notes, bonds and other long-term debt $ - $ 326
Retirement of bonds and other long-term debt (263) (170)
Decrease in notes payable - (201)
Payment of capital lease obligations (3) (3)
Other financing - (2)
-------- --------
Net cash used in financing activities $ (266) $ (50)
-------- --------
EFFECT OF EXCHANGE RATES ON CASH (9) 1
-------- --------
NET INCREASE (DECREASE) IN CASH AND TEMPORARY CASH INVESTMENTS $ (155) $ 305
CASH AND TEMPORARY CASH INVESTMENTS FROM EFFECT OF
FIN 46R CONSOLIDATION 174 -
CASH AND TEMPORARY CASH INVESTMENTS, BEGINNING OF PERIOD 532 351
-------- --------
CASH AND TEMPORARY CASH INVESTMENTS, END OF PERIOD $ 551 $ 656
======== ========
CMS-40
THREE MONTHS ENDED
RESTATED
MARCH 31 2004 2003
- -------- -------- --------
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $ 155 $ 119
Income taxes paid (net of refunds) - -
OPEB cash contribution 18 18
NON-CASH TRANSACTIONS
Other assets placed under capital leases $ 1 $ 8
======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-41
CMS ENERGY CORPORATION
CONSOLIDATED BALANCE SHEETS
RESTATED
MARCH 31 MARCH 31
2004 DECEMBER 31 2003
ASSETS (UNAUDITED) 2003 (UNAUDITED)
----------- ----------- -----------
In Millions
PLANT AND PROPERTY (AT COST)
Electric utility $ 7,698 $ 7,600 $ 7,356
Gas utility 2,891 2,875 2,787
Enterprises 3,408 895 684
Other 32 32 42
-------- -------- --------
14,029 11,402 10,869
Less accumulated depreciation, depletion and amortization 5,942 4,846 4,737
-------- -------- --------
8,087 6,556 6,132
Construction work-in-progress 405 388 496
-------- -------- --------
8,492 6,944 6,628
-------- -------- --------
INVESTMENTS
Enterprises Investments 710 724 754
Midland Cogeneration Venture Limited Partnership - 419 405
First Midland Limited Partnership - 224 259
Other 24 23 2
-------- -------- --------
734 1,390 1,420
-------- -------- --------
CURRENT ASSETS
Cash and temporary cash investments at cost, which approximates market 551 532 656
Restricted cash 216 201 43
Accounts receivable, notes receivable and accrued revenue, less
allowances of $29, $29 and $14, respectively 734 367 392
Accounts receivable - Energy Resource Management,
less allowances of $10, $11 and $9, respectively 29 36 305
Accounts receivable and notes receivable - related parties 69 73 179
Inventories at average cost
Gas in underground storage 419 741 258
Materials and supplies 102 110 100
Generating plant fuel stock 41 41 26
Assets held for sale 66 24 305
Price risk management assets 88 102 95
Derivative instruments 118 14 -
Prepayments and other 286 253 239
-------- -------- --------
2,719 2,494 2,598
-------- -------- --------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 637 648 678
Postretirement benefits 156 162 180
Abandoned Midland Project 10 10 11
Other 303 266 233
Assets held for sale 2 2 2,024
Price risk management assets 178 177 172
Nuclear decommissioning trust funds 566 575 529
Prepaid pension costs 383 388 -
Goodwill 25 25 32
Notes receivable - related parties 231 242 148
Notes receivable 125 125 126
Other 556 390 422
-------- -------- --------
3,172 3,010 4,555
-------- -------- --------
TOTAL ASSETS $ 15,117 $ 13,838 $ 15,201
======== ======== ========
CMS-42
RESTATED
MARCH 31 MARCH 31
2004 DECEMBER 31 2003
STOCKHOLDERS' INVESTMENT AND LIABILITIES (UNAUDITED) 2003 (UNAUDITED)
----------- ----------- -----------
In Millions
CAPITALIZATION
Common stockholders' equity
Common stock, authorized 250.0 shares; outstanding 161.1 shares,
161.1 shares and 144.1 shares, respectively $ 2 $ 2 $ 1
Other paid-in capital 3,846 3,846 3,605
Other comprehensive loss (317) (419) (713)
Retained deficit (1,855) (1,844) (1,718)
-------- -------- --------
1,676 1,585 1,175
Preferred stock of subsidiary 44 44 44
Preferred stock 261 261 -
Company-obligated convertible Trust Preferred Securities
of subsidiaries - - 393
Company-obligated mandatorily redeemable Trust Preferred Securities
of Consumers' subsidiaries - - 490
Long-term debt 5,829 6,020 5,217
Long-term debt - related parties 684 684 -
Non-current portion of capital leases 329 58 121
-------- -------- --------
8,823 8,652 7,440
-------- -------- --------
MINORITY INTERESTS 754 73 41
-------- -------- --------
CURRENT LIABILITIES
Current portion of long-term debt and capital leases 892 519 929
Notes payable - - 253
Accounts payable 257 296 359
Accounts payable - Energy Resource Management 19 21 131
Accounts payable - related parties - 40 55
Accrued interest 118 130 108
Accrued taxes 247 285 283
Liabilities held for sale 2 2 280
Price risk management liabilities 77 89 95
Current portion of purchase power contracts 19 27 26
Current portion of gas supply contract obligations 30 29 26
Deferred income taxes 40 27 23
Other 263 185 201
-------- -------- --------
1,964 1,650 2,769
-------- -------- --------
NON-CURRENT LIABILITIES
Postretirement benefits 264 265 732
Deferred income taxes 663 615 401
Deferred investment tax credit 84 85 89
Regulatory liabilities for income taxes, net 317 312 311
Regulatory liabilities for cost of removal 1,005 983 937
Other regulatory liabilities 175 172 152
Asset retirement obligation 401 359 365
Liabilities held for sale - - 1,266
Price risk management liabilities 174 175 165
Gas supply contract obligations 196 208 226
Power purchase agreement - MCV Partnership - - 21
Other 297 289 286
-------- -------- --------
3,576 3,463 4,951
-------- -------- --------
COMMITMENTS AND CONTINGENCIES (Notes 1, 3 and 4)
TOTAL STOCKHOLDERS' INVESTMENT AND LIABILITIES $ 15,117 $ 13,838 $ 15,201
======== ======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-43
CMS ENERGY CORPORATION
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY
(UNAUDITED)
THREE MONTHS ENDED
RESTATED
MARCH 31 2004 2003
- -------- -------- --------
In Millions
COMMON STOCK
At beginning and end of period $ 2 $ 1
-------- --------
OTHER PAID-IN CAPITAL
At beginning of period 3,846 3,605
Common stock repurchased - -
Common stock reacquired - -
Common stock issued - -
-------- --------
At end of period 3,846 3,605
-------- --------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning of period - (241)
Unrealized gain (loss) on investments (a) - -
-------- --------
At end of period - (241)
-------- --------
Investments
At beginning of period 8 2
Unrealized gain on investments (a) 1 -
-------- --------
At end of period 9 2
-------- --------
Derivative Instruments
At beginning of period (8) (31)
Unrealized gain (loss) on derivative instruments (a) (3) 7
Reclassification adjustments included in net income (loss) (a) (2) (5)
-------- --------
At end of period (13) (29)
-------- --------
Foreign Currency Translation
At beginning of period (419) (458)
Change in foreign currency translation (a) 106 13
-------- --------
At end of period (313) (445)
-------- --------
At end of period (317) (713)
-------- --------
RETAINED DEFICIT
At beginning of period (1,844) (1,800)
Net income (loss) (a) (11) 82
Common stock dividends declared - -
-------- --------
At end of period (1,855) (1,718)
-------- --------
TOTAL COMMON STOCKHOLDERS' EQUITY $ 1,676 $ 1,175
======== ========
(a) DISCLOSURE OF OTHER COMPREHENSIVE INCOME (LOSS):
Minimum Pension Liability
Minimum pension liability adjustments, net of tax of
$- and $-, respectively $ - $ -
Investments
Unrealized gain on investments, net of tax
of $- and $-, respectively 1 -
Derivative Instruments
Unrealized gain (loss) on derivative instruments,
net of tax of $5 and $5, respectively (3) 7
Reclassification adjustments included in net income (loss),
net of tax benefit of $(1) and $(3), respectively (2) (5)
Foreign currency translation, net 106 13
Net income (loss) (11) 82
-------- --------
Total Other Comprehensive Income $ 91 $ 97
======== ========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CMS-44
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, 2003. 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 the parent holding company of Consumers and
Enterprises. Consumers is a combination electric and gas utility company serving
Michigan's Lower Peninsula. Enterprises, through subsidiaries, is engaged in
domestic and international diversified energy businesses including independent
power production, natural gas transmission, storage and processing, and energy
services.
PRINCIPLES OF CONSOLIDATION: The consolidated financial statements include the
accounts of CMS Energy, Consumers and 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. The primary beneficiary
of a variable interest entity is the party that absorbs or receives a majority
of the entity's expected losses or expected residual returns or both as a result
of holding variable interests, which are ownership, contractual, or other
economic interests. As of and for the quarter ended March 31, 2004, we
determined that the MCV Partnership and the FMLP should be consolidated in
accordance with Revised FASB Interpretation No. 46. For additional details, see
Note 11, Implementation of New Accounting Standards. 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. Intercompany transactions and
balances have been eliminated.
USE OF ESTIMATES: We prepare our financial statements in conformity with
accounting principles generally accepted in the United States. Management is
required to make estimates using assumptions that affect the reported amounts
and disclosures. Actual results could differ from those estimates.
We are required to record estimated liabilities in the 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,
Uncertainties.
CMS-45
CMS Energy Corporation
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity
and natural gas, and the transportation, processing, and storage of natural gas
when services are provided. Sales taxes are recorded as liabilities and are not
included in revenues. Revenues on sales of marketed electricity, natural gas,
and other energy products are recognized at delivery. Mark-to-market changes in
the fair values of energy trading contracts that qualify as derivatives are
recognized as revenues in the periods in which the changes occur.
CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred, and our non-regulated businesses are prohibited
from imputing interest costs on any equity funds. Our regulated businesses are
permitted to capitalize an allowance for funds used during construction on
regulated construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an
original maturity of three months or less are considered cash equivalents. At
March 31, 2004, our restricted cash on hand was $216 million. Restricted cash
primarily includes cash collateral for letters of credit to satisfy certain debt
agreements and cash dedicated for repayment of Securitization bonds. It is
classified as a current asset as the related letters of credit mature within one
year and the payments on the related Securitization bonds occur within one year.
EARNINGS PER SHARE: Basic and diluted earnings per share are based on the
weighted average number of shares of common stock and dilutive potential common
stock outstanding during the period. Potential common stock, for purposes of
determining diluted earnings per share, includes the effects of dilutive stock
options, warrants and convertible securities. The effect on number of shares of
such potential common stock is computed using the treasury stock method or the
if-converted method, as applicable. For earnings per share computation, see Note
5, Earnings Per Share and Dividends.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
in accordance with SFAS No. 115. Debt and equity securities can be classified
into one of three categories: held-to-maturity, trading, or available-for-sale.
Our investments in equity securities are classified as available-for-sale
securities. They are reported at fair value, with any unrealized gains or losses
resulting from changes in fair value reported in equity as part of accumulated
other comprehensive income and are excluded from earnings unless such changes in
fair value are determined to be other than temporary. Unrealized gains or losses
from changes in the fair value of our nuclear decommissioning investments are
reported as regulatory liabilities. The fair value of these investments is
determined from quoted market prices. Our debt securities are classified as
held-to-maturity securities and are reported at cost. For additional details
regarding financial instruments, see Note 6, Financial and Derivative
Instruments.
FOREIGN CURRENCY TRANSLATION: 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, and gains and losses on
intercompany foreign currency transactions that are long-term in nature that we
do not intend to settle in the foreseeable future, are shown in the
stockholders' equity section in the Consolidated Balance Sheets. For
subsidiaries operating in highly inflationary economies, the U.S. dollar is
considered to be the functional currency, and transaction gains and losses are
included in determining net income. Gains and losses that arise from exchange
rate fluctuations on transactions denominated in a currency other than the
functional currency, except those that are hedged, are included
CMS-46
CMS Energy Corporation
in determining net income. For the three months ended March 31, 2004, the change
in the foreign currency translation adjustment increased equity by $106 million
and for the three months ended March 31, 2003, the change in the foreign
currency translation adjustment increased equity by $13 million.
IMPAIRMENT OF INVESTMENTS AND LONG-LIVED ASSETS: 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 asset exceeds its
estimated undiscounted future cash flows, an impairment loss is recognized and
the asset is written down to its estimated fair value.
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 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. As
of March 31, 2004, we have recorded a liability to the DOE for $139 million,
including interest, which is payable upon the first delivery of spent nuclear
fuel to the DOE. The amount of this liability, excluding a portion of interest,
was recovered through electric rates. For additional details on disposal of
spent nuclear fuel, see Note 3, Uncertainties, "Other Consumers' Electric
Utility Uncertainties - Nuclear Matters."
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original cost is
charged to accumulated depreciation and cost of removal, less salvage is
recorded as a regulatory liability. For additional details, see Note 10, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.
RECLASSIFICATIONS: Certain prior year amounts have been reclassified for
comparative purposes. These reclassifications did not affect consolidated net
income for the years presented.
UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.
SFAS No. 144 imposes strict criteria for retention of regulatory-created assets
by requiring that such assets be probable of future recovery at each balance
sheet date. Management believes these assets are probable of future recovery.
2: DISCONTINUED OPERATIONS, OTHER ASSET SALES, IMPAIRMENTS, AND RESTRUCTURING
Our continued focus on financial improvement has led to discontinuing
operations, completing many asset sales, impairing some assets, and incurring
costs to restructure our business. Gross cash proceeds received from the sale of
assets totaled $5 million for the three months ended March 31, 2004 and $97
million for the three months ended March 31, 2003.
CMS-47
CMS Energy Corporation
DISCONTINUED OPERATIONS
We have discontinued the following operations:
In Millions
- -------------------------------------------------------------------------------------
Pretax After-tax
Business/Project Discontinued Gain(Loss) Gain(Loss) Status
- ------------------ ------------- ---------- ---------- ------------------
CMS Viron June 2002 (14) (9) Sold June 2003
Panhandle December 2002 (39) (44) Sold June 2003
CMS Field Services December 2002 (5) (1) Sold July 2003
Marysville June 2003 2 1 Sold November 2003
Parmelia (a) December 2003 -- -- Held for sale
(a) We expect the sale of Parmelia to occur in 2004. In December 2003, we
reduced the carrying amount of our Parmelia business to reflect fair
value. The $26 million after-tax loss was reported in discontinued
operations in December 2003.
At March 31, 2004, "Assets held for sale" includes Parmelia, our investment in
Loy Yang, and our investment in the American Gas Index fund. Although Loy Yang
and the American Gas Index fund are considered held for sale, they did not meet
the criteria for discontinued operations. At March 31, 2003, "Assets held for
sale" includes Panhandle, CMS Viron, CMS Field Services, Marysville, and
Parmelia. The major classes of assets and liabilities held for sale are as
follows:
In Millions
- --------------------------------------------------------------------------------
Restated
March 31 December 31 March 31
2004 2003 2003
-------- ----------- --------
Assets
Cash $ 8 $ 7 $ 65
Accounts receivable 14 2 160
Property, plant and equipment - net 2 2 1,833
Goodwill - - 117
Other 44 15 154
-------- ----------- --------
Total assets held for sale $ 68 $ 26 $ 2,329
======== =========== ========
Liabilities
Accounts payable $ 2 $ 2 $ 97
Long-term debt - - 1,147
Minority interest - - 44
Other - - 258
-------- ----------- --------
Total liabilities held for sale $ 2 $ 2 $ 1,546
======== =========== ========
CMS-48
CMS Energy Corporation
The following amounts are reflected in the Consolidated Statements of Income
(Loss) from discontinued operations:
In Millions
- -------------------------------------------------------------------------------
Restated
Three months ended March 31 2004 2003
- --------------------------------------------------------- ------ --------
Revenues $ 5 $ 246
====== ========
Discontinued operations:
Pretax income gain (loss) from discontinued operations $ (1) $ 40
Income tax expense - 15
------ --------
Income (loss) from discontinued operations (1) 25
Pretax gain (loss) on disposal of discontinued operations (2) 9
Income tax expense (benefit) (1) 3
------ --------
Gain (loss) on disposal of discontinued operations (1) 6
------ --------
Income (loss) from discontinued operations $ (2) $ 31
====== ========
The income (loss) from discontinued operations includes a reduction in asset
values, a provision for anticipated closing costs, and a portion of CMS Energy's
interest expense. Interest expense of less than $1 million for the three months
ended March 31, 2004 and $11 million for the three months ended March 31, 2003
has been allocated based on a ratio of the expected proceeds for the asset to be
sold divided by CMS Energy's total capitalization of each discontinued operation
times CMS Energy's interest expense.
OTHER ASSET SALES
Our other asset sales include the following non-strategic and under-performing
assets. The impacts of these sales are included in "Gain (loss) on asset sales,
net" in the Consolidated Statements of Income (Loss).
For the three months ended March 31, 2004, we sold the following assets that did
not meet the definition of, and therefore were not reported as, discontinued
operations:
In Millions
- -------------------------------------------------------------
Pretax After-tax
Date sold Business/Project Gain Gain
- --------- ------------------------- ------ ---------
February Bluewater Pipeline (a) $ 1 $ 1
Various Other 1 1
------ ---------
Total gain on asset sales $ 2 $ 2
====== =========
(a) Bluewater Pipeline is a 24.9 mile pipeline that extends from Marysville,
Michigan to Armada, Michigan.
For the three months ended March 31, 2003, we sold the following assets that did
not meet the definition
CMS-49
CMS Energy Corporation
of, and therefore were not reported as, discontinued operations:
In Millions
- -------------------------------------------------------------
Pretax After-tax
Date sold Business/Project Gain(Loss) Gain(Loss)
- --------- ---------------- ---------- ----------
January CMS MST Wholesale Gas $ (6) $ (4)
March CMS MST Wholesale Power 2 1
Various Other (1) -
---- ----
Total loss on asset sales $ (5) $ (3)
==== ====
In April 2004, we and our partners sold the 2,000-megawatt Loy Yang power plant
and adjacent coal mine in Victoria, Australia for about A$3.5 billion ($2.6
billion in U.S. dollars), including A$145 million for the project equity. Our
share of the gross proceeds was about $54 million and is subject to closing
adjustments and transaction costs. In anticipation of the sale, we recorded an
impairment in the first quarter as reflected below.
ASSET IMPAIRMENTS
We record an asset impairment when we determine that the expected future cash
flows from an asset would be insufficient to provide for recovery of the asset's
carrying value. An asset held-in-use is evaluated for impairment by calculating
the undiscounted future cash flows expected to result from the use of the asset
and its eventual disposition. If the undiscounted future cash flows are less
than the carrying amount, we recognize an impairment loss. The impairment loss
recognized is the amount by which the carrying amount exceeds the fair value. We
estimate the fair market value of the asset utilizing the best information
available. This information includes quoted market prices, market prices of
similar assets, and discounted future cash flow analyses. The assets written
down include both domestic and foreign electric power plants, gas processing
facilities, and certain equity method and other investments. In addition, we
have written off the carrying value of projects under development that will no
longer be pursued.
The table below summarizes our asset impairments:
In Millions
- -----------------------------------------------------------------
Pretax After-tax Pretax After-tax
Three months ended March 31 2004 2004 2003 2003
- --------------------------- ------ --------- ------ ---------
Asset impairments:
Enterprises (a) $ - $ - $ 6 $ 4
Loy Yang (b) 125 81 - -
------ ---- --- ---
Total asset impairments $ 125 $ 81 $ 6 $ 4
====== ==== === ===
(a) In the first quarter of 2003, an impairment was recorded to reflect
the fair value of two generators.
(b) In the first quarter of 2004, an impairment charge was recorded to
recognize the reduction in fair value as a result of the sale of Loy
Yang, completed in April 2004, which included a cumulative net
foreign currency translation loss of approximately $110 million.
RESTRUCTURING AND OTHER COSTS
In June 2002, we announced a series of initiatives to reduce our annual
operating costs by an estimated $50 million. As such, we:
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CMS Energy Corporation
- relocated CMS Energy's corporate headquarters from Dearborn,
Michigan to a new combined CMS Energy and Consumers headquarters in
Jackson, Michigan in July 2003,
- implemented changes to our 401(k) savings program,
- implemented changes to our health care plan, and
- completed the termination of numerous employees, including five
officers.
The following tables shows the amount charged to expense for restructuring
costs, the payments made, and the unpaid balance of accrued costs for the three
months ended March 31, 2004 and March 31, 2003.
In Millions
- -----------------------------------------------------------------------------
March 31, 2004
---------------------------------
Involuntary Lease
Termination Termination Total
----------- ----------- -----
Beginning accrual balance, January 1, 2004 $ 3 $ 6 $ 9
Expense - - -
Payments (1) (1) (2)
---- ---- ----
Ending accrual balance at March 31, 2004 $ 2 $ 5 $ 7
==== ==== ====
In Millions
- -----------------------------------------------------------------------------
March 31, 2003
---------------------------------
Involuntary Lease
Termination Termination Total
----------- ----------- -----
Beginning accrual balance, January 1, 2003 $ 12 $ 8 $ 20
Expense 1 - 1
Payments (5) - (5)
---- ---- -----
Ending accrual balance at March 31, 2003 $ 8 $ 8 $ 16
===== ==== =====
3: UNCERTAINTIES
Several business trends or uncertainties may affect our financial results. These
trends or uncertainties have, or we reasonably expect could have, a material
impact on net sales, revenues, or income from continuing operations. Such trends
and uncertainties are discussed in detail below.
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 has implemented the
recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip
trading. 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
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CMS ENERGY CORPORATION
action against CMS Energy related to round-trip trading. The order did not
assess a fine and CMS Energy neither admitted to nor denied the order's
findings. The settlement resolved the SEC investigation involving CMS Energy and
CMS MST.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. 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. The cases were
consolidated into a single lawsuit and an amended and consolidated class action
complaint was filed on May 1, 2003. The consolidated complaint contains a
purported class period beginning on May 1, 2000 and running through March 31,
2003. It 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. The judge issued an opinion
and order dated March 31, 2004 in connection with various pending motions,
including plaintiffs' motion to amend the complaint and the motions to dismiss
the complaint filed by CMS Energy, Consumers and other defendants. The judge
directed plaintiffs to file an amended complaint under seal and ordered an
expedited hearing on the motion to amend. Based on his decision with respect to
the motion to amend, the judge dismissed certain of plaintiffs' claims without
prejudice and denied without prejudice the motions to dismiss other claims. The
judge will permit CMS Energy and the other defendants to renew the motions to
dismiss at or shortly after the hearing on the motion to amend. CMS Energy,
Consumers, and their affiliates will defend themselves vigorously but cannot
predict the outcome of this litigation.
DEMAND FOR ACTIONS 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 is 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 on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to June 1, 2004, subject to
such further extensions as may be mutually agreed upon by the parties and
authorized by the Court. CMS Energy cannot predict the outcome of this matter.
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. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge
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CMS ENERGY CORPORATION
dismissed certain of the amended counts in the plaintiffs' complaint and denied
CMS Energy's motion to dismiss the other claims in the complaint. CMS Energy,
Consumers and the individual defendants are now required to file answers to the
amended complaint on or before May 14, 2004. CMS Energy and Consumers will
defend themselves vigorously but cannot predict the outcome of this litigation.
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, this investigation will have on
its business.
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 court ordered the Cornerstone
complaint to be consolidated with similar complaints filed by Dominick Viola and
Roberto Calle Gracey. 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. 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, Inc. but
is required to indemnify Cantera Natural Gas, Inc. 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 against a number of energy companies engaged in the sale
of natural gas in the United States. CMS Energy is named as a defendant. The
complaint alleges defendants entered into a price-fixing conspiracy by engaging
in activities to manipulate the price of natural gas in California. The
complaint contains counts alleging violations of the Sherman Act, Cartwright Act
(a California statute), and the California Business and Profession Code relating
to unlawful, unfair and deceptive business practices. There is currently pending
in the Nevada federal district court a multi district court litigation ("MDL")
matter involving 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 Sherman Act claim. Some
of the defendants in the MDL matter who are also defendants in the Texas-Ohio
case are trying to have the Texas-Ohio case transferred to the MDL proceeding.
The plaintiff in the Texas-Ohio case has agreed to extend the time for all
defendants to answer or otherwise respond until after the MDL panel decides
whether to take the case.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint
containing allegations similar to those made in the Texas-Ohio case, albeit
limited to California state law claims, was filed in California state court in
February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed
a notice to remove this action to California federal district court and are
seeking to have it transferred to the MDL proceeding in Nevada.
CMS Energy and the other CMS defendants will defend themselves vigorously, but
cannot predict the outcome of these matters.
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CMS ENERGY CORPORATION
CONSUMERS' UNCERTAINTIES
Several business trends or uncertainties may affect our financial results and
condition. These trends or uncertainties have, or we expect could have, a
material impact on revenues or income from continuing electric and gas
operations. Such trends and uncertainties include:
Environmental
- increased capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts, Superfund, and at former manufactured
gas plant facilities.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- recovery of electric restructuring implementation costs,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer, instead of an electric
transmission owner-operator.
Regulatory
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to
purchased power price increases,
- recovery of nuclear decommissioning costs,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel,
- inadequate regulatory response to applications for requested rate
increases, and
- response to increases in gas costs, including adverse regulatory
response and reduced gas use by customers.
Other
- pending litigation regarding PURPA qualifying facilities, and
- pending other litigation.
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: In 1998, the EPA issued regulations requiring the state of Michigan
to further limit nitrogen oxide emissions at our coal-fired electric plants. The
Michigan Department of Environmental Quality finalized its rules to comply with
the EPA regulations in December 2002. The EPA's conditional approval of the
Michigan rules was published in April 2004. The Michigan Department of
Environmental Quality is currently correcting deficiencies in its rules that
were identified by the EPA. If the Department of Environmental Quality fails to
submit satisfactory revisions to the EPA by the end of May 2004, the EPA's
conditional approval will automatically revert to a disapproval and similar
federal regulations will take effect.
The EPA and the state regulations require us to make significant capital
expenditures estimated to be
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CMS ENERGY CORPORATION
$771 million. As of March 31, 2004, we have incurred $469 million in capital
expenditures to comply with the EPA regulations and anticipate that the
remaining $302 million of capital expenditures will be made between 2004 and
2009. These expenditures include installing catalytic reduction technology on
some of our coal-fired electric plants. Based on the Customer Choice Act,
beginning January 2004, an annual return of and on these types of capital
expenditures, to the extent they are above depreciation levels, is expected to
be recoverable from customers, subject to the MPSC prudency hearing.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek 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.
In addition to modifying the coal-fired electric plants, we expect to purchase
nitrogen oxide emissions credits for years 2004 through 2008. The cost of these
credits is estimated to average $8 million per year and is accounted for as
inventory. The credit inventory is expensed as the coal-fired electric plants
generate electricity. The price for nitrogen oxide emissions credits is volatile
and could change substantially.
The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which
requires additional coal-fired electric plant emission controls for nitrogen
oxides and sulfur dioxide. If implemented, this rule would potentially require
expenditures equivalent to those efforts in progress required to reduce nitrogen
oxide emissions under the Title I provisions of the Clean Air Act. The rule
proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent
and nitrogen oxides by 65 percent by 2015, through the installation of flue gas
desulfurization scrubbers and selective catalytic reduction units. Additionally,
the EPA also proposed two alternative sets of rules to reduce emissions of
mercury and nickel from coal-fired and oil-fired electric plants. Until the
proposed environmental rules are finalized, an accurate cost of compliance
cannot be determined.
Several bills have been introduced in the United States Congress that would
require carbon dioxide emissions reduction. We cannot predict whether any
federal mandatory carbon dioxide emissions reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
To the extent that emissions reduction rules comes into legal effect, such
mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows or financial position
due to the speculative nature of the policy. 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 changed the 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 by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.
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.
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CMS Energy Corporation
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. As of March 31, 2004, 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.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling 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. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants. We believe we
have been performing the calculation in the manner prescribed by the power
purchase agreements, and have filed a request with the MPSC (as a supplement to
the PSCR plan) that asks the MPSC to review this issue and to confirm that our
method of performing the calculation is correct. We filed a motion to dismiss
the lawsuit in the Ingham County Circuit Court due to the pending request at the
MPSC concerning the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
resulted in a dismissal of the circuit court case without prejudice. Although
only eight qualifying facilities have raised the issue, the same energy charge
methodology is used in the PPA with the MCV Partnership and in approximately 20
additional power purchase agreements with us, representing a total of 1,670 MW
of electric capacity. We cannot predict the outcome of this matter.
CONSUMERS' ELECTRIC UTILITY RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: The Michigan legislature passed electric
utility restructuring legislation known as the Customer Choice Act. This act:
- allows all customers to choose their electric generation supplier
effective January 1, 2002,
- provides a one-time five percent residential electric rate
reduction,
- froze all electric rates through December 31, 2003, and established
a rate cap for residential customers through at least December 31,
2005, and a rate cap for small commercial and industrial customers
through at least December 31, 2004,
- allows deferred recovery of an annual return of and on capital
expenditures in excess of depreciation levels incurred during and
before the rate freeze-cap period,
- allows for the use of Securitization bonds to refinance qualified
costs,
- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the act,
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CMS Energy Corporation
- requires Michigan utilities to join a FERC-approved RTO or sell
their interest in transmission facilities to an independent
transmission owner,
- requires Consumers, Detroit Edison, and AEP to jointly expand their
available transmission capability by at least 2,000 MW, and
- establishes a market power supply test that, if not met, may require
transferring control of generation resources in excess of that
required to serve retail sales requirements.
The following summarizes our status under the last three provisions of the
Customer Choice Act. First, we chose to sell our interest in our transmission
facilities to an independent transmission owner in order to comply with the
Customer Choice Act; for additional details regarding the sale of the
transmission facility, see "Transmission Sale" within this section. Second, in
July 2002, the MPSC issued an order approving our plan to achieve the increased
transmission capacity required under the Customer Choice Act. We have completed
the transmission capacity projects identified in the plan and have submitted
verification of this fact to the MPSC. We believe we are in full compliance.
Lastly, in September 2003, the MPSC issued an order finding that we are in
compliance with the market power supply test set forth in the Customer Choice
Act.
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms,
and conditions under which retail customers are permitted to choose an electric
supplier. These revised tariffs allow ROA customers, upon as little as 30 days
notice to us, to return to our generation service at current tariff rates. If
any class of customers' (residential, commercial, or industrial) ROA load
reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods.
We cannot predict the total amount of electric supply load that may be lost to
competitor suppliers. As of April 2004, alternative electric suppliers are
providing 823 MW of load. This amount represents 10 percent of the total
distribution load and an increase of 50 percent compared to April 2003.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings. They are:
- Securitization,
- Stranded Costs,
- implementation costs, and
- transmission.
Securitization: The Customer Choice Act allows for the use of Securitization
bonds to refinance certain qualified costs. Since Securitization involves
issuing bonds secured by a revenue stream from rates collected directly from
customers to service the bonds, Securitization bonds typically have a higher
credit rating than conventional utility corporate financing. In 2000 and 2001,
the MPSC issued orders authorizing us to issue Securitization bonds. We issued
our first Securitization bonds in late 2001. Securitization resulted in:
- lower interest costs, and
- longer amortization periods for the securitized assets.
We will recover the repayment of principal, interest, and other expenses
relating to the bond issuance
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CMS Energy Corporation
through a Securitization charge and a tax charge that began in December 2001.
These charges are subject to an annual true up until one year before the last
scheduled bond maturity date, and no more than quarterly thereafter. The
December 2003 true up modified the total Securitization and related tax charges
from 1.746 mills per kWh to 1.718 mills per kWh. There will be no impact on
customer bills from Securitization for most of our electric customers until the
Customer Choice Act cap period expires, and an electric rate case is processed.
Securitization charge collections, $13 million for the three months ended March
31, 2004, and $13 million for the three months ended March 31, 2003, are
remitted to a trustee. Securitization charge collections are restricted to the
repayment of the principal and interest on the Securitization bonds and payment
of the ongoing expenses of Consumers Funding. Consumers Funding is legally
separate from Consumers. The assets and income of Consumers Funding, including
the securitized property, are not available to creditors of Consumers or CMS
Energy.
In March 2003, we filed an application with the MPSC seeking approval to issue
additional Securitization bonds. In June 2003, the MPSC issued a financing order
authorizing the issuance of Securitization bonds in the amount of $554 million.
This amount relates to Clean Air Act expenditures and associated return on those
expenditures through December 31, 2002; ROA implementation costs, and previously
authorized return on those expenditures through December 31, 2000; and other up
front qualified costs related to issuance of the Securitization bonds. In July
2003, we filed for rehearing and clarification on a number of features in the
financing order.
In December 2003, the MPSC issued its order on rehearing, which rejected our
requests for clarification and modification to the dividend payment restriction,
failed to rule directly on the accounting clarifications requested, and remanded
the proceeding to the ALJ for additional proceedings to address rate design. The
ALJ completed hearings in March 2004 and the MPSC decision is not anticipated
before May 2004, but could be later. The financing order will become effective
after our acceptance of a favorable MPSC order. Bonds will not be issued until
resolution of any appeals.
Stranded Costs: The Customer Choice Act allows electric utilities to recover
their net Stranded Costs, without defining the term. The Act directs the MPSC to
establish a method of calculating net Stranded Costs and of conducting related
true-up adjustments. In December 2001, the MPSC Staff recommended a methodology,
which calculated net Stranded Costs as the shortfall between:
- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and
- the revenues received from customers under existing rates available
to cover the revenue requirement.
The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost transition
charge. However, the MPSC has not yet allowed such a transition charge. As a
result, we have not recorded regulatory assets to recognize the future recovery
of such costs.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero net
Stranded Costs from 1999 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We are
currently in the process of appealing these orders with the Michigan Court of
Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred
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CMS Energy Corporation
in 2002, and for approval of a net Stranded Cost recovery charge. Our net
Stranded Costs incurred in 2002, including the cost of money, are estimated to
be $47 million with the issuance of Securitization bonds that include Clean Air
Act investments, or $104 million without the issuance of Securitization bonds
that include Clean Air Act investments. The MPSC scheduled hearings for our 2002
Stranded Cost application to take place during the second quarter of 2004. Once
a final financing order on Securitization is reached, we will know the amount of
our request for net Stranded Cost recovery for 2002.
In February 2004, the MPSC issued an order on Detroit Edison's request for rate
relief for costs associated with customers leaving under electric customer
choice. The MPSC order allows Detroit Edison to charge a transition surcharge to
ROA customers and eliminates Securitization charge offsets. In April 2004, we
filed an application with the MPSC seeking approval of net Stranded Costs
incurred in 2003, including the cost of money, in the amount of $106 million
with the issuance of Securitization bonds that include Clean Air Act
investments, or $165 million without the issuance of Securitization bonds that
include Clean Air Act investments. Similar to the request that was granted by
the MPSC for Detroit Edison, we also requested interim relief for 2002 and 2003
net Stranded Costs.
We cannot predict whether the Stranded Cost recovery method adopted
by the MPSC will be applied in a manner that will fully offset any associated
margin loss from ROA.
Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines the
applications filed by us with the MPSC and the status of recovery for these
costs.
In Millions
- --------------------------------------------------------------------------------
Year Filed Year Incurred Requested Pending Allowed Disallowed
- --------------------------------------------------------------------------------
1999 1997 & 1998 $20 $ - $15 $5
2000 1999 30 - 25 5
2001 2000 25 - 20 5
2002 2001 8 - 8 -
2003 & 2004 (a) 2002 7 7 Pending Pending
2004 2003 1 1 Pending Pending
================================================================================
(a) On March 31, 2004, we requested additional 2002 implementation cost recovery
of $5 million related to our former participation in the development of the
Alliance RTO. This cost has been expensed; therefore, the amount is not included
as a regulatory asset.
The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. In the
order received for the year 2001, the MPSC also reserved the right to reevaluate
the implementation costs depending upon the progress and success of the ROA
program, and ruled that due to the rate freeze imposed by the Customer Choice
Act, it was premature to establish a cost recovery method for the allowable
implementation costs. In addition to the amounts shown above, we incurred and
deferred as a regulatory asset, as of March 31, 2004, $23 million for the cost
of money associated with total implementation costs. We believe the
implementation costs and associated cost of money are fully recoverable in
accordance with the Customer Choice Act. We expect cash recovery from customers
to begin after rate cap periods expire. The rate cap expired for large
commercial and industrial customers on December 31, 2003.
In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision
finding that the recovery of 1999 implementation costs is conditional and
subject to later disallowance is unlawful. The case was remanded to the MPSC.
The MPSC issued an order regarding the remanded proceeding that directed us to
choose whether we prefer to recover our approved implementation costs through
Securitization pursuant to the MPSC's final order in the Securitization
proceeding or whether we would prefer to have recovery controlled by the remand
proceeding. If the latter option was chosen, the MPSC indicated that it intended
to authorize recovery of such implementation costs through the use of surcharges
on all customer classes that coincide with the expiration of the Customer Choice
Act rate caps. We chose recovery of the approved implementation costs through
the use of surcharges and withdrew our request for approved implementation costs
recovery from our Securitization proposal. The implementation costs withdrawn
from the Securitization case were incurred for the years 1998 through 2000. In
the filing we made electing recovery through separate surcharges, we requested
approval of surcharges that would allow recovery of implementation costs
incurred for the years 1998 through 2001. We requested that the Court of Appeals
issue similar remand orders with respect to appeals of the MPSC orders
addressing 2000 and 2001 implementation costs. We cannot predict the amounts the
MPSC will approve as recoverable costs.
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Also, we are pursuing authorization at the FERC for the MISO to reimburse us for
$8 million in certain electric utility restructuring implementation costs
related to our former participation in the development of the Alliance RTO, a
portion of which has been expensed. The FERC issued an order denying the MISO's
request for authorization to reimburse us and we are in the process of appealing
the FERC ruling at the United States Court of Appeals for the District of
Columbia. We also requested that the MISO seek authorization to reimburse METC
for these development costs. The MISO filed this request but the FERC denied it.
While we appeal the FERC's orders, we are also pursuing other potential means of
recovery, such as recovery of Alliance RTO development costs at the MPSC. We
cannot predict the outcome of the appeal process or the ultimate amount, if any,
we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act allows for recovery of new and enhanced
security costs, as a result of federal and state regulatory security
requirements. All retail customers, except customers of alternative electric
suppliers, would pay these charges. In April 2004, we filed a security cost
recovery case with the MPSC for $25 million of cost that regulatory treatment
has not yet been granted through other means. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. We cannot
predict how the MPSC will rule on our requests for the recoverability of
security costs.
Transmission Rates: Our application of JOATT transmission rates to customers
during past periods is under FERC review. The rates included in these tariffs
were applied to certain transmission transactions affecting both Detroit
Edison's and our transmission systems between 1997 and 2002. We believe our
reserve is sufficient to satisfy our refund obligation to any of our former
transmission customers under our former JOATT.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system for
$290 million to MTH, a non-affiliated limited partnership whose general partner
is a subsidiary of Trans-Elect, Inc. The pretax gain was $31 million ($26
million, net of tax). We are currently in arbitration with MTH regarding
property tax items used in establishing the selling price of our electric
transmission system. We cannot predict whether remaining open items will affect
materially the recorded gain on the sale. As a result of the sale, after-tax
earnings have decreased due to a loss of revenue from wholesale and ROA
customers who will buy services directly from MTH.
METC has completed the capital program to expand the transmission system's
capability to import electricity into Michigan, as required by the Customer
Choice Act. We will continue to maintain the system until May 1, 2007 under a
contract with METC.
Under an agreement with MTH, our transmission rates are fixed by contract at
current levels through December 31, 2005, and are subject to the FERC ratemaking
thereafter. However, we are subject to certain additional MISO surcharges,
which we estimate to be $15 million in 2004.
CONSUMERS' ELECTRIC UTILITY RATE MATTERS
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. They relate to restoration after an
outage, safety, and customer relations. During 2002 and 2003, we monitored and
reported to the MPSC our performance relative to the performance standards.
Year-end results for both 2002 and 2003 resulted in compliance with the
acceptable level of performance as established by the approved standards.
Financial incentives and penalties are contained within the performance
standards. An incentive is possible if all of the established performance
standards have been exceeded for a calendar year. However, the performance
standards do not contain an approved incentive mechanism; therefore, the value
of such incentive cannot be determined at this point. Financial penalties in the
form of customer credits are also possible. These customer credits are based on
duration and repetition of outages. We are a member of an industry coalition
that has appealed the customer credit portion of the performance standards to
the Michigan Court of Appeals. We cannot predict the likely effects of the
financial incentive or penalties, if any, on us, nor can we predict the outcome
of the appeal.
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POWER SUPPLY COSTS: We were required to provide backup service to ROA customers
on a best efforts basis. In October 2003, we provided notice to the MPSC that we
would terminate the provision of backup service in accordance with the Customer
Choice Act, effective January 1, 2004.
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
call options and capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. As of March 31, 2004, we purchased capacity and energy contracts
partially covering the estimated reserve margin requirements for 2004 through
2007. As a result, we have recognized an asset of $19 million for unexpired
capacity and energy contracts. On March 31, 2004, we filed a summer assessment
for meeting 2004 peak load demand as required by the MPSC, stating that our
summer 2004 reserve margin target is 11 percent or supply resources equal to 111
percent of projected summer peak load. Presently, we have a reserve margin of 12
percent, or supply resources equal to 112 percent of projected summer peak load
for summer 2004. Of the 112 percent, approximately 103 percent is from owned
electric generating plants and long-term contracts, and approximately 9 percent
is from short-term contracts. This reserve margin met our summer 2004 reserve
margin target. The total premium costs of electricity call options and capacity
and energy contracts for 2004 is expected to be approximately $9 million, as of
April 30, 2004.
As a result of meeting the transmission capability expansion requirements and
the market power test, as discussed in this Note, we have met the requirements
under the Customer Choice Act to return to the PSCR process. The PSCR process
provides for the reconciliation of actual power supply costs with power supply
revenues. This process assures recovery of all reasonable and prudent power
supply costs actually incurred by us. In September 2003, we submitted a PSCR
filing to the MPSC that reinstates the PSCR process for customers whose rates
are no longer frozen or capped as of January 1, 2004. The proposed PSCR charge
allows us to recover a portion of our increased power supply costs from large
commercial and industrial customers, and subject to the overall rate caps, from
other customers. We estimate the recovery of increased power supply costs from
large commercial and industrial customers to be approximately $30 million in
2004. As allowed under current regulation, we self-implemented the proposed PSCR
charge on January 1, 2004. The revenues received from the PSCR charge are also
subject to subsequent reconciliation at the end of the year after actual costs
have been reviewed for reasonableness and prudence. We cannot predict the
outcome of this filing.
OTHER CONSUMERS' ELECTRIC UTILITY UNCERTAINTIES
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 and to supply electricity and steam to Dow. We hold,
through two wholly owned subsidiaries, the following assets related to the MCV
Partnership and the MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and
- CMS Holdings holds, through the FMLP, a 35 percent lessor interest
in the MCV Facility.
Our consolidated retained earnings include undistributed earnings from the MCV
Partnership, which at March 31, 2004 are $248 million and at March 31, 2003 are
$233 million.
The MCV Partnership and the FMLP are variable interest entities and Consumers
was determined to be the primary beneficiary. Therefore, we have consolidated
the MCV Partnership and the FMLP into our consolidated financial statements for
the first time as of and for the quarter ended March 31, 2004. For additional
details, see Note 11, Implementation of New Accounting Standards.
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Power Supply Purchases from the MCV Partnership: Our annual obligation to
purchase capacity from the MCV Partnership is 1,240 MW through the term of the
PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's
availability, a levelized average capacity charge of 3.77 cents per kWh and a
fixed energy charge. We also pay a variable energy charge based on our average
cost of coal consumed for all kWh delivered. Effective January 1999, we reached
a settlement agreement with the MCV Partnership that capped payments made on the
basis of availability that may be billed by the MCV Partnership at a maximum
98.5 percent availability level.
Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.
In 1992, we recognized a loss and established a liability for the present value
of the estimated future underrecoveries of power supply costs under the PPA
based on the MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $19 million at March 31, 2004 and $47 million at March 31,
2003. We expect the PPA liability to be depleted in late 2004.
We estimate that 51 percent of the actual cash underrecoveries for 2004 will be
charged to the PPA liability, with the remaining portion charged to operating
expense as a result of our 49 percent ownership in the MCV Partnership. We will
expense all cash underrecoveries directly to income once the PPA liability is
depleted. If the MCV Facility's generating availability remains at the maximum
98.5 percent level, our cash underrecoveries associated with the PPA could be as
follows:
In Millions
- -----------------------------------------------------------------------------------
2004 2005 2006 2007
- -----------------------------------------------------------------------------------
Estimated cash underrecoveries at 98.5% $56 $56 $55 $39
Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
===================================================================================
Beginning January 1, 2004, the rate freeze for large industrial customers was no
longer in effect and we returned to the PSCR process. Under the PSCR process, we
will recover from our customers the approved capacity and fixed energy charges
based on availability, up to an availability cap of 88.7 percent as established
in previous MPSC orders.
Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility:
As a result of returning to the PSCR process, we returned to dispatching the MCV
Facility on a fixed load basis, as permitted by the MPSC, in order to maximize
recovery of our capacity and fixed energy payments. This fixed load dispatch
increases the MCV Facility's output and electricity production costs, such as
natural gas. As the spread between the MCV Facility's variable electricity
production costs and its energy payment revenue widens, the MCV's Partnership's
financial performance and investment in the MCV Partnership is and will be
harmed.
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Under the 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. Because natural gas prices have increased
substantially in recent years, while the price the MCV Partnership can charge us
for energy has not, the MCV Partnership's financial performance has been
impacted negatively.
Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges based on the MCV Facility's actual
availability up to the 98.5 percent cap. After September 2007, we expect to
claim relief under the regulatory out provision in the PPA, limiting our
capacity and fixed energy payments to the MCV Partnership to the amount
collected from our customers. The MPSC's future actions on the capacity and
fixed energy payments recoverable from customers subsequent to September 2007
may affect negatively the earnings of the MCV Partnership and the value of our
investment in the MCV Partnership.
In February 2004, we filed a resource conservation plan with the MPSC that is
intended to help conserve natural gas and thereby improve our investment in the
MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility based on natural gas market prices without
increased costs to electric customers,
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The resource conservation plan will reduce the MCV Facility's annual natural gas
consumption by an estimated 30 to 40 billion cubic feet. This decrease in the
quantity of high-priced natural gas consumed by the MCV Facility will benefit
Consumers' ownership interest in the MCV Partnership. The amount of PPA capacity
and fixed energy payments recovered from retail electric customers would remain
capped at 88.7 percent. Therefore, customers will not be charged for any
increased power supply costs, if they occur. Consumers and the MCV Partnership
have reached an agreement that the MCV Partnership will reimburse Consumers for
any incremental power costs incurred to replace the reduction in power
dispatched from the MCV Facility. In April 2004, the presiding ALJ at the MPSC
held a pre-hearing conference regarding the resource conservation plan. The ALJ
denied our request to establish a schedule that would have allowed consideration
of the plan on an interim basis and established a review schedule that calls for
a Proposal for Decision in September 2004 after which point the MPSC would
consider the plan. We cannot predict if or when the MPSC will approve our
resource conservation plan.
The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
22 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Natural gas prices have been volatile
historically. Presently, there is no consensus in the marketplace on the price
or range of prices of natural gas in the short term or beyond the next five
years. Even with an approved resource conservation plan, if gas prices continue
at present levels or increase, the economics of operating the MCV Facility may
be adverse enough to require us to recognize an impairment of our investment in
the MCV Partnership. We presently cannot predict the impact of these issues on
our future earnings, cash flows, or on the value of our investment in the MCV
Partnership.
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 MCV Partnership estimates that the
decision will result in a refund of approximately $35 million in taxes plus $9
million of interest. The Michigan Tax Tribunal decision has been appealed to the
Michigan
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Court of Appeals by the City of Midland and the MCV Partnership has file 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 2003 and
expects to file an appeal contesting property taxes for 2004. The MCV
Partnership cannot predict the outcome of these proceedings; therefore, the
above refund has not been recognized in first quarter 2004 earnings.
NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates
for Big Rock and Palisades assume that each plant site will eventually be
restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
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 each plant 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 being decommissioned,
the estimated cost includes historical expenditures in nominal dollars and
future costs in 2003 dollars, with all Palisades costs given in 2003 dollars.
In 1999,the MPSC orders for Big Rock and Palisades provided for fully funding
the decommissioning trust funds for both sites. In December 2000, funding of the
Big Rock trust fund stopped because the MPSC-authorized decommissioning
surcharge collection period expired. The MPSC order set the annual
decommissioning surcharge for Palisades at $6 million through 2007. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
However, based on current projections, the current levels of funds provided by
the trusts are not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation, as discussed
in "Nuclear Matters" within this section. We will also seek additional relief
from the MPSC.
In the case of Big Rock, excluding the additional nuclear fuel storage costs due
to the DOE's failure to accept this spent fuel on schedule, we are currently
projecting that the level of funds provided by the trust will fall short of the
amount needed to complete the decommissioning by approximately $25 million. At
this point in time, we plan to provide the additional amounts needed from our
corporate funds and, subsequent to the completion of radiological
decommissioning work, seek recovery of such expenditures at the MPSC. We cannot
predict how the MPSC will rule on our request.
In the case of Palisades, again excluding additional nuclear fuel storage costs
due to the DOE's failure to accept this spent fuel on schedule, we have
concluded that the existing surcharge need to be increased to approximately $25
million annually, beginning January 1, 2006, and continue through 2011, our
current license expiration date. We plan to file an application with the MPSC
seeking approval to increase the surcharge for recovery of decommissioning costs
related to Palisades, beginning in 2006. We cannot predict how the MPSC will
rule on our request.
NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor
vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. 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 in mid-2006. An additional 30 acres, the area where seven transportable dry
casks loaded with spent nuclear fuel and an eighth cask loaded with high-level
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radioactive waste material are stored, will be returned to a natural state by
the end of 2012 if the DOE begins removing the spent nuclear fuel by 2010.
The NRC and the Michigan Department of Environmental Quality continue to find
all decommissioning activities at Big Rock are being performed in accordance
with applicable regulations including license requirements.
Palisades: In March 2004, the NRC completed its end-of-cycle plant performance
assessment of Palisades. The assessment for Palisades covered the period from
January 1, 2003 through December 31, 2003. The NRC determined that Palisades was
operated in a manner that preserved public health and safety and fully met all
cornerstone objectives. As of March 2004, all inspection findings were
classified as having very low safety significance and all performance indicators
indicated performance at a level requiring no additional oversight. Based on the
plant's performance, only regularly scheduled inspections are planned through
September 2005.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage
pool capacity. We are using dry casks for temporary onsite storage. As of March
31, 2004, we have loaded 18 dry casks with spent nuclear fuel and are scheduled
to load additional dry casks this summer in order to continue operation.
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. A number of utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. If our litigation against the DOE is successful, we anticipate
future recoveries from the DOE. The recoveries will be used 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. The next step
will be for the DOE to submit an application to the NRC for a license to begin
construction of the repository. The application and review process is estimated
to take several years.
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.
We are unable to predict the outcome of this matter.
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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 $27 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 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 where 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 $10
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.
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.
COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
purchase obligations that represent normal business operating contracts. These
contracts are used to assure an adequate supply of goods and services necessary
for the operation of our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.
Coal Supply and Transportation: We have entered into coal supply contracts with
various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements, we are
obligated to take physical delivery of the coal and make payment based upon the
contract terms. Our coal supply contracts expire through 2005, and total an
estimated $182 million. Our coal transportation contracts expire through 2007,
and total an estimated $132 million. Long-term coal supply contracts have
accounted for approximately 60 to 90 percent of our annual coal requirements
over the last 10 years. Although future contract coverage is unknown at this
time, we believe that it will be within the historic 60 to 90 percent range.
Power Supply, Capacity, and Transmission: As of March 31, 2004, we had future
unrecognized commitments to purchase power transmission services under fixed
price forward contracts for 2004 and 2005 totaling $7 million. We also had
commitments to purchase capacity and energy under long-term power purchase
agreements with various generating plants. These contracts require monthly
capacity payments based on the plants' availability or deliverability. These
payments for 2004 through 2030 total an estimated $3.064 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant was not available to deliver electricity to us, then we would not be
obligated to make the capacity payment until the plant could deliver.
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CONSUMERS' GAS UTILITY CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to have investigation and remedial 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. We have completed initial
investigations at the 23 sites. We will continue to implement remediation plans
for sites where we have received MDEQ remediation plan approval. We will also
work toward resolving environmental issues at sites as studies are completed.
We have estimated our costs for investigation and remedial action at all 23
sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost
Model. We expect our remaining costs to be between $37 million and $90 million.
The range reflects multiple alternatives with various assumptions for resolving
the environmental issues at each site. The estimates are based on discounted
2003 costs using a discount rate of three percent. The discount rate represents
a ten-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 through the MPSC approved rates charged to our customers. As of
March 31, 2004, we have recorded a liability of $42 million, net of $39 million
of expenditures incurred to date, and a regulatory asset of $67 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.
In its November 2002 gas distribution rate order, the MPSC authorized us to
continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.
CONSUMERS' GAS UTILITY RATE MATTERS
GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our gas costs; however, the MPSC reviews these costs
for prudency in an annual reconciliation proceeding. In June 2003, we filed a
reconciliation of GCR costs and revenues for the 12 months ended March 2003. We
proposed to recover from our customers approximately $6 million of
under-recovered gas costs using a roll-in methodology. The roll-in methodology
incorporates the GCR under-recovery in the next GCR plan year. The approach was
approved by the MPSC in a November 2002 order.
In January 2004, intervenors filed their positions in our 2003 GCR case. Their
positions were that not all of our gas purchasing decisions were prudent during
April 2002 through March 2003 and they proposed disallowances. In 2003, we
reserved $11 million for a settlement agreement associated with the 2002-2003
GCR disallowance. Interest on the disallowed amount from April 1, 2003 through
February 2004, at Consumers' authorized rate of return, increased the cost of
the settlement by $1 million. The interest was recorded as an expense in 2003.
In February 2004, the parties in the case reached a settlement agreement that
resulted in a GCR disallowance of $11 million for the GCR period. The settlement
agreement was approved by the MPSC in March 2004. We plan to file a 2003-2004
GCR reconciliation in June 2004.
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In March 2004, the MPSC approved a temporary settlement authorizing us to bill a
maximum allowable GCR factor with two quarterly adjustments. The current GCR
ceiling factor is $5.94 per mcf, and this is the amount included for May 2004
bills. We are continuing to work with the parties in the case to obtain a final
settlement in the 2004-2005 GCR plan case.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period that we receive the interim relief. The MPSC
order allowed us to increase our rates beginning December 19, 2003. As part of
the interim order, Consumers agreed to restrict dividend payments to its parent
company, CMS Energy, to a maximum of $190 million annually during the period of
the interim relief. On March 5, 2004, the ALJ issued a Proposal for Decision
recommending that the MPSC not rely upon the projected test year data included
in our filing and supported by the MPSC Staff and further recommended that the
application be dismissed. In response to the Proposal for Decision the parties
have filed exceptions and replies to exceptions. The MPSC is not bound by the
ALJ's recommendation and will review the exceptions and replies to exceptions
prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order, which reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief. The original filing was based on December 2000 plant
balances and historical data. The December 2003 filing updates the gas
depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, will result in an annual increase of $12
million in depreciation expense based on December 2002 plant balances. The ALJ's
Proposal for Decision is expected in May 2004.
OTHER UNCERTAINTIES
INTEGRUM LAWSUIT: Integrum filed a complaint in Wayne County, Michigan Circuit
Court in July 2003 against CMS Energy, Enterprises and APT. Integrum alleges
several causes of action against APT, CMS Energy, and Enterprises in connection
with an offer by Integrum to purchase the CMS Pipeline Assets. In addition to
seeking unspecified money damages, Integrum is seeking an order enjoining CMS
Energy and Enterprises from selling, and APT from purchasing, the CMS Pipeline
Assets and an order of specific performance mandating that CMS Energy,
Enterprises, and APT complete the sale of the CMS Pipeline Assets to APT and
Integrum. A certain officer and director of Integrum is a former officer and
director of CMS Energy, Consumers, and their subsidiaries. The individual was
not employed by CMS Energy, Consumers or their subsidiaries when Integrum made
the offer to purchase the CMS Pipeline Assets. CMS Energy and Enterprises filed
a motion to change venue from Wayne County to Jackson County, which was granted.
The parties are now awaiting transfer of the file from Wayne County to
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Jackson County. CMS Energy and Enterprises believe that Integrum's claims are
without merit. CMS Energy and Enterprises intend to defend vigorously against
this action but they cannot predict the outcome of this litigation.
CMS GENERATION-OXFORD TIRE RECYCLING: In an administrative order, the California
Regional Water Control Board of the state of California named CMS Generation as
a potentially responsible party for the clean up of the waste from the fire that
occurred in September 1999 at the Filbin Tire Pile, which the State claims was
owned by Oxford Tire Recycling of North Carolina, Inc. CMS Generation reached a
settlement with the state, which the court approved, pursuant to which CMS
Generation paid the state $5.5 million, $1.6 million of which it had paid the
state prior to the settlement. CMS Generation continues to negotiate to have the
insurance company pay a portion of the settlement amount, as well as a portion
of its attorney fees.
At the request of the DOJ in San Francisco, CMS Energy and other parties
contacted by the DOJ in San Francisco entered into separate Tolling Agreements
with the DOJ in San Francisco in September 2002. The Tolling Agreement stops the
running of any statute of limitations during the ninety-day period between
September 13, 2002 and (through several extensions of the tolling period) March
30, 2004, to facilitate settlement discussions between all the parties in
connection with federal claims arising from the fire at the Filbin Tire Pile. On
September 23, 2002, CMS Energy received a written demand from the U.S. Coast
Guard for reimbursement of approximately $3.5 million in costs incurred by the
U.S. Coast Guard in fighting the fire. It is CMS Energy's understanding that
these costs, together with any accrued interest, are the sole basis of any
federal claims. CMS Energy has entered into a consent judgment with the U.S.
Coast Guard to settle this matter for $475,000 that is awaiting final DOJ and
court approval.
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 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, has 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. DFD has
appealed the decision by the judge in the Michigan state court case to stay the
litigation. DIG will continue to defend itself vigorously and pursue its claims.
DIG cannot predict the outcome of this matter.
DIG NOISE ABATEMENT LAWSUIT: In February 2003, DIG was served with a three-count
first amended complaint filed in Wayne County Circuit Court in the matter of
Ahmed, et al v. Dearborn Industrial Generation, LLC. The complaint seeks damages
"in excess of $25,000" and injunctive relief based upon allegations of excessive
noise and vibration created by operation of the power plant. The first amended
complaint was filed on behalf of six named plaintiffs, all alleged to be
adjacent or nearby residents or property owners. The damages alleged are injury
to persons and property of the landowners. Certification of a class of
"potentially thousands" who have been similarly affected is requested. DIG
intends to defend this action aggressively but cannot predict the outcome of
this matter.
MCV EXPANSION, LLC: Under an agreement entered into with General Electric
Company ("GE") in October 2002, MCV Expansion, LLC has a remaining contingent
obligation to GE in the amount of $2.2 million that may become payable in the
fourth quarter of 2004. The agreement provides that this contingent obligation
is subject to a pro rata reduction under a formula based upon certain purchase
orders being entered into with GE by June 30, 2003. MCV Expansion, LLC
anticipates but cannot assure that purchase orders will be executed with GE
sufficient to eliminate contingent obligations of $2.2
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million.
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. CMS Energy has appealed this judgment.
GASATACAMA: On March 24, 2004, the Argentine Government authorized the
restriction of exports of natural gas to Chile giving priority to domestic
demand in Argentina. This restriction could have a detrimental effect on
GasAtacama's earnings since GasAtacama's gas-fired power plant is located in
Chile and uses Argentine gas for fuel. On April 21, 2004, Argentina and Bolivia
signed an agreement in which Bolivian gas producers agreed to supply natural gas
to Argentina for six months. This Agreement should eliminate or greatly reduce
the current domestic gas supply shortage in Argentina. Bolivia has voiced its
opposition to any of its gas supply being exported to Chile. However, the
government of Argentina has announced a settlement with Argentine producers that
should help solve Argentina's long-term gas shortage problems. Currently,
management of GasAtacama is working with government officials of both Chile and
Argentina, as well as meeting with its electricity customers and gas producers,
to attempt to mitigate the impact of this situation. At this point, it is not
possible to predict the outcome of these events and their effect on the earnings
of GasAtacama.
ARGENTINA ECONOMIC SITUATION: 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 President of Argentina to
renegotiate such tariffs.
Effective April 30, 2002, we adopted the Argentine peso as the functional
currency for our Argentine investments. We had previously used the U.S. dollar
as the functional currency for these investments. As a result, on April 30,
2002, we translated the assets and liabilities of our Argentine entities into
U.S. dollars, in accordance with SFAS No. 52, using an exchange rate of 3.45
pesos per U.S. dollar, and recorded an initial charge to the Foreign Currency
Translation component of Common Stockholders' Equity of approximately $400
million.
While we cannot predict future peso-to-U.S. dollar exchange rates, we do expect
that these non-cash charges reduce substantially the risk of further material
balance sheet impacts when combined with anticipated proceeds from international
arbitration currently in progress, political risk insurance, and the eventual
sale of these assets. At March 31, 2004, the net foreign currency loss due to
the unfavorable exchange rate of the Argentine peso recorded in the Foreign
Currency Translation component of Common Stockholders' Equity using an exchange
rate of 2.86 pesos per U.S. dollar was $262 million. This amount also reflects
the effect of recording U.S. income taxes with respect to temporary differences
between the book and tax basis of foreign investments, including the foreign
currency translation associated with our Argentine investments, that were
determined to no longer be essentially permanent in duration.
LEONARD FIELD DISPUTE: Pursuant to a Consent Judgment entered in Oakland County,
Michigan Circuit Court in September 2001, CMS Gas Transmission had 18 months to
extract approximately one bcf of
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pipeline quality natural gas held in the Leonard Field in Addison Township. The
Consent Judgment provided for an extension of that period upon certain
circumstances. CMS Gas Transmission has complied with the requirements of the
Consent Judgment. Addison Township filed a lawsuit in Oakland County Circuit
Court against CMS Gas Transmission in February 2004 alleging the Leonard Field
was discharging odors in violation of the Consent Judgment. Pursuant to a
Stipulated Order entered April 1, 2004, CMS Gas Transmission agreed to certain
undertakings to address the odor complaints and further agreed to temporarily
cease operations at the Leonard Field during the month of April 2004, the last
month provided for in the Consent Judgment. Also, Addison Township was required
to grant CMS Gas Transmission an extension to withdraw its natural gas if
certain conditions were met. Addison Township denied CMS Gas Transmission's
request for an extension on April 5, 2004. CMS Gas Transmission is pursuing its
legal remedies. However, CMS Gas Transmission cannot predict the outcome of this
matter, and unless an extension is provided, it will be unable to extract
approximately 500,000 mcf of gas remaining in the Leonard Field.
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 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 estimated to be approximately $11 million at March 31, 2004.
Following a payment made to OPIC in April 2004, Enterprises now believes this
amount to be approximately $9 million.
An interim arrangement, which provided CMS Ensenada with payments under the PPA
that covered most, but not all, of CMS Ensenada's operating costs, was agreed to
with YPF Repsol in 2002 but expired on December 31, 2003. Efforts to negotiate a
new agreement with YPF Repsol have been unsuccessful.
As a result, CMS Ensenada initiated two legal actions: (1) an ex parte action in
the Argentine commercial courts, requesting injunctive relief in the form of a
temporary increase in the payments by YPF Repsol under the PPA that would allow
CMS Ensenada to continue to operate while seeking a final and permanent
resolution; and (2) an arbitration administered by the International Chamber of
Commerce seeking a ruling that the application of the Emergency Laws to the PPA
is unconstitutional, or, alternatively, that the arbitral panel reestablish the
economic equilibrium of the PPA, as required by the Emergency Laws taking into
account that a significant portion of CMS Ensenada's operating costs are payable
in U.S. dollars. In April 2004, the injunctive relief was granted on appeal, but
in an amount lower than requested by CMS Ensenada.
OTHER: Certain CMS Gas Transmission and CMS Generation affiliates in Argentina
received notice from various Argentine provinces claiming stamp taxes and
associated penalties and interest arising from various gas transportation
transactions. Although these claims total approximately $24 million, we believe
the claims are without merit and will continue to contest them vigorously.
CMS Generation does not currently expect to incur significant capital costs at
its power facilities for compliance with current U.S. environmental regulatory
standards.
In addition to the matters disclosed in this Note, Consumers and certain other
subsidiaries of CMS Energy are parties to certain lawsuits and administrative
proceedings before various courts and
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governmental agencies arising from the ordinary course of business. These
lawsuits and proceedings may involve personal injury, property damage,
contractual matters, environmental issues, federal and state taxes, rates,
licensing, and other matters.
We have accrued estimated losses for certain contingencies discussed in 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
- -------------------------------------------------------------------------------
March 31 December 31
2004 2003
- -------------------------------------------------------------------------------
CMS ENERGY CORPORATION
Senior notes $ 2,063 $ 2,063
General term notes 246 496
Extendible tenor rate adjusted securities
and other 187 187
------- -------
Total - CMS Energy Corporation 2,496 2,746
------- -------
CONSUMERS ENERGY COMPANY
First mortgage bonds 1,483 1,483
Senior notes 1,254 1,254
Bank debt and other 469 469
Securitization bonds 419 426
FMLP debt 411 -
------- -------
Total - Consumers Energy Company 4,036 3,632
------- -------
OTHER SUBSIDIARIES 184 191
------- -------
Total principal amount outstanding 6,716 6,569
Current amounts (849) (509)
Net unamortized discount (38) (40)
- -------------------------------------------------------------------------------
Total consolidated long-term debt $ 5,829 $ 6,020
===============================================================================
FMLP DEBT: We consolidated the FMLP due to the adoption of Revised FASB
Interpretation No. 46. At March 31, 2004, long-term debt of the FMLP, which is
consolidated into our financial statements for the first time, consists of:
In Millions
- ------------------------------------------------------------------------------
Maturity 2004
- ------------------------------------------------------------------------------
11.75% subordinated secured notes 2005 $185
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
- ------------------------------------------------------------------------------
Total amount outstanding $411
==============================================================================
The FMLP debt is essentially project debt secured by certain assets of the MCV
Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy
and Consumers.
DEBT MATURITIES: At March 31, 2004, the aggregate annual maturities for
long-term debt for the nine months ending December 31, 2004 and the next four
years are:
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In Millions
- --------------------------------------------------------------------------------
Payments Due
- --------------------------------------------------------------------------------
2004 2005 2006 2007 2008
- --------------------------------------------------------------------------------
Long-term debt $ 362 $ 785 $ 546 $ 545 $ 1,050
================================================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: At March 31, 2004, Consumers had
remaining FERC authorization to issue or guarantee up to $500 million of
short-term securities and up to $700 million of short-term first mortgage bonds
as collateral for such short-term securities.
At March 31, 2004, Consumers had remaining FERC authorization to issue up to
$740 million of long-term securities for refinancing or refunding purposes, $560
million of long-term securities for general corporate purposes, and $2 billion
of long-term first mortgage bonds to be issued solely as collateral for other
long-term securities. The authorizations expire on June 30, 2004 and Consumers
plans to file a renewal application in early May 2004.
SHORT-TERM FINANCINGS: At March 31, 2004, CMS Energy has a $190 million
revolving credit facility with banks. All of the $190 million is available for
general corporate purposes. Consumers has a $400 million revolving credit
facility with banks of which $376 million is available for general corporate
purposes, working capital, and letters of credit. The MCV Partnership has a $50
million working capital facility available.
FIRST MORTGAGE BONDS: Consumers secures its first mortgage bonds by a mortgage
and lien on substantially all of its property. Its ability to issue and sell
securities is restricted by certain provisions in the first mortgage bond
indenture, its articles of incorporation, and the need for regulatory approvals
under federal law.
CAPITAL LEASE OBLIGATIONS: 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. The MCV Partnership classifies this transaction as a
capital lease. As of March 31, 2004, capital lease obligations total $ 372
million, of which $307 million represents the third-party portion of the MCV
Facility capital lease.
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. We sold no receivables at March 31, 2004 and we sold $325 million
at March 31, 2003. The Consolidated Balance Sheets exclude these amounts from
accounts receivable. We continue to service the receivables sold. The purchaser
of the receivables has no recourse against our other assets for failure of a
debtor to pay when due and the purchaser has no right to any receivables not
sold. No gain or loss has been recorded on the receivables sold and we retain no
interest in the receivables sold.
Certain cash flows received from and paid to us under our accounts receivable
sales program are shown below:
In Millions
- --------------------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- --------------------------------------------------------------------------------
Proceeds from sales (remittance of collections)
under the program $ (297) $ -
Collections reinvested under the program $ 1,549 $1,375
================================================================================
DIVIDEND RESTRICTIONS: Under the provisions of its articles of incorporation, at
March 31, 2004, Consumers had $397 million of unrestricted retained earnings
available to pay common dividends.
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However, covenants in Consumers' debt facilities cap common stock dividend
payments at $300 million in a calendar year. Consumers is also under an annual
dividend cap of $190 million imposed by the MPSC during the current interim gas
rate relief period. As of March 31, 2004, CMS Energy has received $78 million of
common stock dividends from Consumers.
Our $190 million revolving credit facility with banks, which expires in November
2004, contains provisions that prohibit us from paying dividends on our common
stock. For additional details on the cap on common dividends payable during the
current interim gas rate relief period, see Note 3, Uncertainties, "Consumers'
Gas Utility Rate Matters - 2003 Gas Rate Case."
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENTS
FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: This
Interpretation became effective January 2003. It describes the disclosure to be
made by a guarantor about its obligations under certain guarantees that it has
issued. At the beginning of a guarantee, it requires a guarantor to recognize a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and measurement provision of this
Interpretation does not apply to some guarantee contracts, such as warranties,
derivatives, or guarantees between either parent and subsidiaries or
corporations under common control, although disclosure of these guarantees is
required. For contracts that are within the recognition and measurement
provision of this Interpretation, the provisions were to be applied to
Guarantees issued or modified after December 31, 2002.
The following table describes our guarantees at March 31, 2004:
In Millions
- --------------------------------------------------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount(b) Provision(c)
- --------------------------------------------------------------------------------------------------------
Indemnifications from asset sales and
other agreements(a) Various Various $ 1,156 $ 4 $ -
Letters of credit Various Various 248 - -
Surety bonds and other indemnifications Various Various 27 - -
Other guarantees Various Various 212 - -
Nuclear insurance retrospective premiums Various Various 134 - -
=======================================================================================================
(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.
(b) The carrying amount represents the fair market value of guarantees and
indemnities on our balance sheet that are entered into subsequent to January 1,
2003.
(c) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
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The following table provides additional information regarding our guarantees:
Guarantee Description How Guarantee Arose Events That Would Require Performance
- ------------------------------------------------------------------------------------------------------------------------
Indemnifications from asset sales and Stock and asset sales agreements Findings of misrepresentation,
other agreements breach of warranties, and other
specific events or circumstances
Standby letters of credit Normal operations of coal power Noncompliance with environmental
plants regulations
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, permits Nonperformance
and license
Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price Anderson
Act for nuclear incident
We have entered into typical tax indemnity agreements in connection with a
variety of transactions including transactions for the sale of subsidiaries and
assets, equipment leasing, and financing agreements. These indemnity agreements
generally are not limited in amount and, while a maximum amount of exposure
cannot be identified, the amount and probability of liability is considered
remote.
We have guaranteed payment of obligations through letters of credit,
indemnities, surety bonds, and other guarantees of unconsolidated affiliates and
related parties of $487 million as of March 31, 2004. We monitor and approve
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. The off-balance sheet commitments expire as follows:
Commercial Commitments In Millions
- -------------------------------------------------------------------------------
Commitment Expiration
- -------------------------------------------------------------------------------
Total 2004 2005 2006 2007 2008 Beyond
- -------------------------------------------------------------------------------
Off-balance sheet:
Guarantees $ 212 $ 6 $ 36 $ 4 $ - $- $ 166
Indemnities 27 8 - - - - 19
Letters of Credit (a) 248 112 108 5 5 5 13
- -------------------------------------------------------------------------------
Total $ 487 $ 126 $ 144 $ 9 $ 5 $5 $ 198
===============================================================================
(a) At March 31, 2004, we had $173 million of cash collateralized letters of
credit. The cash that collateralizes the letters of credit is included in
Restricted cash on the Consolidated Balance Sheets.
CONTINGENTLY CONVERTIBLE SECURITIES: At March 31, 2004, we have contingently
convertible debt and equity securities outstanding. The significant terms of
these securities are as follows:
Convertible Senior Notes: Our $150 million 3.375 percent convertible senior
notes are putable to CMS Energy by the note holders at par on July 15, 2008,
July 15, 2013 and July 15, 2018. The notes are convertible to Common Stock at
the option of the holder if the price of our Common Stock remains at or above
$12.81 per share for 20 of 30 consecutive trading days ending on the last
trading day of a quarter. The $12.81 price per share may be adjusted if there is
a payment or distribution to our Common Stockholders. If conversion were to
occur, the notes would be converted into 14.1 million shares of Common Stock
based on the initial conversion rate.
Convertible Preferred Stock: Our $250 million 4.50 percent cumulative
convertible perpetual preferred stock has a liquidation value of $50.00 per
share. The security is convertible to Common Stock at the option of the holder
if the price of our Common Stock remains at or above $11.87 per share for 20 of
30 consecutive trading days ending on the last trading day of a quarter. On or
after December 5, 2008, we may cause the Preferred Stock to convert into Common
Stock if the closing price of our Common Stock remains at or above $12.86 for 20
of any 30 consecutive trading days. The $11.87 and $12.86 prices per share may
be adjusted if there is a payment or distribution to our Common Stockholders. If
conversion were to occur, the securities would be converted into 25.3 million
shares of Common Stock based on the initial conversion rate.
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5: EARNINGS PER SHARE AND DIVIDENDS
The following table presents the basic and diluted earnings per share
computations.
Restated
- --------------------------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- --------------------------------------------------------------------------------------
NET INCOME ATTRIBUTABLE TO COMMON STOCK:
CMS Energy - Basic $ (11) $ 82
Add conversion of Trust Preferred
Securities (net of tax) - (a) 5
---------------------------
CMS Energy - Diluted $ (11) $ 87
===========================
AVERAGE COMMON SHARES OUTSTANDING
APPLICABLE TO BASIC AND DILUTED EPS
CMS Energy:
Average Shares - Basic 161.1 144.1
Add conversion of Trust Preferred Securities - (a) 20.9
Stock Options and Warrants - (b) -
---------------------------
Average Shares - Diluted 161.1 165.0
===========================
EARNINGS PER AVERAGE COMMON SHARE
Basic $ (0.07) $ 0.57
Diluted $ (0.07) $ 0.52
======================================================================================
(a) Due to antidilution, the computation of diluted earnings per share excluded
the conversion of our Trust Preferred Securities into 4.2 million shares of
Common Stock and a $2.2 million reduction of interest expense, net of tax,
for the three months ended March 31, 2004. Effective July 2001, we can
revoke the conversion rights if certain conditions are met.
(b) Due to antidilution, the computation of diluted earnings per share excluded
0.5 million shares for stock options and warrants for the three months
ended March 31, 2004.
Computation of diluted earnings per share for the three months ended March 31,
2004 excluded conversion of our $150 million 3.375 percent convertible senior
notes and our 5 million shares of 4.50 percent cumulative convertible preferred
stock since both are "contingently convertible" securities and, as of March 31,
2004, none of the stated contingencies have been met. For additional details,
see Note 4, Financings and Capitalization.
In January 2003, the Board of Directors suspended the payment of common stock
dividends.
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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 carrying
amount of all long-term financial instruments, except as shown below,
approximates fair value. Our held-to-maturity investments consist of debt
securities held by the MCV Partnership totaling $140 million as of March 31,
2004. These securities represent funds restricted primarily for future lease
payments and are classified as Other Assets on the consolidated balance sheets.
These investments have original maturity dates of approximately one year or
less, and because of their short maturities, their carrying amounts approximate
their fair values. For additional details, see Note 1, Corporate Structure and
Accounting Policies.
In Millions
- -------------------------------------------------------------------------------------------------------------
March 31 2004 2003
- -------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Cost Value Gain(Loss) Cost Value Gain
- -------------------------------------------------------------------------------------------------------------
Long-term debt (a) $6,678 $6,985 $(307) $6,134 $6,045 $ 89
Long-term debt - related parties (b) 684 657 27 - - -
Trust Preferred Securities (b) - - - 883 640 243
Available for sale securities:
Nuclear decommissioning (c) 433 566 133 458 529 71
SERP 54 66 12 55 56 1
============================================================================================================
(a) Includes a principal amount of $849 million at March 31, 2004 and $917
million at March 31, 2003 relating to current maturities. Settlement of
long-term debt is generally not expected until maturity.
(b) We determined that we are not the primary beneficiary of our trust preferred
security structures. Accordingly, those entities have been deconsolidated as of
December 31, 2003. Company obligated Trust Preferred Securities totaling $663
million that were previously included in mezzanine equity, have been eliminated
due to deconsolidation and are reflected in Long-term debt - related parties on
the Consolidated Balance Sheets. For additional details, see Note 11,
Implementation of New Accounting Standards. In addition, company obligated Trust
Preferred Securities totaling $220 million have been converted to Common Stock
as of August 2003.
(c) On January 1, 2003, we adopted SFAS No. 143 and began classifying our
unrealized gains and losses on nuclear decommissioning investments as regulatory
liabilities. We previously classified the unrealized gains and losses on these
investments in accumulated depreciation.
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 manage these risks using established
policies and procedures, under the direction of both an executive oversight
committee consisting of senior management representatives and a risk committee
consisting of business-unit managers. We may use various contracts to manage
these risks including swaps, options, and forward contracts.
We intend 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 risk
management 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 minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
Contracts used to manage interest rate, foreign currency, and commodity price
risk may be considered
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CMS Energy Corporation
derivative instruments that are subject to derivative and hedge accounting
pursuant to SFAS No. 133. If a contract is accounted for as a derivative
instrument, it is recorded in the financial statements as an asset or a
liability, at the fair value of the contract. The recorded fair value of the
contract is then adjusted quarterly to reflect any change in the market value of
the contract, a practice known as marking the contract to market. The accounting
for changes in the fair value of a derivative (that is, gains or losses) is
reported either in earnings or accumulated other comprehensive income depending
on whether the derivative qualifies for special hedge accounting treatment.
For derivative instruments to qualify for hedge accounting under SFAS No. 133,
the hedging relationship must be formally documented at inception and be highly
effective in achieving offsetting cash flows or offsetting changes in fair value
attributable to the risk being hedged. If hedging a forecasted transaction, the
forecasted transaction must be probable. If a derivative instrument, used as a
cash flow hedge, is terminated early because it is probable that a forecasted
transaction will not occur, any gain or loss as of such date is immediately
recognized in earnings. If a derivative instrument, used as 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. We use a combination of quoted market prices and mathematical
valuation models to determine fair value of those contracts requiring derivative
accounting. The ineffective portion, if any, of all hedges is recognized in
earnings.
The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives because there is not an active market for the commodity.
Certain of our electric capacity and energy contracts are not accounted for as
derivatives due to the lack of an active energy market in the state of Michigan
and the significant transportation costs that would be incurred to deliver the
power under the contracts to the closest active energy market at the Cinergy hub
in Ohio. If an active market develops in the future, we may be required to
account for these contracts as derivatives. The mark-to-market impact on
earnings related to these contracts could be material to the financial
statements.
Derivative accounting is required for certain contracts used to limit our
exposure to electricity and gas commodity price risk and interest rate risk. The
following table reflects the fair value of all contracts requiring derivative
accounting:
In Millions
- --------------------------------------------------------------------------------------------------------------------------
March 31 2004 2003
- --------------------------------------------------------------------------------------------------------------------------
Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- --------------------------------------------------------------------------------------------------------------------------
Other than trading
Electric - related contracts $ - $ - $ - $ 8 $ 1 $ (7)
Gas contracts 5 11 6 - - -
Interest rate risk contracts - (2) (2) - (27) (27)
Derivative contracts associated with
Consumers' investment in the MCV
Partnership:
Prior to consolidation - - - - 17 17
After consolidation:
Gas fuel contracts - 81 81 - - -
Gas fuel futures - 50 50 - - -
Derivative contracts associated with
equity investments in:
Shuweihat - (33) (33) - (32) (32)
Taweelah (35) (33) 2 - (30) (30)
Jorf Lasfar - (12) (12) - (11) (11)
Other - - - - (4) (4)
Trading
Electric / gas contracts (3) 15 18 - 7 7
=========================================================================================================================
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The fair value of other than trading derivative contracts is included in either
Derivative Instruments or Other Assets on the Consolidated Balance Sheets. The
fair value of trading derivative contracts is included in either Price Risk
Management Assets or Price Risk Management Liabilities on the Consolidated
Balance Sheets. The fair value of derivative contracts associated with our
equity investments is included in Enterprises Investments on the Consolidated
Balance Sheets. The fair value of derivative contracts associated with our
investment in the MCV Partnership for 2003 is included in Investments - Midland
Cogeneration Venture Limited Partnership on the Consolidated Balance Sheets.
Effective, January 1, 2003, EITF Issue No. 98-10 was rescinded by EITF Issue No.
02-03 and as a result, only energy contracts that meet the definition of a
derivative in SFAS No. 133 can be carried at fair value. The impact of this
change was recognized as a cumulative effect of a change in accounting principle
loss of $23 million, net of tax.
ELECTRIC CONTRACTS: Our electric utility business uses purchased electric call
option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods.
GAS CONTRACTS: Our gas utility business uses fixed price and indexed-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or liability
as part of the GCR process.
TRADING ACTIVITIES: CMS ERM accounts for power and gas trading contracts using
the criteria defined in SFAS No. 133. Energy trading contracts that meet the
definition of a derivative 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 in the
period in which the changes occur. Energy trading contracts that do not meet the
definition of a derivative are accounted for as executory contracts (i.e., on an
accrual basis).
The market prices we use to value our energy trading contracts reflect our
consideration of, among other things, closing exchange and over-the-counter
quotations. In certain contracts, long-term commitments may extend beyond the
period in which market quotations for such contracts are available. Mathematical
models are developed to determine various inputs into the fair value calculation
including price and other variables that may be required to calculate fair
value. Realized cash returns on these commitments may vary, either positively or
negatively, from the results estimated through application of the mathematical
model. We believe that our mathematical models use state-of-the-art technology,
pertinent industry data, and prudent discounting in order to forecast certain
elongated pricing curves. Market prices are adjusted to reflect the impact of
liquidating our position in an orderly manner over a reasonable period of time
under present market conditions.
In connection with the market valuation of our energy trading contracts, we
maintain reserves for credit
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risks based on the financial condition of counterparties. We also maintain
credit policies that management believes minimize overall credit risk with
regard to 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 employ standard agreements that allow for netting of positive and
negative exposures associated with a single counterparty. Based on these
policies, our current exposures, and our credit reserves, we do not anticipate a
material adverse effect on our financial position or results of operations as a
result of counterparty nonperformance.
INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk
associated with forecasted interest payments on variable-rate debt. Most of our
interest rate swaps are designated as cash flow hedges. As such, we record any
change in the fair value of these contracts in accumulated other comprehensive
income unless the swaps are sold. For interest rate swaps that did not qualify
for hedge accounting treatment, we record any change in the fair value of these
contracts in earnings.
We have entered into floating-to-fixed interest rate swap agreements to reduce
the impact of interest rate fluctuations. The difference between the amounts
paid and received under the swaps is accrued and recorded as an adjustment to
interest expense over the term of the agreement. We were able to apply the
shortcut method to all interest rate swaps that qualified for hedge accounting
treatment; therefore, there was no ineffectiveness associated with these hedges.
The following table reflects the outstanding floating-to-fixed interest rates
swaps:
In Millions
- -------------------------------------------------------------------------------
Floating to Fixed Notional Maturity Fair
Interest Rate Swaps Amount Date Value
- -------------------------------------------------------------------------------
March 31, 2004 $ 26 2005-2006 $ (2)
March 31, 2003 $ 462 2003-2007 $ (27)
==============================================================================
Notional amounts reflect the volume of transactions but do not represent the
amount exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not necessarily reflect our exposure to credit or market
risks. The weighted average interest rate associated with outstanding swaps was
approximately 7.3 percent at March 31, 2004 and 5.0 percent at March 31, 2003.
Certain equity method investees have issued interest rate swaps, as listed in
the table under "Derivative Instruments" within this Note. These instruments are
not included in this analysis, but can have an impact on financial results.
FOREIGN EXCHANGE DERIVATIVES: We may use forward exchange and option contracts
to hedge certain receivables, payables, long-term debt, and equity value
relating to foreign investments. The purpose of our foreign currency hedging
activities is to protect the company from the risk associated with adverse
changes in currency exchange rates that could affect cash flow materially. These
contracts would not subject us to risk from exchange rate movements because
gains and losses on such contracts offset losses and gains, respectively, on
assets and liabilities being hedged. At March 31, 2004 and March 31, 2003, we
had no outstanding foreign exchange contracts.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP: Natural Gas Fuel Contracts: The MCV Partnership uses natural gas
fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs.
The MCV Partnership believes that its long-term natural gas contracts, which do
not contain volume optionality, qualify under SFAS No. 133 for the normal
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purchases and normal sales exception. Therefore, these contracts are currently
not recognized at fair value on the balance sheet. Should significant changes in
the level of the MCV Facility operational dispatch or purchases of long-term gas
occur, the MCV Partnership would be required to re-evaluate its accounting
treatment for these long-term gas contracts. This re-evaluation may result in
recording mark-to-market activity on some contracts, which could add to earnings
volatility.
The FASB issued Derivatives Implementation Group Issue C-16, which became
effective April 1, 2002, regarding natural gas commodity contracts that combine
an option component and a forward component. This guidance requires either that
the entire contract be accounted for as a derivative or the components of the
contract be separated into two discrete contracts. Under the first alternative,
the entire contract considered together would not qualify for the normal
purchases and sales exception under the revised guidance. Under the second
alternative, the newly established forward contract could qualify for the normal
purchases and sales exception, while the option contract would be treated as a
derivative under SFAS No. 133 with changes in fair value recorded through
earnings.
At April 1, 2002, the MCV Partnership had nine long-term gas contracts that
contained both an option and forward component. As such, they were no longer
accounted for under the normal purchases and sales exception and the MCV
Partnership began mark-to-market accounting of these nine contracts through
earnings. Based on the natural gas prices, at the beginning of April 2002, the
MCV Partnership recorded a $58 million gain for the cumulative effect of this
accounting change. During the fourth quarter of 2002, the MCV Partnership
removed the option component from three of the nine long-term gas contracts,
which should reduce some of the earnings volatility. The MCV Partnership expects
future earnings volatility on the six remaining long-term gas contracts that
contain volume optionality, since changes to this mark-to-market gain will be
recorded on a quarterly basis during the remaining life of approximately four
years for these gas contracts. From April 2002 to March 2004, the MCV
Partnership recorded an additional net mark-to-market gain of $23 million for
these gas contracts for a cumulative mark-to-market gain through March 31, 2004
of $81 million, which will reverse over the remaining life of these gas
contracts, ranging from 2004 to 2007.
For the three months ended March 31, 2004, the MCV Partnership recorded in Fuel
for Electric Generation a $6 million net mark-to-market gain in earnings
associated with these contracts.
Natural Gas Fuel Futures and Options: To manage market risks associated with the
volatility of natural gas prices, the MCV Partnership maintains a gas hedging
program. The MCV Partnership enters into natural gas futures and option
contracts 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 being 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.
These financial instruments are derivatives under SFAS No. 133 and the contracts
that are used to secure the anticipated natural gas requirements necessary for
projected electric and steam sales qualify as cash flow hedges under SFAS No.
133, since they hedge the price risk associated with the cost of natural gas.
The MCV Partnership also engages in cost mitigation activities to offset the
fixed charges the MCV Partnership incurs in operating the MCV Facility. These
cost mitigation activities 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 cost mitigation activities are not considered a
normal course of business for the MCV Partnership and do not
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qualify as hedges under SFAS No. 133. Therefore, the resulting mark-to-market
gains and losses from cost mitigation activities are flowed through the MCV
Partnership's earnings.
Cash is deposited with the broker in a margin account at the time futures or
options contracts are initiated. The change in market value of these contracts
requires adjustment of the margin account balances. The margin account balance
as of March 31, 2004 was recorded as a current asset in Prepayments and Other
Assets, in the amount of $2 million.
For the three months ended March 31, 2004, the MCV Partnership has recognized in
other comprehensive income, an unrealized $20 million increase on the futures
contracts, which are hedges of forecasted purchases for plant use of market
priced gas. This resulted in a net $51 million gain in other comprehensive
income as of March 31, 2004. This balance represents natural gas futures with
maturities ranging from April 2004 to December 2007, of which $34 million of
this gain is expected to be reclassified into earnings within the next twelve
months. As of March 31, 2004, Consumers' pretax proportionate share of the MCV
Partnership's $51 million net gain recorded in other comprehensive income is $25
million. The MCV Partnership also has recorded, as of March 31, 2004, a $50
million current derivative asset, representing the mark-to-market gain on
natural gas futures for anticipated projected electric and steam sales accounted
for as hedges. In addition, for the three months ended March 31, 2004, the MCV
Partnership has recorded a net $5 million gain in earnings from hedging
activities related to natural gas requirements for the MCV Facility operations
and a net $1 million gain in earnings from cost mitigation activities.
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,
- benefits to certain management employees under SERP,
- health care and life insurance benefits under OPEB,
- benefits to a select group of management under EISP, and
- a defined contribution 401(k) plan.
Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.
OPEB: We adopted SFAS No. 106, effective as of the beginning of 1992. Consumers
recorded a liability of $466 million for the accumulated transition obligation
and a corresponding regulatory asset for anticipated recovery in utility rates.
For additional details, see Note 1, Corporate Structure and Accounting Policies,
"Utility Regulation." The MPSC authorized recovery of the electric utility
portion of these costs in 1994 over 18 years and the gas utility portion in 1996
over 16 years. We made a contribution of $18 million to our 401(h) and VEBA
trust funds in March 2004. We plan to make additional contributions of $54
million in 2004.
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Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
- -----------------------------------------------------------------------------
Pension OPEB
Three Months Ended March 31 2004 2003 2004 2003
- -----------------------------------------------------------------------------
Service cost $ 10 $ 10 $ 5 $ 5
Interest expense 18 20 17 17
Expected return on plan assets (27) (20) (12) (11)
Amortization of:
Net loss 1 2 6 5
Prior service cost 3 2 (2) (2)
-------------------------------
Net periodic pension and postretirement
$ 5 $ 14 $ 14 $ 14
=============================================================================
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that
was signed into law in December 2003 establishes a prescription drug benefit
under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree
health care benefit plans that provide a benefit that is actuarially equivalent
to Medicare Part D. Accounting guidance for the subsidy is not yet available,
therefore, we are continuing to defer recognizing the effects of the Act in our
2004 financial statements, as permitted by FASB Staff Position No. 106-b. When
accounting guidance is issued, our retiree health benefit obligation may be
adjusted. For additional details, see Note 11, Implementation of New Accounting
Standards.
As of March 31, 2004, we have recorded a prepaid pension asset of $403 million,
$20 million of which is in other current assets on our consolidated balance
sheets.
8: 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 $6 million for the
three months ended March 31, 2004 and $33 million for the three months ended
March 31, 2003. The most significant of these investments is our 50 percent
interest in Jorf Lasfar, our 45 percent interest in SCP, and our 40 percent
interest in Taweelah. Listed below is the summarized income statement
information for our most significant equity method investments.
Income Statement Data
In Millions
- ----------------------------------------------------------------------------------
Jorf
Three Months Ended March 31, 2004 Lasfar SCP Taweelah Total
- ----------------------------------------------------------------------------------
Operating revenue $ 110 $ 19 $ 22 $151
Operating expenses 65 5 10 80
------------------------------------------
Operating income 45 14 12 71
Other expense, net 15 7 25 47
------------------------------------------
Net income (loss) $ 30 $ 7 $(13) $ 24
=================================================================================
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In Millions
- ------------------------------------------------------------------------------
Jorf
Three Months Ended March 31, 2003 Lasfar SCP Taweelah Total
- -----------------------------------------------------------------------------
Operating revenue $ 90 $ 12 $ 23 $ 125
Operating expenses 43 4 9 56
----------------------------------------
Operating income 47 8 14 69
Other expense, net 19 4 2 25
----------------------------------------
Net income $ 28 $ 4 $ 12 $ 44
============================================================================
9: REPORTABLE SEGMENTS
Our reportable segments consist of business units organized and managed by their
products and services. We evaluate performance based upon the net income of each
segment. We operate principally in three reportable segments: electric utility,
gas utility, and enterprises.
The electric utility segment consists of the generation and distribution of
electricity in the state of Michigan through our subsidiary, Consumers. The gas
utility segment consists of regulated activities like transportation, storage,
and distribution of natural gas in the state of Michigan through our subsidiary,
Consumers. The enterprises segment consists of:
- investing in, acquiring, developing, constructing, managing, and
operating non-utility power generation plants and natural gas
facilities in the United States and abroad, and
- providing gas, oil, and electric marketing services to energy users.
The tables below show financial information by reportable segment. The "Other"
net income segment includes corporate interest and other, discontinued
operations, and the cumulative effect of accounting changes.
REVENUES In Millions
- ----------------------------------------------------------------------------------------
Restated
- ----------------------------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- ----------------------------------------------------------------------------------------
Electric utility $ 630 $ 650
Gas utility 905 789
Enterprises 219 529
-------------------
$ 1,754 $ 1,968
========================================================================================
NET INCOME (LOSS) In Millions
- ----------------------------------------------------------------------------------------
Restated
- ----------------------------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- ----------------------------------------------------------------------------------------
Electric utility $ 45 $ 51
Gas utility 55 54
Enterprises (61) 21
Other (50) (44)
------------------
$ (11) $ 82
========================================================================================
TOTAL ASSETS In Millions
- ----------------------------------------------------------------------------------------
Restated
- ----------------------------------------------------------------------------------------
March 31 2004 2003
- ----------------------------------------------------------------------------------------
Electric utility $ 6,891 $ 6,749
Gas utility 2,637 2,410
Enterprises 4,915 5,622
Other 674 420
--------------------
$ 15,117 $ 15,201
========================================================================================
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10: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard became
effective January 2003. It 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 do so. We have legal obligations to remove some of our assets,
including our nuclear plants, at the end of their useful lives.
Before adopting this standard, we classified the removal cost of assets included
in the scope of SFAS No. 143 as part of the reserve for accumulated
depreciation. For these assets, the removal cost of $448 million that was
classified as part of the reserve at December 31, 2002, was reclassified in
January 2003, in part, as:
- $364 million ARO liability,
- $134 million regulatory liability,
- $42 million regulatory asset, and
- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.
We are reflecting a regulatory asset and liability as required by SFAS No. 71
for regulated entities 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 the asset
retirement obligation is incurred, such as assets with indeterminate lives, the
liability is to be recognized when a reasonable estimate of fair value can be
made. Generally, transmission and distribution assets have indeterminate lives.
Retirement cash flows cannot be determined. There is a low probability of a
retirement date, so no liability has been recorded for these assets. 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
are based largely on third-party cost estimates.
In addition, in 2003, we recorded an ARO liability for certain pipelines and
non-utility generating plants and a $1 million, net of tax, cumulative effect of
change in accounting for accretion and depreciation expense for ARO liabilities
incurred prior to 2003.
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CMS Energy Corporation
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life.
March 31, 2004 In Millions
- --------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- --------------------------------------------------------------------------------------------------------
Palisades-decommission plant site 1972 Palisades nuclear plant $497
Big Rock-decommission plant site 1962 Big Rock nuclear plant 69
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 -
Closure of gas pipelines Various Gas transmission pipelines -
Dismantle natural gas-fired power plant 1997 Gas fueled power plant -
========================================================================================================
March 31, 2004 In Millions
- ----------------------------------------------------------------------------------------------------
ARO Liability ARO
---------------- Cash Flow Liability
ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 3/31/04
- ----------------------------------------------------------------------------------------------------
Palisades-decommission $249 $268 $ - $ - $ 5 $31 $304
Big Rock-decommission 61 35 - (21) 3 22 39
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - - 1 - 53
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
Closure of gas pipelines (a) 8 - - - - - -
Natural gas-fired power plant 1 1 - - 1 - 2
-----------------------------------------------------------------
Total $373 $359 $ - $ (21) $10 $53 $401
====================================================================================================
(a) ARO Liability was settled in 2003 as a result of the sales of Panhandle and
CMS Field Services.
The Palisades and Big Rock cash flow revisions resulted from new decommissioning
reports filed with the MPSC in March 2004. For additional details, see Note 3,
Uncertainties, "Other Consumers' Electric utility Uncertainties - Nuclear Plant
Decommissioning."
Reclassification of certain types of Cost of Removal: Beginning in December
2003, the SEC requires the quantification and reclassification of the estimated
cost of removal obligations arising from other than legal obligations. These
obligations have been accrued through depreciation charges. We estimate that we
had $1.005 billion at March 31, 2004 and $937 million at March 31, 2003 of
previously accrued asset removal costs related to our regulated operations, for
other than legal obligations. These obligations, which were previously
classified as a component of accumulated depreciation, are now classified as
regulatory liabilities in the accompanying consolidated balance sheets.
11: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.
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CMS Energy Corporation
We determined that 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. In addition, 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. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $718 million at March 31, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of $1.471 billion at
March 31, 2004. The creditors of these partnerships do not have recourse to the
general credit of CMS Energy.
At December 31, 2003, we determined that we are the primary beneficiary of three
other entities that are determined to be variable interest entities. We have 50
percent partnership interest in the T.E.S Filer City Station Limited
Partnership, the Grayling Generating Station Limited 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 the first time as of December 31, 2003. These partnerships have
third-party obligations totaling $120 million at March 31, 2004. Property,
plant, and equipment serving as collateral for these obligations have a carrying
value of $171 million. 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.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company obligated Trust Preferred
Securities totaling $663 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $684 million of long-term debt - related parties
and reflected an investment in related parties of $21 million.
We are not required to, and have not, restated prior periods for the impact of
this accounting change.
Additionally, we have variable interest entities in which we are not the primary
beneficiary. FASB Interpretation No. 46 requires us to disclose certain
information about these entities. The chart below details our involvement in
these entities at March 31, 2004:
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Name (Ownership Nature of the Involvement Investment Balance Operating Agreement Total Generating
Interest) Entity Country Date (In Millions) with CMS Energy Capacity
- -----------------------------------------------------------------------------------------------------------------------------------
Taweelah (40%) Power Generator United Arab 1999 $ 75 Yes 777 MW
Emirates
Generator -
Under
Jubail (25%) Construction Saudi Arabia 2001 $ - Yes 250 MW
Generator -
Under United Arab
Shuweihat (20%) Construction Emirates 2001 $(30) (a) Yes 1,500 MW
- --------------------------------------------------------------------------------------------------------------------------------
Total $ 45 2,527 MW
================================================================================================================================
(a) At March 31, 2004, we carried a negative investment in Shuweihat. The
balance is comprised of our investment of $3 million reduced by our
proportionate share of the negative fair value of derivative instruments of $33
million. We are required to record the negative investment due to our future
commitment to make an equity investment in Shuweihat.
Our maximum exposure to loss through our interests in these variable interest
entities is limited to our investment balance of $45 million, and letters of
credit, guarantees, and indemnities relating to Taweelah and Shuweihat totaling
$129 million, including a letter of credit relating to our required initial
investment in Shuweihat of $70 million. We plan to contribute our initial
investment when the project becomes commercially operational in 2004.
In April 2004, we sold our investment in Loy Yang. In March 2004, we recorded an
$81 million after-tax impairment charge. For additional information regarding
the Loy Yang sale, see Note 2, Discontinued Operations, Other Asset Sales,
Impairments, and Restructuring.
EITF ISSUE NO. 02-03, RECOGNITION AND REPORTING OF GAINS AND LOSSES ON ENERGY
TRADING CONTRACTS UNDER EITF ISSUES NO. 98-10 AND 00-17: At its October 25, 2002
meeting, the EITF reached a consensus to rescind EITF Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. As a result, only energy contracts that meet the definition of a
derivative in SFAS No. 133 will be carried at fair value. Energy trading
contracts that do not meet the definition of a derivative must be accounted for
as executory contracts. We recognized a loss for the cumulative effect of change
in accounting principle of $23 million, net of tax, during the three-month
period ended March 31, 2003.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, ACCOUNTING AND DISCLOSURE
REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND
MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (Act), that was signed into law in December 2003,
establishes a prescription drug benefit under Medicare (Medicare Part D), and a
federal subsidy to sponsors of retiree health care benefit plans that provide a
benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003,
we elected a one-time deferral of the accounting for the Act,
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CMS Energy Corporation
as permitted by FASB Staff Position, No. SFAS 106-1.
Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No.
106-1 and provides further guidance for accounting for the Act. Proposed FASB
Staff Position, No. 106-b states that for plans that are actuarially equivalent
to Medicare Part D, employers' measures of accumulated postretirement benefit
obligations (APBO) and postretirement benefit costs should reflect the effects
of the Act.
As of March 31, 2004, we have not determined whether our postretirement benefit
plan is actuarially equivalent to Medicare Part D. Therefore, our measures of
APBO and net periodic postretirement benefit cost do not reflect any amount
associated with the Medicare Prescription Drug, Improvement, and Modernization
Act of 2003. If our prescription drug plan is determined to be actuarially
equivalent to Medicare Part D, we estimate a decrease in OPEB expense of
approximately $23 million for 2004 and a one-time reduction of our benefit
obligation of approximately $150 million, to be amortized over future periods.
This Proposed FASB Staff Position would be effective for the first interim or
annual period beginning after June 15, 2004.
CMS-89
CMS Energy Corporation
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CMS-90
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."
EXECUTIVE OVERVIEW
Consumers, a subsidiary of CMS Energy, a holding company, is a combination
electric and gas utility company that provides service to customers in
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 and services each provides and operate
principally in two business segments: electric utility and gas utility. Our
electric utility operations include the generation, purchase, distribution, and
sale of electricity. Our gas utility operations purchase, transport, store,
distribute, and sell natural gas.
We earn our revenue and generate cash from operations by providing electric and
natural gas services, electric power generation, gas transmission and storage,
and other energy related services. Our businesses are affected by weather,
especially during the traditional heating and cooling seasons, economic
conditions, regulation and regulatory issues, interest rates, our debt credit
rating, and energy commodity prices.
Our strategy involves rebuilding our balance sheet and refocusing on our core
strength: superior utility operation and service. Over the next few years, we
expect this strategy to improve our debt ratings, grow earnings at a mid-single
digit rate, and position the company to make new investments.
Despite strong financial and operational performance in 2003, we face important
challenges in the future. We continue to lose industrial and commercial
customers to other electric suppliers without receiving compensation for
stranded costs caused by the lost sales. As of April 2004, we lost 823 MW or 10
percent of our electric business to these alternative electric suppliers. We
expect the loss to grow to over 1,100 MW in 2004. Existing state legislation
encourages competition and provides for recovery of stranded costs, but the MPSC
has not yet authorized stranded cost recovery. We continue to work cooperatively
with the MPSC to resolve this issue.
Further, higher natural gas prices have harmed the economics of the MCV and we
are seeking approval from the MPSC to change the way in which the facility is
used. Our proposal would reduce gas consumption by an estimated 30 to 40 bcf per
year while improving the MCV's financial performance with no change to customer
rates. A portion of the benefits from the proposal will support additional
renewable resource development in Michigan. Resolving the issue is critical for
our shareowners and customers.
We also are focused on further reducing our business, financial, and regulatory
risks, while growing the equity base of our company. Finally, we are planning to
devote more attention to improving business growth. Our business plan is
targeted at predictable earnings growth. The result of these efforts will be a
strong, reliable utility company that will be poised to take advantage of
opportunities for further growth.
CE-1
Consumers Energy Company
CONSOLIDATION OF THE MCV PARTNERSHIP AND THE FMLP
Under Revised FASB Interpretation No. 46, we are the primary beneficiary of the
MCV Partnership and the FMLP. As a result, we have consolidated their assets,
liabilities, and activities into our financial statements for the first time as
of and for the quarter ended March 31, 2004. The MCV Partnership and the FMLP
were previously reported as equity method investments. Therefore, the
consolidation of these entities had no impact on our consolidated net income.
For additional details, see Note 7, Implementation of New Accounting Standards.
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 Act of 1933, as amended, and
relevant legal decisions. 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 current price
of CMS Energy Common Stock and the effect on the Pension Plan,
interest rates and 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,
- securities 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,
- ability to access the capital markets successfully,
- international, national, regional, and local economic, competitive,
and regulatory policies, conditions and developments,
- adverse regulatory or legal decisions, including environmental laws
and regulations,
- federal regulation of electric sales and transmission of electricity
including re-examination by federal regulators of our market-based
sales authorizations in wholesale power markets, and proposals by
the FERC to change the way public utilities and natural gas
companies, and their subsidiaries and affiliates, interact with each
other,
- energy markets, including the timing and extent of unanticipated
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,
CE-2
Consumers Energy Company
- 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,
- changes in financial or regulatory accounting principles or
policies,
- 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 CMS Energy's or our 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.
RESULTS OF OPERATIONS
NET INCOME AVAILABLE TO COMMON STOCKHOLDER
In Millions
- -----------------------------------------------------------------
March 31 2004 2003 Change
- -----------------------------------------------------------------
Three months ended $101 $99 $2
=================================================================
2004 COMPARED TO 2003: For the three months ended March 31, 2004, our net income
increased $2 million versus 2003 for several reasons. Higher gas tariff rates,
as authorized by the interim MPSC gas rate order issued in December 2003
increased net income by $6 million. This interim order authorized the reduction
of gas depreciation rates as well, decreasing depreciation expense compared to
the same period in 2003. Electric depreciation expense also decreased versus
2003 because in 2004, we were able to defer depreciation on the excess of
capital expenditures over our depreciation base and recognize interest income on
the excess capital expenditures as authorized by the Customer Choice Act. These
reductions to depreciation and the additional interest income, along with a
decrease in nuclear operating costs increased net income by $7 million in the
first quarter of 2004. Nuclear operating costs for the first quarter of 2004
decreased compared to the same period in 2003, because of a scheduled refueling
outage that began in March 2003. Further contributing to increased net income
for the first quarter 2004 versus 2003 was a reduction to general tax expense of
$3 million due to decreased MSBT expense, and a $1 million increase in gas
wholesale and retail services relating to gas transportation and storage
services.
CE-3
Consumers Energy Company
The increase in net income for the first quarter of 2004 versus the first
quarter of 2003 also reflects a 2003 charge of $12 million to non-utility
expense that recognized a decline in the market value of CMS Energy stock we
held.
Partially offsetting these increases to net income were reductions to net income
attributable to decreases in gas and electric deliveries, increased interest
charges, and lower electric power cost recovery revenues compared to the same
period in 2003. Milder weather in the first quarter of 2004 decreased gas
deliveries, reducing net income by $9 million. The weather also had an adverse
effect on electric deliveries, and along with a reduction to the electric tariff
rates and the continued loss of industrial customers switching to other electric
suppliers, decreased net income by $7 million in the first quarter of 2004
versus 2003. Increased costs of borrowing reduced 2004 net income by $6 million,
reflecting higher levels of debt. Finally, electric power supply revenues in
excess of electric power supply costs were reserved in 2004 for possible refund
to customers and did not benefit net income as in 2003. In 2003, our recovery of
power supply costs was fixed as required under the Customer Choice Act. This
change decreased net income $4 million in the first quarter of 2004 versus 2003.
For additional details, see "Electric Results of Operations" and "Gas Results of
Operations" within this section and Note 2, Uncertainties.
ELECTRIC UTILITY RESULTS OF OPERATIONS
In Millions
- -------------------------------------------------------------------------------
March 31 2004 2003 Change
- -------------------------------------------------------------------------------
Three months ended $45 $51 $ (6)
=== === ======
Reasons for the change:
Electric deliveries $ (10)
Power supply costs and related revenue (6)
Other operating expenses and non-commodity revenue 10
General taxes 4
Fixed charges (6)
Income taxes 2
------
Total change $ (6)
==============================================================================
ELECTRIC DELIVERIES: Electric deliveries, including transactions with other
wholesale marketers, other electric utilities, and customers choosing
alternative suppliers increased 0.3 billion kWh or 3.6 percent in the first
quarter of 2004 compared to 2003. Despite increased electric deliveries,
electric delivery revenue decreased in the first quarter of 2004 versus 2003.
This revenue decrease primarily reflects tariff revenue reductions that began
January 1, 2004. The tariff revenue reductions were equivalent to the Big Rock
nuclear decommissioning surcharge in effect when our electric retail rates were
frozen from June 2000 through December 31, 2003. The tariff revenue reduction
decreased electric delivery revenue by $9 million in the first quarter of 2004
versus 2003, and is expected to decrease electric delivery revenues $35 million
in 2004 versus 2003.
CE-4
Consumers Energy Company
The reduction in electric delivery revenue for the first quarter 2004 versus
2003 also reflects the impact of customers switching to alternative electric
suppliers as allowed by the Customer Choice Act. Although deliveries to the
sector of customers choosing an alternative supplier has grown significantly
from the same period in 2003, the margin on these sales is substantially less
than if we had supplied the generation.
POWER SUPPLY COSTS AND RELATED REVENUE: In 2003, our power supply cost rate of
recovery was a fixed amount per kWh, as required under the Customer Choice Act.
Therefore, power supply-related revenue in excess of actual power supply costs
increased operating income. By contrast, if power supply-related revenues had
been less than actual power supply costs, the impact would have decreased
operating income. In 2004, our recovery of power supply costs is no longer
fixed, but is instead restricted to a pre-defined limit for certain customer
classes. The customer classes that have a pre-defined limit, or cap, on the
level of power supply costs they can be charged are primarily the residential
and small commercial customer classes. In 2004, to the extent our power
supply-related revenues are in excess of actual power supply costs, this former
benefit is reserved for possible future refund. This change in the treatment of
excess power supply revenues over power supply costs decreased 2004 versus 2003
first quarter operating income.
OTHER OPERATING EXPENSES AND NON-COMMODITY REVENUE: In the first quarter of
2004, other operating expenses decreased $2 million and non-commodity revenue
increased $8 million versus 2003. The increase in non-commodity revenue relates
primarily to interest income recognized in relation to capital expenditures in
excess of depreciation as allowed by the Customer Choice Act. The decrease in
operating expenses reflects a reduction in nuclear operating and maintenance
expense in 2004 compared to the same period in 2003 that included a scheduled
refueling outage at the Palisades nuclear facility.
GENERAL TAXES: In the first quarter of 2004, general taxes decreased from the
same period in 2003 due primarily to reductions in MSBT expense.
FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004
versus the same period in 2003 due to higher average debt levels, partially
offset by a 41 basis point reduction in the average interest rate.
INCOME TAXES: In the first quarter of 2004, income taxes decreased versus the
same period in 2003 due primarily to lower earnings by the electric utility.
CE-5
Consumers Energy Company
GAS UTILITY RESULTS OF OPERATIONS
In Millions
- ---------------------------------------------------------------------------------------
March 31 2004 2003 Change
- ---------------------------------------------------------------------------------------
Three months ended $55 $54 $ 1
=== === =======
Reasons for the change:
Gas deliveries $ (14)
Gas rate increase 9
Gas wholesale and retail services and other gas revenues 2
Operation and maintenance (4)
General taxes, depreciation, and other income 6
Fixed charges (3)
Income taxes 5
-------
Total change $ 1
=======================================================================================
GAS DELIVERIES: For the first quarter 2004 versus the same period in 2003, gas
deliveries, including miscellaneous transportation, decreased 7 bcf or 4 percent
versus 2003. Deliveries decreased during the first quarter of 2004 due primarily
to milder weather.
GAS RATE INCREASE: In December 2003, the MPSC issued an interim gas rate order
authorizing a $19 million annual increase to gas tariff rates. As a result of
this order, first quarter 2004 gas revenues increased compared to the same
period in 2003.
GAS WHOLESALE AND RETAIL SERVICES AND OTHER GAS REVENUES: Gas wholesale and
retail services and other gas revenues increased for the period ended March 31,
2004 versus the same period in 2003. This increase relates primarily to
increases in gas transportation and storage revenues and late payment fees.
In 2003, we reserved $11 million for a settlement agreement associated with the
2002-2003 GCR disallowance. Interest on the disallowed amount from April 1, 2003
through February 2004, at Consumers' authorized rate of return, increased the
cost of the settlement by $1 million. In March 2004, the MPSC approved this
settlement agreement in the amount we had reserved. Neither the prior year
reservation, nor the current year final MPSC settlement had any effect on
earnings in the first quarter of 2004 versus the same period in 2003.
OPERATION AND MAINTENANCE: In the first quarter 2004 versus 2003, operation and
maintenance expenses increased due to increases in health care costs and
additional expenditures on safety, reliability, and customer service.
GENERAL TAXES, DEPRECIATION, AND OTHER INCOME: In the first quarter 2004 versus
2003, the net change in general tax expense, depreciation expense, and other
income increased operating income primarily because of decreases in depreciation
rates authorized by the MPSC's December 2003 interim rate order.
FIXED CHARGES: Fixed charges increased in the three months ended March 31, 2004
versus the same period in 2003 due to higher average debt levels, partially
offset by a 41 basis point reduction in the average interest rate.
CE-6
Consumers Energy Company
INCOME TAXES: Income tax expense decreased in the period ended March 31, 2004
versus the same period in 2003. This reduction was attributable primarily to the
income tax treatment of items related to plant, property and equipment as
required by past MPSC rulings.
CRITICAL ACCOUNTING POLICIES
The following accounting policies are important to an understanding of our
results and financial condition and should be considered an integral part of our
MD&A:
- use of estimates in accounting for contingencies and equity method
investments,
- accounting for the effects of regulatory accounting,
- accounting for financial and derivative instruments,
- accounting for pension and postretirement benefits,
- accounting for asset retirement obligations,
- accounting for nuclear decommissioning costs, and
- accounting for related party transactions.
For additional accounting policies, see Note 1, Corporate Structure and
Accounting Policies.
USE OF ESTIMATES AND ASSUMPTIONS
In preparing our financial statements, we use estimates and assumptions that may
affect reported amounts and disclosures. Accounting estimates are used for asset
valuations, depreciation, amortization, financial and derivative instruments,
employee benefits, and contingencies. For example, we estimate the rate of
return on plan assets and the cost of future health-care benefits to determine
our annual pension and other postretirement benefit costs. There are risks and
uncertainties that may cause actual results to differ from estimated results,
such as changes in the regulatory environment, competition, regulatory
decisions, and lawsuits.
CONTINGENCIES: We are involved in various regulatory and legal proceedings that
arise in the ordinary course of our business. We record a liability for
contingencies based upon our assessment that the occurrence is probable and,
where determinable, an estimate of the liability amount. 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 past history
and the specifics of each matter. The most significant of these contingencies
are our electric and gas environmental estimates, which are discussed in the
"Outlook" section included in this MD&A, and the potential underrecoveries from
our power purchase contract with the MCV Partnership.
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 and to supply electricity and steam to Dow. We hold a 49
percent partnership interest in the MCV Partnership, and a 35 percent lessor
interest in the MCV Facility.
Under our power purchase agreement with the MCV Partnership, we pay a capacity
charge based on the availability of the MCV Facility whether or not electricity
is actually delivered to us; a variable energy charge for kWh delivered to us;
and a fixed energy charge based on availability up to 915 MW and based on
delivery for the remaining 325 MW of contract capacity. The cost that we incur
under the MCV Partnership power purchase agreement exceeds the recovery amount
allowed by the MPSC. As a result, we estimate cash underrecoveries of capacity
and fixed energy payments will aggregate $206 million from
CE-7
Consumers Energy Company
2004 through 2007. For capacity and fixed energy payments billed by the MCV
Partnership after September 15, 2007, and not recovered from customers, we
expect to claim relief under a regulatory out provision under the MCV
Partnership power purchase agreement. This provision obligates Consumers to pay
the MCV Partnership only those capacity and energy charges that the MPSC has
authorized for recovery from electric customers. The effect of any such action
would be to:
- reduce cash flow to the MCV Partnership, which could have an adverse
effect on our investment, and
- eliminate our underrecoveries for capacity and fixed energy
payments.
Further, under the PPA, variable energy payments to the MCV Partnership are
based on the cost of coal burned in our coal plants and our operations and
maintenance expenses. However, the MCV Partnership's costs of producing
electricity are tied to the cost of natural gas. Because natural gas prices have
increased substantially in recent years, while the price the MCV Partnership can
charge us for energy has not, the MCV Partnership's financial performance has
been affected adversely.
As a result of returning to the PSCR process on January 1, 2004, we returned to
dispatching the MCV Facility on a fixed load basis, as permitted by the MPSC, in
order to maximize recovery from electric customers of our capacity and fixed
energy payments. This fixed load dispatch increases the MCV Facility's output
and electricity production costs, such as natural gas. As the spread between the
MCV Facility's variable electricity production costs and its energy payment
revenue widens, the MCV Partnership's financial performance and our investment
in the MCV Partnership is and will be harmed.
In February 2004, we filed a resource conservation plan with the MPSC that is
intended to help conserve natural gas and thereby improve our investment in the
MCV Partnership, without raising the costs paid by our electric customers. The
plan's primary objective is to dispatch the MCV Facility on the basis of natural
gas market prices, which will reduce the MCV Facility's annual natural gas
consumption by an estimated 30 to 40 bcf. This decrease in the quantity of
high-priced natural gas consumed by the MCV Facility will benefit Consumers'
ownership interest in the MCV Partnership. In April 2004, the presiding ALJ at
the MPSC held a pre-hearing conference regarding the resource conservation plan.
The ALJ denied our request to establish a schedule that would have allowed
consideration of the plan on an interim basis and established a review schedule
that calls for a Proposal for Decision in September 2004 after which point the
MPSC would consider the plan. We cannot predict if or when the MPSC will approve
our resource conservation plan.
The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
22 years and the MPSC's decision in 2007 or beyond related to limiting our
recovery of capacity and fixed energy payments. Natural gas prices have been
volatile historically. Presently, there is no consensus in the marketplace on
the price or range of prices of natural gas in the short term or beyond the next
five years. Even with an approved resource conservation plan, if gas prices
continue at present levels or increase, the economics of operating the MCV
Facility may be adverse enough to require us to recognize an impairment of our
investment in the MCV Partnership. We presently cannot predict the impact of
these issues on our future earnings, cash flows, or on the value of our
investment in the MCV Partnership.
For additional details, see Note 2, Uncertainties, "Other Electric Uncertainties
- - The Midland Cogeneration Venture."
CE-8
Consumers Energy Company
ACCOUNTING FOR THE EFFECTS OF INDUSTRY REGULATION
Because we are involved in a regulated industry, regulatory decisions affect the
timing and recognition of revenues and expenses. We use SFAS No. 71 to account
for the effects of these regulatory decisions. As a result, we may defer or
recognize revenues and expenses differently than a non-regulated entity.
For example, items that a non-regulated entity normally would expense, we may
record as regulatory assets if the actions of the regulator indicate such
expenses will be recovered in future rates. Conversely, items that non-regulated
entities may normally recognize as revenues, we may record as regulatory
liabilities if the actions of the regulator indicate they will require such
revenues be refunded to customers. Judgment is required to determine the
recoverability of items recorded as regulatory assets and liabilities. As of
March 31, 2004, we had $1.125 billion recorded as regulatory assets and $1.497
billion recorded as regulatory liabilities.
For additional details on industry regulation, see Note 1, Corporate Structure
and Accounting Policies, "Utility Regulation."
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. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale securities.
Our investments in equity securities are classified as available-for-sale
securities. They are reported at fair value, with any unrealized gains or losses
resulting from changes in fair value reported in equity as part of accumulated
other comprehensive income and are excluded from earnings unless such changes in
fair value are determined to be other than temporary. Unrealized gains or losses
resulting from changes in the fair value of our nuclear decommissioning
investments are reported as regulatory liabilities. The fair value of these
investments is determined from quoted market prices. Our debt securities are
classified as held-to-maturity securities and are reported at cost.
DERIVATIVE INSTRUMENTS: We use the criteria in SFAS No. 133, as amended and
interpreted, to determine if certain contracts must be accounted for as
derivative instruments. The rules for determining whether a contract meets the
criteria for derivative accounting are numerous and complex. Moreover,
significant judgment is required to determine whether a contract requires
derivative accounting, and similar contracts can sometimes be accounted for
differently.
If a contract is accounted for as a derivative instrument, it is recorded in the
financial statements as an asset or a liability, at the fair value of the
contract. The recorded fair value of the contract is then adjusted quarterly to
reflect any change in the market value of the contract, a practice known as
marking the contract to market. The accounting for changes in the fair value of
a derivative (that is, gains or losses) is reported either in earnings or
accumulated other comprehensive income depending on whether the derivative
qualifies for special hedge accounting treatment. For additional details on the
accounting policies for derivative instruments, see Note 4, Financial and
Derivative Instruments.
The types of contracts we typically classify as derivative instruments are
interest rate swaps, electric call options, gas fuel futures and options, gas
fuel contracts containing volume optionality, fixed priced weather-based gas
supply call options, and fixed price gas supply call and put options. We
generally do not account for electric capacity and energy contracts, gas supply
contracts, coal and nuclear fuel supply contracts, or purchase orders for
numerous supply items as derivatives.
CE-9
Consumers Energy Company
Our electric capacity and energy contracts are not accounted for as derivatives
due to the lack of an active energy market in the state of Michigan, as defined
by SFAS No. 133, and the significant transportation costs that would be incurred
to deliver the power under the contracts to the closest active energy market at
the Cinergy hub in Ohio. If an active market develops in the future, we may be
required to account for these contracts as derivatives. The mark-to-market
impact on earnings related to these contracts could be material to our financial
statements.
To determine the fair value of contracts that are accounted for as derivative
instruments, we use a combination of quoted market prices and mathematical
valuation models. Valuation models require various inputs, including forward
prices, volatilities, interest rates, and exercise periods. Changes in forward
prices or volatilities could change significantly the calculated fair value of
certain contracts. At March 31, 2004, we assumed a market-based interest rate of
1 percent (a rate that is not significantly different than the LIBOR rate) and
an average volatility rate of 66.8 percent to calculate the fair value of our
gas options. At March 31, 2004, we assumed market-based interest rates ranging
between 1.09 percent and 2.7 percent and volatility rates ranging between 23
percent and 38 percent to calculate the fair value of the gas fuel derivative
contracts held by the MCV Partnership.
MARKET RISK INFORMATION: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, and equity security
prices. We manage these risks using established policies and procedures, under
the direction of both an executive oversight committee consisting of senior
management representatives and a risk committee consisting of business-unit
managers. We may use various contracts to manage these risks, including swaps,
options, futures, and forward contracts.
Contracts used to manage market risks may be considered derivative instruments
that are subject to derivative and hedge accounting pursuant to SFAS No. 133. We
intend 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 risk management
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 minimize such risk by performing
financial credit reviews using, among other things, publicly available credit
ratings of such counterparties.
We perform sensitivity analyses to assess the potential loss in fair value, cash
flows, or future earnings based upon a hypothetical 10 percent adverse change in
market rates or prices. We do not believe that sensitivity analyses alone
provide an accurate or reliable method for monitoring and controlling risks.
Therefore, we use our experience and judgment to revise strategies and modify
assessments. Changes in excess of the amounts determined in sensitivity analyses
could occur if market rates or prices exceed the 10 percent shift used for the
analyses. These risk sensitivities are shown in "Interest Rate Risk," "Commodity
Price Risk," and "Equity Securities Price Risk" within this section.
Interest Rate Risk: We are exposed to interest rate risk resulting from issuing
fixed-rate and variable-rate financing instruments, and from interest rate swap
agreements. We use a combination of these instruments to manage this risk as
deemed appropriate, based upon market conditions. These strategies are designed
to provide and maintain a balance between risk and the lowest cost of capital.
CE-10
Consumers Energy Company
Interest Rate Risk Sensitivity Analysis (assuming a 10 percent adverse change in
market interest rates):
In Millions
- ------------------------------------------------------------------------------------------------------
March 31, December 31,
2004 2003
- ------------------------------------------------------------------------------------------------------
Variable-rate financing - before tax annual earnings exposure $ 1 $ 1
Fixed-rate financing - potential loss in fair value (a) 154 154
======================================================================================================
(a) Fair value exposure could only be realized if we repurchased all of our
fixed-rate financing.
As discussed in "Electric Business Uncertainties - Competition and Regulatory
Restructuring - Securitization" within this MD&A, we have filed an application
with the MPSC to securitize certain expenditures. Upon final approval, we intend
to use the proceeds from the Securitization to retire higher-cost debt, which
could include a portion of our current fixed-rate debt. We do not believe that
any adverse change in debt price and interest rates would have a material
adverse effect on either our consolidated financial position, results of
operations, or cash flows.
Commodity Price Risk: For purposes other than trading, we enter into electric
call options, fixed-priced weather-based gas supply call options, and
fixed-priced gas supply call and put options. Electric call options are used to
protect against the risk of fluctuations in the market price of electricity, and
to ensure a reliable source of capacity to meet our customers' electric needs.
Electric call options give us the right, but not the obligation, to purchase
electricity at predetermined fixed prices. Weather-based gas supply call
options, along with the gas supply call and put options, are used to purchase
reasonably priced gas supply. Gas supply call options give us the right, but not
the obligation, to purchase gas supply at predetermined fixed prices. Gas supply
put options give third-party suppliers the right, but not the obligation, to
sell gas supply to us at predetermined fixed prices. At March 31, 2004, we only
held gas supply call and put options.
The MCV Partnership uses natural gas fuel contracts to buy gas as fuel for
generation, and to manage gas fuel costs. Some of these contracts contain volume
optionality and, thus, are treated as derivative instruments. Also, the MCV
Partnership enters into natural gas futures contracts 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 being 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.
CE-11
Consumers Energy Company
Commodity Price Risk Sensitivity Analysis (assuming a 10 percent adverse change
in market prices):
In Millions
- --------------------------------------------------------------------------------------------------
March 31, December 31,
2004 2003
- -------------------------------------------------------------------------------------------------
Potential reduction in fair value:
Gas supply call and put option contracts $12 $ 1
Derivative contracts associated with Consumers' investment in the MCV
Partnership:
Gas fuel contracts 24 N/A
Gas fuel futures 25 N/A
================================================================================================
During the first quarter of 2004, we entered into additional gas supply call and
put option contracts. As a result, the potential reduction in the fair value
increased from December 31, 2003 as shown in the table above. We did not perform
a sensitivity analysis for the derivative contracts held by the MCV Partnership
as of December 31, 2003 because the MCV Partnership was not consolidated into
our financial statements until March 31, 2004, as further discussed in Note 7,
Implementation of New Accounting Standards.
Equity Securities Price Risk: We are exposed to price risk associated with
investments in equity securities. As discussed in "Financial Instruments" within
this section, our investments in equity securities are classified as
available-for-sale securities. They are reported at fair value, with any
unrealized gains or losses resulting from changes in fair value reported in
equity as part of accumulated other comprehensive income and are excluded from
earnings unless such changes in fair value are determined to be other than
temporary. Unrealized gains or losses resulting from changes in the fair value
of our nuclear decommissioning investments are reported as regulatory
liabilities. Our debt securities are classified as held-to-maturity securities
and have original maturity dates of approximately one year or less. Because of
the short maturity of these instruments, their carrying amounts approximate
their fair values.
Equity Securities Price Risk Sensitivity Analysis (assuming a 10 percent adverse
change in market prices):
In Millions
- ----------------------------------------------------------------
March 31, December 31,
2004 2003
- ----------------------------------------------------------------
Potential reduction in fair value:
Nuclear decommissioning investments $56 $57
Other available for sale investments 4 4
================================================================
For additional details on market risk and derivative activities, see Note 4,
Financial and Derivative Instruments.
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Consumers Energy Company
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. We use SFAS No. 87 to account for pension costs.
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.
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 expense, OPEB expense,
and cash contributions for the next three years:
Expected Costs In Millions
- ---------------------------------------------------------------------------------------
Pension Expense OPEB Expense Contributions
- ---------------------------------------------------------------------------------------
2004 $20 $54 $ 125
2005 52 62 114
2006 71 58 106
=======================================================================================
Actual future pension expense 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. As of March 31, 2004, we
have a prepaid pension asset of $379 million recorded on our consolidated
balance sheets.
Lowering the expected long-term rate of return on the Pension Plan assets by
0.25 percent (from 8.75 percent to 8.50 percent) would increase estimated
pension expense for 2004 by $2 million. Lowering the discount rate by 0.25
percent (from 6.25 percent to 6.00 percent) would increase estimated pension
expense for 2004 by $4 million.
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that
was signed into law in December 2003 establishes a prescription drug benefit
under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree
health care benefit plans that provide a benefit that is actuarially equivalent
to Medicare Part D. We are continuing to defer recognizing the effects of the
Act in our 2004 financial statements, as permitted by FASB Staff Position No.
106-b. When accounting guidance is issued, our retiree health benefit obligation
may be adjusted.
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Consumers Energy Company
For additional details on postretirement benefits, see Note 5, Retirement
Benefits, and Note 7, Implementation of New Accounting Standards.
ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS
SFAS No. 143, Accounting for Asset Retirement Obligations, became effective
January 2003. It requires companies to record the fair value of the cost to
remove assets at the end of their useful lives, 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 a
regulatory asset and liability 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 reasonable estimate of fair value cannot be made in the period the asset
retirement obligation is incurred, such as assets with indeterminate lives, the
liability is to be recognized when a reasonable estimate of fair value can be
made. Generally, transmission and distribution assets have indeterminate lives.
Retirement cash flows cannot be determined. There is a low probability of a
retirement date, so no liability has been recorded for these assets. 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
are based largely on third-party cost estimates. For additional details on ARO,
see Note 6, Asset Retirement Obligations.
ACCOUNTING FOR NUCLEAR DECOMMISSIONING COSTS
The MPSC and the FERC regulate the recovery of costs to decommission our Big
Rock and Palisades nuclear plants. We have established external trust funds to
finance the decommissioning of both plants. We record the trust fund balances as
a non-current asset on our balance sheet.
Our decommissioning cost estimates for the Big Rock and Palisades plants assume:
- each plant site will be restored to conform to the adjacent
landscape,
- all contaminated equipment and material will be removed and disposed
of in a licensed burial facility, and
- the site will be released for unrestricted use.
Independent contractors with expertise in decommissioning have helped us develop
decommissioning cost estimates. Various inflation rates for labor, non-labor,
and contaminated equipment disposal costs are used to escalate these cost
estimates to the future decommissioning cost. A portion of future
decommissioning cost will result from the failure of the DOE to remove fuel from
the sites, as required by the Nuclear Waste Policy Act of 1982.
The decommissioning trust funds include equities and fixed income investments.
Equities will be converted to fixed income investments during decommissioning,
and fixed income investments are converted to cash as needed. In December 2000,
funding of the Big Rock trust fund stopped because the
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Consumers Energy Company
MPSC-authorized decommissioning surcharge collection period expired. The funds
provided by the trusts, additional customer surcharges, and potential funds from
the DOE litigation are all required to cover fully the decommissioning costs.
The costs of decommissioning these sites and the adequacy of the trust funds
could be affected by:
- variances from expected trust earnings,
- a lower recovery of costs from the DOE and lower rate recovery from
customers, and
- changes in decommissioning technology, regulations, estimates, or
assumptions.
Based on current projections, the current level of funds provided by the trusts
is not adequate to fully fund the decommissioning of Big Rock or Palisades. This
is due in part to the DOE's failure to accept the spent nuclear fuel on schedule
and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation. We will also
seek additional relief from the MPSC. For additional details, see Note 2,
Uncertainties, "Other Electric Uncertainties - Nuclear Plant Decommissioning"
and "Nuclear Matters."
RELATED PARTY TRANSACTIONS
We enter into a number of significant transactions with related parties. These
transactions include:
- issuance of trust preferred securities with Consumers' affiliated
companies,
- purchases and sales of electricity and gas for generation from
Enterprises,
- purchase of gas transportation from CMS Bay Area Pipeline, L.L.C.,
- payment of parent company overhead costs to CMS Energy, and
- investment in CMS Energy Common Stock.
Transactions involving CMS Energy and its affiliates are generally based on
regulated prices, market prices, or competitive bidding. Transactions involving
the power supply purchases from certain affiliates of Enterprises are based upon
avoided costs under PURPA and competitive bidding. The payment of parent company
overhead costs is based on the use of accepted industry allocation
methodologies.
We determined that the MCV Partnership and the FMLP are variable interest
entities and that we are the primary beneficiary of these entities. Therefore,
we have consolidated these partnerships into our consolidated financial
statements for the first time as of and for the quarter ended March 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 could require additional liquidity due to the timing of the
cost recoveries. In addition, a few of our commodity suppliers have requested
advance payment or other forms of assurances, including margin calls, in
connection with maintenance of ongoing deliveries of gas and electricity.
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Consumers Energy Company
In 2003, we had debt maturities and capital expenditures that required
substantial amounts of cash. As a result, we executed a financial improvement
plan to address these critical liquidity issues. We explored financing
opportunities, such as refinancing debt and issuing new debt. We also reduced
capital expenditures.
In 2004, we will continue to monitor our operating expenses and capital
expenditures and evaluate market conditions for financing opportunities. We
believe that our current level of cash and borrowing capacity, along with
anticipated cash flows from operating activities, and reduced capital
expenditures, will be sufficient to meet our liquidity needs through 2005.
CASH POSITION, INVESTING, AND FINANCING
SUMMARY OF CASH FLOWS:
In Millions
- ----------------------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- ----------------------------------------------------------------------------------
Net cash provided by (used in):
Operating activities $ 263 $ 396
Investing activities (112) (118)
Financing activities (88) (51)
--------------
Net Increase in Cash and Cash Equivalents $ 63 $ 227
==================================================================================
OPERATING ACTIVITIES:
For the three months ended March 31, 2004, net cash provided by operating
activities decreased $133 million due to a greater increase in accounts
receivable and accrued revenue of $284 million primarily due to lower sales of
accounts receivable resulting from our improved liquidity. This change was
offset by a greater decrease in gas inventory of $99 million resulting from
sales at higher prices combined with lower volumes of gas purchased.
INVESTING ACTIVITIES:
For the three months ended March 31, 2004, net cash used in investing activities
decreased $6 million primarily due to a decrease in 2004 versus 2003 capital
expenditures of $4 million as a result of our strategic plan to reduce capital
expenditures and an increase in proceeds from nuclear decommissioning trust
funds of $14 million. These changes were partially offset by a decrease in asset
sale proceeds of $13 million resulting from 2003 asset sales.
FINANCING ACTIVITIES:
For the three months ended March 31, 2004, net cash used in financing activities
increased $37 million primarily due to a decrease of $48 million in net proceeds
from borrowings. For additional details on long-term debt activity, see Note 3,
Financings and Capitalization.
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Consumers Energy Company
OBLIGATIONS AND COMMITMENTS
Our total contractual obligations as of March 31, 2004, are shown in the
following table.
Contractual Obligations In Millions
- --------------------------------------------------------------------------------------------------------------------
Payments/Expiration
---------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 beyond
- --------------------------------------------------------------------------------------------------------------------
On-balance sheet:
Long-term debt $ 4,015 $ 136 $ 559 $ 478 $ 59 $ 504 $ 2,279
Long-term debt - related parties 506 - - - - - 506
Notes payable - related parties 200 200 - - - - -
Capital lease obligations 372 44 31 27 26 26 218
- --------------------------------------------------------------------------------------------------------------------
Total on-balance sheet $ 5,093 $ 380 $ 590 $ 505 $ 85 $ 530 $ 3,003
- --------------------------------------------------------------------------------------------------------------------
Off-balance sheet:
Operating leases $ 64 $ 9 $ 8 $ 7 $ 6 $ 5 $ 29
Long-term service agreements 219 9 12 19 13 12 154
Unconditional purchase obligations 9,154 1,648 1,226 781 582 508 4,409
- --------------------------------------------------------------------------------------------------------------------
Total off-balance sheet $ 9,437 $ 1,666 $ 1,246 $ 807 $ 601 $ 525 $ 4,592
====================================================================================================================
For additional details, see Note 2, Uncertainties, and Note 3, Financings and
Capitalization.
REGULATORY AUTHORIZATION FOR FINANCINGS: We issue short and long-term securities
under the FERC authorization. For additional details of our existing
authorization, see Note 3, Financings and Capitalization.
LONG-TERM DEBT: Details on our long-term debt are presented in Note 3,
Financings and Capitalization.
SHORT-TERM FINANCINGS: At March 31, 2004, we have $376 million available under a
revolving credit facility that is available for general corporate purposes,
working capital, and letters of credit. The MCV Partnership has a $50 million
working capital facility available.
CAPITAL LEASE OBLIGATIONS: Our capital leases are comprised mainly of the leased
portion of the MCV Partnership facility, leased service vehicles, and leased
office furniture. The full obligation of our leases could become due in the
event of lease payment default.
OFF-BALANCE SHEET ARRANGEMENTS: We use off-balance sheet arrangements in the
normal course of business. Our off-balance sheet arrangements include:
- operating leases,
- long-term service agreements,
- sale of accounts receivable, and
- unconditional purchase obligations.
Operating Leases: Leases of railroad cars are accounted for as operating leases.
Long-term Service Agreements: These obligations of the MCV Partnership represent
the cost of the current MCV Facility maintenance service agreements and cost of
spare parts.
Sale of Accounts Receivable: Under a revolving accounts receivable sales
program, we may sell up to $325 million of certain accounts receivable. For
additional details, see Note 3, Financings and Capitalization.
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Consumers Energy Company
Unconditional Purchase Obligations: Long-term contracts for purchase of
commodities and services are unconditional purchase obligations. These
obligations represent operating contracts used to assure adequate supply with
generating facilities that meet PURPA requirements. The commodities and services
include:
- natural gas,
- electricity,
- coal purchase contracts and their associated cost of transportation,
and
- electric transmission.
Included in unconditional purchase obligations are long-term power purchase
agreements with various generating plants. These contracts require us to make
monthly capacity payments based on the plants' availability or deliverability.
These payments will approximate $13 million per month during 2004. If a plant is
not available to deliver electricity, we are not obligated to make the capacity
payments to the plant for that period of time. For additional details on power
supply costs, see "Electric Utility Results of Operations" within this MD&A and
Note 2, Uncertainties, "Electric Rate Matters - Power Supply Costs."
COMMERCIAL COMMITMENTS: Our commercial commitments include indemnities and
letters of credit. Indemnities are agreements to reimburse other companies, such
as an insurance company, if those companies have to complete our contractual
performance in a third-party contract. Banks, on our behalf, issue letters of
credit guaranteeing payment to a third party. Letters of credit substitute the
bank's credit for ours and reduce credit risk for the third-party beneficiary.
Our commercial commitments at March 31, 2004 are as follows:
Commercial Commitments In Millions
- ---------------------------------------------------------------------------------------------------------------
Commitment Expiration
--------------------------------------------------------
2009 and
Total 2004 2005 2006 2007 2008 beyond
- ----------------------------------------------------------------------------------------------------------------
Off-balance sheet:
Indemnities $ 8 $ 8 $ - $ - $ - $ - $ -
Letters of credit 24 8 16 - - - -
================================================================================================================
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
March 31, 2004, we had $397 million of unrestricted retained earnings available
to pay common stock dividends. However, covenants in our debt facilities cap
common stock dividend payments at $300 million in a calendar year. We are also
under an annual dividend cap of $190 million imposed by the MPSC during the
current interim gas rate relief period. In February 2004, we paid $78 million in
common stock dividends to CMS Energy.
For additional details on the cap on common dividends payable during the current
interim gas rate relief period, see Note 2, Uncertainties, "Gas Rate Matters -
2003 Gas Rate Case."
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Consumers Energy Company
OUTLOOK
ELECTRIC BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect electric deliveries to grow at an
average rate of approximately two percent per year based primarily on a steadily
growing customer base and 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 abnormal weather conditions and
changes in economic conditions, including utilization and expansion of
manufacturing facilities. We experienced less growth than expected in 2003 as a
result of cooler than normal summer weather and a decline in manufacturing
activity in Michigan. In 2004, we project electric deliveries to grow
approximately two percent. This short-term outlook for 2004 assumes higher
levels of manufacturing activity than in 2003 and normal weather conditions
during the remainder of the year.
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. Such trends and uncertainties include:
Environmental
- increasing capital expenditures and operating expenses for Clean Air
Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential liability or
expenses relating to the Michigan Natural Resources and
Environmental Protection Acts and Superfund.
Restructuring
- response of the MPSC and Michigan legislature to electric industry
restructuring issues,
- ability to meet peak electric demand requirements at a reasonable
cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- recovery of electric restructuring implementation costs,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer instead of an electric
transmission owner-operator.
Regulatory
- effects of conclusions about the causes of the August 14, 2003
blackout, including exposure to liability, increased regulatory
requirements, and new legislation,
- successful implementation of initiatives to reduce exposure to
purchased power price increases,
- effects of potential performance standards payments,
- effects of the FERC supply margin assessment requirements for
electric market-based rate authority,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel, and
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Consumers Energy Company
- recovery of nuclear decommissioning costs. For additional details,
see "Accounting for Nuclear Decommissioning Costs" within this MD&A.
Other
- effects of commodity fuel prices such as natural gas and coal,
- pending litigation filed by PURPA qualifying facilities,
- pending other litigation, and
- potential rising pension costs due to market losses and lump sum
payments. For additional details, see "Accounting for Pension and
OPEB" within this MD&A.
For additional details about these trends or uncertainties, see Note 2,
Uncertainties.
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.
Compliance with the federal Clean Air Act and resulting regulations has been,
and will continue to be, a significant focus for us. The Title I provisions of
the Clean Air Act require significant reductions in nitrogen oxide emissions. To
comply with the regulations, we expect to incur capital expenditures totaling
$771 million. The key assumptions included 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 8.9 percent. As of March 31, 2004, we have
incurred $469 million in capital expenditures to comply with these regulations
and anticipate that the remaining $302 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology on coal-fired electric plants. In addition to modifying the
coal-fired electric plants, we expect to purchase nitrogen oxide emissions
credits for years 2004 through 2008. The cost of these credits is estimated to
average $8 million per year and is accounted for as inventory.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek 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.
The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which
requires additional coal-fired electric plant emission controls for nitrogen
oxides and sulfur dioxide. If implemented, this rule would potentially require
expenditures equivalent to those efforts in progress required to reduce nitrogen
oxide emissions under the Title I provisions of the Clean Air Act. The rule
proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent
and nitrogen oxides by 65 percent by 2015, through the installation of flue gas
desulfurization scrubbers and selective catalytic reduction units. Additionally,
the EPA also proposed two alternative sets of rules to reduce emissions of
mercury and nickel from coal-fired and oil-fired electric plants. Until the
proposed environmental rules are finalized, an accurate cost of compliance
cannot be determined.
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Consumers Energy Company
Several bills have been introduced in the United States Congress that would
require carbon dioxide emissions reduction. We cannot predict whether any
federal mandatory carbon dioxide emissions reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
To the extent that emissions reduction rules come into legal effect, such
mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows, or financial position
due to the speculative nature of the policy. 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.
In March 2004, the EPA changed the 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 by
2006. We are studying the rules to determine the most cost-effective solutions
for compliance.
For additional details on electric environmental matters, see Note 2,
Uncertainties, "Electric Contingencies - Electric Environmental Matters."
COMPETITION AND REGULATORY RESTRUCTURING: Michigan's Customer Choice Act and
other developments will continue to result in increased competition in the
electric business. Generally, increased competition reduces profitability and
threatens market share for generation services. As of January 1, 2002, the
Customer Choice Act allowed all of our electric customers to buy electric
generation service from us or from an alternative electric supplier. As a
result, alternative electric suppliers for generation services have entered our
market. As of April 2004, alternative electric suppliers are providing 823 MW of
generation supply to ROA customers. This amount represents 10 percent of our
distribution load and an increase of 50 percent compared to April 2003. We
anticipate this upward trend to continue and expect over 1,100 MW of generation
supply to ROA customers in 2004. We cannot predict the total amount of electric
supply load that may be lost to competitor suppliers.
In February 2004, the MPSC issued an order on Detroit Edison's request for rate
relief for costs associated with customers leaving under electric customer
choice. The MPSC order allows Detroit Edison to implement a transition charge on
ROA customers and eliminates securitization charge offsets. We are seeking
similar recovery of Stranded Costs due to ROA customers leaving our system and
are encouraged by this ruling. We cannot predict if or when the MPSC will
approve implementation of a transition charge on our ROA customers.
Securitization: In March 2003, we filed an application with the MPSC seeking
approval to issue Securitization bonds. In June 2003, the MPSC issued a
financing order authorizing the issuance of Securitization bonds in the amount
of approximately $554 million. In July 2003, we filed for rehearing and
clarification on a number of features in the financing order.
In December 2003, the MPSC issued its order on rehearing, which rejected our
requests for clarification and modification to the dividend payment restriction,
failed to rule directly on the accounting clarifications requested, and remanded
the proceeding to the ALJ for additional proceedings to address rate design. We
filed testimony regarding the remanded proceeding in February 2004. The ALJ
completed hearings in March 2004 and the MPSC decision is not anticipated before
May 2004, but could be later. The financing
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Consumers Energy Company
order will become effective after our acceptance of a favorable MPSC order.
Bonds will not be issued until resolution of any appeals.
Stranded Costs: To the extent we experience net Stranded Costs as determined by
the MPSC, the Customer Choice Act allows us to recover such costs by collecting
a transition surcharge from customers who switch to an alternative electric
supplier. We cannot predict whether the Stranded Cost recovery method adopted by
the MPSC will be applied in a manner that will fully offset any associated
margin loss.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero net
Stranded Costs from 2000 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We
currently are in the process of appealing these orders with the Michigan Court
of Appeals and the Michigan Supreme Court.
In March 2003, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2002, and for approval of a net Stranded Cost
recovery charge. Our net Stranded Costs incurred in 2002, including the cost of
money, are estimated to be $47 million with the issuance of Securitization bonds
that include Clean Air Act investments, or $104 million without the issuance of
Securitization bonds that include Clean Air Act investments. Once the MPSC
issues a final financing order on Securitization, we will know the amount of our
request for net Stranded Cost recovery for 2002.
In April 2004, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2003, including the cost of money, in the amount of
$106 million with the issuance of Securitization bonds that include Clean Air
Act investments, or $165 million without the issuance of Securitization bonds
that include Clean Air Act investments. Similar to the request that was granted
by the MPSC for Detroit Edison, we also requested interim relief for 2002 and
2003 net Stranded Costs. We cannot predict how the MPSC will rule on our
requests for the recoverability of Stranded Costs. Therefore, we have not
recorded regulatory assets to recognize the future recovery of such costs.
Implementation Costs: Since 1997, we have incurred significant costs to
implement the Customer Choice Act. The Customer Choice Act allows electric
utilities to recover the Act's implementation costs. The MPSC reviewed and
granted deferred conditional recovery of certain of the implementation costs
incurred through 2001, but has not yet authorized rates that would allow
recovery.
Our applications for $7 million of implementation costs for 2002 and $1 million
for 2003 are currently pending approval by the MPSC. Included in the 2002
request is $5 million related to our former participation in the development of
the Alliance RTO. As of March 31, 2004, implementation costs totaled $93
million, which includes $23 million associated with the cost of money. We
believe the implementation costs and the associated cost of money are fully
recoverable in accordance with the Customer Choice Act. Cash recovery from
customers is expected to begin after rate cap periods expire. For additional
information on rate caps, see "Rate Caps" within this section.
In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision
finding that the recovery of 1999 implementation costs is conditional and
subject to later disallowance is unlawful. The case was remanded to the MPSC.
The MPSC issued an order regarding the remanded proceeding that directed us to
choose whether we prefer to recover our approved implementation costs through
Securitization pursuant to the MPSC's final order in the Securitization
proceeding or whether we would prefer to have recovery controlled by the remand
proceeding. If the latter option was chosen, the MPSC indicated that it intended
to authorize recovery of such implementation costs through the use of surcharges
on all customer classes that coincide with the expiration of the Customer Choice
Act rate caps. We chose recovery of the approved implementation costs through
the use of surcharges and withdrew our request for approved implementation costs
recovery from our Securitization proposal. The implementation costs withdrawn
from the Securitization case were incurred for the years 1998 through 2000. In
the filing we made electing recovery through separate surcharges, we requested
approval of surcharges that would allow recovery of implementation costs
incurred for the years 1998 through 2001. We requested that the Court of Appeals
issue similar remand orders with respect to appeals of the MPSC orders
addressing 2000 and 2001 implementation costs. We cannot predict the amounts the
MPSC will approve as recoverable costs.
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Consumers Energy Company
Also, we are pursuing authorization at the FERC for the MISO to reimburse us for
approximately $8 million in certain electric utility restructuring
implementation costs related to our former participation in the development of
the Alliance RTO, a portion of which has been expensed. In May 2003, the FERC
issued an order denying the MISO's request for authorization to reimburse us. We
appealed the FERC ruling at the United States Court of Appeals for the District
of Columbia. We also requested that the MISO seek authorization to reimburse the
METC for these development costs. The MISO filed this request but the FERC
denied it. While we appeal the FERC's orders, we are also pursuing other
potential means of recovery, such as recovery of Alliance RTO development costs
at the MPSC. We cannot predict the outcome of the appeal process or the ultimate
amount, if any, we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act allows for recovery of new and enhanced
security costs, as a result of federal and state regulatory security
requirements. All retail customers, except customers of alternative electric
suppliers, would pay these charges. In April 2004, we filed a security cost
recovery case with the MPSC for $25 million of cost that regulatory treatment
has not yet been granted through other means. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. We cannot
predict how the MPSC will rule on our requests for the recoverability of
security costs.
Rate Caps: The Customer Choice Act imposes certain limitations on electric rates
that could result in us being unable to collect our full cost of conducting
business from electric customers. Such limitations include:
- rate caps effective through December 31, 2004 for small commercial
and industrial customers, and
- rate caps effective through December 31, 2005 for residential
customers.
As a result, we may be unable to maintain our profit margins in our electric
utility business during the rate cap periods. In particular, if we need to
purchase power supply from wholesale suppliers while retail rates are capped,
the rate restrictions may make it impossible for us to fully recover purchased
power and associated transmission costs.
PSCR: The PSCR process provides for the reconciliation of actual power supply
costs with power supply revenues. This process assures recovery of all
reasonable and prudent power supply costs actually incurred by us, including the
actual cost for fuel, and purchased and interchange power. In September 2003, we
submitted a PSCR filing to the MPSC that reinstates the PSCR process for
customers whose rates are no longer frozen or capped as of January 1, 2004. The
proposed PSCR charge allows us to recover a portion of our increased power
supply costs from large commercial and industrial customers and, subject to the
overall rate caps, from other customers. We estimate the recovery of increased
power supply costs from large commercial and industrial customers to be
approximately $30 million in 2004. As allowed under current regulation, we
self-implemented the proposed PSCR charge on January 1, 2004. The revenues
received from the PSCR charge are also subject to subsequent reconciliation at
the end of the year after actual costs have been reviewed for reasonableness and
prudence. We cannot predict the outcome of this filing.
Decommissioning Surcharge: When our electric retail rates were frozen in June
2000, a nuclear decommissioning surcharge related to the decommissioning of Big
Rock was included. In December 2000, funding of the Big Rock nuclear
decommissioning trust fund stopped because the MPSC-authorized decommissioning
surcharge collection period expired. However, we continued to collect the
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Consumers Energy Company
equivalent to the Big Rock nuclear decommissioning surcharge consistent with the
Customer Choice Act rate freeze through December 31, 2003. Collection of the
surcharge stopped, effective January 1, 2004, when the electric rate freeze
expired.
Industrial Contracts: We entered into multi-year electric supply contracts with
certain large industrial customers. The contracts provide electricity at
specially negotiated prices, usually at a discount from tariff prices. The MPSC
approved these special contracts totaling approximately 685 MW of load. Unless
terminated or restructured, the majority of these contracts are in effect
through 2005. As of March 31, 2004, contracts for 201 MW of load have
terminated. Of the contracts that have terminated, 70 MW of load have gone to an
alternative electric supplier and 131 MW of load have returned to bundled tariff
rates. In January 2004, new special contracts for 91 MW, with the State of
Michigan and three universities, were approved by the MPSC. Initial special
contracts with Dow Corning and Hemlock Semi-Conductor were terminated in
December 2003. New special contracts with Dow Corning and Hemlock Semi-Conductor
for 101 MW received interim approval from the MPSC and are awaiting final
approval. As of April 2004, our special contracts total approximately 580 MW of
load. All new special contracts end by January 1, 2006. We cannot predict
whether additional special contracts will be necessary, advisable, or approved.
Transmission Sale: In May 2002, we sold our electric transmission system for
$290 million to MTH. We are currently in arbitration with MTH regarding property
tax items used in establishing the selling price of our electric transmission
system. We cannot predict whether the remaining open items will affect
materially the sale proceeds previously recognized.
There are multiple proceedings and a proposed rulemaking pending before the FERC
regarding transmission pricing mechanisms and standard market design for
electric bulk power markets and transmission. The results of these proceedings
and proposed rulemakings could affect significantly:
- transmission cost trends,
- delivered power costs to us, and
- delivered power costs to our retail electric customers.
The financial impact of such proceedings, rulemaking, and trends are not
quantifiable currently. In addition, we are evaluating whether or not there may
be impacts on electric reliability associated with the outcomes of these various
transmission related proceedings. For example, in April 2004, Commomwealth
Edison Company received approval from the FERC to join into the PJM RTO
effective May 1, 2004. This integration could create different patterns of flow
and power within the Midwest area and affect adversely our ability to provide
reliable service to our customers.
August 14, 2003 Blackout: On August 14, 2003, the electric transmission grid
serving parts of the Midwest and the Northeast experienced a significant
disturbance that impacted electric service to millions of homes and businesses.
In December 2003, the MPSC issued an order requiring Michigan investor-owned
utilities to file reports by April 1, 2004, on the status of the transmission
and distribution lines used to serve their customers, including details on
vegetation trimming practices in calendar year 2003. We complied with the MPSC's
order.
In February 2004, the Board of Trustees of the NERC approved recommendations to
improve electric transmission reliability. In April 2004, the U.S. and Canadian
Power System Outage Task Force released its final report on the causes and
recommendations surrounding the blackout. The Task Force concluded that
inadequate assessment of voltage instability and vulnerability by First Energy;
inadequate
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Consumers Energy Company
communication between interconnected grid operators; and improper vegetation
management, outside of our operating territory, were the key causes of the
blackout. In addition to the NERC recommendations, the Task Force made 46
recommendations under the following captions:
- institutional issues,
- support for and strengthening of ongoing NERC initiatives,
- physical and cyber security of North American bulk power systems,
and
- Canadian nuclear power sector operating procedures.
Prompted by the Task Force findings, the MPSC issued an order requiring Michigan
utilities and transmission companies to submit a report concerning relay
settings on their systems by May 10, 2004. We intend to comply with the MPSC's
request. Also, the FERC issued a vegetation management order requiring entities
that own, operate, or control designated transmission facilities to report on
their vegetation management practices by June 17, 2004. As defined by this
particular FERC order, we have a limited amount of designated transmission
facilities for reporting purposes pursuant to this order, including a total of
six miles of high voltage lines located on or adjacent to some generating plant
properties.
Few of the recommendations above apply directly to us, since we are not a
transmission operator. However, the above recommendations could result in
increased transmission costs payable by transmission customers in the future and
upgrades to our distribution system. The financial impacts of these
recommendations are not quantifiable currently.
For additional details and material changes relating to the rate matters and
restructuring of the electric utility industry, see Note 2, Uncertainties,
"Electric Restructuring Matters," and "Electric Rate Matters."
FERC SUPPLY MARGIN ASSESSMENT: In April 2004, the FERC adopted two new market
power screens to assess generation market power and modified measures to
mitigate market power where it is found. The screens will apply to all initial
market-based rate applications and reviews on an interim basis, which occur
every three years. The effects of the modifications are not quantifiable
currently.
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. The standards relate to restoration
after an outage, safety, and customer relations. Financial incentives and
penalties are contained within the performance standards. An incentive is
possible if all of the established performance standards have been exceeded for
a calendar year. However, the performance standards do not contain an approved
incentive mechanism; therefore, the value of such an incentive cannot be
determined at this point. Financial penalties in the form of customer credits
are also possible. These customer credits are based on duration and repetition
of outages. Year-end results for both 2002 and 2003 resulted in compliance with
the acceptable level of performance as established by the approved standards. We
are a member of an industry coalition that has appealed the customer credit
portion of the performance standards to the Michigan Court of Appeals. We cannot
predict the likely effects of the financial incentive or penalties, if any, on
us, nor can we predict the outcome of the appeal.
For additional details on performance standards, see Note 2, Uncertainties,
"Electric Rate Matters -Performance Standards."
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Consumers Energy Company
GAS BUSINESS OUTLOOK
GROWTH: Over the next five years, we expect gas deliveries to grow at an average
rate of less than one percent per year. Actual gas deliveries in future periods
may be affected by:
- abnormal weather,
- use by independent power producers,
- competition in sales and delivery,
- Michigan economic conditions,
- gas consumption per customer, and
- increases in gas commodity prices.
In February 2004, we filed an application with the Michigan Public Service
Commission for a Certificate of public convenience and necessity for the
construction of a 25-mile gas transmission pipeline in northern Oakland County.
The project is necessary to meet peak load beginning in the winter of 2005
through 2006. If we are unable to construct the pipeline due to local
opposition, we will need to pursue more costly alternatives or possibly curtail
serving the system's load growth in that area.
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
net sales, revenues, or income from gas operations. The trends and uncertainties
include:
Environmental
- potential environmental remediation costs at a number of
sites, including sites formerly housing manufactured gas plant
facilities.
Regulatory
- inadequate regulatory response to applications for requested
rate increases, and
- response to increases in gas costs, including adverse
regulatory response and reduced gas use by customers,
Other
- potential rising pension costs due to market losses and lump
sum payments as discussed in the "Critical Accounting Policies
- Accounting for Pension and OPEB" within this MD&A,
- pipeline integrity maintenance and replacement costs, and
- pending other litigation.
We sell gas to retail customers under tariffs approved by the MPSC. These
tariffs measure the gas delivered to customers based on the volume (i.e. mcf) of
gas delivered. However, we purchase gas for resale on a Btu basis. The Btu
content of the gas available for purchase fluctuates and may result in customers
using less gas for the same heating requirement. We fully recover our cost to
purchase gas through the approved GCR. However, since the customer may use less
gas on a volumetric basis, the revenue from the distribution charge (the non-gas
cost portion of the customer bill) could be reduced. This could affect adversely
our gas utility earnings. The amount of any possible earnings loss due to
fluctuating btu content in future periods cannot be estimated at this time.
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Consumers Energy Company
In September 2002, the FERC issued an order rejecting our filing to assess
certain rates for non-physical gas title tracking services we offered. In
December 2003, the FERC ruled that no refunds were at issue and we reversed a $4
million reserve related to this matter. In January 2004, three companies filed
with the FERC for clarification or rehearing of the FERC's December 2003 order.
In April 2004, the FERC issued its Order Granting Clarification. In that Order,
the FERC indicated that its December 2003 order that stated no refunds are at
issue was in error. It directed us to file within 30 days a fair and equitable
title-tracking fee and to make refunds to customers with interest based on the
difference between the filed fee and the fee paid. We believe that with respect
to the FERC jurisdictional transportation, we have not charged any customers
title transfer fees, so no refunds will be required. We will make a filing
within the 30 days and cannot predict the outcome of this proceeding.
GAS ENVIRONMENTAL ESTIMATES: We expect to incur investigation and remedial
action costs at a number of sites, including 23 former manufactured gas plant
sites. We expect our remaining remedial action costs to be between $37 million
and $90 million. Any significant change in assumptions, such as remediation
techniques, nature and extent of contamination, and legal and regulatory
requirements, could change the remedial action costs for the sites. For
additional details, see Note 2, Uncertainties, "Gas Contingencies - Gas
Environmental Matters."
GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our gas costs; however, the MPSC reviews these costs
for prudency in an annual reconciliation proceeding. In January 2004, the MPSC
staff and intervenors filed direct testimony in our 2002-2003 GCR case proposing
GCR recovery disallowances. In 2003, we reserved $11 million for a settlement
agreement associated with the 2002-2003 GCR disallowance. Interest on the
disallowed amount from April 1, 2003 through February 2004, at Consumers'
authorized rate of return, increased the cost of the settlement by $1 million.
The interest was recorded as an expense in 2003. In February 2004, the parties
in the case reached a settlement agreement that resulted in a GCR disallowance
of $11 million for the GCR period. The settlement agreement was approved by the
MPSC in March 2004. For additional details, see Note 2, Uncertainties, "Gas Rate
Matters - Gas Cost Recovery."
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period of interim relief. The MPSC order allowed us to
increase our rates beginning December 19, 2003. As part of the interim rate
order, we agreed to restrict dividend payments to our parent company, CMS
Energy, to a maximum of $190 million annually during the period of the interim
relief. On March 5, 2004, the ALJ issued a Proposal for Decision recommending
that the MPSC not rely upon the projected test year data included in our filing
and supported by the MPSC Staff and further recommended that the application be
dismissed. In response to the Proposal for Decision, the parties have filed
exceptions and replies to exceptions. The MPSC is not bound by the ALJ's
recommendation and will review the exceptions and replies to exceptions prior to
issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order, which reduced book
depreciation expense and related income taxes only for the period that we
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Consumers Energy Company
receive the interim relief. The original filing was based on December 2000 plant
balances and historical data. The December 2003 filing updates the gas
depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, will result in an annual increase of $12
million in depreciation expense based on December 2002 plant balances. The ALJ's
Proposal for Decision is expected in May 2004.
OTHER OUTLOOK
CODE OF CONDUCT: In December 2000, the MPSC issued a new code of conduct that
applies to utilities and alternative electric suppliers. The code of conduct
seeks to prevent financial support, information sharing, and preferential
treatment between a utility's regulated and non-regulated services. The new code
of conduct is broadly written and could affect our:
- retail gas business energy related services,
- retail electric business energy related services,
- marketing of non-regulated services and equipment to Michigan
customers, and
- transfer pricing between our departments and affiliates.
We appealed the MPSC orders related to the code of conduct and sought a deferral
of the orders until the appeal was complete. We also sought waivers available
under the code of conduct to continue utility activities that provide
approximately $50 million in annual electric and gas revenues. In October 2002,
the MPSC denied waivers for three programs including the appliance service plan
offered by us, which generated $34 million in gas revenue in 2003. In March
2004, the Michigan Court of Appeals upheld the MPSC's implementation of the code
of conduct without modification. We filed an application for leave to appeal
with the Michigan Supreme Court, but we cannot predict whether the Michigan
Supreme Court will accept the case or the outcome of any appeal. In April 2004,
the Michigan Governor signed legislation that allows us to remain in the
appliance service business.
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 MCV Partnership estimates that the
decision will result in a refund of approximately $35 million in taxes plus $9
million of interest. The Michigan Tax Tribunal decision has been appealed to the
Michigan Court of Appeals by the City of Midland and the MCV Partnership has
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
2003 and expects to file an appeal contesting property taxes for 2004. The MCV
Partnership cannot predict the outcome of these proceedings; therefore, the
above refund has not been recognized in first quarter 2004 earnings.
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 United States Department of Justice.
Additionally, CMS Energy and Consumers are named as parties in various
litigation including a shareholder derivative lawsuit, a securities class action
lawsuit, and a class action lawsuit alleging ERISA violations. For additional
details regarding these investigations and litigation, see Note 2,
Uncertainties.
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Consumers Energy Company
NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.
We determined that 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. In addition, 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. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $718 million at March 31, 2004. Property, plant, and equipment serving
as collateral for these obligations have a carrying value of $1.471 billion at
March 31, 2004. The creditors of these partnerships do not have recourse to the
general credit of Consumers.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company obligated Trust Preferred
Securities totaling $490 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $506 million of long-term debt - related parties
and reflected an investment in related parties of $16 million.
We are not required to, and have not, restated prior periods for the impact of
this accounting change.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, ACCOUNTING AND DISCLOSURE
REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND
MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (Act), that was signed into law in December 2003,
establishes a prescription drug benefit under Medicare (Medicare Part D), and a
federal subsidy to sponsors of retiree health care benefit plans that provide a
benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003,
we elected a one-time deferral of the accounting for the Act, as permitted by
FASB Staff Position, No. SFAS 106-1.
Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No.
106-1 and provides further guidance for accounting for the Act. Proposed FASB
Staff Position, No. 106-b states that for plans that are actuarially equivalent
to Medicare Part D, employers' measures of accumulated postretirement benefit
obligations (APBO) and postretirement benefit costs should reflect the effects
of the Act.
As of March 31, 2004, we have not determined whether our postretirement benefit
plan is actuarially equivalent to Medicare Part D. Therefore, our measures of
APBO and net periodic postretirement benefit
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Consumers Energy Company
cost do not reflect any amount associated with the Medicare Prescription Drug,
Improvement, and Modernization Act of 2003. If our prescription drug plan is
determined to be actuarially equivalent to Medicare Part D, we estimate a
decrease in OPEB expense of approximately $20 million for 2004 and a one-time
reduction of our benefit obligation of approximately $140 million, to be
amortized over future periods. This Proposed FASB Staff Position would be
effective for the first interim or annual period beginning after June 15, 2004.
STATEMENT OF POSITION, ACCOUNTING FOR CERTAIN COSTS AND ACTIVITIES RELATED TO
PROPERTY, PLANT, AND EQUIPMENT: At its September 9, 2003 meeting, the Accounting
Standards Executive Committee, of the American Institute of Certified Public
Accountants voted to approve the Statement of Position, Accounting for Certain
Costs and Activities Related to Property, Plant, and Equipment. The Statement of
Position was presented to the FASB for clearance in April 2004. The FASB elected
not to clear this proposed Statement of Position.
CE-30
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF INCOME
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31 2004 2003
- -------- ------- -------
In Millions
OPERATING REVENUE $ 1,547 $ 1,442
EARNINGS FROM EQUITY METHOD INVESTEES - 16
OPERATING EXPENSES
Operation
Fuel for electric generation 154 80
Purchased power - related parties 16 132
Purchased and interchange power 50 82
Cost of gas sold 661 519
Cost of gas sold - related parties 3 25
Other 175 160
------- -------
1,059 998
------- -------
Maintenance 50 52
Depreciation, depletion and amortization 133 116
General taxes 62 59
------- -------
1,304 1,225
------- -------
OPERATING INCOME 243 233
OTHER INCOME (DEDUCTIONS)
Accretion expense (1) (2)
Other, net 13 (8)
------- -------
12 (10)
------- -------
INTEREST CHARGES
Interest on long-term debt 73 42
Interest on long-term debt - related parties 11 -
Other interest 3 5
Capitalized interest (2) (2)
------- -------
85 45
------- -------
INCOME BEFORE INCOME TAXES 170 178
INCOME TAXES 59 68
MINORITY INTERESTS 10 -
------- -------
NET INCOME 101 110
PREFERRED SECURITIES DISTRIBUTIONS - 11
------- -------
NET INCOME AVAILABLE TO COMMON STOCKHOLDER $ 101 $ 99
======= =======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-31
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
Three Months Ended
March 31 2004 2003
- -------- ----- -------
In Millions
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 101 $ 110
Adjustments to reconcile net income to net cash
provided by operating activities
Depreciation, depletion and amortization (includes nuclear
decommissioning of $1 and $2, respectively) 133 116
Capital lease and other amortization 7 4
Loss on CMS Energy stock - 12
Distributions from related parties less than earnings (16)
Changes in assets and liabilities:
Increase in accounts receivable and accrued revenue (334) (50)
Increase (decrease) in accounts payable (39) 4
Decrease in inventories 337 238
Deferred income taxes and investment tax credit 52 28
Changes in other assets and liabilities 6 (50)
----- -------
Net cash provided by operating activities $ 263 $ 396
----- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (excludes assets placed under capital lease) $(110) $ (114)
Cost to retire property (18) (18)
Restricted cash on hand (a) (1) (1)
Investments in Electric Restructuring Implementation Plan (2) (2)
Investments in nuclear decommissioning trust funds (1) (2)
Proceeds from nuclear decommissioning trust funds 20 6
Cash proceeds from sale of assets - 13
----- -------
Net cash used in investing activities $(112) $ (118)
----- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Proceeds from issuance of long term debt $ - $ 281
Retirement of long-term debt (7) (35)
Payment of common stock dividends (78) (78)
Preferred securities distributions - (11)
Payment of capital lease obligations (3) (3)
Decrease in notes payable, net - (205)
----- -------
Net cash used in financing activities $ (88) $ (51)
----- -------
Net Increase in Cash and Cash Equivalents $ 63 $ 227
Cash and Cash Equivalents from Effect of FIN 46R Consolidation 174 -
Cash and Cash Equivalents, Beginning of Period 46 244
----- -------
Cash and Cash Equivalents, End of Period (a) $ 283 $ 471
===== =======
CE-32
OTHER CASH FLOW ACTIVITIES AND NON-CASH INVESTING AND FINANCING ACTIVITIES WERE:
In Millions
2004 2003
------ ------
CASH TRANSACTIONS
Interest paid (net of amounts capitalized) $ 84 $ 61
Income taxes paid - 5
OPEB cash contribution 18 18
NON-CASH TRANSACTIONS
Other assets placed under capital lease 1 8
====== ======
(a) Cash and Cash Equivalents decreased $19 million for the three months ended
March 31, 2003 due to reflecting restricted cash as an investing activity
rather than classifying as a cash equivalent.
THE ACCOMPANYING NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-33
CONSUMERS ENERGY COMPANY
CONSOLIDATED BALANCE SHEETS
MARCH 31 MARCH 31
2004 DECEMBER 31 2003
ASSETS (UNAUDITED) 2003 (UNAUDITED)
----------- ----------- -----------
In Millions
PLANT (AT ORIGINAL COST)
Electric $ 7,698 $ 7,600 $ 7,356
Gas 2,891 2,875 2,787
Other 2,520 15 21
----------- ----------- -----------
13,109 10,490 10,164
Less accumulated depreciation, depletion and amortization 5,504 4,417 4,330
----------- ----------- -----------
7,605 6,073 5,834
Construction work-in-progress 392 375 487
----------- ----------- -----------
7,997 6,448 6,321
----------- ----------- -----------
INVESTMENTS
Stock of affiliates 21 20 10
First Midland Limited Partnership - 224 259
Midland Cogeneration Venture Limited Partnership - 419 405
Other 18 18 2
----------- ----------- -----------
39 681 676
----------- ----------- -----------
CURRENT ASSETS
Cash and cash equivalents at cost, which approximates market 283 46 471
Restricted cash 19 18 19
Accounts receivable, notes receivable and accrued revenue, less allowances
of $8, $8 and $5 respectively 626 257 279
Accounts receivable - related parties 12 4 15
Inventories at average cost
Gas in underground storage 418 739 256
Materials and supplies 75 70 74
Generating plant fuel stock 41 41 26
Deferred property taxes 161 143 117
Regulatory assets 19 19 19
Derivative instruments 118 14 -
Other 68 66 53
----------- ----------- -----------
1,840 1,417 1,329
----------- ----------- -----------
NON-CURRENT ASSETS
Regulatory Assets
Securitized costs 637 648 678
Postretirement benefits 156 162 180
Abandoned Midland Project 10 10 11
Other 303 266 233
Nuclear decommissioning trust funds 566 575 529
Prepaid pension costs 359 364 -
Other 352 174 199
----------- ----------- -----------
2,383 2,199 1,830
----------- ----------- -----------
TOTAL ASSETS $ 12,259 $ 10,745 $ 10,156
=========== =========== ===========
CE-34
MARCH 31 MARCH 31
2004 DECEMBER 31 2003
----------- ----------- -----------
In Millions
STOCKHOLDER'S EQUITY AND LIABILITIES (UNAUDITED) 2003 (UNAUDITED)
CAPITALIZATION
Common stockholder's equity
Common stock, authorized 125.0 shares; outstanding
84.1 shares for all periods $ 841 $ 841 $ 841
Paid-in capital 682 682 682
Accumulated other comprehensive income (loss) 25 17 (175)
Retained earnings since December 31, 1992 544 521 535
----------- ----------- -----------
2,092 2,061 1,883
Preferred stock 44 44 44
Company-obligated mandatorily redeemable preferred securities
of subsidiaries - - 490
Long-term debt 3,572 3,583 2,724
Long-term debt - related parties 506 506 -
Non-current portion of capital leases 329 58 121
----------- ----------- -----------
6,543 6,252 5,262
----------- ----------- -----------
MINORITY INTERESTS 682 - -
----------- ----------- -----------
CURRENT LIABILITIES
Current portion of long-term debt and capital leases 486 38 290
Notes payable - - 252
Notes payable - related parties 200 200 -
Accounts payable 169 200 252
Accrued taxes 175 209 161
Accounts payable - related parties 29 75 88
Current portion of purchase power contract 19 27 26
Deferred income taxes 37 33 29
Other 269 185 198
----------- ----------- -----------
1,384 967 1,296
----------- ----------- -----------
NON-CURRENT LIABILITIES
Deferred income taxes 1,281 1,233 961
Regulatory liabilities for cost of removal 1,005 983 937
Postretirement benefits 189 190 566
Regulatory liabilities for income taxes, net 317 312 311
Asset retirement obligations 399 358 364
Other regulatory liabilities 175 172 152
Deferred investment tax credit 84 85 89
Power purchase agreement - MCV Partnership - - 21
Other 200 193 197
----------- ----------- -----------
3,650 3,526 3,598
----------- ----------- -----------
COMMITMENTS AND CONTINGENCIES (Notes 1, 2, and 5)
TOTAL STOCKHOLDER'S EQUITY AND LIABILITIES $ 12,259 $ 10,745 $ 10,156
=========== =========== ===========
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
CE-35
CONSUMERS ENERGY COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY
(UNAUDITED)
THREE MONTHS ENDED
MARCH 31 2004 2003
- -------- ------ ------
In Millions
COMMON STOCK
At beginning and end of period (a) $ 841 $ 841
------ ------
OTHER PAID-IN CAPITAL
At beginning and end of period 682 682
------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
Minimum Pension Liability
At beginning and end of period - (185)
------ ------
Investments
At beginning of period 9 1
Unrealized gain on investments (b) 1 -
------ ------
At end of period 10 1
------ ------
Derivative Instruments
At beginning of period 8 5
Unrealized gain on derivative instruments (b) 9 7
Reclassification adjustments included in consolidated net (loss) (b) (2) (3)
------ ------
At end of period 15 9
------ ------
Total Accumulated Other Comprehensive Income (Loss) 25 (175)
------ ------
RETAINED EARNINGS
At beginning of period 521 545
Net Income 101 110
Cash dividends declared - Common Stock (78) (109)
Preferred securities distributions - (11)
------ ------
At end of period 544 535
------ ------
TOTAL COMMON STOCKHOLDER'S EQUITY $2,092 $1,883
====== ======
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(UNAUDITED) THREE MONTHS ENDED
MARCH 31 2004 2003
- ----------- ------ ------
(a)Number of shares of common stock outstanding was 84,108,789 for all periods
presented.
(b)Disclosure of Comprehensive Income:
Investments
Unrealized gain on investments, net of tax of
$-, and $-, respectively $ 1 $ -
Derivative Instruments
Unrealized gain on derivative instruments, net of tax
$4, and $4, respectively 9 7
Reclassification adjustments included in net income,
net of tax benefit $(1), and $(2), respectively (2) (3)
Net income 101 110
------ ------
Total Comprehensive Income $ 109 $ 114
====== ======
THE ACCOMPANYING CONDENSED NOTES ARE AN INTEGRAL PART OF THESE STATEMENTS.
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Consumers Energy Company
CONSUMERS ENERGY COMPANY
CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
These interim Consolidated Financial Statements have been prepared by Consumers
in accordance with accounting principles generally accepted in the United States
for interim financial information and with the instructions to Form 10-Q and
Article 10 of Regulation S-X. As such, certain information and footnote
disclosures normally included in 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, 2003. 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 is a subsidiary of CMS Energy, a holding company.
We are an electric and gas utility company that provides service to customers in
Michigan's Lower Peninsula. Our customers include a mix of residential,
commercial, and diversified industrial customers. The largest customer segment
is the automotive industry.
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. The primary beneficiary of a variable interest entity is
the party that absorbs or receives a majority of the entity's expected losses or
expected residual returns or both as a result of holding variable interests,
which are ownership, contractual, or other economic interests. As of and for the
quarter ended March 31, 2004, we determined that the MCV Partnership and the
FMLP should be consolidated in accordance with Revised FASB Interpretation No.
46. For additional details, see Note 7, Implementation of New Accounting
Standards. 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.
Intercompany transactions and balances have been eliminated.
USE OF ESTIMATES: We prepare our financial statements in conformity with
accounting principles generally accepted in the United States. 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 financial statements when
it is probable that a loss will be incurred in the future as a result of a
current event, and when the amount can be reasonably estimated. We have used
this accounting principle to record estimated liabilities as discussed in Note
2, Uncertainties.
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Consumers Energy Company
REVENUE RECOGNITION POLICY: We recognize revenues from deliveries of electricity
and natural gas, and the storage of natural gas when services are provided.
Sales taxes are recorded as liabilities and are not included in revenues.
CAPITALIZED INTEREST: We are required to capitalize interest on certain
qualifying assets that are undergoing activities to prepare them for their
intended use. Capitalization of interest for the period is limited to the actual
interest cost that is incurred. Our regulated businesses are permitted to
capitalize an allowance for funds used during construction on regulated
construction projects and to include such amounts in plant in service.
CASH EQUIVALENTS AND RESTRICTED CASH: All highly liquid investments with an
original maturity of three months or less are considered cash equivalents. At
March 31, 2004, our restricted cash on hand was $19 million. Restricted cash
primarily consists of cash dedicated for repayment of Securitization bonds. It
is classified as a current asset as the payments on the related Securitization
bonds occur within one year.
FINANCIAL INSTRUMENTS: We account for investments in debt and equity securities
using SFAS No. 115. Debt and equity securities can be classified into one of
three categories: held-to-maturity, trading, or available-for-sale. Our
investments in equity securities are classified as available-for-sale
securities. They are reported at fair value, with any unrealized gains or losses
resulting from changes in fair value reported in equity as part of accumulated
other comprehensive income and are excluded from earnings unless such changes in
fair value are determined to be other than temporary. Unrealized gains or losses
from changes in the fair value of our nuclear decommissioning investments are
reported as regulatory liabilities. The fair value of these investments is
determined from quoted market prices. Our debt securities are classified as
held-to-maturity securities and are reported at cost. For additional details
regarding financial instruments, see Note 4, Financial and Derivative
Instruments.
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 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. As
of March 31, 2004, we have recorded a liability to the DOE for $139 million,
including interest, which is payable upon the first delivery of spent nuclear
fuel to the DOE. The amount of this liability, excluding a portion of interest,
was recovered through electric rates. For additional details on disposal of
spent nuclear fuel, see Note 2, Uncertainties, "Other Electric Uncertainties -
Nuclear Matters."
PROPERTY, PLANT, AND EQUIPMENT: We record property, plant, and equipment at
original cost when placed into service. When regulated assets are retired, or
otherwise disposed of in the ordinary course of business, the original cost is
charged to accumulated depreciation and cost of removal, less salvage is
recorded as a regulatory liability. For additional details, see Note 6, Asset
Retirement Obligations. An allowance for funds used during construction is
capitalized on regulated construction projects. With respect to the retirement
or disposal of non-regulated assets, the resulting gains or losses are
recognized in income.
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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Consumers Energy Company
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 available to the common
stockholder of each segment. We operate principally in two segments: electric
utility and gas utility.
The electric utility segment consists of regulated activities associated with
the generation and distribution of electricity in the state of Michigan. The gas
utility segment consists of regulated activities associated with the
transportation, storage, and distribution of natural gas in the state of
Michigan.
Accounting policies of the segments are the same as we describe in the summary
of significant accounting policies. Our financial statements reflect the assets,
liabilities, revenues, and expenses directly related to the electric and gas
segment where it is appropriate. We allocate accounts between the electric and
gas segments where common accounts are attributable to both segments. The
allocations are based on certain measures of business activities, such as
revenue, labor dollars, customers, other operation and maintenance and
construction expense, leased property, taxes or functional surveys. For example,
customer receivables are allocated based on revenue. Pension provisions are
allocated based on labor dollars.
The following table shows our financial information by reportable segment. We
account for inter-segment sales and transfers at current market prices and
eliminate them in consolidated net income available to common stockholder by
segment. The "Other" segment includes our consolidated special purpose entity
for the sale of trade receivables and the variable interest entities the MCV
Partnership and the FMLP. We consolidated the MCV Partnership and the FMLP into
our consolidated financial statements for the first time as of and for the
quarter ended March 31, 2004. For additional details, see Note 7, Implementation
of New Accounting Standards.
In Millions
- --------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- --------------------------- ------- -------
Operating revenue
Electric $ 631 $ 653
Gas 905 789
Other 11 -
------- -------
Total Operating Revenue $ 1,547 $ 1,442
======= =======
Net income available to common stockholder
Electric $ 45 $ 51
Gas 55 54
Other 1 (6)
------- -------
Total Net Income $ 101 $ 99
======= =======
UTILITY REGULATION: We account for the effects of regulation based on the
regulated utility accounting standard SFAS No. 71. As a result, the actions of
regulators affect when we recognize revenues, expenses, assets, and liabilities.
SFAS No. 144 imposes strict criteria for retention of regulatory-created assets
by requiring that such assets be probable of future recovery at each balance
sheet date. Management believes these assets are probable of future recovery.
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Consumers Energy Company
2: UNCERTAINTIES
Several business trends or uncertainties may affect our financial results and
condition. These trends or uncertainties have, or we expect could have, a
material impact on revenues or income from continuing electric and gas
operations. Such trends and uncertainties include:
Environmental
- increased capital expenditures and operating expenses for
Clean Air Act compliance, and
- potential environmental liabilities arising from various
environmental laws and regulations, including potential
liability or expenses relating to the Michigan Natural
Resources and Environmental Protection Acts, Superfund, and at
former manufactured gas plant facilities.
Restructuring
- response of the MPSC and Michigan legislature to electric
industry restructuring issues,
- ability to meet peak electric demand requirements at a
reasonable cost, without market disruption,
- ability to recover any of our net Stranded Costs under the
regulatory policies being followed by the MPSC,
- recovery of electric restructuring implementation costs,
- effects of lost electric supply load to alternative electric
suppliers, and
- status as an electric transmission customer, instead of an
electric transmission owner-operator.
Regulatory
- effects of potential performance standards payments,
- successful implementation of initiatives to reduce exposure to
purchased power price increases,
- recovery of nuclear decommissioning costs,
- responses from regulators regarding the storage and ultimate
disposal of spent nuclear fuel,
- inadequate regulatory response to applications for requested
rate increases, and
- response to increases in gas costs, including adverse
regulatory response and reduced gas use by customers.
Other
- pending litigation regarding PURPA qualifying facilities, and
- pending other litigation.
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 has implemented the
recommendations of the Special Committee.
CMS Energy is cooperating with an investigation by the DOJ concerning round-trip
trading. CMS Energy is unable to predict the outcome of this matter and what
effect, if any, this investigation will have
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Consumers Energy Company
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.
SECURITIES CLASS ACTION LAWSUITS: Beginning on May 17, 2002, a number of
securities class action complaints were filed against CMS Energy, Consumers, and
certain officers and directors of CMS Energy and its affiliates. 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. The cases were
consolidated into a single lawsuit and an amended and consolidated class action
complaint was filed on May 1, 2003. The consolidated complaint contains a
purported class period beginning on May 1, 2000 and running through March 31,
2003. It 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. The judge issued an opinion
and order dated March 31, 2004 in connection with various pending motions,
including plaintiffs' motion to amend the complaint and the motions to dismiss
the complaint filed by CMS Energy, Consumers and other defendants. The judge
directed plaintiffs to file an amended complaint under seal and ordered an
expedited hearing on the motion to amend. Based on his decision with respect to
the motion to amend, the judge dismissed certain of plaintiffs' claims without
prejudice and denied without prejudice the motions to dismiss other claims. The
judge will permit CMS Energy and its other defendants to renew the motions to
dismiss at or shortly after the hearing on the motion to amend. CMS Energy,
Consumers, and their affiliates will defend themselves vigorously but cannot
predict the outcome of this litigation.
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. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants are now
required to file answers to the amended complaint on or before May 14, 2004. CMS
Energy and Consumers will defend themselves vigorously but cannot predict the
outcome of this litigation.
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: In 1998, the EPA issued regulations requiring the state of Michigan
to further limit nitrogen oxide emissions at our coal-fired electric plants. The
Michigan Department of Environmental Quality finalized its rules to comply with
the EPA regulations in December 2002. The EPA's conditional approval of the
Michigan rules was published in April 2004. The Michigan Department of
Environmental Quality is currently correcting deficiencies in its rules that
were identified by the EPA. If
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Consumers Energy Company
the Department of Environmental Quality fails to submit satisfactory revisions
to the EPA by the end of May 2004, the EPA's conditional approval will
automatically revert to a disapproval, and similar federal regulations will take
effect.
The EPA and the state regulations require us to make significant capital
expenditures estimated to be $771 million. As of March 31, 2004, we have
incurred $469 million in capital expenditures to comply with the EPA regulations
and anticipate that the remaining $302 million of capital expenditures will be
made between 2004 and 2009. These expenditures include installing catalytic
reduction technology on some of our coal-fired electric plants. Based on the
Customer Choice Act, beginning January 2004, an annual return of and on these
types of capital expenditures, to the extent they are above depreciation levels,
is expected to be recoverable from customers, subject to the MPSC prudency
hearing.
The EPA has alleged that some utilities have incorrectly classified plant
modifications as "routine maintenance" rather than seek 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.
In addition to modifying the coal-fired electric plants, we expect to purchase
nitrogen oxide emissions credits for years 2004 through 2008. The cost of these
credits is estimated to average $8 million per year and is accounted for as
inventory. The credit inventory is expensed as the coal-fired electric plants
generate electricity. The price for nitrogen oxide emissions credits is volatile
and could change substantially.
The EPA recently proposed the Clean Air Act Interstate Air Quality Rule, which
requires additional coal-fired electric plant emission controls for nitrogen
oxides and sulfur dioxide. If implemented, this rule would potentially require
expenditures equivalent to those efforts in progress required to reduce nitrogen
oxide emissions under the Title I provisions of the Clean Air Act. The rule
proposes a two-phase program to reduce emissions of sulfur dioxide by 70 percent
and nitrogen oxides by 65 percent by 2015, through the installation of flue gas
desulfurization scrubbers and selective catalytic reduction units. Additionally,
the EPA also proposed two alternative sets of rules to reduce emissions of
mercury and nickel from coal-fired and oil-fired electric plants. Until the
proposed environmental rules are finalized, an accurate cost of compliance
cannot be determined.
Several bills have been introduced in the United States Congress that would
require carbon dioxide emissions reduction. We cannot predict whether any
federal mandatory carbon dioxide emissions reduction rules ultimately will be
enacted, or the specific requirements of any such rules if they were to become
law.
To the extent that emissions reduction rules come into legal effect, such
mandatory emissions reduction requirements could have far-reaching and
significant implications for the energy sectors. We cannot estimate the
potential effect of United States federal or state level greenhouse gas policy
on future consolidated results of operations, cash flows or financial position
due to the speculative nature of the policy. 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.
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Consumers Energy Company
Water: In March 2004, the EPA changed the 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 by 2006. We are studying the rules to determine the most cost-effective
solutions for compliance.
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. As of March 31, 2004, 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.
LITIGATION: In October 2003, a group of eight PURPA qualifying facilities
selling 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. More specifically, the
lawsuit alleges that we should be basing the energy charge calculation on the
cost of more expensive eastern coal, rather than on the cost of the coal
actually burned by us for use in our coal-fired generating plants. We believe we
have been performing the calculation in the manner prescribed by the power
purchase agreements, and have filed a request with the MPSC (as a supplement to
the PSCR plan) that asks the MPSC to review this issue and to confirm that our
method of performing the calculation is correct. We filed a motion to dismiss
the lawsuit in the Ingham County Circuit Court due to the pending request at the
MPSC concerning the PSCR plan case. In February 2004, the judge ruled on the
motion and deferred to the primary jurisdiction of the MPSC. This ruling
resulted in a dismissal of the circuit court case without prejudice. Although
only eight qualifying facilities have raised the issue, the same energy charge
methodology is used in the PPA with the MCV Partnership and in approximately 20
additional power purchase agreements with us, representing a total of 1,670 MW
of electric capacity. We cannot predict the outcome of this matter.
ELECTRIC RESTRUCTURING MATTERS
ELECTRIC RESTRUCTURING LEGISLATION: The Michigan legislature passed electric
utility restructuring legislation known as the Customer Choice Act. This act:
- allows all customers to choose their electric generation supplier
effective January 1, 2002,
- provides a one-time five percent residential electric rate
reduction,
- froze all electric rates through December 31, 2003, and established
a rate cap for residential customers through at least December 31,
2005, and a rate cap for small commercial and industrial customers
through at least December 31, 2004,
- allows deferred recovery of an annual return of and on capital
expenditures in excess of depreciation levels incurred during and
before the rate freeze-cap period,
- allows for the use of Securitization bonds to refinance qualified
costs,
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Consumers Energy Company
- allows recovery of net Stranded Costs and implementation costs
incurred as a result of the passage of the act,
- requires Michigan utilities to join a FERC-approved RTO or sell
their interest in transmission facilities to an independent
transmission owner,
- requires Consumers, Detroit Edison, and AEP to jointly expand their
available transmission capability by at least 2,000 MW, and
- establishes a market power supply test that, if not met, may require
transferring control of generation resources in excess of that
required to serve retail sales requirements.
The following summarizes our status under the last three provisions of the
Customer Choice Act. First, we chose to sell our interest in our transmission
facilities to an independent transmission owner in order to comply with the
Customer Choice Act; for additional details regarding the sale of the
transmission facility, see "Transmission Sale" within this section. Second, in
July 2002, the MPSC issued an order approving our plan to achieve the increased
transmission capacity required under the Customer Choice Act. We have completed
the transmission capacity projects identified in the plan and have submitted
verification of this fact to the MPSC. We believe we are in full compliance.
Lastly, in September 2003, the MPSC issued an order finding that we are in
compliance with the market power supply test set forth in the Customer Choice
Act.
ELECTRIC ROA: The MPSC approved revised tariffs that establish the rates, terms,
and conditions under which retail customers are permitted to choose an electric
supplier. These revised tariffs allow ROA customers, upon as little as 30 days
notice to us, to return to our generation service at current tariff rates. If
any class of customers' (residential, commercial, or industrial) ROA load
reaches ten percent of our total load for that class of customers, then
returning ROA customers for that class must give 60 days notice to return to our
generation service at current tariff rates. However, we may not have capacity
available to serve returning ROA customers that is sufficient or reasonably
priced. As a result, we may be forced to purchase electricity on the spot market
at higher prices than we can recover from our customers during the rate cap
periods.
We cannot predict the total amount of electric supply load that may be lost to
competitor suppliers. As of April 2004, alternative electric suppliers are
providing 823 MW of load. This amount represents 10 percent of the total
distribution load and an increase of 50 percent compared to April 2003.
ELECTRIC RESTRUCTURING PROCEEDINGS: Below is a discussion of our electric
restructuring proceedings. They are:
- Securitization,
- Stranded Costs,
- implementation costs, and
- transmission.
Securitization: The Customer Choice Act allows for the use of Securitization
bonds to refinance certain qualified costs. Since Securitization involves
issuing bonds secured by a revenue stream from rates collected directly from
customers to service the bonds, Securitization bonds typically have a higher
credit rating than conventional utility corporate financing. In 2000 and 2001,
the MPSC issued orders authorizing us to issue Securitization bonds. We issued
our first Securitization bonds in late 2001. Securitization resulted in:
- lower interest costs, and
- longer amortization periods for the securitized assets.
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Consumers Energy Company
We will recover the repayment of principal, interest, and other expenses
relating to the bond issuance through a Securitization charge and a tax charge
that began in December 2001. These charges are subject to an annual true up
until one year before the last scheduled bond maturity date, and no more than
quarterly thereafter. The December 2003 true up modified the total
Securitization and related tax charges from 1.746 mills per kWh to 1.718 mills
per kWh. There will be no impact on customer bills from Securitization for most
of our electric customers until the Customer Choice Act cap period expires, and
an electric rate case is processed. Securitization charge collections, $13
million for the three months ended March 31, 2004, and $13 million for the three
months ended March 31, 2003, are remitted to a trustee. Securitization charge
collections are restricted to the repayment of the principal and interest on the
Securitization bonds and payment of the ongoing expenses of Consumers Funding.
Consumers Funding is legally separate from Consumers. The assets and income of
Consumers Funding, including the securitized property, are not available to
creditors of Consumers or CMS Energy.
In March 2003, we filed an application with the MPSC seeking approval to issue
additional Securitization bonds. In June 2003, the MPSC issued a financing order
authorizing the issuance of Securitization bonds in the amount of $554 million.
This amount relates to Clean Air Act expenditures and associated return on those
expenditures through December 31, 2002; ROA implementation costs, and previously
authorized return on those expenditures through December 31, 2000; and other up
front qualified costs related to issuance of the Securitization bonds. In July
2003, we filed for rehearing and clarification on a number of features in the
financing order.
In December 2003, the MPSC issued its order on rehearing, which rejected our
requests for clarification and modification to the dividend payment restriction,
failed to rule directly on the accounting clarifications requested, and remanded
the proceeding to the ALJ for additional proceedings to address rate design. The
ALJ completed hearings in March 2004 and the MPSC decision is not anticipated
before May 2004, but could be later. The financing order will become effective
after our acceptance of a favorable MPSC order. Bonds will not be issued until
resolution of any appeals.
Stranded Costs: The Customer Choice Act allows electric utilities to recover
their net Stranded Costs, without defining the term. The Act directs the MPSC to
establish a method of calculating net Stranded Costs and of conducting related
true-up adjustments. In December 2001, the MPSC Staff recommended a methodology,
which calculated net Stranded Costs as the shortfall between:
- the revenue required to cover the costs associated with fixed
generation assets and capacity payments associated with purchase
power agreements, and
- the revenues received from customers under existing rates available
to cover the revenue requirement.
The MPSC authorizes us to use deferred accounting to recognize the future
recovery of costs determined to be stranded. According to the MPSC, net Stranded
Costs are to be recovered from ROA customers through a Stranded Cost transition
charge. However, the MPSC has not yet allowed such a transition charge. As a
result, we have not recorded regulatory assets to recognize the future recovery
of such costs.
In 2002 and 2001, the MPSC issued orders finding that we experienced zero net
Stranded Costs from 1999 to 2001. The MPSC also declined to resolve numerous
issues regarding the net Stranded Cost methodology in a way that would allow a
reliable prediction of the level of Stranded Costs for future years. We are
currently in the process of appealing these orders with the Michigan Court of
Appeals and the Michigan Supreme Court.
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Consumers Energy Company
In March 2003, we filed an application with the MPSC seeking approval of net
Stranded Costs incurred in 2002 and for approval of a net Stranded Cost recovery
charge. Our net Stranded Costs incurred in 2002, including the cost of money,
are estimated to be $47 million with the issuance of Securitization bonds that
include Clean Air Act investments, or $104 million without the issuance of
Securitization bonds that include Clean Air Act investments. The MPSC scheduled
hearings for our 2002 Stranded Cost application to take place during the second
quarter of 2004. Once a final financing order on Securitization is reached, we
will know the amount of our request for net Stranded Cost recovery for 2002.
In February 2004, the MPSC issued an order on Detroit Edison's request for rate
relief for costs associated with customers leaving under electric customer
choice. The MPSC order allows Detroit Edison to charge a transition surcharge to
ROA customers and eliminates Securitization charge offsets. In April 2004, we
filed an application with the MPSC seeking approval of net Stranded Costs
incurred in 2003, including the cost of money, in the amount of $106 million
with the issuance of Securitization bonds that include Clean Air Act
investments, or $165 million without the issuance of Securitization bonds that
include Clean Air Act investments. Similar to the request that was granted by
the MPSC for Detroit Edison, we also requested interim relief for 2002 and 2003
net Stranded Costs.
We cannot predict whether the Stranded Cost recovery method adopted by the MPSC
will be applied in a manner that will fully offset any associated margin loss
from ROA.
Implementation Costs: The Customer Choice Act allows electric utilities to
recover their implementation costs. The following table outlines the
applications filed by us with the MPSC and the status of recovery for these
costs.
In Millions
- ----------------------------------------------------------------------------------
Year Filed Year Incurred Requested Pending Allowed Disallowed
- ---------- ------------- --------- ------- ------- -----------
1999 1997 & 1998 $ 20 $ - $ 15 $ 5
2000 1999 30 - 25 5
2001 2000 25 - 20 5
2002 2001 8 - 8 -
2003 & 2004 (a) 2002 7 7 Pending Pending
2004 2003 1 1 Pending Pending
============= ========= ======= ======= ===========
(a) On March 31, 2004, we requested additional 2002 implementation cost recovery
of $5 million related to our former participation in the development of the
Alliance RTO. This cost has been expensed; therefore, the amount is not included
as a regulatory asset.
The MPSC disallowed certain costs, determining that these amounts did not
represent costs incremental to costs already reflected in electric rates. In the
order received for the year 2001, the MPSC also reserved the right to reevaluate
the implementation costs depending upon the progress and success of the ROA
program, and ruled that due to the rate freeze imposed by the Customer Choice
Act, it was premature to establish a cost recovery method for the allowable
implementation costs. In addition to the amounts shown above, we incurred and
deferred as a regulatory asset, as of March 31, 2004, $23 million for the cost
of money associated with total implementation costs. We believe the
implementation costs and associated cost of money are fully recoverable in
accordance with the Customer Choice Act. We expect cash recovery from customers
to begin after rate cap periods expire. The rate cap expired for large
commercial and industrial customers on December 31, 2003.
In April 2004, the Michigan Court of Appeals ruled that the MPSC's decision
finding that the recovery of 1999 implementation costs is conditional and
subject to later disallowance is unlawful. The case was remanded to the MPSC.
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The MPSC issued an order regarding the remanded proceeding that directed us to
choose whether we prefer to recover our approved implementation costs through
Securitization pursuant to the MPSC's final order in the Securitization
proceeding or whether we would prefer to have recovery controlled by the remand
proceeding. If the latter option was chosen, the MPSC indicated that it intended
to authorize recovery of such implementation costs through the use of surcharges
on all customer classes that coincide with the expiration of the Customer Choice
Act rate caps. We chose recovery of the approved implementation costs through
the use of surcharges and withdrew our request for approved implementation costs
recovery from our Securitization proposal. The implementation costs withdrawn
from the Securitization case were incurred for the years 1998 through 2000. In
the filing we made electing recovery through separate surcharges, we requested
approval of surcharges that would allow recovery of implementation costs
incurred for the years 1998 through 2001. We requested that the Court of Appeals
issue similar remand orders with respect to appeals of the MPSC orders
addressing 2000 and 2001 implementation costs. We cannot predict the amounts the
MPSC will approve as recoverable costs.
Also, we are pursuing authorization at the FERC for the MISO to reimburse us for
$8 million in certain electric utility restructuring implementation costs
related to our former participation in the development of the Alliance RTO, a
portion of which has been expensed. The FERC issued an order denying the MISO's
request for authorization to reimburse us and we are in the process of appealing
the FERC ruling at the United States Court of Appeals for the District of
Columbia. We also requested that the MISO seek authorization to reimburse METC
for these development costs. The MISO filed this request but the FERC denied it.
While we appeal the FERC's orders, we are also pursuing other potential means of
recovery, such as recovery of Alliance RTO development costs at the MPSC. We
cannot predict the outcome of the appeal process or the ultimate amount, if any,
we will collect for Alliance RTO development costs.
Security Costs: The Customer Choice Act allows for recovery of new and enhanced
security costs, as a result of federal and state regulatory security
requirements. All retail customers, except customers of alternative electric
suppliers, would pay these charges. In April 2004, we filed a security cost
recovery case with the MPSC for $25 million of cost that regulatory treatment
has not yet been granted through other means. The costs are for enhanced
security and insurance because of federal and state regulatory security
requirements imposed after the September 11, 2001 terrorist attacks. We cannot
predict how the MPSC will rule on our requests for the recoverability of
security costs.
Transmission Rates: Our application of JOATT transmission rates to customers
during past periods is under FERC review. The rates included in these tariffs
were applied to certain transmission transactions affecting both Detroit
Edison's and our transmission systems between 1997 and 2002. We believe our
reserve is sufficient to satisfy our refund obligation to any of our former
transmission customers under our former JOATT.
TRANSMISSION SALE: In May 2002, we sold our electric transmission system for
$290 million to MTH, a non-affiliated limited partnership whose general partner
is a subsidiary of Trans-Elect, Inc. The pretax gain was $31 million ($26
million, net of tax). We are currently in arbitration with MTH regarding
property tax items used in establishing the selling price of our electric
transmission system. We cannot predict whether remaining open items will affect
materially the recorded gain on the sale. As a result of the sale, after-tax
earnings have decreased due to a loss of revenue from wholesale and ROA
customers who will buy services directly from MTH.
METC has completed the capital program to expand the transmission system's
capability to import electricity into Michigan, as required by the Customer
Choice Act. We will continue to maintain the system until May 1, 2007 under a
contract with METC.
Under an agreement with MTH, our transmission rates are fixed by contract at
current levels through December 31, 2005, and are subject to the FERC ratemaking
thereafter. However, we are subject to certain additional MISO surcharges,
which we estimate to be $15 million in 2004.
ELECTRIC RATE MATTERS
PERFORMANCE STANDARDS: Electric distribution performance standards developed by
the MPSC became effective in February 2004. They relate to restoration after an
outage, safety, and customer relations. During 2002 and 2003, we monitored and
reported to the MPSC our performance relative to the performance standards.
Year-end results for both 2002 and 2003 resulted in compliance with the
acceptable level of performance as established by the approved standards.
Financial incentives and penalties are contained within the performance
standards. An incentive is possible if all of the established performance
standards have been exceeded for a calendar year. However, the performance
standards do not contain an approved incentive mechanism; therefore, the value
of such incentive cannot be determined at this point. Financial penalties in the
form of customer credits are also possible. These customer credits are based on
duration and repetition of outages. We are a member of an industry coalition
that has appealed the customer credit portion of the performance
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standards to the Michigan Court of Appeals. We cannot predict the likely effects
of the financial incentive or penalties, if any, on us, nor can we predict the
outcome of the appeal.
POWER SUPPLY COSTS: We were required to provide backup service to ROA customers
on a best efforts basis. In October 2003, we provided notice to the MPSC that we
would terminate the provision of backup service in accordance with the Customer
Choice Act, effective January 1, 2004.
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
call options and capacity and energy contracts for the physical delivery of
electricity primarily in the summer months and to a lesser degree in the winter
months. As of March 31, 2004, we purchased capacity and energy contracts
partially covering the estimated reserve margin requirements for 2004 through
2007. As a result, we have recognized an asset of $19 million for unexpired
capacity and energy contracts. On March 31, 2004, we filed a summer assessment
for meeting 2004 peak load demand as required by the MPSC, stating that our
summer 2004 reserve margin target is 11 percent or supply resources equal to 111
percent of projected summer peak load. Presently, we have a reserve margin of 12
percent, or supply resources equal to 112 percent of projected summer peak load
for summer 2004. Of the 112 percent, approximately 103 percent is from owned
electric generating plants and long-term contracts, and approximately 9 percent
is from short-term contracts. This reserve margin met our summer 2004 reserve
margin target. The total premium costs of electricity call options and capacity
and energy contracts for 2004 is expected to be approximately $9 million, as of
April 30, 2004.
As a result of meeting the transmission capability expansion requirements and
the market power test, as discussed in this Note, we have met the requirements
under the Customer Choice Act to return to the PSCR process. The PSCR process
provides for the reconciliation of actual power supply costs with power supply
revenues. This process assures recovery of all reasonable and prudent power
supply costs actually incurred by us. In September 2003, we submitted a PSCR
filing to the MPSC that reinstates the PSCR process for customers whose rates
are no longer frozen or capped as of January 1, 2004. The proposed PSCR charge
allows us to recover a portion of our increased power supply costs from large
commercial and industrial customers, and subject to the overall rate caps, from
other customers. We estimate the recovery of increased power supply costs from
large commercial and industrial customers to be approximately $30 million in
2004. As allowed under current regulation, we self-implemented the proposed PSCR
charge on January 1, 2004. The revenues received from the PSCR charge are also
subject to subsequent reconciliation at the end of the year after actual costs
have been reviewed for reasonableness and prudence. We cannot predict the
outcome of this filing.
OTHER ELECTRIC UNCERTAINTIES
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 and to supply electricity and steam to Dow. We hold,
through two wholly owned subsidiaries, the following assets related to the MCV
Partnership and the MCV Facility:
- CMS Midland owns a 49 percent general partnership interest in the
MCV Partnership, and
- CMS Holdings holds, through the FMLP, a 35 percent lessor interest
in the MCV Facility.
Our consolidated retained earnings include undistributed earnings from the MCV
Partnership, which at March 31, 2004 are $248 million and at March 31, 2003 are
$233 million.
The MCV Partnership and the FMLP are variable interest entities and Consumers
was determined to be the primary beneficiary. Therefore, we have consolidated
the MCV Partnership and the FMLP into our
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consolidated financial statements for the first time as of and for the quarter
ended March 31, 2004. For additional details, see Note 7, Implementation of New
Accounting Standards.
Power Supply Purchases from the MCV Partnership: Our annual obligation to
purchase capacity from the MCV Partnership is 1,240 MW through the term of the
PPA ending in 2025. The PPA requires us to pay, based on the MCV Facility's
availability, a levelized average capacity charge of 3.77 cents per kWh and a
fixed energy charge. We also pay a variable energy charge based on our average
cost of coal consumed for all kWh delivered. Effective January 1999, we reached
a settlement agreement with the MCV Partnership that capped payments made on the
basis of availability that may be billed by the MCV Partnership at a maximum
98.5 percent availability level.
Since January 1993, the MPSC has permitted us to recover capacity charges
averaging 3.62 cents per kWh for 915 MW, plus fixed and variable energy charges.
Since January 1996, the MPSC has also permitted us to recover capacity charges
for the remaining 325 MW of contract capacity with an initial average charge of
2.86 cents per kWh increasing periodically to an eventual 3.62 cents per kWh by
2004 and thereafter. However, due to the frozen retail rates required by the
Customer Choice Act, the capacity charge for the 325 MW was frozen at 3.17 cents
per kWh until December 31, 2003. Recovery of both the 915 MW and 325 MW portions
of the PPA are subject to certain limitations discussed below.
In 1992, we recognized a loss and established a liability for the present value
of the estimated future underrecoveries of power supply costs under the PPA
based on the MPSC cost-recovery orders. The remaining liability associated with
the loss totaled $19 million at March 31, 2004 and $47 million at March 31,
2003. We expect the PPA liability to be depleted in late 2004.
We estimate that 51 percent of the actual cash underrecoveries for 2004 will be
charged to the PPA liability, with the remaining portion charged to operating
expense as a result of our 49 percent ownership in the MCV Partnership. We will
expense all cash underrecoveries directly to income once the PPA liability is
depleted. If the MCV Facility's generating availability remains at the maximum
98.5 percent level, our cash underrecoveries associated with the PPA could be as
follows:
In Millions
- -------------------------------------------------------------------------------
2004 2005 2006 2007
---- ---- ---- ----
Estimated cash underrecoveries at 98.5% $ 56 $ 56 $ 55 $ 39
Amount to be charged to operating expense 29 56 55 39
Amount to be charged to PPA liability 27 - - -
==== ==== ==== ====
Beginning January 1, 2004, the rate freeze for large industrial customers was no
longer in effect and we returned to the PSCR process. Under the PSCR process, we
will recover from our customers the approved capacity and fixed energy charges
based on availability, up to an availability cap of 88.7 percent as established
in previous MPSC orders.
Effects on Our Ownership Interest in the MCV Partnership and the MCV Facility:
As a result of returning to the PSCR process, we returned to dispatching the MCV
Facility on a fixed load basis, as permitted by the MPSC, in order to maximize
recovery of our capacity and fixed energy payments. This fixed load dispatch
increases the MCV Facility's output and electricity production costs, such as
natural gas. As the spread between the MCV Facility's variable electricity
production costs and its energy payment revenue widens, the MCV's Partnership's
financial performance and investment in the MCV Partnership is and will be
harmed.
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Under the 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. Because natural gas prices have increased
substantially in recent years, while the price the MCV Partnership can charge us
for energy has not, the MCV Partnership's financial performance has been
impacted negatively.
Until September 2007, the PPA and settlement agreement require us to pay
capacity and fixed energy charges based on the MCV Facility's actual
availability up to the 98.5 percent cap. After September 2007, we expect to
claim relief under the regulatory out provision in the PPA, limiting our
capacity and fixed energy payments to the MCV Partnership to the amount
collected from our customers. The MPSC's future actions on the capacity and
fixed energy payments recoverable from customers subsequent to September 2007
may affect negatively the earnings of the MCV Partnership and the value of our
investment in the MCV Partnership.
In February 2004, we filed a resource conservation plan with the MPSC that is
intended to help conserve natural gas and thereby improve our investment in the
MCV Partnership. This plan seeks approval to:
- dispatch the MCV Facility based on natural gas market prices without
increased costs to electric customers,
- give Consumers a priority right to buy excess natural gas as a
result of the reduced dispatch of the MCV Facility, and
- fund $5 million annually for renewable energy sources such as wind
power projects.
The resource conservation plan will reduce the MCV Facility's annual natural gas
consumption by an estimated 30 to 40 billion cubic feet. This decrease in the
quantity of high-priced natural gas consumed by the MCV Facility will benefit
Consumers' ownership interest in the MCV Partnership. The amount of PPA capacity
and fixed energy payments recovered from retail electric customers would remain
capped at 88.7 percent. Therefore, customers will not be charged for any
increased power supply costs, if they occur. Consumers and the MCV Partnership
have reached an agreement that the MCV Partnership will reimburse Consumers for
any incremental power costs incurred to replace the reduction in power
dispatched from the MCV Facility. In April 2004, the presiding ALJ at the MPSC
held a pre-hearing conference regarding the resource conservation plan. The ALJ
denied our request to establish a schedule that would have allowed consideration
of the plan on an interim basis and established schedule that calls for a
Proposal for Decision in September 2004 after which point the MPSC would
consider the plan. We cannot predict if or when the MPSC will approve our
resource conservation plan.
The two most significant variables in the analysis of the MCV Partnership's
future financial performance are the forward price of natural gas for the next
22 years and the MPSC's decision in 2007 or beyond on limiting our recovery of
capacity and fixed energy payments. Natural gas prices have been volatile
historically. Presently, there is no consensus in the marketplace on the price
or range of prices of natural gas in the short term or beyond the next five
years. Even with an approved resource conservation plan, if gas prices continue
at present levels or increase, the economics of operating the MCV Facility may
be adverse enough to require us to recognize an impairment of our investment in
the MCV Partnership. We presently cannot predict the impact of these issues on
our future earnings, cash flows, or on the value of our investment in the MCV
Partnership.
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 MCV Partnership estimates that the
decision will result in a refund of approximately $35 million in taxes
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plus $9 million of interest. The Michigan Tax Tribunal decision has been
appealed to the Michigan Court of Appeals by the City of Midland and the MCV
Partnership has file 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 2003 and expects to file an appeal contesting property taxes for
2004. The MCV Partnership cannot predict the outcome of these proceedings;
therefore, the above refund has not been recognized in first quarter 2004
earnings.
NUCLEAR PLANT DECOMMISSIONING: Our site-specific decommissioning cost estimates
for Big Rock and Palisades assume that each plant site will eventually be
restored to conform to the adjacent landscape and all contaminated equipment
will be disassembled and disposed of in a licensed burial facility.
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 each plant 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 being decommissioned,
the estimated cost includes historical expenditures in nominal dollars and
future costs in 2003 dollars, with all Palisades costs given in 2003 dollars.
In 1999, the MPSC orders for Big Rock and Palisades provided for fully funding
the decommissioning trust funds for both sites. In December 2000, funding of the
Big Rock trust fund stopped because the MPSC-authorized decommissioning
surcharge collection period expired. The MPSC order set the annual
decommissioning surcharge for Palisades at $6 million through 2007. Amounts
collected from electric retail customers and deposited in trusts, including
trust earnings, are credited to a regulatory liability.
However, based on current projections, the current levels of funds provided by
the trusts are not adequate to fully fund the decommissioning of Big Rock or
Palisades. This is due in part to the DOE's failure to accept the spent nuclear
fuel and lower returns on the trust funds. We are attempting to recover our
additional costs for storing spent nuclear fuel through litigation, as discussed
in "Nuclear Matters" within this section. We will also seek additional relief
from the MPSC.
In the case of Big Rock, excluding the additional nuclear fuel storage costs due
to the DOE's failure to accept this spent fuel on schedule, we are currently
projecting that the level of funds provided by the trust will fall short of the
amount needed to complete the decommissioning by $25 million. At this point in
time, we plan to provide the additional amounts needed from our corporate funds
and, subsequent to the completion of radiological decommissioning work, seek
recovery of such expenditures at the MPSC. We cannot predict how the MPSC will
rule on our request.
In the case of Palisades, again excluding additional nuclear fuel storage costs
due to the DOE's failure to accept this spent fuel on schedule, we have
concluded that the existing surcharge needs to be increased to $25 million
annually, beginning January 1, 2006, and continue through 2011, our current
license expiration date. We plan to file an application with the MPSC seeking
approval to increase the surcharge for recovery of decommissioning costs related
to Palisades beginning in 2006. We cannot predict how the MPSC will rule on our
request.
NUCLEAR MATTERS: Big Rock: With the removal and safe disposal of the reactor
vessel, steam drum, and radioactive waste processing systems in 2003,
dismantlement of plant systems is nearly complete and demolition of the
remaining plant structures is set to begin. 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 in mid-2006. An additional 30 acres, the area where seven
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transportable dry casks loaded with spent nuclear fuel and an eighth cask loaded
with high-level radioactive waste material are stored, will be returned to a
natural state by the end of 2012 if the DOE begins removing the spent nuclear
fuel by 2010.
The NRC and the Michigan Department of Environmental Quality continue to find
all decommissioning activities at Big Rock are being performed in accordance
with applicable regulations including license requirements.
Palisades: In March 2004, the NRC completed its end-of-cycle plant performance
assessment of Palisades. The assessment for Palisades covered the period from
January 1, 2003 through December 31, 2003. The NRC determined that Palisades was
operated in a manner that preserved public health and safety and fully met all
cornerstone objectives. As of March 2004, all inspection findings were
classified as having very low safety significance and all performance indicators
indicated performance at a level requiring no additional oversight. Based on the
plant's performance, only regularly scheduled inspections are planned through
September 2005.
The amount of spent nuclear fuel exceeds Palisades' temporary onsite storage
pool capacity. We are using dry casks for temporary onsite storage. As of March
31, 2004, we have loaded 18 dry casks with spent nuclear fuel and are scheduled
to load additional dry casks this summer in order to continue operation.
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. A number of utilities have initiated
litigation in the United States Court of Claims; we filed our complaint in
December 2002. If our litigation against the DOE is successful, we anticipate
future recoveries from the DOE. The recoveries will be used 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. The next step
will be for the DOE to submit an application to the NRC for a license to begin
construction of the repository. The application and review process is estimated
to take several years.
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.
We are unable to predict the outcome of this matter.
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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 $27 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 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 where 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 $10
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.
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.
COMMITMENTS FOR FUTURE PURCHASES: We enter into a number of unconditional
purchase obligations that represent normal business operating contracts. These
contracts are used to assure an adequate supply of goods and services necessary
for the operation of our business and to minimize exposure to market price
fluctuations. We believe that these future costs are prudent and reasonably
assured of recovery in future rates.
Coal Supply and Transportation: We have entered into coal supply contracts with
various suppliers and associated rail transportation contracts for our
coal-fired generating stations. Under the terms of these agreements, we are
obligated to take physical delivery of the coal and make payment based upon the
contract terms. Our coal supply contracts expire through 2005, and total an
estimated $182 million. Our coal transportation contracts expire through 2007,
and total an estimated $132 million. Long-term coal supply contracts have
accounted for approximately 60 to 90 percent of our annual coal requirements
over the last 10 years. Although future contract coverage is unknown at this
time, we believe that it will be within the historic 60 to 90 percent range.
Power Supply, Capacity, and Transmission: As of March 31, 2004, we had future
unrecognized commitments to purchase power transmission services under fixed
price forward contracts for 2004 and 2005 totaling $7 million. We also had
commitments to purchase capacity and energy under long-term power purchase
agreements with various generating plants. These contracts require monthly
capacity payments based on the plants' availability or deliverability. These
payments for 2004 through 2030 total an estimated $4.581 billion, undiscounted.
This amount may vary depending upon plant availability and fuel costs. If a
plant was not available to deliver electricity to us, then we would not be
obligated to
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make the capacity payment until the plant could deliver.
GAS CONTINGENCIES
GAS ENVIRONMENTAL MATTERS: We expect to have investigation and remedial 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. We have completed initial
investigations at the 23 sites. We will continue to implement remediation plans
for sites where we have received MDEQ remediation plan approval. We will also
work toward resolving environmental issues at sites as studies are completed.
We have estimated our costs for investigation and remedial action at all 23
sites using the Gas Research Institute-Manufactured Gas Plant Probabilistic Cost
Model. We expect our remaining costs to be between $37 million and $90 million.
The range reflects multiple alternatives with various assumptions for resolving
the environmental issues at each site. The estimates are based on discounted
2003 costs using a discount rate of three percent. The discount rate represents
a ten-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 through the MPSC approved rates charged to our customers. As of
March 31, 2004, we have recorded a liability of $42 million, net of $39 million
of expenditures incurred to date, and a regulatory asset of $67 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.
In its November 2002 gas distribution rate order, the MPSC authorized us to
continue to recover approximately $1 million of manufactured gas plant
facilities environmental clean-up costs annually. This amount will continue to
be offset by $2 million to reflect amounts recovered from all other sources. We
defer and amortize, over a period of 10 years, manufactured gas plant facilities
environmental clean-up costs above the amount currently included in rates.
Additional amortization of the expense in our rates cannot begin until after a
prudency review in a gas rate case.
GAS RATE MATTERS
GAS COST RECOVERY: The MPSC is required by law to allow us to charge customers
for our actual cost of purchased natural gas. The GCR process is designed to
allow us to recover all of our gas costs; however, the MPSC reviews these costs
for prudency in an annual reconciliation proceeding. In June 2003, we filed a
reconciliation of GCR costs and revenues for the 12 months ended March 2003. We
proposed to recover from our customers approximately $6 million of
under-recovered gas costs using a roll-in methodology. The roll-in methodology
incorporates the GCR under-recovery in the next GCR plan year. The approach was
approved by the MPSC in a November 2002 order.
In January 2004, intervenors filed their positions in our 2003 GCR case. Their
positions were that not all of our gas purchasing decisions were prudent during
April 2002 through March 2003 and they proposed disallowances. In 2003, we
reserved $11 million for a settlement agreement associated with the 2002-2003
GCR disallowance. Interest on the disallowed amount from April 1, 2003 through
February 2004, at Consumers' authorized rate of return, increased the cost of
the settlement by $1 million. The interest was recorded as an expense in 2003.
In February 2004, the parties in the case reached a settlement agreement that
resulted in a GCR disallowance of $11 million for the GCR period. The settlement
agreement was approved by the MPSC in March 2004. We plan to file a 2003-2004
GCR reconciliation in June 2004.
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In March 2004, the MPSC approved a temporary settlement authorizing us to bill a
maximum allowable GCR factor with two quarterly adjustments. The current GCR
ceiling factor is $5.94 per mcf, and this is the amount included for May 2004
bills. We are continuing to work with the parties in the case to obtain a final
settlement in the 2004-2005 GCR plan case.
2003 GAS RATE CASE: In March 2003, we filed an application with the MPSC for a
$156 million annual increase in our gas delivery and transportation rates that
included a 13.5 percent return on equity. In September 2003, we filed an update
to our gas rate case that lowered the requested revenue increase from $156
million to $139 million and reduced the return on common equity from 13.5
percent to 12.75 percent. The MPSC authorized an interim gas rate increase of
$19 million annually. The interim increase is under bond and subject to refund
if the final rate relief is a lesser amount. The interim increase order includes
a $34 million reduction in book depreciation expense and related income taxes
effective only during the period that we receive the interim relief. The MPSC
order allowed us to increase our rates beginning December 19, 2003. As part of
the interim order, we agreed to restrict dividend payments to our parent
company, CMS Energy, to a maximum of $190 million annually during the period
that we receive the interim relief. On March 5, 2004, the ALJ issued a Proposal
for Decision recommending that the MPSC not rely upon the projected test year
data included in our filing and supported by the MPSC Staff and further
recommended that the application be dismissed. In response to the Proposal for
Decision the parties have filed exceptions and replies to exceptions. The MPSC
is not bound by the ALJ's recommendation and will review the exceptions and
replies to exceptions prior to issuing an order on final rate relief.
2001 GAS DEPRECIATION CASE: In December 2003, we filed an update to our gas
utility plant depreciation case originally filed in June 2001. This case is not
affected by the 2003 gas rate case interim increase order, which reduced book
depreciation expense and related income taxes only for the period that we
receive the interim relief. The original filing was based on December 2000 plant
balances and historical data. The December 2003 filing updates the gas
depreciation case to include December 2002 plant balances. The proposed
depreciation rates, if approved, will result in an annual increase of $12
million in depreciation expense based on December 2002 plant balances. The ALJ's
Proposal for Decision is expected in May 2004.
OTHER UNCERTAINTIES
In addition to the matters disclosed in this Note, we are parties to certain
lawsuits and administrative proceedings before various courts and governmental
agencies arising from the ordinary course of business. These lawsuits and
proceedings may involve personal injury, property damage, contractual matters,
environmental issues, federal and state taxes, rates, licensing, and other
matters.
We have accrued estimated losses for certain contingencies discussed in this
Note. Resolution of these contingencies is not expected to have a material
adverse impact on our financial position, liquidity, or results of operations.
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3: FINANCINGS AND CAPITALIZATION
LONG-TERM DEBT:
Long-term debt is summarized as follows:
In Millions
- -------------------------------------------------------------
March 31 December 31
2004 2003
-------- -----------
First mortgage bonds $ 1,483 $ 1,483
Senior notes 1,254 1,254
Bank debt and other 469 469
Securitization bonds 419 426
FMLP debt 411 -
-------- -----------
Principal amount outstanding 4,036 3,632
Current amounts (443) (28)
Net unamortized discount (21) (21)
-------- -----------
Total Long-term debt $ 3,572 $ 3,583
=============================================================
FMLP DEBT: We consolidated the FMLP due to the adoption of Revised FASB
Interpretation No. 46. At March 31, 2004, long-term debt of the FMLP, which is
consolidated into our financial statements for the first time, consists of:
In Millions
- ------------------------------------------------------------------------
Maturity 2004
-------- -----------
11.75% subordinated secured notes 2005 $ 185
13.25% subordinated secured notes 2006 75
6.875% tax-exempt subordinated secured notes 2009 137
6.75% tax-exempt subordinated secured notes 2009 14
-------- -----------
Total amount outstanding $ 411
========================================================================
The FMLP debt is essentially project debt secured by certain assets of the MCV
Partnership and the FMLP. The debt is non-recourse to other assets of CMS Energy
and Consumers.
DEBT MATURITIES: At March 31, 2004, the aggregate annual maturities for
long-term debt for nine months ending December 31, 2004 and the next four years
are:
In Millions
- ---------------------------------------------------------------------
Payments Due
- ---------------------------------------------------------------------
December 31 2004 2005 2006 2007 2008
- -------------- ------ ------ ------ ------ -----------
Long-term debt $ 136 $ 559 $ 478 $ 59 $ 504
=====================================================================
REGULATORY AUTHORIZATION FOR FINANCINGS: At March 31, 2004, we had remaining
FERC authorization to issue or guarantee up to $500 million of short-term
securities and up to $700 million of short-term first mortgage bonds as
collateral for such short-term securities.
At March 31, 2004, we had remaining FERC authorization to issue up to $740
million of long-term securities for refinancing or refunding purposes, $560
million of long-term securities for general corporate purposes, and $2 billion
of long-term first mortgage bonds to be issued solely as collateral for
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other long-term securities. The authorizations expire on June 30, 2004 and we
plan to file a renewal application in early May 2004.
SHORT-TERM FINANCINGS: At March 31, 2004, we have a $400 million revolving
credit facility with banks. $376 million is available for general corporate
purposes, working capital, and letters of credit. The MCV Partnership has $50
million working capital facility available.
FIRST MORTGAGE BONDS: We secure our first mortgage bonds by a mortgage and lien
on substantially all of our property. Our ability to issue and sell securities
is restricted by certain provisions in the first mortgage bond indenture, our
articles of incorporation, and the need for regulatory approvals under federal
law.
CAPITAL LEASE OBLIGATIONS: 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. The MCV Partnership classifies this transaction as a
capital lease. As of March 31, 2004 capital lease obligations total $372
million, of which $307 million represents the third-party portion of the MCV
Facility capital lease.
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. We sold no receivables at March 31, 2004 and we sold $325 million
at March 31, 2003. The Consolidated Balance Sheets exclude these amounts from
accounts receivable. We continue to service the receivables sold. The purchaser
of the receivables has no recourse against our other assets for failure of a
debtor to pay when due and the purchaser has no right to any receivables not
sold. No gain or loss has been recorded on the receivables sold and we retain no
interest in the receivables sold.
Certain cash flows received from and paid to us under our accounts receivable
sales program are shown below:
In Millions
- -------------------------------------------------------------------------------------------
Three Months Ended March 31 2004 2003
- --------------------------- ------- -----------
Proceeds from sales (remittance of collections) under the program $ (297) $ -
Collections reinvested under the program $ 1,549 $ 1,375
======= ===========
DIVIDEND RESTRICTIONS: Under the provisions of our articles of incorporation, at
March 31, 2004, we had $397 million of unrestricted retained earnings available
to pay common dividends. Covenants in our debt facilities cap common stock
dividend payments at $300 million in a calendar year. We are also under an
annual dividend cap of $190 million imposed by the MPSC during the current
interim gas rate relief period. In February 2004, we paid $78 million in common
stock dividends to CMS Energy.
For additional details on the cap on common dividends payable during the current
interim gas rate relief period, see Note 2, Uncertainties, "Gas Rate Matters -
2003 Gas Rate Case."
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Consumers Energy Company
FASB INTERPRETATION NO. 45, GUARANTOR'S ACCOUNTING AND DISCLOSURE REQUIREMENT
FOR GUARANTEES, INCLUDING INDIRECT GUARANTEES OF INDEBTEDNESS OF OTHERS: This
Interpretation became effective January 2003. It describes the disclosure to be
made by a guarantor about its obligations under certain guarantees that it has
issued. At the beginning of a guarantee, it requires a guarantor to recognize a
liability for the fair value of the obligation undertaken in issuing the
guarantee. The initial recognition and measurement provision of this
Interpretation does not apply to some guarantee contracts, such as warranties,
derivatives, or guarantees between either parent and subsidiaries or
corporations under common control, although disclosure of these guarantees is
required. For contracts that are within the recognition and measurement
provision of this Interpretation, the provisions were to be applied to
guarantees issued or modified after December 31, 2002.
The following tables describe our guarantees at March 31, 2004:
In Millions
- ------------------------------------------------------------------------------------------------------------
Issue Expiration Maximum Carrying Recourse
Guarantee Description Date Date Obligation Amount Provision (a)
- --------------------- ------- ---------- ---------- -------- -------------
Standby letters of credit Various Various $ 24 $ - $ -
Surety bonds Various Various 8 - -
Nuclear insurance retrospective premiums Various Various 134 - -
======= ========== ========== ======== =============
(a) Recourse provision indicates the approximate recovery from third parties
including assets held as collateral.
Events That Would Require
Guarantee Description How Guarantee Arose Performance
- ----------------------------------------- ----------------------------------------- --------------------------------------------
Standby letters of credit Normal operations of coal power plants Noncompliance with environmental regulations
Natural gas transportation Nonperformance
Self-insurance requirement Nonperformance
Surety bonds Normal operating activity, permits and Nonperformance
license
Nuclear insurance retrospective premiums Normal operations of nuclear plants Call by NEIL and Price Anderson Act
for nuclear incident
================================================================================================================================
4: FINANCIAL AND DERIVATIVE INSTRUMENTS
FINANCIAL INSTRUMENTS: The carrying amounts of cash, short-term investments, and
current liabilities approximate their fair values because of their short-term
nature. We estimate the fair values of long-term financial instruments based on
quoted market prices or, in the absence of specific market prices, on quoted
market prices of similar instruments or other valuation techniques. The carrying
amount of all long-term financial instruments, except as shown below,
approximates fair value. Our held-to-maturity investments consist of debt
securities held by the MCV Partnership totaling $140 million as of March 31,
2004. These securities represent funds restricted primarily for future lease
payments and are classified as Other Assets on the Consolidated Balance Sheets.
These investments have original maturity dates of approximately one year or less
and, because of their short maturities, their carrying amounts approximate their
fair values. For additional details, see Note 1, Corporate Structure and
Accounting Policies.
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In Millions
- ---------------------------------------------------------------------------------------------------------
2004 2003
-------------------------------- -------------------------------
Fair Unrealized Fair Unrealized
March 31 Cost Value Gain (Loss) Cost Value Gain (Loss)
- -------- ------- -------- ----------- ------- ------- -----------
Long-term debt (a) $ 4,015 $ 4,200 $ (185) $ 3,001 $ 3,011 $ (10)
Long-term debt - related parties (b) 506 521 (15) - - -
Trust Preferred Securities (b) - - - 490 425 65
Available for sale securities:
Common stock of CMS Energy (c) 10 21 11 10 10 -
SERP 17 22 5 18 18 -
Nuclear decommissioning
investments (d) 433 566 133 458 529 71
======= ======== =========== ======= ======= ===========
(a) Includes a principal amount of $443 million at March 31, 2004 and $277
million at March 31, 2003 relating to current maturities. Settlement of
long-term debt is generally not expected until maturity.
(b) We determined that we are not the primary beneficiary of our trust preferred
security structures. Accordingly, those entities were deconsolidated as of
December 31, 2003 and are reflected in Long-term debt - related parties on the
Consolidated Balance Sheets. For additional details, see Note 7, Implementation
of New Accounting Standards.
(c) We recognized a $12 million loss on this investment in 2002 and an
additional $12 million loss in the first quarter of 2003 because the loss was
other than temporary, as the fair value was below the cost basis for more than
six months. As of March 31, 2004, we held 2.4 million shares of CMS Energy
Common Stock.
(d) On January 1, 2003, we adopted SFAS No. 143 and began classifying our
unrealized gains and losses on nuclear decommissioning investments as regulatory
liabilities. We previously classified the unrealized gains and losses on these
investments in accumulated depreciation.
DERIVATIVE INSTRUMENTS: We are exposed to market risks including, but not
limited to, changes in interest rates, commodity prices, and equity security
prices. We manage these risks using established policies and procedures, under
the direction of both an executive oversight committee consisting of senior
management representatives and a risk committee consisting of business-unit
managers. We may use various contracts to manage these risks including swaps,
options, and forward contracts.
We intend 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 risk
management 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 minimize such risk by
performing financial credit reviews using, among other things, publicly
available credit ratings of such counterparties.
Contracts used to manage interest rate and commodity price risk may be
considered derivative instruments that are subject to derivative and hedge
accounting pursuant to SFAS No. 133. If a contract is accounted for as a
derivative instrument, it is recorded in the financial statements as an asset or
a liability, at the fair value of the contract. The recorded fair value of the
contract is then adjusted quarterly to reflect any change in the market value of
the contract, a practice known as marking the contract to market. The accounting
for changes in the fair value of a derivative (that is, gains or losses)
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Consumers Energy Company
are reported either in earnings or accumulated other comprehensive income
depending on whether the derivative qualifies for special hedge accounting
treatment.
For derivative instruments to qualify for hedge accounting under SFAS No. 133,
the hedging relationship must be formally documented at inception and be highly
effective in achieving offsetting cash flows or offsetting changes in fair value
attributable to the risk being hedged. If hedging a forecasted transaction, the
forecasted transaction must be probable. If a derivative instrument, used as a
cash flow hedge, is terminated early because it is probable that a forecasted
transaction will not occur, any gain or loss as of such date is immediately
recognized in earnings. If a derivative instrument, used as 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. We use a combination of quoted market prices and mathematical
valuation models to determine fair value of those contracts requiring derivative
accounting. The ineffective portion, if any, of all hedges is recognized in
earnings.
The majority of our contracts are not subject to derivative accounting because
they qualify for the normal purchases and sales exception of SFAS No. 133, or
are not derivatives because there is not an active market for the commodity. Our
electric capacity and energy contracts are not accounted for as derivatives due
to the lack of an active energy market in the state of Michigan and the
significant transportation costs that would be incurred to deliver the power
under the contracts to the closest active energy market at the Cinergy hub in
Ohio. If an active market develops in the future, we may be required to account
for these contracts as derivatives. The mark-to-market impact on earnings
related to these contracts could be material to the financial statements.
Derivative accounting is required for certain contracts used to limit our
exposure to electricity and gas commodity price risk and interest rate risk.
The following table reflects the fair value of all contracts requiring
derivative accounting:
In Millions
- ---------------------------------------------------------------------------------------------------------
2004 2003
March 31 -------------------------------- -------------------------------
- ---------------------- Fair Unrealized Fair Unrealized
Derivative Instruments Cost Value Gain (Loss) Cost Value Gain (Loss)
- ---------------------- ------- -------- ----------- ------- ------- -----------
Electric - related contracts $ - $ - $ - $ 8 $ 1 $ (7)
Gas contracts 5 11 6 - - -
Interest rate risk contracts - - - - (1) (1)
Derivative contracts associated with
Consumers' investment in the MCV
Partnership:
Prior to consolidation - - - - 17 17
After consolidation:
Gas fuel contracts - 81 81 - - -
Gas fuel futures - 50 50 - - -
======= ======== =========== ======= ======= ===========
The fair value of all derivative contracts is included in either Derivative
Instruments or Other Assets on the Consolidated Balance Sheets. The fair value
of derivative contracts associated with our investment in the MCV Partnership
for 2003 is included in Investments - Midland Cogeneration Venture Limited
Partnership on the Consolidated Balance Sheets.
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ELECTRIC CONTRACTS: Our electric utility business uses purchased electric call
option contracts to meet, in part, our regulatory obligation to serve. This
obligation requires us to provide a physical supply of electricity to customers,
to manage electric costs, and to ensure a reliable source of capacity during
peak demand periods.
GAS CONTRACTS: Our gas utility business uses fixed price and index-based gas
supply contracts, fixed price weather-based gas supply call options, fixed price
gas supply call and put options, and other types of contracts, to meet our
regulatory obligation to provide gas to our customers at a reasonable and
prudent cost. Unrealized gains and losses associated with these options are
reported directly in earnings as part of other income, and then directly offset
in earnings and recorded on the balance sheet as a regulatory asset or liability
as part of the GCR process.
INTEREST RATE RISK CONTRACTS: We use interest rate swaps to hedge the risk
associated with forecasted interest payments on variable-rate debt. These
interest rate swaps are designated as cash flow hedges. As such, we record any
change in the fair value of these contracts in accumulated other comprehensive
income unless the swaps are sold. As of March 31, 2004, we did not have any
interest rate swaps outstanding. As of March 31, 2003, we had entered into a
swap to fix the interest rate on $75 million of variable-rate debt. This swap
expired in June 2003. We were able to apply the shortcut method to this interest
rate hedge; therefore, there was no ineffectiveness associated with this hedge.
DERIVATIVE CONTRACTS ASSOCIATED WITH CONSUMERS' INVESTMENT IN THE MCV
PARTNERSHIP: Natural Gas Fuel Contracts: The MCV Partnership uses natural gas
fuel contracts to buy gas as fuel for generation, and to manage gas fuel costs.
The MCV Partnership believes that its long-term natural gas contracts, which do
not contain volume optionality, qualify under SFAS No. 133 for the normal
purchases and normal sales exception. Therefore, these contracts are currently
not recognized at fair value on the balance sheet. Should significant changes in
the level of the MCV Facility operational dispatch or purchases of long-term gas
occur, the MCV Partnership would be required to re-evaluate its accounting
treatment for these long-term gas contracts. This re-evaluation may result in
recording mark-to-market activity on some contracts, which could add to earnings
volatility.
The FASB issued Derivatives Implementation Group Issue C-16, which became
effective April 1, 2002, regarding natural gas commodity contracts that combine
an option component and a forward component. This guidance requires either that
the entire contract be accounted for as a derivative or the components of the
contract be separated into two discrete contracts. Under the first alternative,
the entire contract considered together would not qualify for the normal
purchases and sales exception under the revised guidance. Under the second
alternative, the newly established forward contract could qualify for the normal
purchases and sales exception, while the option contract would be treated as a
derivative under SFAS No. 133 with changes in fair value recorded through
earnings.
At April 1, 2002, the MCV Partnership had nine long-term gas contracts that
contained both an option and forward component. As such, they were no longer
accounted for under the normal purchases and sales exception and the MCV
Partnership began mark-to-market accounting of these nine contracts through
earnings. Based on the natural gas prices, at the beginning of April 2002, the
MCV Partnership recorded a $58 million gain for the cumulative effect of this
accounting change. During the fourth quarter of 2002, the MCV Partnership
removed the option component from three of the nine long-term gas contracts,
which should reduce some of the earnings volatility. The MCV Partnership expects
future earnings volatility on the six remaining long-term gas contracts that
contain volume optionality, since changes to this mark-to-market gain will be
recorded on a quarterly basis during the remaining life of approximately four
years for these gas contracts. From April 2002 to March 2004, the MCV
Partnership recorded an additional net mark-to-market gain of $23 million for
these gas contracts for a cumulative
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mark-to-market gain through March 31, 2004 of $81 million, which will reverse
over the remaining life of these gas contracts, ranging from 2004 to 2007.
For the three months ended March 31, 2004, the MCV Partnership recorded in Fuel
for Electric Generation a $6 million net mark-to-market gain in earnings
associated with these contracts
Natural Gas Fuel Futures and Options: To manage market risks associated with the
volatility of natural gas prices, the MCV Partnership maintains a gas hedging
program. The MCV Partnership enters into natural gas futures and option
contracts 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 being 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.
These financial instruments are derivatives under SFAS No. 133 and the contracts
that are used to secure the anticipated natural gas requirements necessary for
projected electric and steam sales qualify as cash flow hedges under SFAS No.
133, since they hedge the price risk associated with the cost of natural gas.
The MCV Partnership also engages in cost mitigation activities to offset the
fixed charges the MCV Partnership incurs in operating the MCV Facility. These
cost mitigation activities 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 cost mitigation activities are not considered a
normal course of business for the MCV Partnership and do not qualify as hedges
under SFAS No. 133. Therefore, the resulting mark-to-market gains and losses
from cost mitigation activities are flowed through the MCV Partnership's
earnings.
Cash is deposited with the broker in a margin account at the time futures or
options contracts are initiated. The change in market value of these contracts
requires adjustment of the margin account balances. The margin account balance
as of March 31, 2004 was recorded as a current asset in Other Assets, in the
amount of $2 million.
For the three months ended March 31, 2004, the MCV Partnership has recognized in
other comprehensive income, an unrealized $20 million increase on the futures
contracts, which are hedges of forecasted purchases for plant use of market
priced gas. This resulted in a net $51 million gain in other comprehensive
income as of March 31, 2004. This balance represents natural gas futures with
maturities ranging from April 2004 to December 2007, of which $34 million of
this gain is expected to be reclassified into earnings within the next twelve
months. As of March 31, 2004, Consumers' pretax proportionate share of the MCV
Partnership's $51 million net gain recorded in other comprehensive income is $25
million. The MCV Partnership also has recorded, as of March 31, 2004, a $50
million current derivative asset, representing the mark-to-market gain on
natural gas futures for anticipated projected electric and steam sales accounted
for as hedges. In addition, for the three months ended March 31, 2004, the MCV
Partnership has recorded a net $5 million gain in earnings from hedging
activities related to natural gas requirements for the MCV Facility operations
and a net $1 million gain in earnings from cost mitigation activities.
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5: 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,
- benefits to certain management employees under SERP,
- health care and life insurance benefits under OPEB,
- benefits to a select group of management under EISP, and
- a defined contribution 401(k) plan.
Pension Plan: The Pension Plan includes funds for our employees and our
non-utility affiliates, including former Panhandle employees. The Pension Plan's
assets are not distinguishable by company.
OPEB: We adopted SFAS No. 106, effective as of the beginning of 1992. We
recorded a liability of $466 million for the accumulated transition obligation
and a corresponding regulatory asset for anticipated recovery in utility rates.
For additional details, see Note 1, Corporate Structure and Accounting Policies,
"Utility Regulation." The MPSC authorized recovery of the electric utility
portion of these costs in 1994 over 18 years and the gas utility portion in 1996
over 16 years. We made a contribution of $18 million to our 401(h) and VEBA
trust funds in March 2004. We plan to make additional contributions of $53
million in 2004.
Costs: The following table recaps the costs incurred in our retirement benefits
plans:
In Millions
- ------------------------------------------------------------------------------------------
Pension OPEB
Three Months Ended March 31 2004 2003 2004 2003
- --------------------------- ------ ------ ------ ------
Service cost $ 10 $ 10 $ 5 $ 4
Interest expense 18 19 16 15
Expected return on plan assets (27) (20) (11) (10)
Amortization of:
Net loss 3 2 6 5
Prior service cost 1 2 (2) (1)
------ ------ ------ ------
Net periodic pension and postretirement benefit cost $ 5 $ 13 $ 14 $ 13
====== ====== ====== ======
The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 that
was signed into law in December 2003, establishes a prescription drug benefit
under Medicare (Medicare Part D), and a federal subsidy to sponsors of retiree
health care benefit plans that provide a benefit that is actuarially equivalent
to Medicare Part D. We are continuing to defer recognizing the effects of the
Act in our 2004 financial statements, as permitted by FASB Staff Position No.
106-b. When accounting guidance is issued, our retiree health benefit obligation
may be adjusted. For additional details, see Note 7, Implementation of New
Accounting Standards.
As of March 31, 2004, we have recorded a prepaid pension asset of $379 million,
$20 million of which is in other current assets on our consolidated balance
sheets.
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6: ASSET RETIREMENT OBLIGATIONS
SFAS NO. 143, ACCOUNTING FOR ASSET RETIREMENT OBLIGATIONS: This standard became
effective January 2003. It 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 do so. We have legal obligations to remove some of our assets,
including our nuclear plants, at the end of their useful lives.
Before adopting this standard, we classified the removal cost of assets included
in the scope of SFAS No. 143 as part of the reserve for accumulated
depreciation. For these assets, the removal cost of $448 million that was
classified as part of the reserve at December 31, 2002, was reclassified in
January 2003, in part, as:
- $364 million ARO liability,
- $134 million regulatory liability,
- $42 million regulatory asset, and
- $7 million net increase to property, plant, and equipment as
prescribed by SFAS No. 143.
We are reflecting a regulatory asset and liability as required by SFAS No. 71
for regulated entities 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 the asset
retirement obligation is incurred, such as assets with indeterminate lives, the
liability is to be recognized when a reasonable estimate of fair value can be
made. Generally, transmission and distribution assets have indeterminate lives.
Retirement cash flows cannot be determined. There is a low probability of a
retirement date, so no liability has been recorded for these assets. 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
are based largely on third-party cost estimates.
The following tables describe our assets that have legal obligations to be
removed at the end of their useful life.
March 31, 2004 In Millions
- ----------------------------------------------------------------------------------------------------------------------
In Service Trust
ARO Description Date Long Lived Assets Fund
- ----------------------------------------- ---------- ------------------------------------ --------
Palisades - decommission plant site 1972 Palisades nuclear plant $ 497
Big Rock - decommission plant site 1962 Big Rock nuclear plant 69
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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March 31, 2004 In Millions
- ------------------------------------------------------------------------------------------------------------------
ARO Liability ARO
------------------ Cash flow Liability
ARO Description 1/1/03 12/31/03 Incurred Settled Accretion Revisions 3/31/04
- ------------------------------- ------ -------- -------- ------- --------- --------- ---------
Palisades - decommission $ 249 $ 268 $ - $ - $ 5 $ 31 $ 304
Big Rock - decommission 61 35 - (21) 3 22 39
JHCampbell intake line - - - - - - -
Coal ash disposal areas 51 52 - - 1 - 53
Wells at gas storage fields 2 2 - - - - 2
Indoor gas services relocations 1 1 - - - - 1
------ -------- -------- ------- --------- --------- ---------
Total $ 364 $ 358 $ - $ (21) $ 9 $ 53 $ 399
====== ======== ======== ======= ========= ========= =========
The Palisades and Big Rock cash flow revisions resulted from new decommissioning
reports filed with the MPSC in March 2004. For additional details, see Note 2,
Uncertainties, "Other Electric Uncertainties - Nuclear Plant Decommissioning."
Reclassification of certain types of Cost of Removal: Beginning in December
2003, the SEC requires the quantification and reclassification of the estimated
cost of removal obligations arising from other than legal obligations. These
obligations have been accrued through depreciation charges. We estimate that we
had $1.005 billion at March 31, 2004 and $937 million at March 31, 2003 of
previously accrued asset removal costs related to our regulated operations, for
other than legal obligations. These obligations, which were previously
classified as a component of accumulated depreciation, are now classified as
regulatory liabilities in the accompanying consolidated balance sheets.
7: IMPLEMENTATION OF NEW ACCOUNTING STANDARDS
FASB INTERPRETATION NO. 46, CONSOLIDATION OF VARIABLE INTEREST ENTITIES: The
FASB issued this Interpretation in January 2003. The objective of the
Interpretation is to assist in determining when one party controls another
entity in circumstances where a controlling financial interest cannot be
properly identified based on voting interests. Entities with this characteristic
are considered variable interest entities. The Interpretation requires the party
with the controlling financial interest, known as the primary beneficiary, in a
variable interest entity to consolidate the entity.
On December 24, 2003, the FASB issued Revised FASB Interpretation No. 46. For
entities that have not previously adopted FASB Interpretation No. 46, Revised
FASB Interpretation No. 46 provided an implementation deferral until the first
quarter of 2004. As of and for the quarter ended March 31, 2004, we adopted
Revised FASB Interpretation No. 46 for all entities.
We determined that 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. In addition, 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. As such, we consolidated their assets, liabilities, and
activities into our financial statements for the first time as of and for the
quarter ended March 31, 2004. These partnerships have third-party obligations
totaling $718 million at March 31, 2004. Property, plant, and equipment serving
as collateral for these obligations has a carrying value of
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Consumers Energy Company
$1.471 billion at March 31, 2004. The creditors of these partnerships do not
have recourse to the general credit of Consumers.
We also determined that we are not the primary beneficiary of our trust
preferred security structures. Accordingly, those entities have been
deconsolidated as of December 31, 2003. Company obligated Trust Preferred
Securities totaling $490 million, that were previously included in mezzanine
equity, have been eliminated due to deconsolidation. As a result of the
deconsolidation, we reflected $506 million of long-term debt - related parties
and reflected an investment in related parties of $16 million.
We are not required to, and have not, restated prior periods for the impact of
this accounting change.
ACCOUNTING STANDARDS NOT YET EFFECTIVE
PROPOSED FASB STAFF POSITION, NO. SFAS 106-B, ACCOUNTING AND DISCLOSURE
REQUIREMENTS RELATED TO THE MEDICARE PRESCRIPTION DRUG, IMPROVEMENT, AND
MODERNIZATION ACT OF 2003: The Medicare Prescription Drug, Improvement, and
Modernization Act of 2003 (Act), that was signed into law in December 2003,
establishes a prescription drug benefit under Medicare (Medicare Part D), and a
federal subsidy to sponsors of retiree health care benefit plans that provide a
benefit that is actuarially equivalent to Medicare Part D. At December 31, 2003,
we elected a one-time deferral of the accounting for the Act, as permitted by
FASB Staff Position, No. SFAS 106-1.
Proposed FASB Staff Position, No. SFAS 106-b supersedes FASB Staff Position, No.
106-1 and provides further guidance for accounting for the Act. Proposed FASB
Staff Position, No. 106-b states that for plans that are actuarially equivalent
to Medicare Part D, employers' measures of accumulated postretirement benefit
obligations (APBO) and postretirement benefit costs should reflect the effects
of the Act.
As of March 31, 2004, we have not determined whether our postretirement benefit
plan is actuarially equivalent to Medicare Part D. Therefore, our measures of
APBO and net periodic postretirement benefit cost do not reflect any amount
associated with the Medicare Prescription Drug, Improvement, and Modernization
Act of 2003. If our prescription drug plan is determined to be actuarially
equivalent to Medicare Part D, we estimate a decrease in OPEB expense of
approximately $20 million for 2004 and a one-time reduction of our benefit
obligation of approximately $140 million, to be amortized over future periods.
This Proposed FASB Staff Position would be effective for the first interim or
annual period beginning after June 15, 2004.
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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.
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, 2003. Reference is also made to the Condensed Notes to the Consolidated
Financial Statements, in particular, Note 3, Uncertainties
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for CMS Energy and Note 2, Uncertainties for Consumers, included herein for
additional information regarding various pending administrative and judicial
proceedings involving rate, operating, regulatory and environmental matters.
SEC INVESTIGATION
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. In March 2004, the SEC also 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.
CMS ENERGY
DEMAND FOR ACTIONS 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 at 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 is 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 on behalf of
the shareholder in the Circuit Court of Jackson County, Michigan in furtherance
of his demands. The date for CMS Energy and other defendants to answer or
otherwise respond to the complaint has been extended to June 1, 2004, subject to
such further extensions as may be mutually agreed upon by the parties and
authorized by the Court. CMS Energy cannot predict the outcome of this matter.
INTEGRUM LAWSUIT
Integrum filed a complaint in Wayne County, Michigan Circuit Court in July 2003
against CMS Energy, Enterprises and APT. Integrum alleges several causes of
action against APT, CMS Energy and Enterprises in connection with an offer by
Integrum to purchase the CMS Pipeline Assets. In addition to seeking unspecified
money damages, Integrum is seeking an order enjoining CMS Energy and Enterprises
from selling, and APT from purchasing, the CMS Pipeline Assets and an order of
specific performance mandating that CMS Energy, Enterprises and APT complete the
sale of the CMS Pipeline Assets to APT and Integrum. A certain officer and
director of Integrum is a former officer and director of CMS Energy, Consumers
and their subsidiaries. The individual was not employed by CMS Energy, Consumers
or their subsidiaries when Integrum made the offer to purchase the CMS Pipeline
Assets. CMS Energy and Enterprises filed a motion to change venue from Wayne
County to Jackson County, which was granted. The parties are now awaiting
transfer of the file from Wayne County to Jackson County. CMS Energy and
Enterprises believe that Integrum's claims are without merit. CMS Energy and
Enterprises intend to defend vigorously against this action but they cannot
predict the outcome of this litigation.
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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 court ordered the Cornerstone complaint to be consolidated with
similar complaints filed by Dominick Viola and Roberto Calle Gracey. 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. 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, Inc. but is required to
indemnify Cantera Natural Gas, Inc. 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 against a number of energy companies engaged in the sale
of natural gas in the United States. CMS Energy is named as a defendant. The
complaint alleges defendants entered into a price-fixing conspiracy by engaging
in activities to manipulate the price of natural gas in California. The
complaint contains counts alleging violations of the Sherman Act, Cartwright Act
(a California statute), and the California Business and Profession Code relating
to unlawful, unfair and deceptive business practices. There is currently pending
in the Nevada federal district court a multi district court litigation ("MDL")
matter involving 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 Sherman Act claim. Some
of the defendants in the MDL matter who are also defendants in the Texas-Ohio
case are trying to have the Texas-Ohio case transferred to the MDL proceeding.
The plaintiff in the Texas-Ohio case has agreed to extend the time for all
defendants to answer or otherwise respond to the complaint until after the MDL
panel decides whether to take the case.
Benscheidt v. AEP Energy Services, Inc., et al., a new class action complaint
containing allegations similar to those made in the Texas-Ohio case, albeit
limited to California state law claims, was filed in California state court in
February 2004. CMS Energy and CMS MST are named as defendants. Defendants filed
a notice to remove this action to California federal district court and are
seeking to have it transferred to the MDL proceeding in Nevada.
CMS Energy and the other CMS defendants will defend themselves vigorously but
cannot predict the outcome of these matters.
LEONARD FIELD DISPUTE
Pursuant to a Consent Judgment entered in Oakland County, Michigan Circuit Court
in September 2001, CMS Gas Transmission had 18 months to extract approximately
one bcf of pipeline quality natural gas held in the Leonard Field in Addison
Township. The Consent Judgment provided for an extension of that period upon
certain circumstances. CMS Gas Transmission has complied with the requirements
of the Consent Judgment. Addison Township filed a lawsuit in Oakland County
Circuit Court against CMS Gas Transmission in February 2004 alleging the Leonard
Field was discharging odors in violation of the Consent Judgment. Pursuant to a
Stipulated Order entered April 1, 2004, CMS Gas Transmission agreed to certain
undertakings to address the odor complaints and further agreed to temporarily
cease operations at the Leonard Field during the month of April 2004, the last
month provided for in the Consent Judgment. Also, Addison Township was required
to grant CMS Gas Transmission an extension to withdraw its natural gas if
certain conditions were met. Addison Township denied CMS Gas Transmission's
request for an extension on April 5, 2004. CMS Gas Transmission is pursuing its
legal remedies.
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However, CMS Gas Transmission cannot predict the outcome of this matter, and
unless an extension is provided, it will be unable to extract approximately
500,000 mcf of gas remaining in the Leonard Field.
CMS ENERGY AND CONSUMERS
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. The judge issued an opinion and order dated March 31,
2004 in connection with the motions to dismiss filed by CMS Energy, Consumers
and the individuals. The judge dismissed certain of the amended counts in the
plaintiffs' complaint and denied CMS Energy's motion to dismiss the other claims
in the complaint. CMS Energy, Consumers and the individual defendants are now
required to file answers to the amended complaint on or before May 14, 2004. CMS
Energy and Consumers will defend themselves vigorously but cannot predict the
outcome of this litigation.
SECURITIES CLASS ACTION LAWSUITS
Beginning on May 17, 2002, a number of securities class action complaints were
filed against CMS Energy, Consumers, and certain officers and directors of CMS
Energy and its affiliates. 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. The cases were consolidated into a single lawsuit and an
amended and consolidated class action complaint was filed on May 1, 2003. The
consolidated complaint contains a purported class period beginning on May 1,
2000 and running through March 31, 2003. It 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. The
judge issued an opinion and order dated March 31, 2004 in connection with
various pending motions, including plaintiffs' motion to amend the complaint and
the motions to dismiss the complaint filed by CMS Energy, Consumers and other
defendants. The judge directed plaintiffs to file an amended complaint under
seal and ordered an expedited hearing on the motion to amend. Based on his
decision with respect to the motion to amend, the judge dismissed certain of
plaintiffs' claims without prejudice and denied without prejudice the motions to
dismiss other claims. The judge will permit CMS Energy and the other defendants
to renew the motions to dismiss at or shortly after the hearing on the motion to
amend. CMS Energy, Consumers, and their affiliates will defend themselves
vigorously but cannot predict the outcome of this litigation.
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
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Energy's and Consumers' MANAGEMENT'S DISCUSSION AND ANALYSIS and CMS Energy's
and Consumers' CONDENSED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
ITEM 5. OTHER INFORMATION
A shareholder who wishes to submit a proposal for consideration at the CMS
Energy 2005 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 24,
2004. In any event if CMS Energy has not received written notice of any matter
to be proposed at that meeting by March 9, 2005, the holders of the proxies may
use their discretionary voting authority on any such matter. The proposals
should be addressed to:
Corporate Secretary, CMS Energy, One Energy Plaza, Jackson, Michigan 49201.
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) LIST OF 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
(b) REPORTS ON FORM 8-K
CMS ENERGY
During the first quarter of 2004, CMS Energy filed or furnished the
following Current Reports on Form 8-K:
- 8-K filed on January 22, 2004 covering matters pursuant to
Item 5, Other Events and Item 12, Results of Operations and
Financial Condition;
- 8-K furnished on March 10, 2004 covering matters pursuant to
Item 12, Results of Operations and Financial Condition
(including a Summary of Consolidated Earnings, Summarized
Comparative Balance Sheets, Summarized Statements of Cash
Flows, and a Summary of Consolidated Earnings); and
- 8-K filed on March 18, 2004 covering matters pursuant to Item
5, Other Events.
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CONSUMERS
During the first quarter of 2004, Consumers filed or furnished the
following Current Reports on Form 8-K:
- 8-K filed on January 22, 2004 covering matters pursuant to
Item 5, Other Events and Item 12, Results of Operations and
Financial Condition;
- 8-K furnished on March 10, 2004 covering matters pursuant to
Item 12, Results of Operations and Financial Condition
(including a Summary of Consolidated Earnings, Summarized
Comparative Balance Sheets, Summarized Statements of Cash
Flows, and a Summary of Consolidated Earnings); and
- 8-K filed on March 18, 2004 covering matters pursuant to Item
5, Other Events.
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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: May 7, 2004 By: /s/ Thomas J. Webb
-------------------------------------
Thomas J. Webb
Executive Vice President and
Chief Financial Officer
CONSUMERS ENERGY COMPANY
(Registrant)
Dated: May 7, 2004 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